21stCenturyPower.org Technical Report

NREL/TP-6A20-57477

October 2013

Contract No. DE-AC36-08GO28308

Market Evolution: 

Wholesale Electricity 

Market Design for 21st Century 

Power Systems

Jaquelin Cochran, Mackay Miller, Michael Milligan, Erik Ela, 

Douglas Arent, and Aaron Bloom

National Renewable Energy Laboratory

Matthew Futch 

IBM

Juha Kiviluoma and Hannele Holtinnen 

VTT Technical Research Centre of Finland

Antje Orths 

Energinet.dk 

Emilio Gómez-Lázaro and Sergio Martín-Martínez 

Universidad de Castilla La Mancha

Steven Kukoda and Glycon Garcia

International Copper Association

Kim Møller Mikkelsen

Global Green Growth Institute (GGGI)

Zhao Yongqiang and Kaare Sandholt 

China National Renewable Energy Center
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

21stCenturyPower.org

Market Evolution: 

Wholesale Electricity 

Market Design for 21st Century 

Power Systems 

Jaquelin Cochran, Mackay Miller, Michael Milligan, Erik Ela, 

Douglas Arent, and Aaron Bloom

National Renewable Energy Laboratory

Matthew Futch 

IBM

Juha Kiviluoma and Hannele Holtinnen 

VTT Technical Research Centre of Finland

Antje Orths 

Energinet.dk 

Emilio Gómez-Lázaro and Sergio Martín-Martínez 

Universidad de Castilla La Mancha

Steven Kukoda and Glycon Garcia

International Copper Association

Kim Møller Mikkelsen

Global Green Growth Institute 

Zhao Yongqiang and Kaare Sandholt 

China National Renewable Energy Center

Produced under the guidance of the Department of Energy and 

the Clean Energy Ministerial by the National Renewable Energy 

Laboratory under Interagency Agreement S-OES-12-IA-0010 

and Task Number WFH1.2010

Technical Report

NREL/TP-6A20-57477

October 2013

Contract No. DE-AC36-08GO28308
NOTICE

This manuscript has been authored by employees of the Alliance for Sustainable Energy, LLC (“Alliance”) 

under Contract No. DE-AC36-08GO28308 with the U.S. Department of Energy (“DOE”).

This report was prepared as an account of work sponsored by an agency of the United States 

government. Neither the United States government nor any agency thereof, nor any of their employees, 

makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, 

completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents 

that its use would not infringe privately owned rights. Reference herein to any specific commercial 

product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily 

constitute or imply its endorsement, recommendation, or favoring by the United States government or any 

agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect 

those of the United States government or any agency thereof.

Printed on paper containing at least 50% wastepaper, including 10% post consumer waste.
iii

Abstract

Demand for affordable, reliable, domestically sourced, and low-carbon electricity is on the rise. 

This growing demand is driven in part by evolving public policy priorities, especially reducing 

the health and environmental impacts of electricity service and expanding energy access to 

underserved customers. Consequently, variable renewable energy resources comprise an 

increasing share of electricity generation globally. At the same time, new opportunities for 

addressing the variability of renewables are being strengthened through advances in smart grids, 

communications, and technologies that enable dispatchable demand response and distributed 

generation to extend to the mass market. A key challenge of merging these opportunities is 

market design—determining how to create incentives and compensate providers justly for 

attributes and performance that ensure a reliable and secure gridin a context that fully realizes 

the potential of a broad array of sources of flexibility in both the wholesale power and retail 

markets. 

This report reviews the suite of wholesale power market designs in use and under consideration 

to ensure adequacy, security, and flexibility in a landscape of significant variable renewable 

energy. It also examines considerations needed to ensure that wholesale market designs are 

inclusive of emerging technologies, such as demand response, distributed generation, and 

distributed storage. The report concludes with a review of potential areas for future research on 

wholesale power markets. 

Well-designed markets encourage economically efficient solutions, promote innovation, and 

minimize unintended consequences. Yet, many uncertainties remain about how to achieve these 

aims in power markets, given the need to accommodate contextual constraints and effectively 

invite and sustain capital investments. There is an acute need for international collaboration on 

wholesale market design questions. The 21st Century Power Partnership aims to provide a 

platform for collaborative analysis, and the authors of this report sincerely hope that it lays the 

groundwork for future collaboration.

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
iv

Acknowledgments

The authors are greatly indebted to the many reviewers of this study, including Sam Baldwin and 

Matthew Wittenstein (U.S. Department of Energy); José María Valenzuela (Secreteriat of 

Energy in Mexico); Myung Kyoon Lee and Rene Karottki (Global Green Growth Institute); 

Gordon Feller (Cisco); Morgan Bazilian (Joint Institute for Strategic Energy Analysis); and 

Jeffrey Logan, Karlynn Cory, Tom Schneider, Robin Newmark, Lori Bird, David Kline, Trieu 

Mai, Scott Gossett, and Mike Meshek (National Renewable Energy Laboratory). 

The authors also wish to acknowledge the Ministerio de Economía y Competitividad ENE2012-

34603 project, co-financed with European Union FEDER funds and the Spanish Wind Energy 

Association (Mr. Alberto Ceña).

List of Acronyms

CAISO California Independent System Operator

CFE Comisión Federal de Electricidad

DSO distribution system operator

ELCC effective load-carrying capability

ERCOT Electric Reliability Council of Texas

EU European Union 

FERC Federal Energy Regulatory Commission

ISO independent system operator 

ISO-NE ISO New England 

LMP locational marginal price

LOLP loss of load probability 

LSE load-serving entity

MISO Midcontinent Independent System Operator

NERC North American Electric Reliability Corporation

NREL National Renewable Energy Laboratory

PJM PJM Interconnection

PV photovoltaic 

RAP Regulatory Assistance Project

RTO regional transmission organization 

TSO transmission system operator 

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v 

Executive Summary

Wholesale electricity market designs represent both a challenge and an opportunity for realizing 

21st century power systems, in which variable renewable energy and emerging technologies such 

as smart grids, demand response, distributed generation, and distributed storage, are tightly 

integrated into power system operations. Wholesale electricity markets in restructured, 

competitive markets serve two roles: they define the security-constrained, merit-order dispatch 

that ensures short-term reliability, and they define the financial incentives and rules of eligibility 

for investment in resources that ensure long-term reliability. The continuing evolution of policy 

objectives and emergence of new technologies is dramatically changing the nature of wholesale 

market design. Fortunately, learning and expertise accumulated over recent history provides an 

indication of how electricity market design might evolve. This report summarizes the key issues 

and evolving approaches in the field, and looks ahead to the research areas and collaborations 

that will support further advances. 

