Effective Mechanisms to 

Increase the Use of 

Demand-Side Resources

Global Power Best Practice Series 3

January

2013
Electronic copies of this paper and other RAP publications 

can be found on our website at www.raponline.org.

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please send relevant contact information to 

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Author

David Crossley

Effective Mechanisms to 

Increase the Use of Demand-Side Resources

The Global Power Best Practice Series was funded by the Climate Works 

Foundation (CWF) and The Regulatory Assistance Project (RAP). The information 

and material provided in this series is general in nature. RAP and CWF make no 

warranty or guarantee regarding the accuracy of any forecasts, estimates or analyses 

contained in the Global Power Best Practice Series reports. RAP and CWF are not 

responsible for any liability in association with this content.

Acknowledgements

This paper was written primarily by RAP Senior Advisor David Crossley, who has more 

than 35 years of experience in the energy sector, providing advice on sustainable energy 

policy and programs to governments, regulators, energy companies, industry associations, 

and NGOs. The RAP review team included Riley Allen, John Gerhard, Mike Hogan, Dave 

Lamont, Jim Lazar, David Moskovitz, and Chris Neme.
1

Effective Mechanisms to Increase the Use of Demand-Side Resources

Worldwide, the electricity sector is 

undergoing a fundamental transformation. 

Policymakers recognize that fossil fuels, 

the largest fuel source for the electricity 

sector, contribute to greenhouse gas emissions and 

other forms of man-made environmental contamination. 

Through technology gains, improved public policy, and 

market reforms, the electricity sector is becoming cleaner 

and more affordable. However, significant opportunities 

for improvement remain and the experiences in different 

regions of the world can form a knowledge base and 

provide guidance for others interested in driving this 

transformation. 

This Global Power Best Practice Series is designed to 

provide power-sector regulators and policymakers with 

useful information and regulatory experiences about key 

topics, including effective rate design, innovative business 

models, financing mechanisms, and successful policy 

interventions. The Series focuses on four distinct nations/

regions covering China, India, Europe, and the United 

States (U.S.). However, policymakers in other regions will 

find that the Series identifies best — or at least valued — 

practices and regulatory structures that can be adapted to a 

variety of situations and goals. 

Contextual differences are essential to understanding 

and applying the lessons distilled in the Series. Therefore, 

readers are encouraged to use the two supplemental 

resources to familiarize themselves with the governance, 

market, and regulatory institutions in the four highlighted 

regions. 

About the Global Power Best Practice Series

The Series includes the following topics: 

1. New Natural Gas Resources and the Environmental 

Implications in the U.S., Europe, India, and China

2. Policies to Achieve Greater Energy Efficiency

3. Effective Mechanisms to Increase the Use of 

Demand-Side Resources

4. Time-Varying and Dynamic Rate Design

5. Rate Design Where Advanced Metering 

Infrastructure Has Not Been Fully Deployed

6. Strategies for Decarbonizing the Electric 

Power Supply

7. Innovative Power Sector Business Models to 

Promote Demand-Side Resources 

8. Integrating Energy and Environmental Policy

9. Policies to Promote Renewable Energy

10. Strategies for Energy Efficiency Financing

11. Integrating Renewable Resources into Power Markets 

Supplemental Resources:

12. Regional Power Sector Profiles in the U.S., Europe, 

India, and China

13. Seven Case Studies in Transmission: Planning, 

Pricing, and System Operation

In addition to best practices, many of the reports also 

contain an extensive reference list of resources or an 

annotated bibliography. Readers interested in deeper study 

or additional reference materials will find a rich body of 

resources in these sections of each paper. Authors also 

identify the boundaries of existing knowledge and frame 

key research questions to guide future research.

Please visit www.raponline.org to access all papers in the Series. 

This Global Power Best Practice Series was funded by the ClimateWorks Foundation www.climateworks.org
2

Effective Mechanisms to Increase the Use of Demand-Side Resources

I

t’s hard to say why change comes slowly to some 

areas of human endeavor and quickly to others. The 

occurrence of that curious confluence of technology, 

economics, and societal readiness is as unpredictable 

as the flight of a honeybee. A revolution in communications 

brought about by the internet, cell phones, and the nanotransistor might have tickled imaginations fifty years ago, 

but its imminence, had that been foretold, would surely 

have amazed the very faculties of those mid-century eyes 

and ears.

So too would have the lethargy of certain elements of 

the energy sector. The uses to which we put electricity 

have, for reasons marveled at a moment ago, expanded 

greatly; but our relationship to the thing itself—how we 

produce it, how we sell it, how we think about it—hasn’t 

really changed in the eleven decades since Thomas Edison’s 

inspired idea to sell lighting—that is, end-use services—

rather than kilowatt-hours was undone by a proliferation of 

competitors and, perversely enough, end uses. Electricity 

became commoditized, distributed and paid for according 

to usage, delivered by wires, and available on demand at 

the flick of a switch. That’s still pretty much the story today. 

For all that roils in this industry—and the last half century 

has been nothing if not turbulent—its essential methods do 

not.

Or, at least, not much—and certainly not enough. Forty 

years ago began the great effort to apply, with real rigor, the 

principles of economics to investment and operations in 

the power sector. Approaches around the world varied—in 

China the focus was on modernizing the generating fleet; 

in England, on privatization and competition; in America, 

on a better allocation of risk between consumers and 

suppliers—but the common, overarching goal has been 

to improve efficiency, spur innovation, and drive down 

the cost to society of this essential good. And, to varying 

Foreword

degrees, the enterprise has been successful. Thermal 

efficiencies have risen, renewable technologies abound, 

and elasticities of demand are revealing themselves. But 

these advances have been rather more evolutionary 

than revolutionary, and crucial progress along several 

dimensions—in particular, the integration of environmental 

damage costs into planning and dispatch and the means by 

which comprehensive investment in the truly lowest cost 

resources, among them end-use energy efficiency, can be 

secured—is still dreadfully lagging.

It is the latter need that this paper addresses. Nearly 

four decades of experience has demonstrated that key 

policy reforms are necessary to ensure that the demand side 

is fully exploited. Identified here is a suite of fourteen—

some aimed at still-regulated vertically integrated power 

sectors, some at liberalized market systems, and some at 

both—that have proven particularly effective in breaking 

down the economic and institutional barriers to investment 

in clean energy resources on the customer’s side of the 

meter. To policymakers for whom the demand side is an 

intriguing cipher, this paper offers a detailed look at the 

important first tools that they might consider adapting to 

their particular needs. Other policymakers, those who 

are already working in this arena, should find value here 

too—a new approach to a recurring problem, perhaps, or 

a different idea altogether whose time has come. We might 

hope for some kind of swift, revolutionary change in the 

power sector, but we cannot wait for it. At the very least, 

we can pick up the pace a little bit. Inside these pages are 

some very good ideas for doing so.

Frederick Weston

Principal

Regulatory Assistance Project
3

Effective Mechanisms to Increase the Use of Demand-Side Resources

Executive Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Abbreviations and Acronyms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

1. Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

A. What Are Demand-Side Resources?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

B. Mechanisms for Increasing the Use of Demand-Side Resources. . . . . . . . . . . . . . . . . . . . . 10

2 Application and Effectiveness of Mechanisms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

A. Vertically Integrated Utilities with Regulated Markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

B. Markets with Unbundled Electricity Providers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

C. Competitive Wholesale Electricity Generation Market with Regulated Electricity Retailers. . . 13

D. Fully Competitive Electricity Generation and Retail Markets. . . . . . . . . . . . . . . . . . . . . . . 14

3. Regulatory Mechanisms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

A. Imposing an Obligation to Carry Out Integrated Resource Planning. . . . . . . . . . . . . . . . . 15

B. Decoupling Electricity Provider Revenue from Sales Volume. . . . . . . . . . . . . . . . . . . . . . . 18

C. Requiring Published Information on Opportunities for Demand-Side Resources. . . . . . . . 21

D. Mandating Implementation of Cost-Effective Demand-Side Measures. . . . . . . . . . . . . . . . 24

E. Imposing Energy Efficiency Obligations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

F. Mandating Implementation of Time-Varying Electricity Pricing. . . . . . . . . . . . . . . . . . . . . 30

4. Policy Mechanism. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

A. Establishing an Energy Saving Fund. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

5. Market-Based Mechanisms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

A. Enabling Demand-Side Bidding into Electricity Markets. . . . . . . . . . . . . . . . . . . . . . . . . . 37

B. Enabling Bidding of Demand-Side Measures to Relieve Network Constraints. . . . . . . . . . . 40

C. Providing Network Support Payments for Demand-Side Measures. . . . . . . . . . . . . . . . . . . 44

6. Load Targeting Mechanisms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

A. Using Load Control to Address System Needs and Integrate Renewables. . . . . . . . . . . . . . 46

B. Implementing Load Scheduling to Time-Target Changes in End-User Loads. . . . . . . . . . . 49

C. Operating Energy Storage to Time-Target Changes in System Load. . . . . . . . . . . . . . . . . . 50

D. Implementing Geographic Targeting of Demand-Side Measures. . . . . . . . . . . . . . . . . . . . . 54

7. Conclusion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

Table of Contents
4

Effective Mechanisms to Increase the Use of Demand-Side Resources

List of Tables

Table 1: Mechanisms for Increasing the Use of Demand-Side Resources. . . . . . . . . . . . . . . . . . . . . . 10

Table 2: Demand-Side Options Identified in the Drummoyne DSM Project. . . . . . . . . . . . . . . . . . . 43

Table 3: Definition of Energy Storage Applications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Table 4: Forecast Impacts and Costs of Identified DSM Measures to be 

Implemented Through the Eco-Energy Plan. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

List of Figures

Figure 1: The Integrated Resource Planning Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Figure 2: Equations for Setting Electricity Prices with and Without Decoupling. . . . . . . . . . . . . . . 19

Figure 3: Electricity System Development Procedure for Distributors in New South Wales. . . . . . . 24

Figure 4: Tempo Tariff Rates in France from 18 August 2010. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Figure 5: Value of Avoided Distribution Costs for Various Levels of 

Demand Reduction at the Drummoyne Zone Substation. . . . . . . . . . . . . . . . . . . . . . . . . 41

Figure 6: Cost and Demand Reduction Impact of Demand-Side Options Compared with

the Value of Avoided Distribution Costs in the Drummoyne DSM Project. . . . . . . . . . . . 43

Figure 7: Load Control System Components. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Figure 8: ComfortChoice Thermostat Used in the LIPAedge Program. . . . . . . . . . . . . . . . . . . . . . . 47

Figure 9: The Carrier/Silicon Energy Direct Load Control System for the LIPAedge Program. . . . . . 48

Figure 10: Technology Options for Energy Storage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Figure 11: Total Worldwide Installed Energy Storage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Figure 12: A 12 MW Lithium-ion Battery Frequency Regulation and 

Spinning Reserve Project in Northern Chile. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Figure 13: High Voltage Transmission Lines in the Eastern Part of the 

Provence-Alpes-Côte d’Azur Region of France. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Figure 14: Capacity Constraints in Winter with Fault Level n-1 

Following Scheduled Completion of the New 400 kV Line in 2005. . . . . . . . . . . . . . . . . 56

Figure 15: Capacity Constraints in Summer with Fault Level n-2 

Following Scheduled Completion of the New 400 kV Line in 2005. . . . . . . . . . . . . . . . . 56

Figure 16: Winter Peak Demand by End-use in the Eastern Part of the 

Provence-Alpes-Côte d’Azur Region. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Figure 17: Summer Peak Demand by End-use in the Eastern Part of the 

Provence-Alpes-Côte d’Azur Region. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Figure 18: Forecasts of Potential Load Reductions Achievable Through the 

Eco-Energy Plan 2005 to 2020. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Figure 19: Forecasts of Potential Load Reductions Achievable Through the 

Eco-Energy Plan in Winter 2006. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
5

Effective Mechanisms to Increase the Use of Demand-Side Resources

Measures using demand-side resources comprise 

actions taken on the customer’s side of the 

meter to change the amount and/or timing 

of electricity use in ways that will provide 

benefits to the electricity supply system.

Decades of experience around the world make it clear 

that demand-side resources provide the fastest, lowest 

cost, and cleanest way to meet energy service needs. 

More recently, new approaches provide exciting and low 

cost demand-side options to improve electricity system 

reliability and allow for reliable integration of renewable 

resources. However, the electricity sector has long been 

dominated by a primary focus on the supply side. So it is 

not surprising that regulatory rules, market reforms, and 

power sector planning have been designed with electricity 

generation, transmission, and distribution in mind, without 

considering the use of demand-side resources where these 

are cost-effective and appropriate.

This paper describes a relatively small number (14) of 

the most effective mechanisms for increasing the use of 

demand-side resources in the electricity sector. Some of 

these mechanisms aim at integrating demand-side resources 

into electricity markets. Others aim at increasing the role of 

demand-side resources in system operations and planning 

processes.

Mechanisms for Increasing the 

Use of Demand-Side Resources

The following mechanisms are included in this paper.

Regulatory Mechanisms

• Imposing an Obligation to Carry Out Integrated 

Resource Planning

• Decoupling Electricity Provider Revenue from Sales 

Volume

• Requiring Published Information on Opportunities for 

Demand-Side Resources

Executive Summary

• Mandating Implementation of Cost-Effective DemandSide Measures

• Imposing Energy Efficiency Obligations

• Mandating Implementation of Time-Varying 

Electricity Pricing

Policy Mechanism

• Establishing an Energy Saving Fund

Market-Based Mechanisms

• Enabling Demand-Side Bidding into Electricity 

Markets

• Enabling Bidding of Demand-Side Measures to Relieve 

Network Constraints

• Providing Network Support Payments for DemandSide Measures

Load-Targeting Mechanisms

• Using Load Control to Address System Needs and 

Integrate Renewables

• Implementing Load Scheduling to Time-Target 

Changes in End-User Loads

• Operating Energy Storage to Time-Target Changes in 

System Load

• Implementing Geographic Targeting of Demand-Side 

Measures

Summaries of the Mechanisms

Imposing an Obligation to Carry Out Integrated 

Resource Planning

This mechanism places a regulatory obligation on 

electricity providers to implement a planning process 

that examines the forecasted growth in future demand for 

electricity and evaluates alternative methods of meeting the 

resulting load on the system, including using demand-side 

resources. The goal is to identify the least-cost resource 

mix for electricity providers and their end-use customers. 
6

Effective Mechanisms to Increase the Use of Demand-Side Resources

This planning process is known as “integrated resource 

planning” (IRP).

Decoupling Electricity Provider Revenue 

from Sales Volume

Decoupling is a regulatory mechanism that breaks the 

link between the amount of electricity sold and the actual 

(allowed) revenue collected by an electricity provider. The 

purpose is to reduce the incentive that electricity providers 

have to increase profits by increasing electricity sales. 

Consequently, the corresponding disincentive to avoid 

reductions in sales, such as by investing in energy efficiency 

programs or other activities that may reduce load, is also 

reduced. This enables decision-making by the electricity 

provider to be refocused on making least-cost investments 

to deliver reliable energy services to customers even when 

such investments reduce the volume of electricity sales.

Requiring Published Information on 

Opportunities for Demand-Side Resources

This mechanism requires electricity providers to publish 

information about opportunities for using demand-side 

resources to reduce loads in ways that can:

• defer or eliminate the need to build additional 

electricity generation capacity; and/or

• defer or eliminate the need to augment and/or expand 

the electricity network by building poles and wires.

The purpose of publishing the information is to 

enable proponents of demand-side resource projects to 

propose options to an electricity provider that can achieve 

the objectives of the electricity provider in relation to 

expanding generation or network capacity at a lower cost 

than supply-side options.

Mandating Implementation of Cost-Effective 

Demand-Side Measures

This mechanism requires electricity providers to include 

all available cost-effective demand side measures when 

they are acquiring resources for use in meeting customer 

demand for electricity. The mechanism applies a policy 

or regulatory condition on the usual resource acquisition 

procedure adopted by electricity providers. This condition 

requires electricity providers to investigate, assess, and 

select cost-effective demand-side measures in preference 

to supply-side resources. The condition may specify the 

methodology to be used when assessing cost effectiveness 

and may also stipulate the relative priorities to be assigned 

to different demand-side measures.

Imposing Energy Efficiency Obligations

This mechanism requires obligated parties to meet 

quantitative energy savings targets through implementing 

cost-effective demand-side measures, particularly end-use 

energy efficiency. Typically, this mechanism sets annual 

energy savings targets for a long-term period, requiring 

obligated parties to achieve specified reductions in energy 

use through energy efficiency measures.

Mandating Implementation of Time-Varying 

Electricity Pricing

This mechanism requires electricity providers to 

implement time-varying electricity prices for some or all of 

their end-use customers. The purpose is:

• to increase economic efficiency by better matching 

prices to the time-varying costs of supplying 

electricity;

• to provide pricing signals encouraging customers to 

modify the way they use electricity, particularly by 

reducing load at peak times; and

• to delay investment in new electricity generation and 

network infrastructure.

The mechanism can result in increased use of demandside resources in the electricity sector through incentivising 

the use of demand response measures.

Establishing an Energy Saving Fund

This mechanism involves the establishment of a financial 

facility dedicated primarily to funding projects that 

acquire energy savings through installing energy efficiency 

measures. The range of financial products such a fund 

may offer to proponents of energy efficiency projects is 

potentially very wide and may include grants, senior and 

junior loans, loan guarantees, and equity participation.

Enabling Demand-Side Bidding into 

Electricity Markets

Demand-side bidding enables the demand side of an 

electricity market to participate in market trading. Demandside bids are typically made over timescales ranging from a 

year to a few seconds ahead of the time of delivery. There 
7

Effective Mechanisms to Increase the Use of Demand-Side Resources

are two basic types of offer in demand-side bidding: offers 

involving a bid for total demand, and offers involving a bid 

for a change in demand.

Enabling Bidding of Demand-Side Measures to 

Relieve Network Constraints

This mechanism establishes a process that enables 

parties to bid demand-side measures to relieve constraints 

on electricity networks. Demand-side measures are bid as 

alternatives to building network infrastructure (“poles and 

wires”) to augment or expand the existing network.

Providing Network Support Payments for 

Demand-Side Measures

This mechanism establishes rules within an electricity 

market for:

• valuing the network benefits and services available 

from the implementation of demand-side measures; 

and

• providing a commensurate financial return to parties 

implementing demand-side measures that deliver 

defined network benefits and services.

This is a separate mechanism to bidding of demandside measures to relieve network constraints. In the 

bidding mechanism, payments for implementing demandside measures are determined by the bidding process. 

In contrast, network support payments are determined 

through a process of valuing the benefits and services 

delivered.

Using Load Control to Address System Needs 

and Integrate Renewables

This mechanism uses load control technology to enable 

changes in the levels of end-use customer loads:

• in response to particular events such as periods of 

high electricity prices or problems on the electricity 

network; or

• to integrate intermittent generation such as wind or 

photovoltaics into the system.

Implementing Load Scheduling to Time-Target 

Changes in End-User Loads

This mechanism establishes contractual arrangements 

that enable system operators to request specified changes 

in end-user load levels at times when doing so delivers 

benefits or services to the system. This is a type of shortterm demand response; typically system operators request 

changes in end-user load levels for periods lasting from one 

to several hours.

The effect of this mechanism is very similar to some 

types of demand-side bidding into electricity markets, 

but the method of implementation is quite different. In 

demand-side bidding, scheduling of demand-side measures 

is determined by the bidding process. In contrast, in load 

scheduling the system operator directly requests the owners 

or aggregators of the loads involved to implement changes 

in load levels.

Operating Energy Storage to Time-Target 

Changes in System Load

This mechanism uses energy storage technology to 

convert grid-connected electricity into another form of 

energy, hold it for later use, and when required at a future 

time, release the stored energy as electricity or as another 

useful form of energy. Just as transmission and distribution 

systems move electricity over distances to end-users, 

energy storage systems can move electricity through time, 

providing it when and where it is needed. Energy storage 

systems can help balance variable renewable generation 

and, properly deployed and integrated, can help increase 

the reliability of the electricity network.

Implementing Geographic Targeting of DemandSide Measures

This mechanism establishes processes for targeting the 

implementation of demand-side measures to particular 

geographic areas or localities where they will be most 

effective in relieving network constraints. This mechanism 

is similar to bidding of demand-side measures to relieve 

network constraints except that this mechanism is focused 

on delivering the results of implementing demand-side 

measures to targeted geographic localities.