Toward 21st Century Power Systems

Demand for affordable, reliable, domestically sourced, and low-carbon electricity is on the rise. 

This growing demand is driven in part by evolving public policy priorities, especially of 

reducing the health and environmental impacts of electricity service and expanding energy 

access to underserved customers. Consequently, variable renewable energy resources comprise 

an increasing share of electricity generation globally. Expanding the grid penetration of 

resources with variable output requires more nimble power systems that can adjust quickly to 

balance supply and demand. At the same time, new opportunities for addressing the variability of 

renewables are being strengthened through advances in smart grids, communications, and 

technologies that enable dispatchable demand and distributed generation to extend to the mass 

market. Figure ES-1 illustrates the range of dynamic interactions that might characterize 21st

century power systems. 

Figure ES-1. Illustrative view of 21st century power systems. NREL

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vi 

Wholesale Market Design Principles for Integrating Variable 

Renewable Energy

Broadly speaking, there are three paradigms in use around the world to organize electricity 

delivery. In some regions utilities operate under the traditional vertically integrated utility 

modelthe first paradigm. In these regions, most or all assets are owned and operated by a 

single entity, and costs are recovered through a regulated rate of return. In other regions, 

representing the focus of this paperthe second and third paradigmsthe main segments of 

integrated utilities (generation, transmission, and distribution) are “unbundled.” The transmission 

network typically remains regulated, while generation activities (and sometimes retail 

distribution activities) are opened to competition. Energy is then transacted in a wholesale power 

market. In the second paradigm, long-term adequacy is addressed through the energy market (socalled “energy-only” markets). In the third paradigm, there is an additional revenue mechanism 

to reward generators for their availability, regardless of actual generation (so-called “energy plus 

capacity” markets). 

Policy debates in Europe currently focus on whether to transition to an energy plus capacity 

paradigm, since significant thermal generation risks becoming uneconomical in the next 20 

years. In many rapidly developing economies, policy debates center on whether and how to 

move from a vertically-integrated paradigm to an energy-only or energy plus capacity paradigm 

in order to better meet rapidly growing demand, improve reliability, achieve better economic 

efficiency, and accelerate the integration of variable renewable energy.

This paper focuses on market designs that have emerged to meet these various challenges, and is 

structured along the three main domains of power markets—adequacy, energy, and ancillary 

services. 

Adequacy: This function ensures adequate investment in capacity that is needed to meet future 

demand occurs with sufficient lead-time to complete construction and interconnection of the 

generating unit. High penetrations of variable renewable energy (with its inherently low marginal 

costs) have led to lower average prices in energy markets. Conventional generators—which will 

be displaced more often and sell energy at lower prices when they are selected—are likely to run 

at lower (and less predictable) capacity factors and earn less revenue from the energy markets 

(Milligan et al. 2012; Bauknecht et al. 2013), precipitating adequacy concerns. Also, the type of 

capacity (e.g., ability to cycle on and off) that the system requires in the long-term to ensure a 

reliable system becomes more important. Approaches to sustain adequate and appropriate 

capacity may include some combination of scarcity pricing, capacity markets, and capacity 

payments, and energy efficiency is increasingly considered an eligible resource in some markets.

Energy: This is the central transaction platform in power markets. To deliver energy when it is 

needed, generators are dispatched on an economic basis, subject to reliability constraints and 

congestion. In some markets, the economic dispatch of demand-side resources is growing 

significantly, altering the economics for conventional generators. Increased penetrations of 

variable renewable energy affect the energy markets in three primary ways: 1) the frequency and 

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vii 

magnitude of changes to net load1 increase, which in turn require that the system have 

capabilities such as fast ramping and frequent on-off cycling; 2) the possibility of forecast errors 

increases the difficulty in anticipating market outcomes, increasing the relevance of intraday 

markets (where available); and 3) the proportion of fully dispatchable supply could decrease as 

the low marginal costs of renewable energy displace them from the market.2 Variable renewable 

resources, such as wind, can in many markets bid in as a dispatchable resource, but their 

performance improves significantly with good forecasts. Other energy market modifications 

reviewed in this report include: dispatch resolution, more frequent markets, ramp products, 

negative pricing, and forecast integration. 

Ancillary services: This collection of services is necessary to maintain system balance between 

supply and demand, and to ensure voltage and frequency support. Many markets include 

secondary and tertiary reserves (e.g., regulation, spinning) in the ancillary services market; other 

services, such as system inertia and voltage control, are not subject to markets. Variable 

renewable energy can affect the design of ancillary services markets in the following ways. First, 

the variability and uncertainty of wind and solar energy increases requirements for various 

ancillary services, affecting the scheduling and pricing of those services. Second, their impacts 

vary depending on system conditions, which makes the ancillary service demands difficult to 

generalize across timescales and systems. Third, allowing variable renewable energy to 

participate in ancillary service markets can offer more supply to the market, but could offer 

challenges based on the unique characteristics of variable resources. The aggregate impact of 

significant variable renewable energy on the grid suggests the need for modifications to current 

ancillary service market designs and rules, and suggests the potential for new separate ancillary 

service markets.

Table ES-1 summarizes the market design considerations reviewed in this report. 

Table ES-1. Market Design Considerations Reviewed for Adequacy, Energy, and Ancillary Services

Adequacy Energy Ancillary Services

Market 

Design 

Considerations 

Reviewed

Scarcity pricing Dispatch resolution Dynamic reserve requirements 

(secondary and tertiary reserves) 

Capacity markets More frequent markets Primary frequency response

Capabilities markets Ramp products System inertia

Capacity provision by 

renewable resources Negative pricing Voltage control

Forecast integration Co-optimization

Dispatchable variable 

renewables

Ancillary service provision by 

renewable resources

 

1 Net load refers to electricity demand minus electricity supplied by variable renewable energy and hence the 

electricity that must be supplied by other resources. 