Effectiveness of Mechanisms

The effectiveness of these mechanisms in any particular 

region or country will depend on the structure of the 

electricity sector, and the regulatory regime and system 

planning processes in place. It is therefore important to 

take these factors into account when planning the use of 

any of the mechanisms described in this paper. 
8

Effective Mechanisms to Increase the Use of Demand-Side Resources

ADEME Agence de l’Environnement et de la Maîtrise 

de l’Énergie (the French Government’s 

environmental and energy management agency)

ARRA American Recovery and Reinvestment Act of 

2009

AUD Australian Dollar

BEC Business Energy Coalition (California)

CAISO California Independent System Operator

CERT Carbon Emissions Reduction Target 

(United Kingdom)

CFL Compact Fluorescent Lamp

CPUC California Public Utilities Commission 

(United States)

DC Direct Current

DEUS Department of Energy, Utilities and 

Sustainability (New South Wales) 

DM Demand (-Side) Management

DPS Vermont Department of Public Service

DSB Demand-Side Bidding

DSM Demand-Side Management

EDF Électricité de France

EEC Energy Efficiency Commitment (United 

Kingdom)

EEO Energy Efficiency Obligation

EERS Energy Efficiency Resource Standard

EESoP Energy Efficiency Standards of Performance 

(United Kingdom)

EU European Union

FERC Federal Energy Regulatory Commission 

(United States)

GBP British Pound

GW Gigawatt

GWh Gigawatt-hour

IRP Integrated Resource Planning

ISO Independent System Operator

km Kilometer

kV Kilovolt

kVA Kilovolt-Ampere

kW Kilowatt

LCP Least-Cost Planning

LIPA Long Island Power Authority (United States)

MVA Megavolt-Ampere

MW Megawatt

MWh Megawatt-hour

PACA Provence-Alpes-Côte d’Azur (region of France)

PG&E Pacific Gas and Electric Company (United 

States)

PPA Power Purchase Agreement

PSB Public Service Board

PUC Public Utility Commission (United States)

RDM Revenue Decoupling Mechanism

USD US Dollar

VEIC Vermont Energy Investment Corporation

WMECO Western Massachusetts Electric Company 

(United States)

Abbreviations and Acronyms
9

Effective Mechanisms to Increase the Use of Demand-Side Resources

1. Introduction

Measures using demand-side resources 

comprise actions taken on the customer’s 

side of the meter to change the amount and/

or timing of electricity use in ways that will 

provide benefits to the electricity supply system.

Decades of experience around the world make it clear 

that demand-side resources provide the fastest, lowest 

cost, and cleanest way to meet energy service needs. 

More recently, new approaches provide exciting and low 

cost demand-side options to improve electricity system 

reliability and allow for reliable integration of renewable 

resources. However, the electricity sector has long been 

dominated by a primary focus on the supply side. So it is 

not surprising that regulatory rules, market reforms, and 

power sector planning have been designed with electricity 

generation, transmission, and distribution in mind, without 

considering the use of demand-side resources where these 

are cost-effective and appropriate.

This paper describes a relatively small number (14) of 

the most effective mechanisms for increasing the use of 

demand-side resources in the electricity sector. Some of 

these mechanisms aim at integrating demand-side resources 

into electricity markets. Others aim at increasing the role of 

demand-side resources in system operations and planning 

processes.

The relative effectiveness of these mechanisms in any 

particular state or country will depend on the structure of 

the electricity sector, and the regulatory regime and system 

planning processes in place. 

A. What Are Demand-Side Resources?

Demand-side resources can be used to change the load 

on an electricity network in three ways:

• by increasing energy efficiency;

• by implementing load management; and/or

• by installing distributed generation.

Energy efficiency develops and deploys technologies and 

design practices that reduce energy use while delivering the 

same level of energy service (e.g., well-lit rooms at a comfortable temperature). Energy efficiency measures are essentially 

non-dispatchable and always involve a load reduction.

Load management involves changes in end-use 

electricity consumption, particularly during times of high 

demand and/or high electricity prices. Load management 

includes direct load control, demand response, 

interruptible loads, load shifting, power factor correction, 

and fuel substitution. Until recently, load management 

measures have not been dispatchable, have generally been 

deployed in a “broad-brush” fashion, and have usually 

required some involvement by the end-use customer. In 

the future, load management will become a much more 

fine-grained and controllable tool deployed in the course 

of everyday operations than has traditionally been the 

case. Load management will increasingly be dispatchable 

under the control of a utility, system operator, or demandside aggregator, and in many cases, will be carried out 

automatically without any intervention by the customer. 

Load management will also have to be able to deliver both 

reductions and increases in load to enable cost-effective 

integration of renewables into the generation mix.

Distributed generation comprises usually small-scale 

generation units that may or may not be connected to and 

synchronised with the main electricity network. Distributed 

generators may be operated in several different ways. They 

may be dispatched to meet system needs, dispatched to 

meet local needs of the grid, operated by the customer to 

control utility bills, or operated by the customer in the 

event of a lack of service from the system.

Changes in load achieved through deploying demandside resources may reduce the need for additional 

generation and/or network capacity. In addition, demandside resources can play a crucial role in creating efficient 

regional power markets, integrating renewables, lowering 

price volatility and generator market power, disciplining 

power costs, and improving reliability.
10

Effective Mechanisms to Increase the Use of Demand-Side Resources

B. Mechanisms for Increasing the Use of 

Demand-Side Resources

There are four main types of mechanisms for increasing 

the use of demand-side resources in the electricity sector:

• regulatory mechanisms;

• policy mechanisms;

• market-based mechanisms; and

• load-targeting mechanisms.

Fourteen individual mechanisms classified into the four 

main types are listed in Table 1.

The mechanisms included in Table 1 have been selected 

on the basis that they act directly on the electricity sector 

to increase the use of demand-side resources. Other 

mechanisms, such as codes and standards, act more 

broadly and may also influence increased use of demandside resources. However, because such mechanisms are 

not focussed directly on the electricity sector, they are not 

considered in this paper.

In addition, many of the mechanisms identified in Table 1 

overlap and interact with each other in the same way that, 

in the real world, a suite of actions will overlap and interact 

in a fairly jumbled and muddled way. Consequently, this 

paper is not intended to provide a neat and mutually 

exclusive classification of mechanisms. Rather, it is 

intended to stimulate policy makers to think about policy 

actions that they could develop and implement in their 

own jurisdictions.
11

Effective Mechanisms to Increase the Use of Demand-Side Resources

Table 1

Mechanisms for Increasing the Use of Demand-Side Resources

Vertically 

Integrated 

Electricity 

Utilities 

with 

Regulated 

Markets

Markets 

with 

Unbundled 

Electricity 

Providers

Competitive 

Wholesale 

Electricity 

Generation 

Markets with 

Regulated 

Electricity 

Retailers

Fully 

Competitive 

Electricity 

Generation 

and Retail 

Markets

Regulatory Mechanisms

R1 Imposing an obligation to carry out integrated resource planning E Y* Y*

R2 Decoupling electricity provider revenue from sales volume E E+ Y+ Y+

R3 Requiring published information on opportunities for 

demand-side resources Y Y Y Y

R4 Mandating implementation of cost-effective demand-side measures Y Y Y Y

R5 Imposing energy efficiency obligations E E E E

R6 Mandating implementation of time-varying electricity pricing Y Y Y

Policy Mechanism

P1 Establishing an energy saving fund E E E E

Market-Based Mechanisms

M1 Enabling demand-side bidding into electricity markets E E

M2 Enabling bidding of demand-side measures to relieve network constraints Y Y Y Y

M3 Providing network support payments for demand-side measures Y Y Y Y

Load-Targeting Mechanisms

T1 Using load control to address system needs and integrate renewables Y Y Y Y

T2 Implementing load scheduling to time-target changes in end-user loads Y Y Y Y

T3 Operating energy storage to time-target changes in system load Y Y Y Y

T4 Implementing geographic targeting of demand-side measures Y Y Y Y

Y: Mechanism can be applied in this market structure

E: Mechanism is particularly effective in this market structure

*: Electricity retailers only

+: Electricity transmission and distribution service providers only

Table created by David Crossley, 2012.
12

Effective Mechanisms to Increase the Use of Demand-Side Resources

2. Application and Effectiveness of Mechanisms

Mechanisms for increasing the use of demandside resources vary in their applicability to, 

and effectiveness in, the four main types of 

electricity markets:

• vertically integrated electricity utilities with regulated 

markets;

• markets with unbundled electricity providers;

• competitive wholesale electricity generation markets 

with regulated electricity retailers; and

• fully competitive electricity generation and retail 

markets.

In Table 1 (page 11), “Y” indicates that a mechanism 

can be applied to a particular type of market. The Table 

shows that, although some mechanisms (particularly load 

targeting mechanisms and mechanisms related to providers 

of electricity transmission and distribution services) can 

be applied across all the four types of markets, other 

mechanisms can be applied only to some types of markets. 

Each market type has a group of mechanisms that are 

particularly effective in that market structure (shown as “E” 

in Table 1).

A. Vertically Integrated Electricity 

Utilities with Regulated Markets

By definition, vertically integrated utilities own facilities 

along the whole electricity supply chain from generation 

plant, through transmission and distribution networks, 

to the retail sale of electricity to end-users. Although 

neighbouring utilities often trade bulk quantities of 

electricity, the lack of competition means most jurisdictions 

regulate all aspects of vertically integrated utilities.

Because these utilities are vertically integrated they are 

able to take full advantage of the range of generation-, 

transmission-, and distribution-related benefits demandside resources provide. Nevertheless, the benefits of even 

very low cost demand-side resources are outweighed by 

regulatory practices, especially rules that allow utilities 

to pass through changes in generation cost directly to 

consumers. Typical regulatory practices mean increased 

electricity sales are profitable and demand-side resources 

that reduce sales, reduce profits.

There are several regulatory, policy, and load targeting 

mechanisms that:

• encourage the integration of demand-side resources 

into a vertically-integrated electricity supply chain;

• encourage utilities to invest in these resources;

• impose demand-side resource obligations on utilities; 

or

• limit the utility role to collecting funds needed to 

support demand-side investment.

Relevant mechanisms discussed in this paper include:

• imposing an obligation to carry out integrated 

resource planning during system planning;

• decoupling the revenue of electricity providers from 

the volume of electricity sales;

• imposing energy efficiency obligations on electricity 

providers; and

• establishing an energy saving fund with financial 

contributions from electricity providers and/or 

emissions trading schemes.

B. Markets with Unbundled Electricity 

Providers

In some regions, vertically integrated utilities have 

been unbundled into separate electricity generation, 

transmission, and combined distribution/retail supply 

providers.1

 In some cases, unbundling is taken one step 

further to create stand-alone electricity retailers that sell 

electricity without owning and operating the distribution 

1 There are also numerous examples, particularly in the United 

States, of competitive wholesale generation markets being 

introduced without unbundling vertically integrated utilities.
13

Effective Mechanisms to Increase the Use of Demand-Side Resources

systems that enable delivery to end-users. Although 

unbundling can be carried out without establishing 

a formal competitive wholesale electricity market,2

unbundling necessitates some form of trading of bulk 

quantities of electricity between the individual generation 

providers and the providers responsible for selling 

electricity to end-users.

In markets with unbundled electricity providers, the 

entity that bears the generation cost is the key to increasing 

the use of demand-side resources in the electricity sector.

Where generation costs do not pass through to enduse consumers, the electricity retailer (which may also 

be the operator of the distribution network) will see the 

generation cost savings. When marginal generation costs 

exceed marginal revenue from kWh sales, demand-side 

resources will produce a net benefit to the retailer. This 

however is the rare case.

More often, unbundling of vertically integrated utilities 

results in generation costs being passed directly through 

to end-users. In this case, only the customer bears the 

generation cost. None of the entities that comprise the 

power sector are positioned to benefit from the generation 

cost-related savings that may be achieved by implementing 

demand-side measures.

In this case, only the wires businesses (operators of 

transmission and distribution networks) are positioned 

to see any benefits from implementing demand-side 

measures. However, they only see the benefits that relate 

to cost savings in transmission and distribution networks. 

For the wires businesses, achieving load reductions in 

specific locations and/or at specific times of the day may 

be more cost-effective in relieving network congestion than 

expanding or augmenting the network through building 

poles and wires. However the benefits from implementing 

demand-side measures can be significantly reduced if 

(as is often the case) the profits of wires businesses are 

mainly determined by the volume of electricity transported 

through the network, or their earnings growth is primarily 

driven by an allowed rate of return on capital invested in 

building poles and wires.

In contrast, generators and stand-alone electricity 

retailers rely entirely on the volume of electricity sales 

(“throughput”) to generate revenue and profits. Any 

reduction in electricity sales from deploying demand-side 

resources reduces both their revenue and their profits.

There are several regulatory, policy, and load targeting 

mechanisms that:

• reform regulatory practices to encourage wires 

businesses to invest in demand-side resources;

• impose demand-side resource obligations on 

particular electricity providers; or

• limit the electricity provider role to collecting funds 

needed to support demand-side investment.

Relevant mechanisms discussed in this paper include:

• decoupling the revenue of wires businesses from the 

volume of electricity sales;

• imposing energy efficiency obligations on electricity 

providers;

• establishing an energy saving fund with financial 

contributions from electricity providers and/or 

emissions trading schemes.

C. Competitive Wholesale Electricity 

Generation Markets with Regulated 

Electricity Retailers

Competitive wholesale electricity generation markets can 

function effectively with both vertically integrated utilities, 

as in many parts of the United States, and with unbundled 

electricity providers, as in Europe, Australia, New Zealand, 

and several other countries. The first stage in introducing 

competition is usually to make the wholesale electricity 

generation market competitive while retaining franchises 

for the retail sale of electricity to end-users. Retail franchises 

are typically established on a geographic basis with all endusers located within a geographic area being served by the 

same vertically integrated utility or stand-alone electricity 

retailer and retail prices being controlled by a regulator.

The introduction of competition at the wholesale level 

may provide an opportunity for demand-side resources 

to compete with supply-side resources through directly 

bidding load reductions into wholesale energy markets and 

2 For example, in China electricity generators have been 

unbundled into stand-alone generators and the grid 

companies (combined transmission, distribution, and retail 

supply providers). The grid companies purchase bulk 

electricity from the generators at fixed prices rather than at 

prices determined by a competitive market. However, this 

is an unusual arrangement, and unbundling of generation 

is more usually accompanied by the establishment of some 

form of competitive wholesale electricity market.
14

Effective Mechanisms to Increase the Use of Demand-Side Resources

bidding to provide ancillary services and forward capacity 

where markets for such services exist.

There are several regulatory, policy, and load targeting 

mechanisms that:

• impose demand-side resource obligations on 

particular electricity providers;

• enable electricity providers to bid load reductions into 

markets; and

• limit the utility role to collecting funds needed to 

support demand-side investment.

Relevant mechanisms discussed in this paper include:

• imposing energy efficiency obligations on electricity 

providers;

• enabling demand-side bidding into electricity 

markets; and

• establishing an energy saving fund with financial 

contributions from electricity providers and/or 

emissions trading schemes.

D. Fully Competitive Electricity 

Generation and Retail Markets

Fully competitive electricity generation and retail 

markets often include completely unbundled energy 

providers.3

 The addition of retail competition to electricity 

markets in theory provides electricity retailers with a 

commercial rationale to provide energy efficiency and 

demand response services to their customers as a way of 

3 In some fully competitive markets, such as the Australian 

National Electricity Market, some previously unbundled 

electricity generators and retailers are recombining to form 

so-called “gentailers.” The advantage of this arrangement is 

that the combined entity can use its generation assets as a 

physical hedge to shield the electricity retailing business from 

exposure to high prices in the wholesale electricity market.

differentiating themselves from competitors. In practice, 

however, few electricity retailers in competitive markets 

have changed their business models to incorporate energy 

efficiency and demand response products.

The most effective mechanisms to achieve increased 

use of demand-side resources in competitive wholesale 

and retail electricity markets are the same as those for 

wholesale-only markets. However, the effectiveness of 

these mechanisms will depend on how well competitive 

electricity retailers are able to respond to customer and 

system needs. This will in turn depend on the retail pricing 

and market design.

Relevant mechanisms discussed in this paper include:

• imposing energy efficiency obligations on electricity 

providers;

• enabling demand-side bidding into electricity 

markets; and

• establishing an energy saving fund with financial 

contributions from electricity providers and/or 

emissions trading schemes.
15

Effective Mechanisms to Increase the Use of Demand-Side Resources

4 Lazar, 2011a. 

5 See the list of references (page 60) for information on how to 

access documents referenced in this paper.

6 IRP is included in this paper as a regulatory mechanism that 

can be imposed on one or more parts of the electricity sector 

depending on the structure of the sector. However, it is also 

a vital tool that should be used more generally by regulators 

and policymakers, because it is at the core of all electricity sector-related decision making and policy, regardless of 

the structure of the sector. Where the electricity sector is 

vertically integrated and regulated, IRP informs utilities and 

regulators whether investments and operating practices are 

prudent and least-cost. Where the sector is unbundled and 

competitive, IRP informs policymakers on whether the market is delivering what is needed, and if not, the changes in 

market design and rules that may be required. Simply stated, 

IRP tells you what you need. Markets can then be designed 

to deliver what you need in an efficient manner.

7 Lazar, 2011a.

3. Regulatory Mechanisms

Economic regulation is the explicit public or 

governmental intervention into a market to 

achieve public benefits that the market fails to 

achieve on its own.4,5 In the case of increasing 

the use of demand-side resources in the electricity sector, 

the purpose of regulation is to achieve this increase where 

the level of demand-side resources participating in the 

electricity market is below an economically optimal level.

A. Imposing an Obligation to Carry Out 

Integrated Resource Planning

i. Description

This mechanism places a regulatory obligation on electricity providers to implement a planning process that examines 

the forecasted growth in future demand for electricity and 

evaluates alternative methods of meeting the resulting load 

on the system, including using demand-side resources. The 

goal is to identify the least-cost resource mix for electricity 

providers and their end-use customers. This planning process is known as “integrated resource planning” (IRP). Figure 

1 (page 16) presents an outline of the IRP process.

Traditional electricity sector planning, as carried out 

worldwide, begins with a forecast of electricity demand. It 

then considers the capital and operating cost of different 

generating options and finds the least-cost generation mix 

that meets demand. IRP expands the process to consider a 

broader range of options, especially demand-side resources. 

When done well, IRP essentially identifies the size, 

location, cost, and value of demand-side resources to the 

electricity sector and the least-cost mix of generation and 

demand-side resources needed to meet customer energy 

service needs.6

Ideally, the IRP process should look at a wide range of 

options to meet future needs and include consideration 

of all social and environmental costs when evaluating the 

options. Supply-side options for evaluation should include 

continued operation of existing power plants, building 

new power plants, buying power from other generators, 

and encouraging customer-owned distributed generation. 

Demand-side options should include non-generation 

alternatives, such as investing in DSM programs, promoting 

energy efficient new construction, reducing transmission 

and distribution system line losses, and any other available, 

reliable, and cost-effective means of meeting future demand 

for electricity.7

The IRP process may also consider future requirements 

for local and regional transmission and distribution 

network infrastructure and establish a plan for future 

upgrades to existing lines, and/or construction of new lines, 

and/or the deployment of demand-side resources to relieve 

network constraints.

Such a broad-ranging planning process provides an 

opportunity for demand-side resources to be evaluated 

on their merits (particularly their cost-effectiveness) as 

methods for meeting forecasted future electricity demand 

and future requirements for network infrastructure.
16

Effective Mechanisms to Increase the Use of Demand-Side Resources

Figure 1

The Integrated Resource Planning Process 8

Implementation

Setting IRP Objectives

Demand Forecasting

Gathering Energy 

Demand Data

Investigation of 

DSM Measures

Preparation/Evaluation of 

Candidate Integrated 

Resource Plans

Choose Preferred 

Integrated Resource Plans

Investigation of 

Supply Technologies

8 The Tellus Institute (undated). 

9 Lazar, 2011a.

ii. Implementation

As a regulatory mechanism, IRP can be made an 

obligation on vertically integrated utilities to implement 

a planning process that examines the forecasted growth 

in future demand for electricity and evaluates alternative 

methods of meeting the demand, including demand-side 

resources. Where the power sector has been unbundled, 

IRP can be made an obligation on transmission and 

distribution system operators (“wires businesses”) 

to consider demand-side resources and other nonwire alternatives to meet future requirements for local 

and regional transmission and distribution network 

infrastructure and to establish a plan for future upgrades to 

existing lines and/or construction of new lines.

The purpose of IRP is to identify the least-cost option. 

Least-cost in this case means lowest total cost over the 

planning horizon, given the risks faced. The best resource 

mix is typically the one that remains cost-effective across a 

wide range of futures and sensitivity cases, while meeting 

established resource security and reliability standards.9

Many aspects of the implementation of IRP are technical 

and straightforward, and follow established electricity 

planning methodologies. Others aspects of IRP add new 

methodologies and slightly more complexity to the analysis. 

For example, most demand-side resources are very different 

from supply-side resources. Demand-side resources 

are usually smaller in scale, and may be intermittent or 

otherwise not as predictable or as “firm” as supply-side 

resources. These perceived disadvantages may be reduced 

by technology that enables targeting of some demand-side 

measures to particular time periods and/or geographic 

locations. Such targeting enables these measures to be used 

effectively to provide demand response during peak periods 

or at times of high prices in wholesale electricity markets. 

In particular, an evaluation methodology that takes into 

account the particular characteristics of demand-side 

resources can enable their deployment in system planning 

to defer investment in grid infrastructure (i.e., “poles and 

wires”).

Finally, many aspects of IRP require the application of 

judgment and policy. This is why IRP is often described 

as an iterative and public process that involves many 

stakeholders and interested parties. These complexities are 

a strength, not a weakness of IRP. In particular, developing 

a robust methodology for estimating the relative costeffectiveness of different demand-side and supply-side 

options can be challenging. Determining how to value 

social and environmental costs is a particularly difficult 

methodological issue that requires both judgement and the 

development of policy positions.

Utility & Other 

Interested Parties

Preparation/

Evaluation of 

DSM Plans

Preparation/

Evaluation of 

Supply Plans

Monitoring and Evaluation
17

Effective Mechanisms to Increase the Use of Demand-Side Resources

10 D’Sa, 2005. 

11 Betkowski, 2009. 

12 Betkowski, 2009.

13 D’Sa, 2005.

iii. Application

This regulatory mechanism was first implemented 

during the 1980s and early 1990s when regulators in 

several US states placed IRP obligations on large verticallyintegrated investor-owned monopoly utilities. The 

boundary within which the planning process applied 

was primarily the utility’s geographic service territory. All 

resources owned by the utility, wherever located, were 

included. Resources not owned by the utility and located 

outside the service territory could be included if they were 

likely to be cost-effective and compliant with resource 

security and reliability standards.

Although IRP was originally applied to individual 

monopoly utilities, this planning process can, and has been, 

applied in other situations.

• Denmark’s 1994 Electricity Act included an effective 

IRP obligation. Combined electricity distribution/

retail supply companies were required to prepare 

DSM plans. Generation and transmission companies 

and the independent system operator (ISO) drew up 

scenarios for generation and transmission. The Danish 

Energy Agency developed guidelines and coordinated 

an overall 20-year plan for the whole country.10

• Since 2008, the two investor-owned utilities in 

Connecticut have been required by state legislation 

to submit an annual IRP for the state as a whole, 

while also participating in the competitive forward 

capacity market operated by ISO-New England. The 

Connecticut statute stipulates that resource needs 

should first be met through all available energy 

efficiency and demand reduction resources that are 

cost-effective, reliable, and feasible. In addition, the 

projected customer cost impact of any demandside resources considered must be reviewed on an 

equitable basis with other resources.11

• The current round of electricity market reform in 

the United Kingdom is driven by IRP-type studies 

that show what mix of generation and demand-side 

resources is needed to meet long-term climate goals. 

Similar activities are underway in other regions.

iv. Market Impact

A regulatory obligation requiring electricity providers 

to implement IRP can increase the use of demand-side 

resources where these are more cost-effective than supplyside resources. The requirement to procure cost-effective 

demand-side resources:

• establishes a market for demand-side resources where 

such a market does not already exist; and

• increases the quantity of demand-side resources bid 

into competitive wholesale electricity markets where 

the market rules enable demand-side bidding.

For example, in May 2009, the results of the second 

auction in the ISO-New England forward capacity market 

showed that energy efficiency measures bid by the two 

Connecticut utilities accounted for 25 percent of the total 

capacity and 50 percent of the total energy efficiency 

resource purchased.12

v. Effectiveness

Where this regulatory mechanism has been implemented, 

obligated electricity providers are legally required to 

implement IRP. The effectiveness of the mechanism is 

therefore determined by how successfully IRP operates 

within an existing regulatory regime and market structure.

Following the restructuring of electricity markets in the 

United States, questions have arisen about the effectiveness 

of IRP where competitive electricity markets have been 

implemented, perhaps because IRP was traditionally seen 

as a centralised planning approach, while deregulation 

was supposed to allow individual decision-making by 

electricity providers.13 Among the states that restructured, 

some suspended the IRP obligation, while in other cases 

the Public Utilities Commissions (PUCs) shifted from 

mandatory to optional IRP, or have imposed obligations on 

electricity providers to implement resource portfolios with 

defined levels of investment in DSM and/or renewables.

However, IRP can still have a role in jurisdictions with 

restructured electricity markets. As the case of Connecticut 

demonstrates, it is possible to maintain an IRP obligation 

while the obligated electricity providers participate in a 

competitive electricity market. An IRP obligation can also 

be imposed on electricity providers that own and operate 

transmission and distribution networks; the obligation will 

require them to implement an IRP process when they are 

considering augmenting and/or expanding their networks.
18

Effective Mechanisms to Increase the Use of Demand-Side Resources

vi. Case Study

The following case study briefly describes the IRP 

process carried out by the vertically integrated utility 

PacifiCorp in the United States. PacifiCorp serves more 

than 1.7 million customers across 136,000 square miles 

in six states. The company comprises three business units: 

Pacific Power serves customers in Oregon, Washington, 

and California; Rocky Mountain Power serves customers 

in Utah, Wyoming, and Idaho; and PacifiCorp Energy 

operates a broad portfolio of power-generating assets.

PacifiCorp prepares its integrated resource plan on 

a biennial schedule, filing its plan with state utility 

commissions during each odd numbered year. For five of 

its six state jurisdictions, the Company receives a formal 

notification as to whether the IRP meets the commissions’ 

IRP standards and guidelines, referred to as IRP 

acknowledgement. For even-numbered years, the Company 

updates its preferred resource portfolio and action plan by 

considering the most recent resource cost, load forecast, 

regulatory, and market information.14

PacifiCorp’s IRP process uses system modelling tools 

as part of its analytical framework to determine the longrun economic and operational performance of alternative 

resource portfolios. These models simulate the integration 

of new resource alternatives with the companies’ existing 

assets, thereby informing the selection of a preferred 

portfolio judged to be the most cost-effective resource mix 

after considering risk, supply reliability, uncertainty, and 

government energy resource policies.

PacifiCorp filed its 11th Integrated Resource Plan15 with 

state regulatory commissions on March 31, 2011. The filing 

initiated the state processes for acknowledgment in Idaho, 

Oregon, Utah, Washington, and Wyoming.

The 2011 Plan is a comprehensive decision support 

tool and road map for meeting the company’s objective of 

providing reliable and least-cost electric service to all of 

its customers while addressing the substantial risks and 

uncertainties inherent in the electric utility business. The 

Plan was developed with considerable public involvement 

from state utility commission staff, state agencies, customer 

and industry advocacy groups, project developers, and 

other stakeholders.

The key elements of the 2011 Plan included:

• the resource portfolio modelling process and 

assumptions;

• a finding of resource need, focusing on the first 10 

years of a 20-year planning period;

• the preferred portfolio of supply-side and demandside resources to meet this need; and

• an action plan that identified the steps to be taken 

during the next two to four years to implement the 

plan.

The preferred portfolio in the 2011 Plan reflected a significant increase in energy efficiency relative to prior IRPs.

For PacifiCorp, the 2011 Plan is part of an evolving 

process that incorporates current information and reflects 

continuous improvements in system modelling capability 

required to address new issues and an expanding analytical 

scope. PacifiCorp’s preferred portfolio and action plans are 

not seen as static products reflecting resource acquisition 

commitments, but rather represent a flexible framework 

for considering resource acquisition paths that may vary as 

market and regulatory conditions change.16 The preferred 

portfolio and action plans are augmented by a resource 

acquisition path analysis informed by extensive portfolio 

scenario modelling. Specific resource acquisition decisions 

stem from PacifiCorp‘s procurement process as supported 

by the IRP and business planning processes, as well as 

compliance with then-current laws and regulatory rules 

and orders.

B. Decoupling Electricity Provider 

Revenue from Sales Volume

i. Description

Decoupling is a regulatory mechanism that breaks the 

link between the amount of electricity sold and the actual 

(allowed) revenue collected by an electricity provider.17 The 

purpose is to reduce the incentive that electricity providers 

have to increase profits by increasing electricity sales.18

14 PacifiCorp, 2011a. 

15 PacifiCorp, 2011b. 

16 PacifiCorp, 2011b.

17 Lazar, Weston, & Shirley, 2011b. 

18 In theory, under traditional regulation, marginal revenue 

is equal to marginal costs, so increased sales do not lead to 

increased profits. The adoption of deferred accounting practices and pass-through mechanisms has produced perverse 

incentives in which practically all increases in sales lead to 

increased profits and vice versa.
19

Effective Mechanisms to Increase the Use of Demand-Side Resources

Consequently, the corresponding disincentive to avoid 

reductions in sales, such as by investing in energy efficiency 

programs or other activities that may reduce load, is also 

reduced. This enables decision-making by the electricity 

provider to be refocused on making least-cost investments 

to deliver reliable energy services to customers even when 

such investments reduce the volume of electricity sales.

There is a variety of different approaches to decoupling, 

all of which share a common goal of ensuring the recovery 

of a defined amount of revenue, independent of changes in 

sales volume during the period under consideration.19

Decoupling mechanisms are usually implemented within 

a regulatory framework referred to as “revenue regulation” 

or “revenue cap regulation.” Under revenue regulation, a 

portion of the total revenue of an electricity provider is set 

each year by the regulator at a particular monetary value 

(“cap”) calculated according to an established formula. The 

structure and levels of retail prices are then set to ensure 

that the regulated portion of revenue remains within the 

cap determined by the regulator. Any over- or undercollection of revenue during one time period is corrected in 

determining the revenue cap for the following time period.

To achieve full decoupling, the portion of total revenue 

subject to a cap must be set at 100 percent; a lower value 

will achieve only partial decoupling. Full decoupling 

insulates the revenue collected by an electricity provider 

from any deviation of actual sales from expected sales. The 

cause of the deviation (e.g., increased investment in energy 

efficiency, weather variations, changes in economic activity) 

does not matter. Any and all deviations will result in an 

adjustment (“true-up”) of collected revenue with allowed 

revenue.20

ii. Implementation

In implementing decoupling for an electricity provider, 

the regulator first determines the revenue requirement for 

19 Lazar et al, 2011b.

20 Id.

21 Id.

22 National Renewable Energy Laboratory, 2009.

the provider. The revenue requirement is the aggregate of 

all approved costs incurred by the provider, comprising: 

operating expenses; the cost of invested capital including 

both interest on debt and a “fair” return to equity investors; 

and a depreciation allowance. The next step involves 

selecting the method whereby the allowed revenue (the 

revenue “cap”) will be set so as to deliver the revenue 

requirement; a common method is to set the cap on a 

revenue-per-customer basis. The final step is to set the 

structure and levels of retail prices.

Decoupling differs most from traditional regulation 

when setting retail prices (see Figure 2). While traditional 

regulation sets prices, then lets revenues float up or down 

with consumption, decoupling sets the allowed revenue, 

then lets prices float down or up with consumption. 

This price recalculation is done repeatedly – either with 

each billing cycle or on some other periodic basis (e.g., 

annually).21 The focus here is on delivering the level of 

revenue needed to match the revenue requirement.

iii. Application

Revenue regulation and decoupling were first developed 

during the late 1980s and early 1990s and applied by 

regulators in several US states to large vertically integrated, 

investor-owned monopoly utilities. Revenue regulation and 

decoupling have since been implemented in several other 

countries, including Northern Ireland and Australia.

Decoupling can only be applied to electricity providers 

that are subject to regulatory price controls. It cannot 

Figure 2

Equations for Setting Electricity Prices With and Without Decoupling22

Traditional Ratemaking Equation Ratemaking Equation with Current Period Decoupling

Unit Price =

Unit Price =

Allowed Revenue Requirement

Expected Units of Consumption

Allowed Revenue

Actual Units of Consumption Actual Revenue =

Allowed Revenue =

Unit

Price x Actual Units of Consumption

Last Rate Case 

Revenue Requirement
20

Effective Mechanisms to Increase the Use of Demand-Side Resources

be applied to providers that are free to set their prices 

and thereby determine their own revenue, such as in 

jurisdictions where the retail electricity market is fully 

competitive.

In jurisdictions where electricity providers have been 

unbundled, decoupling can be applied to regulated 

monopoly providers, particularly the providers that own 

and/or operate electricity transmission and distribution 

networks. In Australia, revenue regulation is the standard 

form of regulation applied to all transmission service 

providers and to distribution service providers in some 

states. Consequently, the revenue of these providers is 

independent of the volume of energy transported through 

their networks. This removes a disincentive for the providers 

to utilise demand-side resources to reduce loads as an 

alternative to augmenting or expanding their networks.

iv. Market Impact

As a mechanism that applies only to electricity providers 

that are subject to regulatory price controls, decoupling 

does not affect electricity markets directly. To the extent 

that removing the disincentive to reducing sales increases 

the use of demand-side resources by electricity providers, 

decoupling may contribute to:

• establishing a market for demand-side resources 

where such a market does not already exist; and

• increasing the quantity of demand-side resources bid 

into competitive wholesale electricity markets where 

the market rules enable demand-side bidding.

v. Effectiveness

Decoupling diminishes a bias against reducing sales but 

it does not provide any incentive for electricity providers to 

use demand-side measures to reduce load. Consequently, 

the effectiveness of decoupling (e.g., as a mechanism to 

increase the implementation of energy efficiency measures 

by electricity providers) has been questioned. However, 

decoupling is not intended to be the main driver for 

increased energy efficiency and/or increased utilisation 

of demand-side resources. Achieving these objectives 

may require the implementation of other mechanisms in 

addition to decoupling.

vi. Case Study

The following case study briefly describes a decoupling 

mechanism applied to the electricity distributor Western 

Massachusetts Electric Company (WMECO) in the United 

States.

The State of Massachusetts has adopted decoupling 

measures to provide distribution companies with better 

financial incentives to pursue an aggressive expansion of 

investment in energy efficiency and demand-side resources.

In July 2008, the Massachusetts Department of Public 

Utilities stated in its Order in D.P.U. 07 50 A:23

Distribution companies must have the proper regulatory 

and financial incentives to fully pursue the economic, price, 

reliability, and environmental benefits that are available from 

(1) improving the efficiency of energy production, delivery, 

and consumption; (2) building a strong and effective priceresponsive demand; (3) fostering the rapid development 

of renewable energy and distributed generation within 

Massachusetts; and (4) supporting the evolution towards a 

more efficient distribution infrastructure.

The Order in D.P.U 07-50-A also directed each gas and 

electric utility to include a decoupling proposal in its next 

rate case.

On 31 January 2011, the Department issued an Order24

in D.P.U. 10-70 (the WMECO rate case) that applied a 

mechanism for the annual reconciliation of WMECO’s 

distribution revenue and adjustment of the company’s 

distribution rates in accordance with a revenue decoupling 

mechanism (RDM).

As stated in WMECO’s testimony to the rate case 

hearing,25 the purpose of the RDM was to adjust base rates 

on an annual basis to account for the impact of changes in 

the company’s actual base revenues relative to the Target 

Revenues (i.e., revenue caps) by rate class established in 

the company’s rate case. The differences between Actual 

Revenues and Target Revenues were primarily the result of 

the company’s energy demand-side resource initiatives and 

the energy efficiency efforts of its customers, as well as the 

continued economic decline in the company’s service area, 

particularly among commercial and industrial customers.

For many years, WMECO has offered its customers 

support to implement energy efficiency measures to help 

23 Massachusetts Department of Public Utilities, 2008.

24 Massachusetts Department of Public Utilities, 2011. 

25 Massachusetts Department of Public Utilities, 2010.
21

Effective Mechanisms to Increase the Use of Demand-Side Resources

26 Massachusetts Department of Public Utilities, 2011. 

them reduce electrical usage. These programs include 

the residential “MassSAVE” program that provides home 

energy audits and incentives to implement measures such 

as insulation and air sealing. They also include programs 

that cover the entire cost of implementing energy saving 

measures for the company’s low-income customers. 

WMECO offers programs for all businesses in its territory 

– from small commercial to large industrial – that help 

to fund both retrofit and new construction measures. 

Following approval of its Three Year Energy Efficiency Plan 

for 2010 through 2012, the company began to implement 

a significant increase in the size of its investment in energy 

efficiency from USD 12 million in 2009 to USD 35 million 

by 2012.

WMECO proposed a total revenue decoupling 

mechanism that annually reconciled the difference 

between the company’s actual distribution revenues and 

Target Revenues for that year. The Company’s proposed 

mechanism was designed to provide for annual filings that 

were straightforward to audit and review.

The Order implementing the RDM was generally based 

on WMECO’s proposal. The Order required an annual 

adjustment to be made to Base Rates in a given Rate Year 

to reconcile Target Revenue with Actual Revenue received 

during the immediately preceding Rate Year. The Order 

specified that the annual RDM Adjustment should be 

calculated in accordance with the following formula, and 

applied in the upcoming Rate Year:26

RDMAFi = (TRi-1 - ARi-1 + PPAi) / FkWhi

Where, 

RDMAFi

 means the RDM Adjustment factor applicable 

during year i,

TRi-1 equals the total Target Revenue specified in the 

Order,

ARi-1 means the Actual Revenue reported during year 

i-1,

PPAi

 means the reconciliation in the upcoming Rate 

Year of estimated actual revenue included in prior 

period calculations of RDMA, and the recovery of 

any deferred amounts, and

FkWhi

 = the forecast of total kWh sales applicable in 

the upcoming Rate Year, defined as the forecasted 

amount of electricity to be distributed to the 

Distribution Company’s distribution customers.

The effect of this formula is that the annual RDM 

Adjustment Factor is calculated by dividing (1) the 

difference between Target Revenues and Actual Revenues 

for the most recently completed annual period by (2) 

projected kWh deliveries for the next recovery period. 

This method of determining the RDM Adjustment Factor 

on a total revenue basis is consistent with the approach 

authorised by the Massachusetts Department of Public 

Utilities in previous rate cases for other electricity 

distributors.

WMECO will calculate class Target Revenues for each 

rate class. The initial Target Revenues will be equal to base 

revenues by class at the base rates that were provided in 

section 3 of the Order implementing the RDM. Actual 

Revenues, by class, will be determined directly from the 

actual booked base distribution revenues on a calendar 

month basis accumulated for the 12- to 23-month period. 

The difference between Actual Revenues and Target 

Revenues for that year by class will be summed and then 

divided by the projected total annual WMECO sales for the 

period over which the adjustment is to be recovered.

The Order implementing the RDM also required that 

as part of its annual filing, WMECO must submit the 

following information for its residential, commercial, 

industrial, and street lighting customers: (1) monthly 

customer counts; (2) monthly kWh sales; (3) weathernormalised kWh sales; (4) lost base revenue from energy 

efficiency programs for the most recent calendar year 

available; and (5) forecasted sales for the next two years.

C. Requiring Published Information 

on Opportunities for Demand-Side 

Resources

i. Description

This mechanism requires electricity providers to publish 

information about opportunities for using demand-side 

resources to reduce loads in ways that can:

• defer or eliminate the need to build additional 

electricity generation capacity; and/or

• defer or eliminate the need to augment and/or expand 

the electricity network by building poles and wires.

The purpose of publishing the information is to enable 

proponents of demand-side resource projects to propose 
22

Effective Mechanisms to Increase the Use of Demand-Side Resources

options to an electricity provider that can achieve the 

objectives of the electricity provider at a lower cost than 

supply-side options such as building new generation 

capacity or poles and wires. In its simplest form the 

mechanism simply requires energy providers to publish 

the specified information without necessarily acquiring 

demand-side resources. However, the mechanism can 

be linked to a mandate that requires energy providers 

to implement cost-effective demand-side measures (see 

section 3.D, page 24).

Information that an electricity provider is required to 

publish under this mechanism may include:

• detailed information regarding the forecast need for 

additional capacity in a way that enables interested 

parties to identify the likely nature, size, timing, and 

geographic locations of future capacity expansions;

• information that makes transparent the underlying 

assumptions and decision-making process relating 

to investments that expand its generation and/or 

network capacity; and

• details of the process that will be followed by 

the electricity provider in soliciting, evaluating, 

and procuring both demand-side and supplyside resources to address future requirements for 

additional capacity.

ii. Implementation

The information required by this mechanism is typically 

published either by an individual electricity provider 

or by a market operator as a regular public report on 

the adequacy of the existing generation and/or network 

capacity to maintain an acceptable level of supply reliability. 

This public report is often referred to as a “Statement of 

Opportunities” or a “Regional System Plan.” For example, 

in the United States, the 2011 Regional System Plan 

published by the independent system operator ISO-New 

England27 outlines the region’s electricity needs for the 

next 10 years and explores the generation, demand-side 

resources, and transmission improvements that can meet 

those needs. In Australia, the 2011 Electricity Statement of 

Opportunities28 published by the Australian Energy Market 

Operator provides a broad analysis of opportunities for 

generation and demand-side investment in the Australian 

National Electricity Market (NEM).

The following levels of information are typically included 

in such public reports:

• a low level of detail across the whole system to 

provide an indication of where additional capacity 

is, and is not, likely to be required in the foreseeable 

future;

• a medium level of detail for parts of the system where 

additional capacity is forecast to be required within 

a defined period (e.g., five years) to allow customers 

and third parties to consider whether they may be 

able to assist in addressing any capacity shortfalls; and

• when action is being taken to acquire additional 

capacity, a higher level of detail on the nature, size, 

timing, and geographic location of the forecast 

capacity shortfall, including illustrative system 

support options developed by the electricity provider.