2 Hybrid systems (e.g., wind + storage, solar + storage, solar + natural gas) enhance dispatchability and thus revenue 

certainty to investors, but are not the focus of this markets report, which focuses market designs that accommodate 

variability and uncertainty.

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
viii

Bridging Wholesale Markets and Emerging Technologies

Bridging opportunities between wholesale markets and emerging technologies, such as demand 

response, distributed generation, and distributed solar, has the potential to reduce system costs, 

including costs at the distribution level, where these resources in particular can address 

congestion, losses, and inadequate infrastructure. But, the distinct characteristics of these 

resources, particularly for distributed resources, present challenges to creating nondiscriminatory access in the wholesale market. Examples of persistent challenges include:

1. Increasing demand response participation. 

Demand response holds significant promise to increase the elasticity and economic 

efficiency of wholesale market operation. Nonetheless significant barriers remain before 

these resources contribute in a significant way to system operation because traditional

markets follow 20th century demarcations between wholesale and retail sides. 

Increasingly, market design might need to redraw these boundaries. Some markets, 

especially in the United States, have established new specifications that have clarified the 

role and trading parameters of demand response resources, resulting in significant 

participation. 

2. Integrating distributed generation.

Deployment of distributed generation, for example solar photovoltaic and combined heat 

and power, impacts wholesale market operation in unique ways. For example, in 

Denmark, combined heat and power plants are required to participate in wholesale power 

markets, and a third of the plants also participate in real-time energy markets. Distributed 

photovoltaic electricity, on the other hand, rarely participates in wholesale markets, but 

has an indirect effect by reducing net demand levels during midday hours that used to 

represent peak price hours. Given these unique characteristics, there will likely be no 

single approach to integrating distributed generation into market design. Instead, local 

contextual factors will figure prominently in market designs that result in coordinated 

deployment of centralized and distributed energy resources, as well as in the treatment of 

hybrid market actors such as microgrids. 

3. Clarifying the role of storage. 

Electricity storage—mechanical, thermal, or chemical—promises to ease concerns over 

wind and solar market and system impacts and to decrease curtailment. Yet, significant 

policy and regulatory barriers make it difficult for storage to participate in centralized 

markets. For example, storage can provide generation, transmission, and distribution 

benefits, but in many markets storage can only be classified (and valued) as one type. 

Emerging solutions, such as allowing the owner of a storage resource to disaggregate 

these various services and sell them each to a third party for transaction in markets, could 

induce more optimal use of storage options. 

Challenges to 21st Century Market Design

Wholesale market designs provide significant efficiency in real-time dispatch of system 

resources, and offer great promise for integrating variable renewable energy and introducing new 

resources on the demand side, because they help encourage innovation, minimize system costs, 

and facilitate access to a broad range of options that increase system flexibility. Yet, there remain

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
ix

ongoing challenges involved with the design of markets for enabling higher penetrations of 

variable renewable resources and emerging technologies. A few topics are listed below: 

Minimizing Complexity: Around the world, most power markets have evolved into complex 

designs that integrate efficient economic principles with the engineering and physics of the 

electric power system. New designs, such as for flexibility, are being introduced, but at the cost 

of amplifying existing market complexity. Too much complexity could necessitate market 

revisions too frequently, fail to achieve extensive market participation, and create unintended 

conflicts between markets, such as energy market rules that create a disincentive to provide 

reliability services. 

Encouraging Investment: In most wholesale markets, energy prices are based on the marginal 

cost of providing energy, and therefore do not include any of the capital costs of the resources. 

Investors calculate the risk adjusted returns of potential projects; and as energy prices decrease 

with increasing penetration of zero dispatch generation sources, other revenue sources become 

increasingly important, including scarcity pricing, capacity markets or payments, and bilateral, 

long-term power purchase agreements. There is debate as to the merit of each. 

Harmonizing across timescales: A reliable and secure electricity supply requires sensitivity to 

multiple timescales. Electricity markets provide short-term price signals (seconds to days), 

which are effective at allocating available capacity. In contrast, few power markets provide any 

long term price visibility and are ineffective at incentivizing the optimal amount of long-term 

installed capacity to meet reliability (Cramton and Stoft 2006). A challenge in market design is 

how to provide long-term market signals to encourage investments in new merchant generation 

(renewable or otherwise).

Ensuring Market Depth: In many power markets, a significant amount of energy is sold 

through bilateral contracts, which addresses the absence of long-term market signals, but which 

reduces market participation. The implications for systems with high variable renewables but 

significant bilateral contracts are threefold. First, most energy delivery is purchased months to 

years in advance, locking in generation that could be inflexible, and leaving a small day-ahead 

and real-time market for new, innovative, and flexible supply. Second, spot-market prices might 

be inconsistent with marginal costs due to the limited supply of flexibility. Third, limited 

participation in the day-ahead and real-time markets can decrease market efficiency by reducing 

the potential for market software to optimize supply resources based on their bid costs. 

Conclusions

Experience in many countries illustrates the value in using markets to access flexibility. Welldesigned markets encourage economically efficient and stable solutions, promote desired 

behavior, and minimize unintended consequences. Yet, many uncertainties remain about how to 

evaluate system requirements and effectively induce and sustain investments in appropriate 

resources. This report reviews market designs that help access flexibility, and it suggests that 

sources of revenue could shift away from energy toward tailored services. 

It is apparent that market design is a difficult task. Many competing objectives must be met, 

including using short-term price signals to incentivize long-term investments, minimizing market 

power, and providing incentives for suppliers for the many non-energy services that are needed 

to balance the grid. Wholesale markets in many locations are markedly uncorrelated with pricing 

mechanisms in the retail market. This means that participants in the wholesale markets have 

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x 

minimal ability to predict, plan, or account for consumer actions. Further, in some markets with 

scarcity pricing, spikes in wholesale prices serve only to increase total costs, and do not provide 

any incentives for consumers to change their behaviors to promote economic efficiency.

The challenge of appropriate market design becomes more apparent in emerging 21st century 

power systems. Assets such as variable renewable energy, demand response, storage, and 

distributed generation offer benefits that can be realized throughout the power system—

generation, transmission, and distribution—and therefore are difficult to capture in current 

markets and regulatory structures, which deliberately segregated generation from transmission to 

support utility unbundling. The power system may require a transformation from a system 

premised on a strict separation between wholesale and retail, or generation and distribution, to 

one that can integrate these markets, such that assets from across the system can contribute to 

flexibility and reliability.