The reports may also include:

• information about consultation with customers and 

other interested parties in relation to specific forecast 

capacity shortfalls; and

• details of the resource procurement process to be 

implemented by the electricity provider.

iii. Application

This is a relatively new mechanism that has not yet been 

widely used. It can be implemented under any electricity 

sector structure, although it is currently used in regions 

with restructured electricity markets.

The unbundling of electricity providers has driven 

requirements for increased public disclosure about 

operational issues. Individual providers carrying out only 

one of the electricity industry functions require information 

about the activities of the separate providers carrying 

out the other functions so that they can plan their own 

activities. Regulators have assisted by mandating the public 

disclosure of this information.

The increased availability of information has allowed 

third parties, including providers of demand-side 

resources, to identify opportunities to contribute to the 

activities of electricity providers, particularly by providing 

load reductions as alternatives to expanding generation 

and network capacity. Regulators have used mandatory 

information disclosure to encourage the use of demand-side 

27 ISO New England, 2011. 

28 Australian Energy Market Operator, 2011.
23

Effective Mechanisms to Increase the Use of Demand-Side Resources

resources where such resources are cost-effective compared 

with supply-side resources. 

iv. Market Impact

Mandatory disclosure of information about opportunities 

for using demand-side resources to address capacity 

shortfalls creates markets for such resources. These range 

from highly structured markets, as in the forward capacity 

markets that have been established in some regions of 

the United States, to less structured markets, as when 

individual electricity providers include demand-side 

resources in their resource acquisition processes.

v. Effectiveness

Mandatory disclosure of information is a necessary 

but not sufficient condition to achieve increased use of 

demand-side resources in the electricity sector. Information 

disclosure will enable providers of demand-side resources 

to propose options to an electricity provider, but does 

not guarantee that these options will be taken up by the 

electricity provider. In the early years of operation of the 

information disclosure Code of Practice described in the 

following case study, some providers of demand-side 

resources complained that they were spending considerable 

funds in developing demand-side options, but these 

options were not being taken up. Additional supportive 

mechanisms and policies may be required to ensure uptake 

of all cost-effective demand-side resources identified 

through an information disclosure process. Some of these 

additional mechanisms and policies are highlighted in the 

following case study.

vi. Case Study

Expansion and augmentation of electricity networks is 

an area in which information disclosure can be effective in 

encouraging increased use of cost-effective demand-side 

resources. Many jurisdictions with unbundled electricity 

providers are now requiring mandatory disclosure about 

forecast network constraints.

The following case study briefly describes the mandatory 

Code of Practice29, 30 in the state of New South Wales in 

Australia that requires electricity distributors to publish 

information about network constraints in their systems 

and evaluate alternative options for addressing these 

constraints.

The current third edition of the Code has been formally 

issued in accordance with Clause 6 of the Electricity Supply 

(Safety and Network Management) Regulation 2002. This 

requires electricity distributors in the state of New South 

Wales to take the Code into account in the development 

and implementation of their network management plans. 

In particular, the network management plan must specify 

where it or its implementation departs from the provisions 

of the Code and, if so, what arrangements are in place to 

ensure an equal or better outcome.

The Code requires electricity distributors in New South 

Wales to:

• publish information that makes transparent the 

underlying assumptions and decision-making process 

relating to investments that expand their distribution 

networks;

• publish detailed information regarding the need for 

network expansion in a way that enables interested 

parties to identify likely locations of forthcoming 

network constraints;

• use a formal process to determine whether demand 

management31 (DM) investigations are warranted for 

identified emerging network constraints, and publish 

the results;

• carry out DM investigations that provide 

opportunities for market participation;

• analyse DM and network expansion options on an 

equal basis according to the published methodology 

and assumptions and publish the result of those 

determinations;

• implement DM options where they are determined to 

be cost effective; and

• prepare and publish reports on these activities 

annually.

The Code’s objectives are for transparency in information 

provision and equal treatment in processes and evaluation 

in “circumstances in which it would be reasonable to 

expect that it would be cost-effective to avoid or postpone 

29 Department of Energy, Utilities and Sustainability, 2004. 

30 A Code of Practice provides detailed practical guidance in 

relation to meeting legislative obligations. Codes of practice 

are often applied to occupational health and safety issues 

but can also be applied to any situation in which legislative 

obligations exist.

31 “Demand management” is the term used in Australia for 

demand-side management.
24

Effective Mechanisms to Increase the Use of Demand-Side Resources

Figure 3

Electricity System Development Procedure for Distributors in New South Wales32

32 Department of Energy, Utilities and Sustainability, 2004.

Inform the 

Market

Identify 

Options and 

Consult

Specify 

Constraint

Test the 

Market

Evaluate 

Options

Negotiate 

Contracts

Announce

Implement

Report

Start

End

S1: Maintain

practical 

expertise in 

network, 

targeted DM 

and broadbased DM 

options

D6: Establish 

Register of 

Interested Parties

S2: Consult customers 

and interested parties

E1-E4: Evaluate options and 

Determine preferred option(s)

Negotiate and Finalise contracts with 

system support service providers

E5: Announce preferred option(s), 

including costs

Implement preferred option(s)

S4-S6: Issue Request for Proposals 

for system support, i.e. standard offer 

or negotiated offer (including detailed 

information on support required)

DEUS Annual Electricity 

Network Performance 

Report

Code Protocols

Distributor 

Cost Recovery

Disclosure Protocol 

Defines when disclosure 

required and what 

information to be 

disclosed

No

Yes

Document process and outcomes

Specification Protocol

Defines Reasonableness 

Test for deciding when 

to issue Request for 

Proposals (RFP)

Defines information 

to be included in and 

sought by RFP

Economic Regulatory 

Medium Term Review

D1-D4: Distributor Publishes annual Electricity 

System Development Review with historical 

and forecast peak load and capacity for all zone 

substations and, where appropriate, supply areas

D5: Where constraint forecast within five years, 

Include additional details

S3: Decide

if reasonable to 

undertake 

RFP?

Evaluation Protocol

Defines procedure for 

evaluating options
25

Effective Mechanisms to Increase the Use of Demand-Side Resources

the expansion of the network by the implementation of 

[demand management] strategies.”

The Code recognises that the focus should not just be on 

the network, but rather on the delivery of end-user energy 

services by means of the electricity system as a whole. 

Constraints that arise within the distribution network 

can be addressed by changes in customer behaviour, by 

changes in equipment used by customers, or by installation 

of small-scale generation at a local level, as well as by 

enhancement of the distribution network.

These options could be devised and implemented by 

customers or by electricity distributors. The market-based 

procedure in the Code is intended to ensure that all supplyand demand-side options developed by customers or third 

parties and by the distributor itself can be developed and 

evaluated at the same time and in the same manner as 

network augmentation, including the use of a competitive 

process.

The procedure described in the Code is illustrated in 

Figure 3 (page 24). The procedure requires:

• a process for informing the market by disclosing 

appropriate information about the current and future 

state of the electricity supply system – the Disclosure 

Protocol;

• a process for fully and consistently specifying the 

constraint in the electricity supply system – the 

Specification Protocol; and

• a process for fairly and consistently evaluating 

proposals to overcome this constraint – the Evaluation 

Protocol.

The Disclosure Protocol ensures that distributors 

provide regular public reports on the status of their 

networks that include all necessary information in a clear 

and consistent form, without wasting effort in providing 

unnecessary information.

The Specification Protocol ensures that system 

constraints are fully and accurately specified. The Protocol 

requires distributors to consult with customers and 

interested parties in relation to each of the constraints and 

options to address them. The Protocol also describes the 

process through which alternative options for addressing 

constraints can be invited and proposed in a manner that 

allows direct comparison with each other and with options 

developed by the distributor. The Specification Protocol 

defines a Reasonableness Test, which the distributor should 

apply in deciding whether to issue a formal Request for 

Proposals in relation to each constraint.

The Evaluation Protocol ensures that disparate 

network enhancement and other system support options 

are given fair consideration and are equitably evaluated 

including all relevant costs and benefits. The Protocol 

requires that all conforming options should be evaluated 

and ranked on the basis of total annualised cost of 

providing the system support adjusted to account for the 

relative risk profile of options. The Protocol also requires 

distributors to publicly announce the recommended 

options resulting from the evaluation and the annualised 

cost to the distributor of the recommended options.

D. Mandating Implementation of CostEffective Demand-Side Measures

i. Description

This mechanism requires electricity providers to include 

all available cost-effective demand-side measures when 

they are acquiring resources for use in meeting customer 

demand for electricity.

The mechanism applies a policy or regulatory condition 

on the usual resource acquisition procedure adopted by 

electricity providers. This condition requires electricity 

providers to investigate, assess, and select cost-effective 

demand-side measures in preference to supply-side 

resources. The condition may specify the methodology to 

be used when assessing cost effectiveness and may also 

stipulate the relative priorities to be assigned to different 

demand-side measures.

This mechanism does not set quantitative targets but 

instead relies on measures of cost-effectiveness to determine 

the amount of demand-side measures to be acquired. This 

distinguishes mandating implementation of cost-effective 

demand-side measures from imposing energy efficiency 

obligations on electricity providers (see section 3.E, page 27).

In some cases, targets may be set in which a policy 

decision has been made to preferentially acquire certain types 

of demand-side resources. For example, if there is a policy to 

acquire renewable energy, then a specific renewable energy 

target may be set with a different set of cost effectiveness 

criteria to that of other demand side resources.

The cost-effectiveness of demand response resources 

may also be assessed differently from other demand-side 

resources because demand response is often acquired 

specifically to deal with peak load problems or to assist 
26

Effective Mechanisms to Increase the Use of Demand-Side Resources

with the integration of renewable energy into the resource 

mix, rather than to contribute to meeting overall demand.

ii. Implementation

There are two main ways in which this mechanism 

can be implemented. One way is to implement a “loading 

order,” which requires electricity demand to be met first by 

cost-effective demand-side measures. The second way is 

to simply mandate electricity providers to acquire all or a 

proportion of demand-side measures that are cost-effective, 

reliable, and feasible.

iii. Application

This mechanism has been implemented mainly in the 

United States. The states of California, Washington, and 

Massachusetts have adopted mandates requiring their 

electricity providers to identify and pursue all achievable 

cost-effective energy efficiency before considering 

investment in new generation options. The California 

mandate applies to investor-owned utilities, and the 

Washington mandate applies to both investor-owned and 

public utilities with more than 25,000 customers.33

iv. Market Impact

By increasing the quantity of demand-side resources 

acquired by electricity providers, this mechanism:

• establishes a market for cost-effective demand-side 

resources where such a market does not already exist; 

and

• significantly changes the dynamics of wholesale 

electricity markets by lowering the clearing price and 

therefore changing the merit order of generators that 

are less cost-effective than demand-side measures.

v. Effectiveness

Mandating implementation of cost-effective demand-side 

measures should be very effective in achieving increased 

use of demand-side resources in the electricity sector. 

However, in practice, the effectiveness of this mechanism 

will be largely determined by the methodology used to 

assess the cost-effectiveness of demand-side measures. For 

this reason, jurisdictions adopting this approach generally 

specify a methodology to be used in evaluating demandside measures to avoid a situation in which only small 

quantities of demand-side resources are being acquired by 

electricity providers. In addition, applying rewards and 

penalties based on the performance of electricity providers 

in acquiring cost-effective demand-side resources will 

increase the effectiveness of this mechanism.

vi. Case Study

The following case study briefly describes the loading 

order34 policy for electricity resources implemented in the 

state of California in the United States.

In 2003, California’s principal energy agencies – the 

California Energy Commission, the California Public 

Utilities Commission (CPUC), and the California Consumer 

Power and Conservation Financing Authority – established 

an energy resource loading order policy to guide their 

energy decisions. The purpose of the loading order is:35

• to reduce electricity demand by increasing energy 

efficiency and demand response; and

• to meet new generation needs first with renewable 

and distributed generation resources, and second with 

clean fossil-fuelled generation.

The loading order was adopted in the 2003 Energy 

Action Plan prepared by the California energy agencies. The 

California Energy Commission’s 2003 Integrated Energy 

Policy Report also used the loading order as the foundation 

for its recommended energy policies and decisions.

The loading order policy was codified by statute in 

2005.36 The statute requires the procurement plans 

developed by each of California’s three investor-owned 

utilities to first meet the utility’s unmet resource needs 

through all available energy efficiency and demand 

reduction resources that are cost effective, reliable, and 

feasible. The loading order puts energy efficiency first 

because it is believed to be the lowest-cost, environmentally 

preferred resource.37

33 Hopper et al, 2009. 

34 Although the term “loading order” is often used to describe 

the dynamic process used by system operators to meet demand on a short-term basis, in California the term is applied 

to the process whereby energy providers acquire resources 

over the long term.

35 California Energy Commission, 2005. 

36 California, 2005. 

37 Hopper et al, 2009.

38 California Public Utilities Commission, 2004. 
27

Effective Mechanisms to Increase the Use of Demand-Side Resources

To implement the loading order policy, the CPUC 

adopted long-term energy efficiency goals for the state’s 

investor-owned utilities, drawing in part from the results 

of a study that estimated the achievable cost-effective 

energy efficiency potential in the three utilities’ service 

territories.38 The loading order policy had a direct impact 

on the amount of energy efficiency proposed in the utilities’ 

resource plans, and their proposals closely match the CPUC 

goals. Although several additional supporting policies and 

factors are in place to encourage and eliminate barriers 

to California’s investor-owned utilities pursuing energy 

efficiency, it was the annual energy savings goals specified 

by the CPUC, and the underlying statutory mandate for 

utilities to acquire all achievable cost-effective energy 

efficiency, that drove the specific levels of energy efficiency 

proposed in these utilities’ resource plans.39

E. Imposing Energy Efficiency Obligations

i. Description

This mechanism requires obligated parties to meet 

quantitative energy savings targets through implementing 

cost-effective demand-side measures, particularly end-use 

energy efficiency. Typically, this mechanism sets annual 

energy savings targets for a long-term period, requiring 

obligated parties to achieve specified reductions in energy 

use through energy efficiency measures.

Different jurisdictions have used a variety of terms to 

describe this mechanism, including “energy efficiency 

obligation” (EEO), “energy efficiency resource standard” 

(EERS), “energy efficiency portfolio standard,” and “energy 

efficiency commitment.”

Energy efficiency obligations may be placed on vertically 

integrated electricity utilities or on one or more types of 

unbundled electricity providers. Because the targets usually 

specify percentage reductions in electricity sales to enduse customers, the obligation is often placed on electricity 

retailers. The obligation may also be placed on distribution 

network operators, particularly where these businesses are 

also electricity retailers.

In some jurisdictions, EEOs are placed on providers of 

other fuels such as gas and heating oil, or even on endusers. Energy efficiency projects in the electricity sector 

may be included as eligible activities for meeting the 

obligations of these other obligated parties. Such projects 

will increase the contribution of demand-side resources in 

meeting the demand for electricity.

ii. Implementation

In implementing an EEO, a government or regulator 

determines:

• the level of the energy savings target to be achieved;

• the type and level of any penalties applicable for 

noncompliance with the obligation;

• who the obligated parties will be and how the overall 

energy savings target will be allocated to individual 

obligated parties;

• the sectoral overage of the EEO, that is, both the 

energy types covered and the end-use sectors in 

which energy savings measures may be implemented 

to achieve the EEO target;

• the eligible energy efficiency measures that may be 

implemented to achieve energy savings that contribute 

to the EEO target;

• which parties may be accredited to carry out eligible 

energy efficiency projects and how this accreditation 

is carried out;

• how energy savings are to be measured, reported, and 

verified, including any deemed energy saving values40

for specified energy efficiency measures; and

• where required, how activities undertaken by 

obligated parties to meet their obligations will be 

funded.

Obligated parties generally achieve their EEO targets by 

assisting end-use customers to save energy through energy 

efficiency programs, including the use of rebates and other 

38 California Public Utilities Commission, 2004. 

39 Hopper et al, 2009. 

40 A deemed energy saving is an estimate of the energy saving 

achieved by installing a single unit of an energy efficiency 

measure, such as replacing an incandescent light bulb with a 

compact fluorescent one. The estimate is usually developed 

from data sources and analytical methods that are widely 

considered acceptable for the specified measure and purpose. 

The estimate may be applied to situations other than that for 

which it was developed. Then the estimate is “deemed” to be 

acceptable as the quantity of energy saving claimable for installing a particular energy efficiency measure. Using deemed 

energy savings significantly reduces the cost of measuring 

and verifying energy savings.
28

Effective Mechanisms to Increase the Use of Demand-Side Resources

incentives. The obligated parties may themselves carry out 

energy efficiency projects in customers’ premises, or may 

commission specialists such as energy service companies 

to carry out the projects. Some EEOs allow savings from 

building codes, appliance efficiency standards, combined 

heat and power facilities, and distribution system efficiency 

improvements to count toward meeting the target.

If the jurisdiction adopts a cumulative savings objective 

– say, 15 percent electricity savings by 2020 – annual 

targets will typically increase over time to reflect the 

continued impacts of measures installed each year. With 

a cumulative target, the lifetime savings associated with 

installation of energy efficiency measures are counted. Thus 

program administrators are fully credited for installing 

long-lived and well maintained measures. Yearly savings 

targets provide short-term goals and a yardstick for 

monitoring progress.

An EEO may allow obligated parties to make a 

compliance payment in lieu of meeting the target, with the 

money directed to a state agency charged with achieving 

the intended savings. A penalty may be imposed if an 

obligated party fails to meet their target.

An EEO may also be placed across a whole jurisdiction 

and incentive payments provided to third parties who 

install eligible energy efficiency measures in residences, 

businesses, or industrial facilities. The incentives are 

typically based on engineering estimates of the savings 

achieved by eligible measures. In this model, the obligated 

party has no role in delivering energy efficiency – it simply 

pays for the resource delivered.

Some EEOs are accompanied by energy efficiency 

certificate41 trading schemes. Energy efficiency certificates 

are legal instruments that certify that a particular quantity 

of verified energy savings has been achieved. At the end 

of each accounting period, the obligated parties surrender 

sufficient certificates to meet their energy savings targets for 

that period.

Energy efficiency certificate trading schemes accredit 

either or both obligated parties and non-obligated parties42

to carry out eligible energy efficiency projects and to create 

certificates for the total amount of verified energy savings 

they achieve through each project. When non-obligated 

parties are enabled to carry out eligible energy efficiency 

projects and to create certificates, this can provide a 

powerful stimulus to the development of an energy services 

industry. Certificates created by non-obligated parties are 

sold to obligated electricity providers and this provides a 

funding stream for energy efficiency projects.

Jurisdictions vary in the arrangements established to 

fund the costs incurred by obligated parties in undertaking 

activities to meet their obligations. In many jurisdictions, 

particularly in Europe and Australia, the costs incurred by 

the obligated parties are treated as costs of doing business 

and are funded entirely by the obligated parties. Obligated 

parties who are energy providers may then seek to recover 

these costs through increasing the prices they charge endusers. In other jurisdictions, a more formal process may be 

established to determine the reasonable costs involved in 

meeting the obligations and then include these costs into a 

pricing determination or rate case.

iii. Application

Energy efficiency obligations have been implemented 

widely in many countries throughout the world. The 

United Kingdom regulator first imposed an EEO on 

electricity retailers in 1994. More recently, obligations have 

been placed on electricity retailers in Belgium (Flanders), 

Denmark, France, and Italy.43 In the United States between 

2007 and 2010, 26 states adopted energy efficiency 

resources standards for electricity so that now more than 

half of all states have an EERS in place.44 Three Australian 

states have imposed EEOs on electricity retailers.45 In South 

America, an EEO has been implemented in Brazil.46 In 

India, an EEO on end-users is being planned and will be 

implemented in 2012.47

iv. Market Impact

An EEO establishes a new market or expands an existing 

market for installing energy efficiency measures. An EEO 

accompanied by an energy certificate trading scheme 

41 Energy efficiency certificates are also known as “white certificates” or “white tags.”

42 Such non-obligated parties may include specialised energy 

service companies or even individual end-use customers.

43 Bertoldi et al, 2009. 

44 Nowak et al, 2011. 

45 Crossley, 2009. 

46 Lees, 2010. 

47 Bureau of Energy Efficiency, 2011.
29

Effective Mechanisms to Increase the Use of Demand-Side Resources

establishes a new market for certificates and also provides a 

source of funding for energy efficiency projects.

v. Effectiveness

EEOs are generally very effective in establishing new 

markets for energy efficiency as a demand-side resource. 

Typically, electricity providers and other obligated parties 

that fail to achieve their EEO targets must pay a penalty. 

Experience with EEOs has shown that providers generally 

strive to meet the targets and avoid paying the penalty. 

In the United States, some states are implementing EEOs 

requiring as much as 1.5 to 2 percent savings per year after 

a period of ramp-up.48

One problem that has emerged with EEOs is that they 

tend to encourage the implementation of low cost, easy 

to install energy efficiency measures (“low hanging fruit”), 

such as the replacement of incandescent with compact 

fluorescent light globes. This occurs particularly where 

energy savings values are deemed for such measures and 

may lead to situations in which not all the cost-effective 

energy savings available at a site are acquired (“cream 

skimming”). The additional cost involved in returning 

to the same site at a later date may make acquiring the 

remaining energy savings not cost-effective. This problem 

may be overcome by establishing provisions that require a 

minimum proportion of an obligated party’s energy savings 

target to be achieved by implementing comprehensive 

packages of energy savings measures that acquire all the 

cost-effective energy savings available at a site.

vi. Case Study

The following case study briefly describes the longrunning energy efficiency obligation imposed on electricity 

retailers in the United Kingdom.

The first EEO implemented in the United Kingdom, and 

in Europe, commenced in 1994 when the then electricity 

regulator for England and Wales commenced an initiative 

known as the Energy Efficiency Standards of Performance 

(EESoP).49 Under this initiative, the regulator required 

electricity suppliers (i.e., electricity retailers) with more 

than 15,000 customers to spend GBP 1.00 per residential 

customer on household energy savings measures. The 

regulator also set energy savings targets to be achieved by 

the suppliers. The program was extended to electricity 

suppliers in Scotland in 1995 and in Northern Ireland in 

1997. In 2000, the EESoP program was extended by the 

regulator to all electricity and gas suppliers in the United 

Kingdom with at least 50,000 customers. The suppliers 

were required to spend GBP 1.20 per customer on 

household energy savings measures.

The EESoP ran from 1994 until 2002 and became 

the dominant vehicle through which energy efficiency 

measures were delivered to residential customers in the 

United Kingdom. Suppliers met their energy saving targets 

by setting up in excess of 800 schemes to deliver energy 

efficiency measures.

EESoP had both social goals and environmental 

benefits. The majority of customers assisted under EESoP 

1 (1994 to 1998) were disadvantaged.50 In EESoP 2 

(1998 to 2000) and EESoP 3 (2000 to 2002) energy 

suppliers were required to focus approximately two thirds 

of their expenditure on this customer group. To reach 

disadvantaged households, suppliers integrated some of 

their schemes with social housing providers. In this way 

energy suppliers could target a large number of low-income 

consumers and offer them the benefits of energy efficiency 

at little and no cost by leveraging funds from social housing 

providers. Energy suppliers also provided energy efficiency 

solutions to their own consumers who were in need. Some 

suppliers ran schemes that were targeted at their consumers 

who were in debt. Other suppliers ran schemes with their 

prepayment meter customers.

The EESoP program demonstrated that energy suppliers 

were capable of meeting, and exceeding, the energy 

efficiency targets set. Over the eight years of the program, 

suppliers developed in-house expertise through managing 

and delivering energy efficiency schemes.51

Under the Utilities Act 2000, a new program called the 

Energy Efficiency Commitment (EEC) was established 

that built on the success of the EESoP. Under this 

program, the United Kingdom government took over 

the role of the regulator in setting energy savings targets 

for energy suppliers, commencing in 2002. EEC was the 

UK government’s key energy efficiency policy for existing 

households.

48 Nowak et al, 2011.

49 Energy Saving Trust, 2001. 

50 Ofgem and the Energy Saving Trust, 2003. 

51 Ofgem and the Energy Saving Trust, 2003.
30

Effective Mechanisms to Increase the Use of Demand-Side Resources

The EEC program was implemented in two phases, 

EEC1 (2002 to 2005) and EEC2 (2005 to 2008). EEC1 

required electricity and gas suppliers to achieve an energy 

savings target of 62 TWh in domestic households in Great 

Britain between 1 April 2002 and 31 March 2005.52 At 

least 50 percent of the target had to be met in relation to a 

Priority Group of consumers, defined as those in receipt of 

certain income-related benefits and tax credits.

Energy suppliers promoted their schemes through 

numerous routes and partnered with different organisations 

to deliver measures to consumers. The main routes for 

suppliers to promote measures to consumers involved 

them:

• offering measures direct to consumers;

• partnering with other organisations such as social 

housing providers and charities;

• partnering with appliance retailers and manufacturers; 

and

• linking in with other government programs.

In early 2008, the United Kingdom government 

announced that, following the completion of EEC2, the 

EEC would be renamed the Carbon Emissions Reduction 

Target (CERT). CERT has become the government’s 

main policy instrument for reducing carbon emissions 

from existing households. CERT requires certain gas and 

electricity suppliers to meet a carbon emissions reduction 

obligation (carbon obligation).53 At least 40 percent of this 

target must be achieved by targeting certain low-income 

domestic consumers or those over 70 years old – the 

“Priority Group.”

The target is divided between the obligated suppliers 

according to the number of domestic customers to whom 

they supply electricity and gas. Energy efficiency measures 

can be provided to any domestic household in Great Britain 

that is heated by gas, electricity, coal, oil, or liquefied 

petroleum gas (LPG). The funding for the installation 

or distribution of measures comes from the obligated 

suppliers. However, they are not required to spend a fixed 

amount of money per household.

Energy suppliers are not limited to offering measures 

to their own consumers and can partner with other 

organisations for the distribution of measures or to 

encourage the uptake of measures. For each scheme, 

suppliers must demonstrate that their activity has led to 

additional energy efficiency measures being installed.

Suppliers can meet up to five percent of their obligation 

through the Priority Group flexibility mechanism. This 

aims to target low-income, hard-to-treat homes. Priority 

Group flexibility recipients must be in receipt of relevant 

benefits or tax credits and not in social housing.

An uplift of 50 percent additional energy savings is 

available on market transformation activities, which 

include microgeneration. Suppliers can also meet a 

proportion of their obligation through carrying out 

demonstration projects, to trial new types of measures or 

customer reactions to information or measures. Market 

transformation activities and demonstration activities 

combined are capped at six percent of a supplier’s 

obligations.

F. Mandating Implementation of 

Time-Varying Electricity Pricing

i. Description

This mechanism requires electricity providers to 

implement time-varying electricity prices for some or all of 

their end-use customers. The purpose is:

• to increase economic efficiency by better matching 

prices to the time-varying costs of supplying 

electricity;

• to provide pricing signals encouraging customers to 

modify the way they use electricity, particularly by 

reducing load at peak times; and

• to delay investment in new electricity generation and 

network infrastructure.

The mechanism can result in increased use of demandside resources in the electricity sector through incentivising 

the use of demand response measures.

ii. Implementation

Electricity providers generally implement time-varying 

pricing by requiring customers who have particular enduse applications or high-volume electricity use to go on to 

time-of-use or critical peak pricing.

Historically, time-varying pricing was implemented by 

installing time clocks that energised particular circuits in 

customer’s premises only during set time periods of the day. 

52 Ofgem, 2005.

53 Ofgem, 2007.
31

Effective Mechanisms to Increase the Use of Demand-Side Resources

This technology was introduced for storage appliances such 

as storage water heaters and space heating, which were 

supplied with low-price electricity during off-peak periods.

Implementing more sophisticated time-varying electricity 

pricing requires the installation of interval electricity 

meters that are capable of recording the quantities of 

energy consumed over set, frequent time intervals. When 

such meters include one-way or two-way communications 

between the electricity provider and the meter, they are 

generally known as “smart meters.”

iii. Application

In some jurisdictions, electricity providers have 

implemented voluntary schemes of time-varying prices 

in which customers could choose to go on to time-of-use 

tariffs. The largest and longest-running of these types of 

scheme is in France (see the case study on page 32).

No jurisdiction has successfully implemented mandatory 

time-varying electricity prices for all general supply 

customers over the long term. Governments in several 

jurisdictions have mandated universal rollouts of smart 

meters to particular customer classes and have also 

attempted to mandate time-of-use pricing for all customers 

with smart meters. However, following complaints from 

customers, most jurisdictions have replaced mandatory 

time-of-use pricing with voluntary schemes. For example, 

the government in the Australian state of Victoria 

suspended mandatory time-of-use pricing associated with a 

smart meter rollout after an investigation found that timeof-use pricing would negatively impact many Victorians, 

increasing household energy costs by approximately AUD 

100 a year.54

Pilot programs of time-varying pricing have been carried 

out in many jurisdictions and these have provided some 

indication of the benefits available from altering the timing 

of electricity use through time-of-use and critical peak 

pricing, particularly where the introduction of time-varying 

pricing was accompanied by the installation of devices that 

enabled the energy provider to directly control customer 

loads.

iv. Market Impact

Time-varying pricing coupled with direct load control of 

customer loads can give electricity providers considerable 

flexibility to manage loads during different time periods 

throughout the day, and also throughout the year. This 

flexibility can provide significant benefits to electricity 

markets, system operations, and planning processes. 

Consequently, the mechanism may indirectly contribute 

to increasing the use of demand-side resources in the 

electricity sector.

v. Effectiveness

The effectiveness of time-varying pricing depends on 

end-use customers modifying the way they use electricity, 

particularly by reducing load at peak times. Trials and 

full-scale implementations of time-varying pricing have 

generally shown that customers’ responses are variable. A 

particular problem is that customers’ responses tend not to 

persist over time. Customers will change their behaviour 

for a period after they go on to time-varying prices but 

often revert to their previous usage patterns, particularly if 

reductions in electricity bills are not large, or if bills actually 

increase with time-varying pricing.

A tentative conclusion from the results of critical peak 

pricing trials carried out in several countries is that a 

price differential of about ten times between the critical 

peak price and the off-peak price is required to achieve 

significant and firm peak load reductions.55 A more robust 

conclusion is that linking time-of-use pricing with load 

control technology that directly reduces peak loads on the 

electricity network by remotely switching appliances and 

equipment at customers’ premises is the most effective 

mechanism for reducing peak loads, because remote 

switching requires only one “set and forget”decision by 

end-use customers.56

In jurisdictions with full retail competition it is not 

possible to mandate any particular price structure, because 

the actual price structure implemented is determined by 

the electricity retailers. Retailers will still have an incentive 

to implement time-varying pricing, maybe in conjunction 

with load control technology, to reduce customers’ loads 

during times of high prices in the wholesale electricity 

market.

54 Energy Matters, 2010. 

55 Crossley, 2008a. 

56 Crossley, 2008a. 
32

Effective Mechanisms to Increase the Use of Demand-Side Resources

vi. Case Study57

The following case study briefly 

describes time-of-use electricity pricing in 

France.

In France, electricity bills for residential 

and small business customers include a 

standing charge determined by the level 

of maximum demand (in kVA) nominated 

by the customer (puissance souscrite), and 

an energy usage charge based on the type 

of tariff chosen by the customer (type 

d’abonnement). There are three types of 

electricity contract from which residential 

and small business customers can choose.

Option Base

Option Base is suitable for lower usage, 

smaller homes and holiday homes with 

only occasional usage. This is the simplest 

of the three contract types with the lowest 

standing charge and a flat rate for electricity usage all the 

time throughout the day and year.

Option Heures Creuses (Option HC)

Option HC suits the majority of houses occupied fulltime where heating is non-electric.

This is a two-part time-of-use tariff with normal (heures 

pleines) and off-peak (heures creuses) rates. The standing 

charge is slightly higher than that of Option Base, but this 

is offset against a lower off-peak rate for part of the day. The 

off-peak period is from 10 pm until 6 am each night and, in 

some regions, also at midday. Option HC is usually used in 

conjunction with a water heater operated by ripple control 

so that the heating element is switched on only during offpeak periods.

Option Tempo

Option Tempo is for high-use households, such as very 

large houses, and those with electric heating and full-time 

occupation, and for small business customers.

This is a quite complicated charging system with six 

rates of electricity pricing based upon the actual weather 

on particular days and on hours of use. Under Option 

Tempo, each day of the year is colour coded. There are 

three colours, blue (jours bleus), white (jours blancs), and 

red (jours rouges), which correspond to low, medium, and 

57 This case study is based on Giraud, 2004 and Kärkkäinen, 

2004.

58 Giraud, 2004, plus updated price information from the 

Électricité de France website at: http://bleuciel.edf.com/

abonnement-et-contrat/les-prix/les-prix-de-l-electricite/tarif-bleu-47798.html#acc52410

high electricity prices.

The colour of each day is determined mostly by the 

electricity provider Électricité de France (EDF) based on 

the forecast of electricity demand for that day – the level of 

demand is mainly influenced by the weather. The French 

transmission network operator also has the ability to 

determine the day colour if there is significant congestion 

on the electricity network.

In addition to a colour, each day also has normal and offpeak periods based on Option HC outlined above, with 10 

pm until 6 am being the off-peak period.

The rules for the Option Tempo are as follows:

• the Tempo year starts on 1st September;

• the Tempo day starts at 6 am;

• the number of days per year of each colour is fixed 

- there are 300 blue days, 43 white days, and 22 red 

days;

• Sunday is always a blue day; and

• red days cannot fall on a holiday or a weekend or on 

Figure 4

Tempo Tariff Rates in France from 18 August 201058

40

35

30

25

20

15

10

5

0

8 Hours

Night

300 Days

c€/kWh

43 Days 22 Days

8 Hours

Night

6 Hours

Night

16 Hours

Day

16 Hours

Day

18 Hours

Day

2.99 3.81 6.51

7.79

12.42

Annual subscription in €/year 35.46

9 kVA: 138.84

12-15-18 kVa: 190.08

24-30 kVa: 349.68

36 kVa: 469.93
33

Effective Mechanisms to Increase the Use of Demand-Side Resources

more than five weekdays in a row.

On blue days, the electricity price is by far the lowest 

– during the off-peak period on a blue day the price is 

extremely low (see Figure 4, page 32). On white days, the 

price is higher than under Option Base or Option HC. 

On red days, the price is very high to encourage lower 

electricity usage – the normal rate on red days is nine times 

that of the off-peak rate on blue days. Red days are usually 

the coldest days in winter.

There are four different versions of Option Tempo, 

depending on the metering, communications, and load 

control equipment installed at the customer’s premises:

• standard Tempo (the customer has only an 

electronic interval meter);

• dual energy Tempo (the customer’s space-heating 

boiler can be switched from one energy source to 

another);

• thermostat tempo (the customer has load control 

equipment that is able to adjust space heating and 

water heating loads according to the electricity price); 

and

• comfort Tempo (the customer has a sophisticated 

energy controller).

Customers who choose Option Tempo are informed each 

night about the colour for the next day. At 8 pm a signal 

is sent down power lines using a ripple control system. 

Most Tempo customers have a display unit that plugs into 

any power socket and picks up the signal. The display 

unit shows the day colour with lights, both for the current 

day and (from 8 pm) for the next day. An (optional) beep 

informs the consumer if the following day will be a red 

day. The display unit also shows whether or not the current 

electricity price is at the off-peak rate. For older systems 

without a display unit the information is available over the 

telephone or via the internet.

Customers can adjust their electricity consumption 

manually by switching off appliances, adjusting thermostat 

settings, and so on. Some customers who have the 

necessary communications and load control equipment are 

able to select load control programs that enable automatic 

connection and disconnection of separate water-heating 

and space-heating circuits.

Compared with blue days, the Tempo tariff has led to 

a reduction in electricity consumption of 15 percent on 

white days and 45 percent on red days, on average 1 kW 

per customer. Tempo customers have saved 10 percent 

on average on their electricity bill, and 90 percent of the 

customers are satisfied with the tariff. However, customers 

do not appreciate red days occurring consecutively.

Although the Tempo tariff has been successful, less than 

20 percent of electricity customers in France have chosen 

Option Tempo. Tempo customers have very particular 

customer profiles and are interested in managing their 

energy use. They are prepared to constrain their lifestyles to 

make comparatively small financial savings relative to their 

incomes.

The Tempo tariff was designed specifically for the 

situation in which EDF is a monopolistic generator and 

retailer of electricity. Specifically, much of the impetus 

for implementing the Tempo tariff and the associated 

load control systems came from the fact that EDF needs 

responsive load in order to operate a system with 80 

percent of electricity produced by baseload nuclear plants.

However, the Tempo tariff is not adapted to the 

competitive electricity market, which is being introduced in 

France. In this market:

• the network use of system charge does not vary 

between seasons; and

• the value of peak load reduction is not reflected in 

spot prices for energy, which are less volatile than the 

marginal costs of supply.

When EDF needs to manage its global load curve in 

a competitive electricity market, it will have to develop 

other types of dynamic pricing for mass market customers. 

In July 2009, EDF discontinued the Tempo tariff for new 

customers and for customers who are on the tariff at their 

current residence and then move house.
34

Effective Mechanisms to Increase the Use of Demand-Side Resources

A. Establishing an Energy Saving Fund

i. Description

This mechanism involves the establishment of a 

financial facility dedicated primarily to funding 

projects that acquire energy savings through 

installing energy efficiency measures. The range 

of financial products such a fund may offer to proponents 

of energy efficiency projects is potentially very wide 

and may include grants, senior and junior loans, loan 

guarantees, and equity participation.

In addition to providing funding for energy efficiency 

projects, energy saving funds can be used to:

• address technical, regulatory, and market barriers 

preventing the uptake of all cost-effective energy 

efficiency;

• stimulate the development of an energy services 

industry with the capability to deliver energy efficient 

solutions; and

• improve consumers’ awareness of energy efficiency 

opportunities.

ii. Implementation

Energy saving funds are most commonly developed and 

implemented by governments, although other entities such 

as business associations and philanthropic foundations may 

also be involved.

The implementation of an energy saving fund involves a 

number of steps, including:

• establishing the purpose and goal of the energy saving 

fund;

• deciding how the fund will be capitalised, the sources 

of capital, and the level of capitalisation;

• establishing a new organisation, or nominating an 

existing organisation, that will be responsible for the 

administration of the fund;

• determining the allowed uses for funding as well as 

prohibited uses;

4. Policy Mechanism

• setting the eligibility criteria for parties applying for 

funding;

• establishing a process for reviewing applications for 

funding;

• setting criteria for selecting successful applications;

• determining the conditions applicable to various types 

of disbursements from the fund (e.g., grants, loans, 

investments, and the like);

• providing technical and other assistance to successful 

applicants for funding; and

• tracking and monitoring the results of successful 

applications.

In general, there are three basic models that can be used 

to allocate funding from an energy saving fund:

• the investment model uses loans and equity 

participation to directly invest in energy efficiency 

projects and companies implementing such projects;

• the project development model promotes the 

implementation of energy efficiency projects 

by providing grants to fund part of the cost of 

implementing projects and/or by paying incentives for 

energy savings achieved; and

• the industry development model uses business 

development grants, marketing support programs, 

research and development grants, resource 

assessments, technical assistance, consumer 

education, and demonstration projects to facilitate 

market transformation toward increased energy 

efficiency.

Around the world, a wide variety of different types of 

organisations are responsible for the administration of 

energy saving funds, including:

• government agencies;

• regulatory agencies;

• quasi-autonomous non-governmental organisations 

(“qangos”);

• non-profit organisations; and

• energy providers.
35

Effective Mechanisms to Increase the Use of Demand-Side Resources

iii. Application

Since the mid-1970s, many energy saving funds have 

been established by various levels of government and other 

parties all around the world.

In the most recent wave of activity in this area, capital 

sourced from government economic stimulus packages 

implemented in response to the Global Financial Crisis 

has been used to establish energy saving funds in 

many countries. For example, in the United States, the 

American Recovery and Reinvestment Act of 2009 (ARRA) 

provides funding totalling USD 3.1 billion for state energy 

programs. One of the program areas that the ARRA 

legislation encourages is the creation of long-term funding 

mechanisms to extend the impact of the ARRA funds. Many 

states have applied for ARRA funding to set up revolving 

loan funds for energy efficiency and/or renewable energy.59

Another new source of capital for energy saving funds is 

the revenue obtained from selling permits and allowances 

in emissions trading schemes. For example, over the 

initial two years of the Regional Greenhouse Gas Initiative 

emissions trading scheme in the northeast of the United 

States, 86 percent of permits were auctioned. Of the twoyear revenue of USD 789 million, 52 percent was allocated 

to state and utility programs to improve energy efficiency.60

iv. Market Impact

Energy saving funds increase the level of energy 

efficiency in a jurisdiction and may indirectly expand 

the participation of demand-side resources in electricity 

markets. Where electricity providers are mandated to 

make financial contributions to an energy saving fund,61

the connection with, and impact on, the local electricity 

market is more direct. In particular, a proportion of the 

demand that would otherwise be served by the energy 

provider supplying electricity will now be served by the 

implementation of energy efficiency measures funded by 

the energy provider.

v. Effectiveness

Energy saving funds can be very effective in increasing 

the level of energy efficiency in a jurisdiction, although as 

noted in the previous section, their impact on increasing 

the use of demand-side resources in the electricity sector is 

mostly indirect.

vi. Case Study62

The following case study of the implementation of an 

“efficiency utility” in the US state of Vermont is an example 

of an energy saving fund that has had a significantly 

direct impact on integrating energy efficiency into a retail 

electricity market.

Throughout the 1980s and 1990s Vermont’s electricity 

distribution utilities were responsible for implementing 

energy efficiency programs. In late 1999 the state’s 

regulator, the Vermont Public Service Board (PSB), decided 

to transfer that responsibility to an independent “efficiency 

utility.” This body was to be funded by a small system 

benefits charge on electricity prices, effectively creating an 

energy saving fund.