Moreover, market solutions are not the only option. Various hybrid designs—combinations of 

regulations and competitive markets—might serve as alternatives. A key driver in any market or 

hybrid design is to start with the characteristics that maximize the value of the power system and 

ensure that the type and quantity of services that deliver economically efficient operation and 

design of the power system are understood. 

The power system is just that, a system, relegating various design and operational issues to 

entities that are uncoordinated, possess imperfect information, and possess varying degrees of 

market power. Moreover, these entities operate in a complex market with many economic 

externalities; thus economies of scope (e.g., coordination of transmission and generation 

planning) are difficult to achieve. On balance, however, markets can enable efficiency gains that 

emerge from competitive (or nearly competitive) markets in electricity. Nevertheless, market 

approaches remain just one option in a broader range of possible approaches, such as vertically 

integrated utilities. 

There is an acute need for international collaboration on wholesale market design questions. A 

platform for collaborative analysis and modeling will help to evaluate pathways to 21st century 

power systems. Proposed market or hybrid market-regulation paradigms should be rigorously 

tested to understand both technical and financial outcomes, but also the alignment with the 

public policy objectives that drive market design. The 21st Century Power Partnership aims to 

provide this platform, and the authors of this report sincerely hope that it lays the groundwork for 

future collaboration. 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
xi

Table of Contents

1 Introduction........................................................................................................................................... 1

2 Toward 21st Century Power Systems ................................................................................................. 3

3 Wholesale Market Design Principles for Integrating Variable Renewable Energy ........................ 7

3.1 Adequacy ......................................................................................................................................... 7

3.2 Energy ............................................................................................................................................ 15

3.3 Ancillary Services .......................................................................................................................... 20

4 Bridging Opportunities Between Wholesale Markets and Emerging Technologies ................... 26

4.1 Demand Response .......................................................................................................................... 26

4.2 Distributed Generation ................................................................................................................... 30

4.3 Storage ........................................................................................................................................... 31

5 Challenges to 21st Century Market Design....................................................................................... 33

5.1 Minimizing Complexity ................................................................................................................. 33

5.2 Encouraging Investment ................................................................................................................ 33

5.3 Harmonizing Across Timescales ................................................................................................... 35

5.4 Ensuring Market Depth .................................................................................................................. 35

6 Market-Design Research As a Platform for International Collaboration ...................................... 36

6.1 Short-term Operational Timescale ................................................................................................. 36

6.2 Long-term Planning Timescale ...................................................................................................... 37

7 Conclusion .......................................................................................................................................... 40

8 References .......................................................................................................................................... 42

List of Figures

Figure 1. Projected electricity demand by sector, 2010–2035. World Energy Outlook 2011 © 

OECD/IEA 2011 (Fig. 5.1, p. 177) ......................................................................................................... 3

Figure 2. Illustrative view of 21st century power systems. NREL........................................................... 4

Figure 3. Mean diary [daily] market prices based on wind penetration levels (Spanish hourly data, 

2007–2012, provided by Red Eléctrica de España) ......................................................................... 13

List of Tables

Table 1. Market Design Considerations Reviewed for Adequacy, Energy, and Ancillary Services ... 7

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1 

1 Introduction

Around the world, wholesale electricity market designs are being reconsidered in an effort to 

meet a broader range of objectives—including accelerating private investment, promoting 

competition and efficiency, encouraging the development and deployment of non–fossil fuel 

sources of energy, and increasing flexibility in system operation. In light of this growing interest 

in establishing or reforming wholesale electricity markets, there is a clear need for an 

international discussion of the market design principles and paradigms that can guide the 

transition to 21st century power systema system which integrates variable renewable energy 

and emerging technologies such as smart grids, demand response, distributed generation, and 

distributed storage. 

This report aims to identify and briefly discuss the landscape of key issues in wholesale market 

design for achieving power systems that are cleaner and more efficient, resilient, and reliable

(see Text Box 1 for explanation of wholesale market terminology). It is the first in an ongoing 

series of issue papers from the 21st Century Power Partnership, a multilateral initiative to 

accelerate power system transformation. Contributors to this report include public- and privatesector experts from around the world, who provide a uniquely broad range of perspectives. 

Subsequent papers will examine international perspectives on related topics, such as emerging 

designs for the retail power market. 

The report is structured as follows. Section 2 describes 21st century power systems. Section 3

examines specific market design features that have evolved to accommodate high penetration 

levels of variable renewable energy. Section 4 examines the need to bridge opportunities 

between wholesale market designs and emerging technologies such as demand response. Section 

5 examines the likely challenges to effective market design. Section 6 explores a research agenda 

that might build international collaboration. Section 7 synthesizes conclusions. 

Text Box 1. Wholesale Power MarketsDefinitions

Wholesale power markets refer to the exchange of energy, ancillary services, and capacity in the bulk 

power system, which comprises the interconnected resources at the high-voltage level—generation, 

transmission, and interties to neighboring systems. The retail power market refers to the exchange of 

energy and services at the lower-voltage distribution level. 

Bulk system (or “grid”) operators go by different names in different jurisdictions. In Europe they are 

called transmission system operators (TSOs). In India they are called load dispatch centers. In the 

United States they are called regional transmission organizations (RTOs) or independent system 

operators (ISOs). 

Approaches to system operation also vary widely. The United States, for example, uses two approaches 

to wholesale electricity market designvertically integrated utilities and RTOs/ISOs.

3 The vertically 

integrated utility paradigm—common to many jurisdictions globally—relies on the public utility 

 

3 The U.S. RTOs/ISOs are California ISO (CAISO), Electric Reliability Council of Texas (ERCOT), ISO New 

England (ISO-NE), Midcontinent ISO (MISO), NYISO, PJM Interconnection (PJM), and Southwest Power Pool. 

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2 

transmission provider to procure the necessary resources to manage the uncertainty and variability of 

the power system.4 In the United States, the transmission providers are required to provide open access 

transmission service. In areas with RTOs/ISOs (the focus of this report), transmission owners gave 

operational control of transmission facilities to the RTO/ISO, which is an independent entity. The 

RTOs/ISOs allocate transmission rights based on a system of bids and offers, and optimize unit 

commitment and dispatch decisions to minimize system costs. In Europe, often the TSO both operates 

and owns the transmission facilities.