The PSB issued a Request for Proposal to engage an 

organisation to serve as the efficiency utility under a threeyear contract with an option for renewal for a second three 

years. The Vermont Energy Investment Corporation (VEIC), 

a local non-profit organisation, was selected from among 

five bidders to play that role. It subsequently created 

the Efficiency Vermont brand under which all statewide 

electric efficiency programs for residential, commercial, and 

industrial customers have been marketed.

In 2005, VEIC rebid (this time against one competitor) 

and won the right to continue serving as the efficiency 

utility for the period 2006 through 2008 and potentially 

through 2011 (i.e., the same three-year contract with an 

option for a three-year renewal). Beginning in 2012, the 

state will treat the efficiency utility – with VEIC continuing 

to play that role – as more of a regulated “franchise” with 

a longer-term commitment, rather than rebidding the 

contract every six years. The objectives of this change 

include allowing Efficiency Vermont to take a longerterm view on energy efficiency planning and investments 

and to interact more in policy arenas and with the states’ 

distribution utilities than it had in the past. However, it will 

still operate with three-year performance goals.

59 Booth, 2009.

60 Regional Greenhouse Gas Initiative, Inc., 2011. 

61 For example, by adding a small fee (known in the United 

States as a “system benefits charge”) to the electricity prices 

paid by customers, with the revenue from the fee being 

allocated to an energy saving fund.

62 This case study is taken from Wasserman & Neme, 2011.
36

Effective Mechanisms to Increase the Use of Demand-Side Resources

Responsibility for evaluating Efficiency Vermont’s 

programs is vested with the Vermont Department of Public 

Service (DPS), using a portion (roughly USD 3 million 

over three years) of the funds collected through the system 

benefit charge. Efficiency Vermont developed the country’s 

first Technical Reference Manual in which deemed savings 

values or formulas were developed and documented for 

a wide range of prescriptive measures (which typically 

account for about half of Efficiency Vermont’s savings). 

Those values are periodically updated through collaborative 

discussions with the DPS when evaluation work in Vermont 

(or elsewhere) provides a basis for changes.

Efficiency Vermont issues an annual report on its 

previous year’s energy savings based on both deemed 

savings values and site-specific calculations for custom 

commercial and industrial projects (which typically 

account for the other half of the savings). The DPS reviews 

the savings estimates and makes recommendations for 

modifications. The review is typically conducted by a 

third-party consultant with expertise in energy efficiency 

program evaluation and involves, among other things, a 

detailed review of a statistically representative sample of 

custom projects. Efficiency Vermont and the DPS then 

attempt to resolve any differences of opinion on technical 

matters and ultimately file recommended adjustments to 

the regulator for final approval or – if there are outstanding 

disagreements – resolution of disputes.

The Efficiency Vermont contract includes a “hold-back” 

of roughly 3 percent. That 3 percent is allocated across 

several different performance metrics, including total 

first-year MWh savings actually delivered, coincident peak 

demand (MW) savings delivered, and the net present value 

of the economic benefits of the energy efficiency programs. 

As the operator of Efficiency Vermont, VEIC eventually 

receives the held back payments, or portions of the 

payments, based on its performance relative to the metrics.

The impact of Vermont’s policies has been significant. 

From 2009 through 2011 Efficiency Vermont programs 

are expected to achieve verified annual electricity savings 

of nearly 300 GWh. That is less than the goal of 360 

GWh due largely to the impacts of a downturn in the 

economy making sales of energy efficiency measures 

and services more difficult than expected when the goals 

were established. However, it still represents incremental 

annual savings of 5.5 percent of electricity sales (an average 

reduction of about 1.8 percent per year). Electricity savings 

have been delivered at a levelised cost of approximately 

USD 0.04/kWh.
37

Effective Mechanisms to Increase the Use of Demand-Side Resources

5. Market-Based Mechanisms

A. Enabling Demand-Side Bidding into 

Electricity Markets

i. Description

Demand-side bidding (DSB) enables the demand 

side of an electricity market to participate in 

market trading. Demand-side bids are typically 

made over timescales ranging from a year to a 

few seconds ahead of the time of delivery.

There are two basic types of offer in DSB:63

• offers involving a bid for total demand; and

• offers involving a bid for a change in demand.

Bids for total demand are typically made in day-ahead 

electricity markets and consist of a series of downward 

sloping demand curves in which less electricity is 

purchased as the price increases. A typical scheme for 

DSB in a day-ahead energy market would be for buyers of 

electricity to submit their demand curves by noon the day 

before the operating day with different demand curves for 

each operating hour and delivery location. Each demand 

curve would typically consist of a sequence of pricequantity pairs that would represent the buyers’ willingness 

to pay a certain amount for the quantity indicated. For 

instance, if a buyer was willing to pay $100/MWh for 

1,000 MW, but would only want 800 MW if the price 

rose to $120/MWh, the buyer would submit the pricequantity pairs: ($120/MWh, 800 MWh) and ($100/MWh, 

1,000 MW). The demand curves submitted to the market 

operator would then be cleared with the supply curves 

submitted by electricity generators. This would give the 

buyer a position that would be delivered the next day.64

Bids for a change in demand comprise an offer to reduce 

or increase demand at a given time. The bid may be made 

by an individual large customer, or bids from a group of 

smaller customers may be combined by an aggregator. Bids 

for changes in demand may be made in several different 

types of electricity markets:

• in real-time spot markets where the bidder is essentially 

a price taker and receives the marginal clearing price 

when the price for the demand-side offer is below or 

at the margin;

• in day-ahead markets where demand-side bids are 

based on the bidder’s expectations of what the realtime price on the next day will be;

• in longer-term forward capacity markets where the 

bidder has a reasonable expectation that they will be 

able to reduce or increase load at a specified time in 

the future;

• in emergency and reserve trader65 markets, where the 

bidder is confident that they will be able to reduce 

or increase load when an emergency or unforecasted 

event occurs; and

• in ancillary services markets, where the bidder is 

confident that they will be able to reduce or increase 

load within the notice period specified by the type of 

ancillary service required.

A demand-side bidder may receive one or more of 

several payments for their bid, including

• a payment for the quantity of energy consumption

reduced or increased over the time period that the 

change in demand occurred;

• a payment for the change in the load level (reduction 

or increase) achieved – this can be based on the 

maximum or average change in load; and

• an availability payment for the contracted change in 

demand – this type of payment is usually not available 

in real-time spot markets or day-ahead markets.

63 Roberts, 2002. 

64 Earle & Faruqui, 2008. 

65 The purpose of a reserve trader market is to allow the market 

operator to contract for reserve generation capacity to be 

deployed when a shortfall of reserve capacity is projected.
38

Effective Mechanisms to Increase the Use of Demand-Side Resources

ii. Implementation

Implementation of DSB requires the operator of an 

electricity market to establish specific market rules that 

allow consumers to make bids for total demand and/or 

bids for changes in demand into the market and define 

the conditions under which DSB can occur. Specific issues 

addressed by the DSB rules will vary depending on the type 

of bid and the type of electricity market to which the rules 

apply. In general, issues that should be addressed by the 

rules include:

• a protocol for making a demand-side bid into the 

market (which may be different from the protocol for 

bidding generation output because of the different 

characteristics of demand-side resources);

• protocols for defining the size of a change in load 

(reduction or increase), the shape of the load profile, 

and the duration of the change in load;

• the minimum size of changes in load that may be 

offered into the market;

• the minimum and maximum number of occasions 

that a demand-side bidder can change their load over 

a specified time period;

• the different notice periods required for changes in 

load depending on the type of service a demand-side 

bid is intended to provide;

• the method whereby a demand-side bidder will be 

informed whether a bid has been accepted;

• methods for measuring, reporting, and verifying the 

change in load actually achieved; and

• the payments that demand-side bidders will receive 

for different types and durations of changes in load.

There is some debate about whether demand-side 

bidders who submit bids for changes in demand in dayahead or real-time markets should receive a payment in 

addition to the marginal clearing price. In the PJM market 

in the United States, bids to curtail load in the day-ahead 

or real-time energy markets receive a payment to reduce 

load. These payments to demand-side bidders are funded 

through a charge levied on energy providers who sell 

electricity directly to end-users. The reasoning is that 

the payment to demand-side bidders corrects a market 

imperfection and that the charge is justified because the 

energy providers benefit from the reduction in load, which 

results in a lowering of the wholesale market price. This 

approach is supported by a 2011 Order66 from the United 

States Federal Energy Regulatory Commission (FERC) 

requiring that a cost-effective demand response resource 

must be compensated for the service it provides to the 

energy market at the market price for energy. FERC reasons 

that this approach for compensating demand response 

resources helps to ensure the competitiveness of organised 

wholesale energy markets and to remove barriers to the 

participation of demand response resources, thus ensuring 

just and reasonable wholesale rates.

In other markets, payments to demand-side bidders are 

treated no differently from other payments for bids into 

the market and affect the financial positions of all market 

participants, (i.e., generators as well as energy providers). 

This is the case in the England and Wales market.67

iii. Application

Currently, DSB is practiced in several electricity markets 

in North America and Europe.

In the United States, there are six regional wholesale 

electricity markets with significant DSB programs. These 

programs range from direct participation in energy markets 

(both day-ahead and real-time), participation in parts of 

ancillary services markets, as well as specialised demand 

response programs centred around responding to system 

emergencies.68

In the England and Wales wholesale electricity market, 

DSB occurs in the Balancing Mechanism, which was 

specifically designed from the outset to allow this to occur. 

Demand-side bidders have to provide information on their 

intended level of consumption during the settlement period 

and the price and extent to which they are prepared to 

move away from this level. If their offer is accepted (i.e., 

they are requested to reduce their demand), they are paid 

their offer price for the energy they do not consume.69

iv. Market Impact

DSB is a mechanism that directly increases the 

integration of demand-side resources into electricity 

markets. DSB can improve the efficiency of the 

66 United States Federal Energy Regulatory Commission, 

2011a. 

67 Earle & Faruqui, 2008.

68 Ibid.

69 Ibid.
39

Effective Mechanisms to Increase the Use of Demand-Side Resources

electricity supply chain by increasing competition in the 

wholesale energy market and by acting as an alternative 

to conventional generation. For example, DSB can be 

used to balance electricity supply and demand and also 

maintain the quality and security of supply. In addition, 

a very important effect of DSB is that it often lowers the 

clearing price in wholesale electricity markets because most 

demand-side options are usually available at lower bid 

prices than many generation options.

v. Effectiveness

The effectiveness of this mechanism is dependent on 

the level of DSB actually achieved. In US markets, there 

appears to be less DSB than potential estimates indicate is 

possible. This is probably also the case in other countries. 

Reasons for the low level of DSB in the United States 

include:70

• the disconnect between wholesale prices that are set 

by the market and retail prices that are approved by 

regulators;

• wholesale prices that have price caps so that the 

ability to capture high prices through demand 

response is limited; and

• barriers to DSB in the particular business rules in the 

wholesale market.

It should also be noted that DSB is mainly concerned 

with demand reductions rather than energy efficiency. 

Although some demand reductions bid into markets 

are achieved through energy efficiency, the majority are 

achieved through short-term demand response. While 

demand response is a demand-side resource, it does not 

necessarily lead to reductions in energy use over the long 

term.

vi. Case Study71

The following case study briefly describes DSB in the 

Nord Pool wholesale electricity market that operates 

across the Nordic region (Norway, Sweden, Denmark, and 

Finland).

In the Nord Pool day-ahead market (Elspot), 

participation is optional. After taking account of any 

obligations under their physical bilateral contracts, Elspot 

market participants submit generation offers and demandside bids in the form of a price/volume curve for each hour 

of the following day. Nord Pool sets hourly ex ante prices 

at the intersection of the aggregate supply and demand 

curves. By 1:30 p.m. on the day ahead, Nord Pool informs 

each participant of its generation or purchase commitments 

in the spot market and allows participants 30 minutes 

to check that their net trading position is in accordance 

with their bids and offers. Once confirmed, accepted bid 

and offer quantities become firm contracts for physical 

delivery. Participants have no opportunity to revise their 

bids and/or offers. Because market participants provide 

demand curves as well as supply curves, provision is made 

for price-responsive demand to participate in the market. 

Over 20 percent of Norwegian demand is considered to be 

potentially price-responsive.

Because of the ready availability of balancing services 

from hydropower plants, the opportunities for DSB in the 

Nord Pool real-time ancillary services markets are limited. 

Opportunities for the demand side to provide fast reserve 

and constraint management have been developed, and in 

the future it is anticipated that opportunities to provide 

frequency response may also be developed.

A separate reserve options market has been in existence 

in Norway since winter 2000, and demand-side bidders 

are able to participate in this market. The purpose of the 

reserve options market is to ensure that an adequate level 

of regulating reserve offers are submitted during the winter 

months when there is most need for reserve.

Over 2,000 MW of option contracts are required 

to supplement the regulating reserve that is normally 

available. Weekly auctions are held for the option contracts 

and successful bidders receive an option fee, in return for 

which they are obliged to offer reserve in the regulating 

reserve market although they are free to choose the price at 

which they do so. When Statnett, the transmission system 

operator, schedules reserve, the marginal price is paid for 

all reserve provided (i.e., the price of the most expensive 

accepted offer for upward regulation and the price of the 

cheapest accepted bid for downward regulation).

Option contracts may be offered for a minimum of 25 

MW of reserve capacity. Reserve must be made available 

between 6 a.m. and 10 p.m. on business days with the 

potential for delivery within 15 minutes for a period of 

not less than one hour (and at least 10 hours of reserve 

delivery per week must be possible). The obligation to 

70 Ibid.

71 This case study is taken from Earle & Faruqui, 2008.
40

Effective Mechanisms to Increase the Use of Demand-Side Resources

offer reserve placed on demand-side participants with 

option contracts is reduced (or removed) if they reduce 

their consumption in the Elspot market in response to high 

prices. In these circumstances, however, their option fees 

are correspondingly reduced.

The reserve options market has proved popular 

with consumers, with up to 1,200 MW of the contracts 

signed with demand-side participants. At times, this has 

represented almost 70 percent of the contracts signed 

(although a much smaller proportion of the total available 

reserve of about 8 TWh). Participation has mostly 

been from large industrial facilities (metals and paper 

production). However, Statnett has also been working to 

encourage medium-sized consumers (electric boilers and 

back-up generation) to participate in the reserve options 

market and, indeed, in the day-ahead market.

Some studies have also been carried out to explore 

the extent to which smaller loads (including domestic 

customers) could also participate in the broad Nord Pool 

market. This would require the introduction of smart 

metering (to allow consumers to respond to price signals) 

and automatic load shedding controls. Although these 

studies showed that there was a potential for greater 

demand-side involvement, they also highlighted the 

technologic and cost-related challenges that would need to 

be overcome to encourage participation.

B. Enabling Bidding of Demand-Side 

Measures to Relieve Network Constraints

i. Description

This mechanism establishes a process that enables 

parties to bid demand-side measures to relieve constraints 

on electricity networks. Demand-side measures are bid as 

alternatives to building network infrastructure (“poles and 

wires”) to augment or expand the existing network.

To be effective in relieving network constraints, demandside measures must be capable of addressing the particular 

characteristics of these constraints. Network constraints 

have both timing and spatial dimensions.72

In relation to timing, network constraints may be:

• narrow peak related – occurring strongly at the time 

of the system peak and lasting seconds, minutes, or a 

couple of hours; or 

• broad peak related – less strongly related to the 

absolute system peak, occurring generally across the 

electrical load curve and lasting several hours, days, 

months, years, or indefinitely (e.g., where the network 

is close to capacity).

In relation to the spatial dimension, network constraints 

can:

• occur generally across the network in a particular 

geographic area; or

• be associated with one or more specific network 

elements such as certain lines or substations.

Demand-side measures that may be used to relieve 

network constraints include:

• direct load control;

• distributed generation, including standby generation 

and cogeneration;

• demand response;

• energy efficiency;

• fuel substitution;

• interruptible loads;

• load shifting; and

• power factor correction.

ii. Implementation

The bidding process is typically established by the 

operator of an electricity distribution or transmission 

network and consists of six stages:

• identification and characterisation of the network 

constraint;

• identification of a supply-side solution for relieving 

the constraint and determination of the cost of 

implementing this solution;

• identification of possible demand-side options for 

relieving the constraint;

• publication of a Request for Proposals to implement 

demand-side measures that will address the identified 

network constraint;

• comparison of the costs of demand-side options with 

the costs avoided by deferring or avoiding the supplyside solution; and

• selection of demand-side or supply-side solutions for 

implementation.

72 Crossley, 2008c. 
41

Effective Mechanisms to Increase the Use of Demand-Side Resources

iii. Application

This mechanism is routinely used in the state of New 

South Wales in Australia to implement cost-effective 

demand-side measures to relieve location-specific, smallscale network constraints typically involving one network 

element (e.g., a substation or a particular line).

iv. Market Impact

This mechanism establishes a market for cost-effective 

demand-side resources to contribute to relieving network 

constraints. It therefore contributes directly to increasing 

the integration of demand-side resources into electricity 

markets.

v. Effectiveness

The effectiveness of the mechanism depends on:

• the availability of demand-side resources that can 

deliver firm load reductions with appropriate timing 

and in specific locations to address identified network 

constraints; and

• the robustness of the analysis of the costs of 

implementing demand-side measures as compared 

with the avoided costs of deferring or avoiding 

supply-side solutions.

vi. Case Study73

The following case study briefly describes a project using 

bidding of demand-side measures to relieve a network constraint undertaken by EnergyAustralia, 

a distribution network operator in the 

state of New South Wales, Australia.

EnergyAustralia’s objective for the 

project was to implement demand-side 

measures that would maintain network 

performance at the required level at 

a lower cost than investing AUD 4 

million for an additional transformer at 

the zone substation for the suburb of 

Drummoyne in Sydney.

The capacity limits of the 

Drummoyne zone substation were 

66.6 MVA in summer and 72 MVA in winter. Peak demand 

in the Drummoyne area had grown steadily. Loads were 

growing more rapidly in summer than in winter, but off 

a lower base. Peak demand was forecast to exceed the 

capacity limit by 0.5 MVA in the winter of 2008 unless 

action was taken to increase capacity or reduce demand. 

The winter peak demand usually occurred on weekday 

evenings between 6:00 and 9:30 pm. The forecast summer 

peak demand indicated no overload issue during the 

summer in the foreseeable future.

Based on the load profiles, the key drivers for load 

growth appeared to be a mix of residential loads and a 

sizeable proportion of retail or commercial load. The area 

had experienced steady load growth in the years prior 

to 2005 that might be attributable to new residential 

development and multiunit residential construction.

The preferred supply-side solution was to install a 

third transformer in the Drummoyne zone substation and 

extend the 11kV switchboard at an estimated cost of AUD 

4 million. A decision to proceed would need to be made 

before the end of 2006 to enable the installation to be 

completed before winter 2008.

To defer the supply-side investment by one year (that 

is, until 2009), EnergyAustralia would need to implement 

demand reductions totalling 500 kVA prior to winter 

2008. Because a decision had to be made by late 2006, 

EnergyAustralia would need to be confident before then 

that the demand reductions were going to be delivered in 

73 This case study is taken from Crossley, 

2008b. 

74 EnergyAustralia, 2006

Figure 5

Value of Avoided Distribution Costs for Various Levels of 

Demand Reduction at the Drummoyne Zone Substation74

$900

$800

$700

$600

$500

$400

$300

$200

$100

$0

Value

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6

Demand Reduction (MVA)

$/kVA

$ total (in thousands)
42

Effective Mechanisms to Increase the Use of Demand-Side Resources

experience in other areas, EnergyAustralia assembled 

a list of demand-side options for analysis. Each of the 

options was assessed in relation to the likely size of 

demand reduction that would result at the time of network 

peak at the Drummoyne zone substation. The cost to 

EnergyAustralia of establishing and utilising each option 

at this level for varying periods of availability from one to 

three years was also estimated. Based on these estimates, 

EnergyAustralia ranked the options and compared them to 

the value of deferring the proposed supply-side investment.

Eight possible demand-side options were identified:

• Contracting with customers who had standby 

diesel generators to enable the use of the generators 

to provide short period demand reduction when 

required.

• Installation of power factor correction equipment at 

customers’ premises.

• Installation of fixed dimming systems for commercial 

lighting.

• Upgrading of commercial lighting systems using 

retrofitted efficient lighting kits.

• Peak load control by advanced control system.

• Peak demand reduction by using advanced residential 

metering and control devices.

• Residential compact fluorescent lamp (CFL) direct 

distribution program.

• Installation of thermal storage systems.

Table 2 (Page 43) summarises the estimated size and cost 

of each identified DSM option.

Figure 6 (Page 43) compares the cost and demand 

reduction impact of the identified demand-side options 

with the value of avoided distribution costs. Stacking the 

options from lowest relative cost to highest showed that 

sufficient demand reduction to achieve a one-year deferral 

could be identified at a lower cost than the value of the 

avoided costs. However, a two-year deferral would be 

unlikely to be cost effective.