Operators of the low-voltage level, who reduce the voltage from the transmission lines and deliver 

power through distribution lines, also have different names, including distribution system operators 

(DSOs) in Europe and utilities in the United States. The load-serving entities (LSEs), such as utilities, 

competitive retailers, and the DSOs that sell electricity to retail consumers, purchase their power from 

the wholesale energy market. Many European DSOs are considered “entry gates” to retail markets and 

contribute to the effective functioning of energy wholesale markets (Council of European Energy 

Regulators 2013b). 

This report uses “wholesale power markets” to refer to the unbundled, competitive markets, such as the 

RTOs/ISOs and electricity markets in Europe.

 

4 Variability refers to variations in demand and supply, for example, wind and solar generation can vary based on 

changes in the intensity of their energy sources, and conventional generation and load can deviate from schedule. 

Uncertainty refers to unexpected events, for example, forced plant outages or load or wind forecast errors.

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3 

2 Toward 21st Century Power Systems

Globally, investment in power systems is expected to exceed $15 trillion over the next 20 years 

(IEA 2012), and electricity demand is expected to nearly double (see Figure 1). This growth will 

give added urgency to the goals of achieving affordability, energy security, reliability, and 

reduced health and environmental impact. In this context, energy-efficient devices, appliances,

and power systems will allow for more rapid expansion of energy access. Renewable energy

resources will support cleaner system operation, as wind and solar represent an increasing share 

of electricity generation. 

Figure 1. Projected electricity demand by sector, 2010–2035. 

World Energy Outlook 2011 © OECD/IEA 2011 (Fig. 5.1, p. 177)

Expanding the grid penetration of solar energy and wind energy—and accommodating their 

variable output—requires more nimble power systems that can adjust quickly to balance supply 

and demand. At the same time, options for addressing the variability of solar and wind energy 

are being strengthened through advances in smart grids, communications, and technologies that 

enable dispatchable demand and distributed generation to extend to the mass market. Figure 2 

illustrates the range of dynamic interactions that might characterize 21st century power systems. 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
4 

Figure 2. Illustrative view of 21st century power systems. NREL

Wholesale market design is crucial for realizing these opportunities, in two key distinct regards. 

In the operational sense, electricity market design defines the protocols for dispatching electricity 

in a reliable and economic fashion. At the same time, market design determines the long-term 

landscape of financial incentives and rules of eligibility for investment in resources that ensure a 

reliable and secure grid. The dual roles of electricity markets simultaneously operational and 

financialare a defining characteristic of electricity market design. Ensuring harmonization 

between the two roles is a persistent challenge. The need for harmonization is increasingly 

evident in the pursuit of 21st century power systems. For example, as a general trend, flexible 

performance (e.g., the ability to ramp quickly, as discussed in Section 3) and expanded resource 

eligibility (e.g., demand- , delivery- , and supply-side resources, as discussed in Section 4) are

issues of growing importance, as new technologies and systems stand poised to enter both the 

wholesale and retail power markets. 

There is a wide range of starting points and motivations for market development; therefore, the 

evolution of market design will follow myriad pathways. Some common objectives, however, 

are present in all systems, including: 

1. Promoting efficient operation of power systems,

2. Creating clear and effective incentives for investment, and

3. Improving reliability and cost-effectiveness of electricity service.

These objectives have driven power market design for decades. More recently, other objectives 

have emerged that increasingly impact power market design, namely: 

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5 

4. Reducing the health and environmental impacts of electricity service,

5. Rapidly expanding energy access to underserved or unserved customers, and

6. Encouraging power-system innovation. 

The importance of the latter objectives depends heavily on context. Not all jurisdictions give 

equal weight to each of these objectives, and it remains to be seen what, if any, market designs 

optimize all of them. This report primarily focuses on the challenges and opportunities involved 

in achieving objective 4—a more energy-efficient and cleaner power system—but recognizes 

that objective 5 is a primary public-policy objective in many settings, which in turn influences 

the design of wholesale power markets and power system evolution generally. Policy makers and 

regulators working to create 21st century power systems must balance disparate or competing 

objectives, consult with broad networks of stakeholders, and attempt to render frameworks that 

advance the public good, recognizing that there exists no single solution that maximizes all 

objectives.

Wholesale power market design has evolved significantly since the first experiments in the early 

1980s. Resolving fundamental issues of adequate investment, transparency, and competition, 

however, has proven to be a complex task. Further expanding the scope of market design to 

include objectives of health, environmental, energy access, and innovation presents new 

challenges and opportunities. For example, 

• Promoting the entry of new sources of distributed generation could be perceived as a 

challenge to existing market participants (Lopes et al. 2007; Kind 2013); 

• Rapidly expanding energy access might increase costs for other customers (Ranjit and 

Sullivan 2002; Brew-Hammond 2010); and 

• Reducing health and environmental impacts by encouraging energy efficiency and greater 

deployment of variable renewable energy sources could challenge existing investment 

frameworks. 

Although an examination of many of these interactions and tensions is beyond the scope of this 

report—which addresses specific market design concepts on the bulk power system, namely 

greater integration of variable renewable resources, energy efficiency, and smarter grids—the 

broader market design context is vital for understanding the drivers for policy and investments in 

energy at both the wholesale and retail levels (see Text Box 2). 

This report focuses primarily on wholesale market designs and complementary operational 

practices administered at the system operator level. Retail market evolution also is important,

however, and many forces in evidence today will prompt a reconsideration of the role of 

traditional utilities. Future research and analysis performed by the 21st Century Power 

Partnership will examine the parallel questions concerning the transformation of the power sector 

on the retail side, including how utilities can earn a return on services in a context of increasing 

energy efficiency, significant demand response, and distributed generation. 

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6 

Text Box 2. Electricity Markets in the Context of Power System Reform

Power system reform processes have been revealed to be sensitive to contextual factorstechnical, 

financial, political, and institutionalthat constrain options and pathways for the design of electricity 

markets. Broadly speaking, power system reform efforts globally fall into three categories. The first 

consists of mature, restructured markets in which significant generation capacity already exists, and 

where economic, social, and technological forces are precipitating a reassessment of market design. 

Most markets in the European Union (EU), Australia, and the United States fall into this category, with 

a reassessment driven by slow demand growth, rapid growth in energy efficiency and variable 

renewable energy, and increased interest in deploying smart-grid technologies. 

The second category consists of “hybrid markets” (Gratwick and Eberhard 2008), in which earlier 

restructuring efforts have stalled out, leaving a mix of competitive and state-owned actors. Many 

emerging economies fall into this category, including Tanzania, Argentina, Bolivia, Jamaica, and

various states within China and India. In many of these settings, the impetus for continued market 

reform stems from rapid demand growth, lagging investment in new capacity by independent power 

producers, and poor financial conditions of state-owned entities. In contrast with earlier rounds of 

restructuring, many of these countries also show growing interest in adding variable renewable energy 

to the generation portfolio and investing in smarter distribution grids—new objectives that significantly 

change the market reform conversation.

The third category consists of monopoly power sectors, in which little or no restructuring has occurred. 

Mexico and South Africa fall into this camp, for example. Similar to the second category, in these 

settings the impetus for power system reform typically is driven by a need for accelerated private 

investment to meet rapidly growing demand or the need to change the current inefficient set-up of 

pricing and dispatching. 

The set of electricity market design principles that has been developed and refined largely in developed

economies faces translational challenges in emerging-economy settings. These challenges stem both 

from the different objectives of emerging economies—especially meeting rapidly growing demand and 

improving energy access—but also due to unique institutional challenges that commonly occur in 

developing countries. Four unique institutional challenges have been identified that are relevant to the 

translation of market-design principles: Limited regulatory capacity, limited accountability, limited 

commitment, and limited fiscal efficiency (Estache and Wren-Lewis 2009). 

Limited regulatory capacity pertains to the ability of regulators to implement and enforce policy. 

Limited accountability refers to the level of accountability to which regulatory institutions are held. 

Limited commitment refers to the diminished ability to rely upon contracts (Guasch et al. 2003).5

Limited fiscal efficiency refers to the difficulties in financing infrastructure investment. The prevalence 

of four challenges varies significantly by jurisdiction, but all are important considerations in the 

development of electricity markets.

Although addressing the full diversity of institutional challenges and power system contexts is beyond 

the scope of this report, it does attempt to provide general insights into the unique challenges that 

emerging economies could face in the transition to market frameworks.

 

5 See, e.g., Guasch et al. (2003). The authors discuss the common occurrence of renegotiated government 

concessions, and estimate that in Latin America between 1985 and 2000, more than 40% of concessions (excluding 

the telecoms sector) were renegotiated—the majority at the request of governments.

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7 

3 Wholesale Market Design Principles for Integrating 

Variable Renewable Energy

This section reviews wholesale market designs in use and under consideration to ensure 

adequacy and security in a landscape of significant amount of variable renewable energy. The 

concepts are organized along three categories of markets commonly found in mature contexts: 

Capacity adequacy, energy, and ancillary services.6 These three categories represent the 

foundational market domains of the bulk power system that will enable 21st century power 

systems. Table 1 provides an overview of the design considerations reviewed in this section. 

Table 1. Market Design Considerations Reviewed for Adequacy, Energy, and Ancillary Services

Adequacy Energy Ancillary Services

Market 

Design 

Considerations 

Reviewed

Scarcity pricing Dispatch resolution Dynamic reserve requirements 

(secondary and tertiary reserves) 

Capacity markets More frequent markets Primary frequency response

Capabilities markets Ramp products System inertia

Capacity provision by 

renewable resources Negative pricing Voltage control

Forecast integration Co-optimization

Dispatchable variable 

renewables

Ancillary service provision by 

renewable resources

3.1 Adequacy

Ensuring resource adequacy is a critical function of power system policy and market design. In 

jurisdictions with wholesale energy markets, the central challenge of this issue is balancing the 

power generators’ desire to minimize investment risk with the public-policy priority to maintain 

cost-efficient and dynamic functioning of wholesale power markets. 

Broadly speaking, ensuring minimal investment risk for generators (for example through longterm contracts) shifts risk to consumers. Conversely, ensuring cost-efficient market function (for 

example, forcing all generators to compete in economic dispatch with no guaranteed production) 

shifts the risk to generators. Well-functioning wholesale markets do not guarantee long-term 

 

6 Another important component of electricity market design, the financial transmission rights market, is not 

extensively covered herein. Although these auctions could change based on the changing flows and changing 

locational marginal prices from high penetrations of variable renewable resources, the fundamental design of the 

market remains relatively unchanged from greater adoption of renewables in the electricity market, and therefore 

these markets were omitted from this report. 

Also not considered in this report are costs and benefits of renewable energy systems on the grid, such as energy loss 

savings or costs, increases or offsets of transmission equipment, and environmental benefits, and policy and market 

designs that would create incentives specific to new renewable energy generation. This report instead focuses on 

market designs to accommodate existing variable renewable energy and emerging technologies, and market 

modifications needed to ensure adequacy of supply from all sources. For more on international best practices to 

achieve new renewable energy generation, see Miller et al. (2013).

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8 

revenue certainty, therefore price and volume risk over the long term imply that less-efficient 

generators might—and perhaps should—go out of business. 

The policy and regulatory challenge in designing markets, therefore, is to fairly apportion risk 

while meeting social, economic, and environmental objectives. In pursuit of economic operation 

of power systems with large proportions of variable renewable energy, market design 

increasingly aims to avoid rewarding inefficient generators, and instead encourages efficient, 

flexible units. Even in well-developed and integrated markets, such as in the European Union 

and in one of the most integrated marketsthe Nordic Nord Pool regionthis design challenge 

has proven to be significant. 

Additional challenges include the lead-time needed to develop new generation resources and the 

often even longer lead-times needed if new transmission services are required. Although this 

period can be relatively short for renewable resources such as wind or solar energy, it can take up 

to several years for natural gas combined-cycle power plants—and even longer for coal-fired or 

nuclear plants—and take as much as a decade or more for new green-field transmission services. 

Some additional mechanism therefore might be needed to ensure investment in the long-term 

security of supply in a timely manner, so that enough generation with the desired attributes is 

available when needed.