Figure 6 suggests that all demand reductions would 

be cumulative. However, because several of the identified 

demand-side options targeted the same opportunities, some 

demand reductions would not be cumulative. Therefore, 

achieving sufficient demand reductions for a two-year 

deferral would be more difficult and more expensive than 

Figure 6 indicates.

On the basis of this analysis, the power factor correction 

project and the first of the CFL proposals appeared likely 

time and that they would be effective on winter evenings. 

Deferring the supply-side investment for periods longer 

than one year would require a 2.3 MVA reduction in peak 

demand before winter 2009 and a 3.7 MVA reduction 

before winter 2010.

In assessing the cost effectiveness of options, the cost to 

EnergyAustralia of the demand-side options was compared 

to the value of the avoided costs from the change in timing 

of expenditure on the supply-side solution. This provided 

a broad indication of the level of funding that might be 

available for a portfolio of demand-side measures. However, 

the determination of cost effectiveness is complex and the 

value EnergyAustralia assigned to individual projects might 

be higher or lower than this figure.

The value of avoided costs at various levels of demand 

reduction is shown in Figure 5 (page 41). A 0.5 MVA 

reduction would enable a one-year deferral and have a 

value of about AUD 280,000 or AUD 550/kVA (2005 

values). For a two-year deferral, the value rose to about 

AUD 540,000, but significantly larger demand reductions 

would be required and the relative value reduced to 

approximately AUD 220/kVA. To be considered costeffective, the overall cost to EnergyAustralia of a portfolio of 

demand-side measures had to be below these amounts.

EnergyAustralia’s investigation identified potentially costeffective demand-side options, analysed each of the options 

and their potential impact and cost, and then shortlisted 

the options that might form feasible demand-side projects. 

The most cost-effective demand-side options were then 

developed further and compared with the supply-side 

solution.

EnergyAustralia prepared a Demand Management 

Options Consultation Paper seeking proposals for 

demand-side measures capable of contributing to deferring 

the construction of a new transformer at Drummoyne 

zone substation. The consultation paper was advertised 

in July 2005 in newspapers and on EnergyAustralia’s 

website. Notifications were also sent to parties in the 

EnergyAustralia register of organisations interested in DSM. 

Nine submissions were received.

In addition, EnergyAustralia identified 20 major 

customers in the Drummoyne area, based on their peak 

demands, and visited their sites and collected information 

about their usage of energy and possible demand-side 

options.

Using these various sources and information from 
43

Effective Mechanisms to Increase the Use of Demand-Side Resources

common in the state of New South Wales as a way 

of creating tradeable emission abatement certificates 

under a state-wide emissions trading scheme. However, 

in the Drummoyne project, the 

distribution of CFLs was much more 

closely targeted and monitored to 

ensure that the lamps were actually 

installed. The project was initiated by 

EnergyAustralia’s network business 

rather than by its retailer arm, even 

though the abatement certificates 

generated were used by the retail 

business to help meet its obligations 

under the New South Wales emissions 

trading scheme.

The CFL installations were carried 

out by a third-party contractor 

who had proposed the measure in 

response to EnergyAustralia’s Demand 

Management Options Consultation 

Table 2

Demand-Side Options Identified in the Drummoyne DSM Project75

DSM Options

Winter 

Peak Load 

Reduction

Total Cost to 

EnergyAustralia 

($NPV)

Cost to 

EnergyAustralia 

($/kVA)

Number of 

Customers 

Involved

Time for 

Implementation

Ice storage system 40 kVA – – 1 1 to 2 years

Power factor correction 66 kVA AUD 9,400 AUD 142 5 1 to 2 years

Residential CFL program Proposal 1 1,052 kVA AUD 180,000 AUD 171 10,000 1 to 2 years

Residential CFL program Proposal 2 1,165 kVA AUD 295,000 AUD 253 12,500 1 to 2 years

Peak load control by advanced AUD 44,000 AUD 187

control system 234 kVA to AUD 89,000 to AUD 380 3 1 to 2 years

Standby diesel generator 170 kVA AUD 67,000 AUD 394 1 1 to 2 years

Combined demand reduction projects 600 kVA AUD 238,000 AUD 398 2,226 1 to 2 years

Fixed dimming for lighting system 175 kVA AUD 87,500 AUD 500 17 1 to 2 years

Installation of Cent-a-Meter 

energy monitoring device 712 kVA AUD 706,000 AUD 992 9,410 1 to 2 years

Upgrade of lighting system 106 kVA AUD 123,700 AUD 1,166 11 1 to 2 years

Figure 6

Cost and Demand Reduction Impact of Demand-Side Options

Compared with the Value of Avoided Distribution Costs

in the Drummoyne DSM Project76

$1,000k

$900k

$800k

$700k

$600k

$500k

$400k

$300k

$200k

$100k

$0k

Value ($NPV)

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6

Demand Reduction (MVA)

DM Project Costs 

(cumulative)

Avoided Distribution 

Costs

to be cost effective. The CFL project was selected for 

implementation.

Mass distributions of CFLs to households had become 

75 EnergyAustralia, 2006

76 Ibid.
44

Effective Mechanisms to Increase the Use of Demand-Side Resources

Paper. The CFL project commenced with an advertising 

campaign in the target area that involved local municipal 

councils. Marketing activities were employed to promote 

the program, including posters sent to local businesses, 

letterbox drops, calling cards, outdoor banners, press 

advertisements, and targeted media relations.

High power factor, 15 watt CFLs were packaged in boxes 

of five for distribution to households in the target area. 

Each household was given one box of five CFLs free of 

charge. Door-to-door delivery and installation were carried 

out during specific times and days to maximise the number 

of people at home. For each box of CFLs delivered, delivery 

staff completed forms that included the householders’ 

names, addresses, and signatures, plus answers to a short 

survey. The signed forms provided verification of the 

number of boxes of CFLs distributed. For households 

where no one was home, a flyer containing project 

information and a mail order form was left at the house. A 

follow-up phone survey was conducted during the delivery 

period to assess how many CFLs were actually installed.

C. Providing Network Support Payments 

for Demand-Side Measures

i. Description

This mechanism establishes rules within an electricity 

market for:

• valuing the network benefits and services available 

from the implementation of demand-side measures; 

and

• providing a commensurate financial return to parties 

implementing demand-side measures that deliver 

defined network benefits and services.

This is a separate mechanism to bidding of demandside measures to relieve network constraints (see section 

5.B, page 41). In the bidding mechanism, payments for 

implementing demand-side measures are determined by 

the bidding process. In contrast, network support payments 

are determined through a process of valuing the benefits 

and services delivered.

ii. Implementation

There are three main types of benefits and services that 

demand-side measures may provide to electricity networks:

• reducing energy losses resulting from the transmission 

and distribution of electricity;

• deferring or avoiding augmentation or expansion of 

electricity networks;

• delivering various ancillary services, including:

• voltage regulation;

• load following;

• active/reactive power balancing;

• frequency response;

• supplemental reserve; and

• spinning reserve.

The value of each of these benefits or services to the 

network operator depends on the particular circumstances 

in which they are delivered. Consequently, determining 

values on which to base network support payments to 

parties implementing demand-side measures is complex. 

Market rules that implement network support payments 

should therefore specify the methodologies to be used for 

determining the values of the network benefits and services 

delivered by demand-side measures and for setting the 

levels of the network support payments based on these 

values.

The market rules should also specify the parties 

responsible for funding the payments. Because the 

operators of transmission and distribution networks will 

be the main beneficiaries from the implementation of 

demand-side measures, they should bear the main burden 

of making network support payments. Depending on the 

circumstances, a particular electricity generator, or even 

a large end-user, may also be a beneficiary. Where this is 

the case, the particular generator or end-user should also 

contribute a portion of the network support payments.

Finally, the market rules implementing network support 

payments should also specify how network operators may 

recover the cost of these payments. Typically this is done 

through a pass-through mechanism that allows the network 

operator to include the cost of network support payments 

in its regulated return on assets, or in its next price 

determination or rate case.

iii. Application

In the Australian National Electricity Market, network 

support payments are available to distributed generators to 

reflect the benefits they provide to the electricity network 

(see the case study on page 45).
45

Effective Mechanisms to Increase the Use of Demand-Side Resources

iv. Market Impact

Market rules that provide for network support payments 

to be made to parties that implement demand-side 

measures may contribute to increasing the integration of 

demand-side resources into electricity markets. However, 

this mechanism is not sufficient by itself to increase the use 

of demand-side resources.

v. Effectiveness

The effectiveness of this mechanism depends on 

the value ascribed to the network benefits and services 

provided by demand-side measures and the proportion 

of this value allocated to network support payments. To 

be effective, the level of the payments made will have 

to be sufficiently higher than the costs of implementing 

demand-side measures to provide a reasonable profit to the 

implementing parties.

vi. Case Study

The following case study briefly describes the rules 

governing network support payments for embedded 

generators in the Australian National Electricity Market.

In Australia, the National Electricity Market currently 

operates under a detailed set of rules called the National 

Electricity Rules.77 The Rules authorise network support 

agreements between an operator of a transmission or 

distribution network and a market participant or any other 

persons providing network support services to improve 

network capability by providing a non-network alternative 

to a network augmentation.

Generators that are connected to distribution networks 

(embedded generators) have the potential to reduce 

the long-term need for investment in transmission 

infrastructure. This is because such embedded generators 

may be able to reduce the distribution network’s need to be 

supplied from the transmission network. When a network 

support agreement is established between a network 

operator and an embedded generator, the agreement may 

include payments to the generator in recognition of the 

network support being provided by the generator.

There are currently two payments that embedded 

generators can receive:

• a network support payment directly from a 

transmission network operator for a specific service 

provided by the embedded generator to defer 

investment in the transmission network; and

• a payment from the distribution network operator 

that recognises that the embedded generator has 

enabled the distributor to avoid transmission use of 

system charges levied by the transmission network 

operator. This is paid where the embedded generator 

has reduced the demand taken by the distributor from 

the transmission system at times of peak demand. 

The National Electricity Rules require this benefit to be 

passed on to the embedded generator.

In December 2011, a change was made to the National 

Electricity Rules to place an obligation on transmission 

system operators, when negotiating a network support 

payment with an embedded generator, to take into account 

the services being provided by the generator, and the extent 

to which the generator will be compensated for those 

services by avoided transmission use of system payments.78

This clarifies that embedded generators can receive both 

payments, but should only be compensated once for each 

distinguishable benefit they provide.

77 Australian Energy Market Commission, 2011a. 

78 Australian Energy Market Commission, 2011b.
46

Effective Mechanisms to Increase the Use of Demand-Side Resources

6. Load-Targeting Mechanisms

A. Using Load Control to Address System 

Needs and Integrate Renewables

i. Description

This mechanism uses load control technology to enable 

changes in the levels of end-use customer loads:

• in response to particular events such as periods of 

high electricity prices or problems on the electricity 

network; or

• to integrate intermittent generation such as wind or 

photovoltaics into the system.

ii. Implementation

A complete load control system consists of three basic 

elements as shown in Figure 7:

• technology located at the program operator’s premises;

• communications technology; and

• technology located at the customer’s site.

There are a variety of ways in which load control systems 

can be implemented:80

• the program operator for the load control system 

may be:

• an electricity retailer or distributor;

• a market or system operator; or

• a demand response service provider.

• switching of end-use customer loads may be:

• carried out manually by the customer turning 

down or switching off appliances and equipment in 

response to a request from the program operator; 

• carried out automatically according to thresholds 

(e.g., time of day or electricity prices) pre-set by 

the customer following guidelines provided by the 

program operator; or

Figure 7

Load Control System Components79

79 Modified from Lockheed Martin Aspen, 2006. 

80 Crossley, 2008a.

Program Operator

Central Control Initiation Device

Data Receipt Device

Database

Automated QC Procedures

Communications

Wired Link

PTSN

Internet

Fibre-optic

Power line carrier

or

Wireless Link

Paging system

Radio

Mobile phone

Microwave

GPRS

Wi-Fi

Customer Site

Communications Device

Control Device

Switch

Thermostat

Demand controller

Measurement Device

Information Display Service
47

Effective Mechanisms to Increase the Use of Demand-Side Resources

81 The signal may be sent manually by the program operator or 

automatically in response to trigger events such as exceedances of pre-set electricity price levels or pre-set load levels 

on particular network elements, or excursions outside pre-set 

frequency or voltage parameters.

82 Crossley, 2008a. 

83 This case study is taken from Crossley, 2008b.

84 Long Island Power Authority, 2002.

• initiated remotely by a signal sent from the program 

operator81 through direct communication links 

to the customers’ electrical equipment; a second 

signal is sent to restore normal operation at the 

conclusion of a program event.

• switching of loads may involve:

• cycling loads on and off according to pre-set timing 

schedules;

• reducing or increasing loads to pre-set levels; or

• switching off loads completely.

The particular way in which a load control system is 

implemented and operated will be driven by the objective 

to be achieved. In general, automated and remote switching 

of appliances and equipment are the most effective methods 

of operation, because they require only one “set and 

forget”decision by end-use customers.82

iii. Application

Load control systems are currently being implemented 

by a range of program operators in many countries around 

the world.

iv. Market Impact

Load control systems actively enable increased use of 

demand-side resources in the electricity sectors. It is likely 

that such systems will increasingly be deployed to address 

peak load problems on electricity networks and to integrate 

intermittent generation into the system.

v. Effectiveness

The effectiveness of this mechanism in achieving 

increased use of demand-side resources depends on 

the level of take-up of load control systems by end-use 

customers. Take-up can be increased by targeted marketing 

and communication to end-use customers by load control 

program operators.

vi. Case Study83

The following case study describes the LIPAedge 

program developed by Long Island Power Authority (LIPA) 

in the United States to use central control of residential and 

small commercial air-conditioning thermostats to achieve 

peak load reduction.

The LIPAedge program is based on the programmable 

ComfortChoice thermostat (see Figure 8). The system 

operator uses an internet-based system to control a demandside resource comprising approximately 20,000 thermostatcontrolled air conditioners. Skytel two-way pagers are used 

to transmit a curtailment order to the thermostat and to 

receive acknowledgment and monitoring information. One 

or more pager signals are generated and transferred to the 

SkyTel pager network (see Figure 9, page 48).

Commands go via satellite to pager towers, where they 

are broadcast to the thermostats. The thermostats take 

immediate action or adjust their schedules for future action, 

depending on what the system operator ordered. The 

thermostats log the order and respond via pager, enabling 

LIPA to monitor the response to the event. The thermostats 

also collect data every minute on temperature, set point, and 

power consumption (hourly duty cycle). They retain this 

information as hourly averages and report it to the utility. 

The thermostat itself holds seven days of hourly data.

Figure 8

ComfortChoice Thermostat 

Used in the LIPAedge Program84

Seven-day programming

Four periods per day

Two-way 

communications

Curtailment override
48

Effective Mechanisms to Increase the Use of Demand-Side Resources

For a summer load curtailment, the system operator 

might send a command at 9:00 am directing all thermostats 

to move their set points up four degrees, starting at 2:00 

pm and ending at 6:00 pm. Alternatively, the system 

operator could send a command directing all thermostats 

to completely curtail immediately. The command would 

be received and acted upon by all loads, providing full 

response within approximately 90 seconds. This is far 

faster than generator response, which typically requires a 

10-minute ramp time.

Thermostats can be addressed individually, in groups, or 

in total. This important advantage provides both flexibility 

and speed. System operator commands that are addressed 

to the entire resource are implemented through a single 

page that all thermostats receive. Similarly, 15 subgroups 

can be addressed if response is required in a specific area 

to alleviate a transmission constraint. Thermostats can be 

addressed individually as well. This capability is useful for 

monitoring the performance of the system (each thermostat 

is checked weekly for a “heartbeat”).

The customer also receives benefits. The thermostat is 

fully programmable and remotely accessible, with all of the 

associated energy savings and convenience benefits. A webbased remote interface is provided for customer interaction. 

Customers can also override curtailment events. This feature 

appears to be important to gain customer acceptance and it 

probably increases the reliability of the response.

Two-way paging communication enables the utility to 

monitor load performance both during response events and 

under normal conditions. Response from the thermostats 

is staggered over a time period set by the utility to avoid 

overwhelming the paging system. It typically requires 

90 minutes for 20,000 thermostats to respond. Thus the 

system provides for performance monitoring but not in the 

Figure 9

The Carrier/Silicon Energy Direct Load Control System for the LIPAedge Program 85

85 Long Island Power Authority, 2002.
49

Effective Mechanisms to Increase the Use of Demand-Side Resources

2- to 8-second intervals typical for large generators.

The LIPAedge program is available for Residential 

Central Air Conditioning customers and Small Business 

customers, although the program is now closed to new 

participants. Customers who sign up to the LIPAedge 

program receive a ComfortChoice thermostat and 

installation free of charge. Customers also receive a onetime bonus payment of USD 25 (residential customers) or 

USD 50 (small commercial customers).

LIPAedge customers agree to have their central air conditioning system adjusted between the hours of 2 pm and 6 

pm for a maximum of seven days throughout the four-month 

summer season. Customers have access to a dedicated web 

page for their thermostat and are able to remotely change the 

set point of their air conditioner whenever they want.

LIPA initiates curtailment events by either increasing the 

set point on LIPAedge thermostats by 3 to 4 degrees, or by 

cycling air conditioner compressors off for a portion of each 

hour.

Customers can override curtailment messages sent to 

their thermostat, although LIPA encourages its customers 

not to override during a curtailment event. If the customer 

decides to override the curtailment, the change is recorded 

by the thermostat and a wireless message is then sent back 

to the central server.

LIPA collected name-plate power consumption 

information on the air-conditioning equipment being 

controlled when it installed the ComfortChoice thermostats 

for the LIPAedge program. It also directly measured the 

power consumption of a subset of those loads to estimate 

the actual load of the aggregation. LIPA determined that 

the average capacity of residential air-conditioning units 

being controlled was 3.84 kW, whereas the average capacity 

of small commercial units was 6.38 kW. The total 23,400 

individual loads had a peak capacity of 97.4 MW if all the 

units were on at 100 percent duty cycle.

LIPA monitored the performance of 400 units from 

1 May 2002 through 29 September 2002. Hourly 

data were collected from each unit for duty cycle and 

facility temperature. Those data were used to estimate 

the performance of all 23,400 responsive loads. LIPA 

found that each controlled load provided an average of 

1.06 kW of demand reduction (1.03 kW per residential 

air-conditioner and 1.35 kW per small commercial airconditioner). LIPA expected 24.9 MW of peak reduction 

response from the full 23,400 controlled air-conditioners.

B. Implementing Load Scheduling to 

Time-Target End-User Loads

i. Description

This mechanism establishes contractual arrangements 

that enable system operators to request specified changes 

in end-user load levels at times when doing so delivers 

benefits or services to the system.

This is a type of short-term demand response; typically 

system operators request changes in end-user load levels 

for periods lasting from one to several hours.

The effect of this mechanism is very similar to some 

types of demand-side bidding (DSB) into electricity 

markets (see section 5.A, page 37), but the method of 

implementation is quite different. In DSB, scheduling 

of demand-side measures is determined by the bidding 

process. In contrast, in load scheduling the system operator 

directly requests the owners or aggregators of the loads 

involved to implement changes in load levels.

ii. Implementation

Load scheduling is implemented by the system operator 

establishing contractual arrangements directly with the 

owners or aggregators of the loads involved. Typically, the 

terms of the contract include:

• the minimum size of loads that will be accepted under 

the contractual arrangements;

• technical requirements for switching and monitoring 

the levels of loads under contract;

• the circumstances in which the system operator may 

request changes in load levels;

• the minimum and maximum notice periods provided 

by the system operator before requested load level 

changes are required to be delivered; and

• the remuneration paid by the system operator to the 

owners or aggregators of contracted loads.

iii. Application

This mechanism is an updated version of interruptibility 

contracts that many electricity providers used to have with 

end-use customers before the introduction of competitive 

electricity markets. Implementation of this newer form of 

interruptibility as contractual arrangements between system 

operators and end-users is not widespread.
50

Effective Mechanisms to Increase the Use of Demand-Side Resources

iv. Market Impact

This mechanism directly facilitates the integration of 

demand-side resources, in the form of short-term demand 

response, into electricity markets.

v. Effectiveness

The effectiveness of this mechanism in achieving 

increased use of demand-side resources depends on:

• the level of interest among system operators in 

establishing contractual arrangements directly with 

end-users and aggregators; and

• the take-up rate of the contractual arrangements by 

end-use customers.

Given the load switching and load monitoring required, 

end-users will require technical assistance in evaluating and 

making a decision about any load scheduling proposals.

vi. Case Study86

The following case study describes the load scheduling 

activities of the Business Energy Coalition (BEC) in 

California.

The BEC is a project between Pacific Gas and Electric 

Company (PG&E), major businesses, and civic leaders. 

Facilitated by The Energy Coalition, the BEC is designed 

to address the specific business challenges regarding load 

reductions during critical peak hours. Working closely with 

its members individually and as a group, the BEC develops 

and implements effective load curtailment strategies for 

periods of high demand.