To evaluate whether a current or projected power system meets adequacy requirements, 

wholesale markets and regulators primarily use one of two metrics. Either a fixed percentage of 

peak load (e.g., 15% planning reserve margin above peak load), or a probabilistic measurethe 

loss of load probability (LOLP)—is used. As new generation is added to the resource mix the 

LOLP generally declines. The effective load-carrying capability (ELCC) metric then is 

calculated to determine the contribution that any given resource makes to the reliability target. 

This often is an LOLP of 1 day/10 years (Keane et al. 2011a). The North American Electric 

Reliability Corporation (NERC) makes a similar recommendation (NERC 2011). 

How markets then achieve adequacy reflects an ongoing debate about whether a reserve 

requirement is necessary and who should bear the risk. Some markets and regulators, such as 

Nord Pool, rely on energy-only markets through scarcity pricing, to ensure sufficient cost 

recovery for generators and thus maintain sufficient planning reserve margins. Generators bear 

the market risk of meeting annual income targets through the power market. An alternative 

approach is to require the RTO/ISO/TSO or load-serving entity to maintain a target planning 

reserve margin, which could be satisfied through a centralized market mechanism (e.g., RTObased capacity market or payment), or decentralized requirements (e.g., require an LSE to 

demonstrate sufficient reserve margins for its specific distribution system, such as through longterm, bilateral contracts). In this context, the ratepayer bears the market risk of paying for too 

much capacity. Bilateral power purchase agreements—a predominant mechanism used by

CAISO)—make it possible that these requirements could limit participation in energy-balancing 

markets, and thus would limit flexibility. Following an overview of these two 

mechanismsscarcity pricing and capacity markets—the impact of variable renewable energy 

on these market options is discussed. 

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9 

3.1.1 Energy-only Markets with Scarcity Pricing

Scarcity pricing7 implies that when demand is very high, the supply may be insufficient and/or 

costly to deploy to meet the load (Stoft 2002, p. 70). These price spikes reflect the relative 

inelasticity of supply (and demand) at high load levels or due to other sources of capacity 

constraints. Scarcity pricing can be designed to encourage investments in flexible response, such 

as storage and price-responsive load, because these resources can respond quickly to brief 

periods of scarcity. Scarcity pricing is favored in some markets on the basis that policy 

interference in pricing mechanisms, such as through a capacity market, would jeopardize market 

participants’ trust in the market and discourage investors from investing in new capacity. 

In practice, regulators in many energy-only markets impose bid caps in an effort to protect 

consumers from too high and volatile prices and to mitigate market power. Also, some energy 

regulators are tasked to procure strategic reserves to ensure long-term adequacy. Strategic 

reserves are withheld from the market entirely or included only when prices are high—they 

create a de facto price cap for the market (European Commission 2012b). In Finland, for 

example, where the power system is part of energy-only Nord Pool Spot, capacity adequacy is 

the responsibility of the Energy Market Authority. Capacity can be acquired from new peak load 

plants, demand response, or old units (based on bids), which would otherwise be dismantled and 

instead receive “power reserve” payments. In the latest auction, demand response was able to 

participate to deliver part of this reserve. The need for the reserve was calculated with ELCC 

calculations considering wind power and stochastic imports from neighboring countries. Without 

neighbors, Finland would have a capacity deficiency. 

Scarcity pricing predominantly is found in the European Union, where the policy goal in several 

states has been to combine scarcity pricing with carbon prices to increase the competitiveness of 

low-carbon flexible units and use extensive interconnections to balance integrated regions. 

Nevertheless, the European Union reflects different policy approaches to adequacy, and member 

state policy actions have yet to create a coordinated market-based approach. The differing 

approaches to adequacy have complicated cross-border trades, such as those between countries 

with and without capacity payments (European Commission 2012b). 

Examples of energy-only markets with scarcity pricing: Australia’s NEM, Nord Pool, ERCOT

3.1.2 Reserve Requirements: Capacity Markets or Payments 

Alternatively, or even to supplement scarcity pricing, a capacity market or some form of capacity 

payment could help ensure revenue adequacy. Although the specific characteristics among 

existing capacity markets differ, their common objective is to procure capacity for a future time 

periodoften 1 to 3 years. A qualifying resource that participates in the capacity market receives 

a payment in return for providing capacity in the day-ahead market, or some other requirement. 

Capacity markets also have their own challenges, including the potential abuse of market power 

and providing sufficient incentives to induce the desired level of capacity in forward markets. 

The ISO-NE Capacity Market, for example, conducted five years worth of auctions that did not 

 

7 Scarcity rent is revenue minus variable operating cost, which is needed to cover startup and fixed costs (Stoft 

2002). Scarcity pricing reflects the situation in which generators are supplying at full output, and load would be 

willing to pay a generator more than its variable cost of production to produce more.

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10 

clear at a competitively set auction price, and instead cleared at an administratively set floor 

price (Coutu 2011). 

In the United States, where capacity markets are more common, the markets offer 1-year 

contracts, auctioned 3 years in advance of delivery (ISO-NE and PJM) and 6-month contracts, 1 

month in advance (NYISO).8 Yet, these markets have not been critical to initiating new 

investments (Caplan 2012), and they have been challenging to design due to difficulty in 

anticipating required levels and types of capacity (Milligan et al. 2012). Also, the timescale of 

current markets (6 months to 1 year) does not match the timescale needed to secure financing 

and attract new investments (e.g., 15 years minimum). In comparison, most power purchase 

agreements range in duration from 20 to 25 years. Furthermore, existing capacity markets do not 

differentiate between resources that have different flexibility attributes. This likely will become 

more important as the shares of variable renewables and demand response in the electricity 

supply increase. 

A new variant on reserve requirements that is gaining support in the European Union is the use 

of a reliability option contract (Keay et al. 2013), which is the financial version of capacity 

markets (Bauknecht et al. 2013). This mechanism imposes a reserve obligation on the buyer of 

electricity (e.g., retail company, system operator). Capacity is sold via an auction, which 

establishes a strike price in the day-ahead market. Sellers then must provide capacity at the strike 

price when called upon (i.e., when market prices are high). Generators must pay the difference 

between the spot price and the strike price. This addresses concerns of market power during 

scarcity, because generators are encouraged to make capacity available at high prices. Because 

they must pay the difference between the spot market price and the strike price, generators do not 

gain from price manipulation (Bauknecht et al. 2013). 