The BEC targets large end-use customers with roughly 

1000 kW or more of peak demand who are able to drop 

10 to 15 percent of their peak load during curtailment 

events. Commercial properties that have not historically 

participated in any demand response program before are 

targeted, such as Class “A” high-rise office buildings and 

premier hotels. The BEC works with end-users to develop 

a set of realistic load curtailment protocols that are based 

on individual site characteristics. Should one site fail to 

meet an individual goal on a particular day, other group 

members stand ready to step-up their own contributions to 

meet the group goal.

In 2005, the BEC enrolled 32 PG&E customers who 

agreed to deliver, as a group, 10 MW of electrical load 

reduction during peak hours. These charter members 

easily surpassed their group goal. In 2006, the group was 

expanded to include an additional 30+ new members, who 

delivered more than 15 MW of peak reduction. By 2008, 

the BEC had enrolled over 130 members with a group goal 

of delivering up to 50 MW of demand response electrical 

reduction capacity.

BEC members receive a comprehensive demand 

response assessment by leading engineering experts, 

advanced real-time metering equipment, and a specialised 

web-based load monitoring software system. Load 

reduction is achieved through a customised step-by-step 

curtailment protocol for each facility.

A load curtailment may be requested by PG&E in 

response to the following Program Triggers:

• the California Independent System Operator (CAISO) 

declares – or PG&E expects the CAISO to declare – a 

Stage 1 or higher emergency;

• the CAISO forecasts – or PG&E expects CAISO to 

forecast – a system load to meet or exceed 43,000 

MW; and

• the CAISO or PG&E foresee or declare a localised 

system emergency, including high temperature 

forecasts and loss of generation or transmission 

resources. In this case, PG&E may call an event for 

a particular BEC participant group, as defined by 

PG&E’s transmission planning areas.

Curtailment events are limited to five hours per event 

and five curtailments per month.

BEC members receive incentive payments of up to 

USD 75/kW of contracted load reduction annually with no 

non-performance penalties. The actual incentive payment 

received is based on a member’s hourly performance over 

the course of the curtailment season.

C. Operating Energy Storage to 

Time-Target Changes in System Load

i. Description

This mechanism uses energy storage technology to 

convert grid-connected electricity into another form of 

energy, hold it for later use, and when required at a future 

time, release the stored energy as electricity or as another 

useful form of energy.

86 This case study is taken from The Energy Coalition website 

at www.energycoalition.org/BEC/
51

Effective Mechanisms to Increase the Use of Demand-Side Resources

Just as transmission and distribution systems move 

electricity over distances to end-users, energy storage 

systems can move electricity through time, providing it 

when and where it is needed.87 Energy storage systems can 

help balance variable renewable generation and, properly 

deployed and integrated, can help increase the reliability of 

the electricity network.

Storage applications differ from other distributed energy 

resource options, such as distributed generation or energy 

efficiency, in three key respects:88

• they do not have a typical operating profile or load 

shape that can be applied prospectively;

• they are “limited energy” resources with a narrow 

band of dispatch and operation; and

• they can participate in multiple wholesale electricity 

markets and provide several benefits simultaneously 

to the wholesale system, electricity distributors, and 

end-use customers.

ii. Implementation

A range of technologies are available for energy storage, 

as shown in Figure 10.

Energy storage technology can be used in a number 

Figure 10

Technology Options for Energy Storage 89

Pumped Hydro

Stationary Battery

Compressed Air

Mobile Batteries

Flywheels

Water Heaters

of different ways. Table 3 (page 52) shows ten major 

applications for energy storage identified in an EPRI study.

Energy storage may be used by both end-use customers 

and system operators.

Customers can use energy storage as a price hedging 

mechanism that stores electricity generation output when 

electricity prices are low and releases useful energy when 

prices are high. Storage electric water heaters are an 

example of this use of energy storage technology.

System operators can use energy storage in three main 

ways:

• to reduce peak loads on the network and particularly 

to integrate intermittent generation such as wind or 

photovoltaics into the system;

• to provide a capacity reserve that can be made 

available at short notice; and

• to provide a variety of ancillary services.

87 Electric Power Research Institute, 2010. 

88 Electric Power Research Institute, 2010.

89 Cowart, 2011. 
52

Effective Mechanisms to Increase the Use of Demand-Side Resources

To use an energy storage facility effectively, system 

operators must be able to both direct generation output 

into storage and dispatch the release of electrical energy 

from storage. This will require the establishment of 

contractual arrangements between the system operator and 

energy storage providers.

The terms of an energy storage contract should include:

• technical requirements for accessing and monitoring 

the energy storage facility under contract;

• the circumstances in which the system operator may 

direct generation output into storage and dispatch the 

release of electrical energy from storage; and

• the remuneration paid by the system operator to the 

energy storage provider.

Table 3

Definition of Energy Storage Applications 90

Generation and 

System-Level 

Applications

T&D System 

Applications

End-User 

Applications

Value Chain Application Description

1

2

3

4

5

6

7

8

9

10

Wholesale Energy 

Services

Renewables 

Integration

Stationary Storage 

for T&D Support

Transportable Storage 

for T&D Support

Distributed Energy 

Storage Systems

ESCO Aggregated 

Systems

C&I Power Quality 

and Reliability

C&I Energy Management

Home Energy Management

Home Backup

Utility-scale storage systems for bidding into energy, capacity, and ancillary 

services markets

Utility-scale storage providing renewables time shifting, load and ancillary 

services for grid integration

Systems for T&D system support, improving T&D system utilisation factor, 

and T&D capital deferral

Transportable storage systems for T&D system support and T&D deferral at 

multiple sites as needed

Centrally managed modular systems providing increased customer reliability, 

grid T&D support, and potentially ancillary services

Residential-customer-sited storage aggregated and centrally managed to provide 

distribution system benefits

Systems to provide power quality and reliability to commercial and industrial 

customers

Systems to reduce TOU energy charges and demand charges for C&I customers

Systems to shift retail load to reduce TOU energy and demand charges

Systems for backup power for home offices with high reliability value

T&D = Transmission and Distribution; C&I = Commercial and Industrial; ESCO = Energy Services Company; TOU = Time of Use

iii. Application

On a worldwide basis, 125.5 GW of energy storage has 

been installed, the overwhelming majority being pumped 

storage technology (see Figure 11, page 53).

iv. Market Impact

Energy storage provides a technology whereby demandside resources, particularly distributed generation, can 

be integrated into electricity markets. Energy storage is 

typically used by system operators to enable the integration 

of intermittent distributed generation such as wind and 

photovoltaics and to provide a range of ancillary services.

90 Electric Power Research Institute, 2010.
53

Effective Mechanisms to Increase the Use of Demand-Side Resources

In 2009, A123 Systems and 

AES Energy Storage began 

commercial operation of a 12 MW 

lithium-ion battery energy storage 

system installed at AES Gener’s 

Los Andes substation in the 

Atacama Desert in northern Chile. 

The system delivers Capacity 

Release for Power Generators, a 

service developed by AES Energy 

Storage to enable a batterybased installation to meet system 

obligations for spinning reserve, 

allowing power generators 

to produce and sell power 

previously required to be held in 

reserve. It continuously monitors 

the condition of the power system, and if a significant 

frequency deviation occurs (e.g., the loss of a generator or 

transmission line), the energy storage system can provide 

up to 12 megawatts of power nearly instantaneously. This 

output is designed to be maintained for 15 minutes at full 

power, allowing the system operator to resolve the event or 

bring other standby units online.93

The project helps the system operator manage 

fluctuations in demand, delivering frequency regulation 

in a less expensive, more responsive, and more accurate 

manner than traditional methods. In addition, because 

the project replaces unpaid reserve from the power plant, 

AES Gener receives payment for its full output capacity by 

selling directly to the electric grid.94

Performing continuously for more than 18 months as a 

critical reserve unit for Chile’s Northern Grid, the project 

is the only reserve unit that has responded to all generatorassisted fault restorations since January 2010. During this 

time it has demonstrated a response speed consistently 

higher than other units, while continuously overachieving 

in delivering the committed level of response. In addition 

to fast and accurate response times benefitting the grid, 

91 Cowart, 2011.

92 Electric Power Research Institute, 2010.

93 Wesoff, 2012. 

94 AES Energy Storage, 2012a.

v. Effectiveness

Energy storage can be a highly effective mechanism 

to integrate intermittent distributed generation into the 

system. In particular, the use of energy storage can mitigate 

or avoid a requirement to spill intermittent generation 

when the system is overloaded or there is insufficient 

demand on the system.

vi. Case Study

This case study describes two projects in northern Chile 

that use energy storage technology to provide the ancillary 

services frequency regulation and spinning reserve.

Figure 11

Total Worldwide Installed Energy Storage91

Figure 12

A 12 MW Lithium-ion Battery Frequency

Regulation and Spinning Reserve Project 

in Northern Chile92

Pumped Hydro:

123,390 MW

Flywheel & Other:

95 MW

Molten Salt: 142 MW

Batteries:

451 MW

Compressed 

Air:

440 MW

Thermal:

1,002 MW

Total: 125,520 MW

Total Minus Pumped Hydro: 2,129 MW
54

Effective Mechanisms to Increase the Use of Demand-Side Resources

the project has allowed AES Gener to increase power 

generation from its Norgener plant by four percent.95

In May 2011, AES Gener and AES Energy Storage began 

construction on another 20 MW project in northern Chile 

that will deliver the same service. Located near a new 

thermal power plant, the system will increase AES Gener’s 

storage capacity from 12 MW to 32 MW and allow the 

plant to more effectively use its generating capability while 

still providing critical spinning reserve services to the 

northern grid.

D. Implementing Geographic Targeting 

of Demand-Side Measures

i. Description

This mechanism establishes processes for targeting the 

implementation of demand-side measures to particular 

geographic areas or localities where they will be most 

effective in relieving network constraints.

This mechanism is similar to bidding of demandside measures to relieve network constraints (see section 

5.B, page 40), except that this mechanism is focussed 

on delivering the results of implementing demand-side 

measures to targeted geographic localities.

ii. Implementation

Geographic targeting is typically implemented through a 

five-stage process:

• the network operator identifies a network constraint 

in a particular geographic location that may be 

addressable through demand-side measures;

• the network operator characterises the constraint and 

carries out a preliminary assessment of the potential 

for demand-side measures to address the constraint;

• the network operator publishes the information it has 

assembled on the network constraints and possible 

demand-side measures and issues a Request for 

Proposals to potential implementors of demand-side 

projects;

• project implementors submit proposals to the 

network operator; and

• the network operator selects cost-effective projects for 

implementation.

iii. Application

Geographic targeting of demand-side measures is 

implemented extensively by electricity distributors in the 

state of New South Wales in Australia where it is routinely 

used in small-scale demand-side management projects 

targeted at a particular network element (e.g., a substation 

or an individual distribution feeder). Geographic targeting 

has also been used on similar small scales in a few localities 

in the United Kingdom and the United States. Larger scale 

geographic targeting was used in the Provence-Alpes-Côte 

d’Azur (PACA) region of France (see the case study below).

iv. Market Impact

Geographic targeting establishes a market for demandside resources, although opportunities to implement 

demand-side measures are limited to areas or locations 

where network constraints have been identified.

v. Effectiveness

The effectiveness of this mechanism depends on 

the identification of opportunities to use demand-side 

measures to relieve network constraints and the willingness 

of network operators to consider implementing demandside measures as alternatives to network augmentation or 

expansion.

vi. Case Study 96

This case study describes geographic targeting 

of demand-side measures to address overloading of 

transmission lines in the Provence-Alpes-Côte d’Azur 

(PACA) region of France.

The PACA region is supplied from Tavel near Avignon, 

via two 400 kV transmission lines – a southern line that 

goes to Broc Carros via Néoules and a northern line that 

goes as far as Boutre. A 225 kV line completes the ring by 

connecting Boutre to Broc-Carros (see Figure 13, page 55).

Planning for the upgrading of the Boutre-Carros line 

to supply increasing load growth in the area commenced 

in 1983. The initial plan comprised double 400 kV lines 

on separate easements over 170 km in length. Six route 

options for the upgraded line were proposed. However, 

there was strong opposition to this project because the 

95 AES Energy Storage, 2012b. 

96 This case study is taken from Crossley, 2008b.
55

Effective Mechanisms to Increase the Use of Demand-Side Resources

the capacity of the existing 250 kV line.

The Eco-Energy Plan comprised a very large 

integrated DSM project (including distributed 

generation). At the time, it was the largest DSM 

project in the European Union and possibly the 

world. It had three main objectives:

• to increase the efficiency of electricity 

usage and to create a critical mass of 

scientific and technological competence 

in relation to electricity DSM;

• to modify the electricity-using behaviour 

of consumers, and building owners and 

managers; and

• to contribute to the development of local 

renewable energies and to establish a 

solid basis for future energy choices.

The following description is based on 

the analysis and program design developed 

following the initial decision in 2000. Following the refusal 

of planning permission in 2006, the DSM program was 

strengthened to meet the new constraints.

Preliminary studies were carried out in 2001:

• to quantify the level of load reduction required, after 

the scheduled completion of the new 400 kV line in 

2005, to avoid network constraints in the period to 

2020;

• to understand the evolution and structure of peak 

demand in the eastern part of the PACA region;

• to quantify the potential load reductions achievable 

through implementing DSM and distributed 

generation; and

• to identify a detailed program of DSM and distributed 

generation measures.

Figure 14 (page 56) shows that, following the scheduled 

completion of the new 400 kV line in 2005, with a fault 

level of n-1 (involving the loss of one line or substation) 

capacity constraints were likely to reappear in the winter 

of 2018. To avoid a further new line being required before 

2020, the Eco-Energy Plan would have to reduce load by 

35 MW in winter.

lines would pass through the classified scenic gorges of the 

Verdon Regional Park.

In 1994, a petition against all the route options collected 

3,000 signatures. In January 1997, a seventh route option 

was proposed. In July and August, a petition was circulated 

supported by local governments in the area. The petition 

requested studies of alternatives to the line and 23,000 

signatures were obtained, including 12 percent of tourists 

in the European Union. In November, the Department 

of the Environment established a public commission of 

inquiry into the Boutres-Carros line and the project was 

suspended.

In 2000, a decision was made on an alternative solution. 

This comprised:

• replacement of the existing 225 kV line by a single 

400 kV line, 100 km in length, on the same easement;

• removal of an existing 150 kV line, which 

accompanied the 225 kV line; and

• implementation of an ambitious DSM and renewable 

energy distributed generation program called the 

“Eco-Energy Plan” to slow down the growth in 

demand.

In May 2006, the state court, after a complaint from an 

environmental group, refused planning permission for the 

upgrading of the Boutre-Carros line. Following the court 

decision, the Eco Energy Plan program was the only way to 

secure supply to this region by keeping load growth within 

Figure 13

High Voltage Transmission Lines in the Eastern Part

of the Provence-Alpes-Côte d’Azur Region of France97

97 Harinck and Combes (2003)
56

Effective Mechanisms to Increase the Use of Demand-Side Resources

Figure 15 shows that with a fault 

level of n-2 (involving the loss of 

two lines or substations), capacity 

constraints were likely to reappear 

in the summer of 2016. An n-2 fault 

level is possible in summer because 

of the risk of forest fires under the 

southern double circuit 400 kV line. 

To avoid a further new line being 

required before 2020, the EcoEnergy Plan would have to reduce 

load by 130 MW in summer.

Figure 16 and Figure 17 show 

the end-use composition of peak 

demand in the region in winter and 

summer. In winter, peak demand is 

dominated by lighting and heating, 

and in summer, air conditioning 

is dominant with lighting also an 

important contributor to the peak.

Figure 18 (page 57) shows 

forecasts of the potential load 

reductions achievable through the 

Eco-Energy Plan by implementing 

DSM and distributed generation 

over the period 2005 to 2020.

Figure 14

Capacity Constraints in Winter with Fault Level n-1 Following 

Scheduled Completion of the New 400-kV Line in 200598

Figure 15

Capacity Constraints in Summer with Fault Level n-2 Following 

Scheduled Completion of the New 400-kV Line in 200599

Figure 16

Winter Peak Demand by End-Use in the Eastern 

Part of the Provence-Alpes-Côte d’Azur Region100

Figure 17

Summer Peak Demand by End-Use in the Eastern 

Part of the Provence-Alpes-Côte d’Azur Region101

40 MW

35 MW

30 MW

25 MW

20 MW

15 MW

10 MW

5 MW

0 MW

140 MW

120 MW

100 MW

80 MW

60 MW

40 MW

20 MW

0 MW

2005

2005

2006

2006

2007

2007

2008

2008

2009

2009

2010

2010

2011

2011

2012

2012

2013

2013

2014

2014

2015

2015

2016

2016

2017

2017

2018

2018

2019

2019

2020

2020

Var est

Var est

Alpes-M. ouest

Alpes-M. ouest

Alpes-M. est

Déficit Déficit

Others (Monaco): 5%

Others (Monaco): 11%

Cooling: 11%

Losses: 4%

Losses: 4%

Cool Appliances: 5%

Appliances: 7%

Cooking: 7% Appliances: 10%

Cooking: 3%

Heating: 25%

Holiday Homes: 3%

Holiday Homes: 3%

Electronic: 4%

Electronic: 3%

Motors & Industrial 

Process: 8%

Motors & Industrial Process: 9%

Domestic 

Hot Water: 4%

Domestic Hot Water: 3%

Lighting: 28%

Lighting: 11%

Air Conditioning: 32%

98 Harinck and Combes, 2003

99 Ibid.

100 Rosenstein, 2004

101 Ibid.
57

Effective Mechanisms to Increase the Use of Demand-Side Resources

Figure 18

Forecasts of Potential Load Reductions

Achievable through the Eco-Energy Plan 

2005 to 2020102

Figure 19

Forecasts of Potential Load Reductions

Achievable through the Eco-Energy Plan 

in Winter 2006103

Table 4

Forecast Impacts and Costs of Identified DSM Measures to be Implemented 

Through the Eco-Energy Plan104

250 MWe

200 MWe

150 MWe

100 MWe

50 MWe

0 MWe

Winter

Summer

2005

5 MWe 10 MWe 15 MWe 20 MWe

2010 2020

Hydro

Biogas

Photovoltaic

Wind

Combustion

Greenhouses

Education

Offices

Residential

Health

Winter

45 MWe

Communication and information campaigns

Increasing awareness and training of engineering departments and 

installers

Demonstration energy management projects in State and local 

authorities, EDF and ADEME

Specific measures for new residential and commercial buildings

Large-scale dissemination of CFLs in social sector

Promotion of efficient lighting in commercial sector

Promotion of CFLs and energy efficient white goods

Energy efficient retrofitting in residential and commercial sectors

Energy efficient retrofitting in tourism sector

Domestic hot water

Wood heating

Specific measures for large industrial and commercial consumers

Cogeneration, biogas, hydro installations

Photovoltaic installations

Evaluation

Total

 2.9

3.6

26 5.5 52.5 4.6

1.2 0.1 2.5 7.6

2.3 0.5 6 2

24 12 72 1.8

57 8 115 3.6

41 11.5 125 9.1

3 2.3 9 2.6

 15 5 3.3

8 7 2.1

16.5 11 2.3

45 23 3

0 0.3 0.9

 3

224 89.2 394 52.4

Impact on 

Winter Peak 

(MW)

Impact on 

Summer Peak 

(MW)

Impact on 

Consumption 

(GWh)

Public 

Funding 

(M€)
58

Effective Mechanisms to Increase the Use of Demand-Side Resources

Figure 19 (page 57) shows a breakdown of the forecast 

load reductions achievable in winter 2006. Based on these 

forecasts, the target load reduction to be achieved through 

the Eco-Energy Plan in winter 2006 was set at 45 MW.

The Eco-Energy Plan was launched in March 2003. 

Initially six priority areas were identified:

• communication and information;

• new building construction;

• efficient lighting and domestic electrical appliances;

• large consumers and distributed generation;

• demonstration projects by the Eco-Energy Plan 

institutional partners; and

• public housing.

In 2004, a further two priority areas were added:

• existing buildings; and

• tourism.

Table 4 (page 57) shows the forecast impacts and costs 

of the identified DSM measures to be implemented through 

the Eco-Energy Plan

102 Harinck and Combes, 2003

103 Ibid.

104 Rosenstein, 2004
59

Effective Mechanisms to Increase the Use of Demand-Side Resources

7. Conclusion

The aim of this paper is to provide information 

about how to increase the use of demand-side 

resources in the electricity sector where these 

resources are cost-effective and appropriate.

The paper has described 14 of the most effective 

mechanisms for increasing the use of demand-side 

resources. Some of these mechanisms aim at integrating 

demand-side resources into electricity markets. Others aim 

at increasing the role of demand-side resources in system 

operations and planning processes.

The relative effectiveness of these mechanisms in any 

particular region or country will depend on the structure of 

the electricity sector, and the regulatory regime and system 

planning processes in place. It is therefore important to 

take these factors into account when planning the use of 

any of the mechanisms described in the paper.
60

Effective Mechanisms to Increase the Use of Demand-Side Resources

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