In Europe, the question of capacity remuneration mechanisms is discussed very differently 

among the member states. Conventional power plants (even new flexible gas plants) are being 

closed or are threatening to close not only because some are at the end of their lifetimes, but in 

some cases because of changes in fuel prices. As a result, generation adequacy regionally is 

becoming a matter of concern (European Commission 2012b; Council of European Energy 

Regulators 2013a; Miller et al. 2013). Also, limited interconnection capacity, for example in 

countries such as Spain, has increased interest in capacity payments (see Text Box 3). 

In Europe, security of supply is a national question, but over-capacities would occur if solved 

strictly nationally. Thus, European organizations and associations strongly recommend 

international coordination (European Commission 2012a; European Wind Energy Association 

2012; ACER 2013; ENSO-E 2013). 

Examples of energy markets with capacity mechanisms: Ireland, Spain, Ontario, PJM, NYISO, 

and ISO-NE

 

8 Other design differences include auction style (descending clock vs. sealed bid), participation (for example, the 

PJM capacity market is open to transmission upgrades; ISO-NE and PJM’s timeframe allows new resources to 

participate), and measurements of availability (such as whether a generator is penalized for a forced outage during 

tight capacity periods) (Coutu 2011). 

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11 

Text Box 3. Revisions to Spain’s Capacity Mechanisms

In 2012, capacity payments represented 10.2% of the total Spanish market price (Red Eléctrica de 

España 2012). Recently, a new competitive capacity mechanism has been proposed (Ministerio de 

Industria Energía y Turismo 2013), which includes an investment incentive for a 10-year period and is 

conducted through an auction configuration. The incentive amount is calculated as the product of the 

capacity value of the technology (for example, 0.95 for nuclear and 0.09 for onshore wind power) and 

the result of the auction. The incentive includes a hibernation mechanism, which would allow the 

possibility of temporarily closing generation units when capacity is exceeded, especially during 

minimal load periods. The plants scheduled for hibernation also are determined through an auction. 

Additionally, availability service is applied for 1-year periods and combined cycle and coal thermal 

plants are able to participate. Hourly payments for this service are calculated as a function of a monthly 

payment, hourly total thermal generation, and hourly total dispatchable thermal generation.

There is no widespread agreement on the need for a capacity mechanism to supplement energyonly markets—and, if the need exists, how best to do it. There also is little, if any, evidence 

regarding whether scarcity pricing would result in revenue sufficiency for capacity, as illustrated 

by the current review of options in ERCOT (Newell et al. 2012). Because most retail consumers 

do not see real-time prices that reflect cost, the demand curve for electricity is muted (Stoft 2002; 

Kirschen and Strbac 2004). Proponents for capacity mechanisms argue that this malfunction of 

the market for electricity, coupled with the lack of ability to differentiate reliability among 

customers on a widespread basis, renders an energy-only market incapable of providing 

sufficient forward capacity (Cramton and Stoft 2006). This debate is not new, and began long 

before variable renewable energy sources were significant in the electricity supply.

Text Box 4 describes Brazil’s approach—using capacity auctions to achieve adequacy through 

long-term contracts. Text Box 5 discusses how capacity markets can be designed to invite 

participation by demand-side resources (demand response). 

Text Box 4. Brazil: Market-based Mechanisms to Meet Reserve Requirements

In Brazil, the power system is dominated by hydro generation. Capacity adequacy assumed urgent 

importance in 2001, as years of successive droughts resulted in reservoir depletion and widespread 

power rationing. Subsequent reforms implemented from 2004 onward have established long-term 

contracting of power as the only form of electricity procurement (Pinguelli Rosa et al. 2013). This 

principle has been driven by the urge to reduce investment risk for new capacity additions. By this 

metric, the reforms largely have been successful, resulting in significant investment in new capacity. 

The 2004 reforms established two separate energy-trading environments. In the first, the Regulated 

Contracting Environment, energy is sold by electric utilities, independent power producers, selfgenerators, and power marketers; the only buyers are distribution companies that are required to 

contract their entire forecast demand for captive consumers. Contracts are auctioned off over time with 

delivery dates of 1, 3, and 5 years after the date of the auction. There are separate auctions for “new” 

and “existing” electricity.

Within this environment, contracts for new electricity are longer (duration of more than 15 years) than 

those for existing electricity (duration of 8 years). Distribution companies are required to contract 

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12 

100% of their expected power needs, but there are annual “adjustment” auctions where they can buy 

additional energy when their forecasts are inaccurate. In the regulated environment, “marketers”—

entities that either may purchase and resell energy, or may only help broker deals between buyers and 

sellers—are only allowed to participate in these adjustment auctions.

The second trading environment is called the Free Contracting Environment, and brings together 

electric utilities, independent power producers, self-generators, marketers, importers, exporters, and 

free consumers (those that do not need to buy power from distribution companies, typically industrial 

and commercial firms). Buyers and sellers are free to enter bilateral contracts and negotiate prices, 

quantities, delivery dates, and conditions. The Free Contracting Environment, also known as the “free 

market” in Brazilian electricity sector parlance, has been growing steadily in the past few years. It 

consisted of about 1,650 free and special consumers in 2012, which accounted for approximately 27% 

of total consumption in the Brazilian electricity system (ABRACEEL 2012). 

Dispatch decisions essentially are made on a hydro-centric schedule of weekly increments, part of the 

legacy of a hydro-dominated system. Slow dispatch periods significantly limit short-term system 

flexibility. Similarly, the pure long-term contracting environment in Brazil could blunt economic 

signals—for example prices of natural gas—that could lead to generator fuel switching in the mediumterm. Taken together these characteristics of the Brazilian case illustrate that a focus on procuring 

resource adequacy, and operational rules focused on large legacy generators, could conflict with other 

market objectives such as short-term and medium-term flexibility. 

Text Box 5. Bidding Demand Response into U.S. Capacity Markets

In some U.S. capacity markets, demand response can bid in alongside new generation resources. This 

serves a dual role in power system evolution, on the one hand shaving peak load and mitigating the 

need for new supply-side resources, and on the other hand providing a supplemental revenue stream for 

load beyond the avoided energy costs. Such allowances of capacity markets appear to stimulate 

investment. For example, in the PJM capacity market in the eastern United States (known as the 

“reliability pricing model”), the megawatts of demand response resources that bid into the auction for 

delivery in year 2015/16 grew more than 150% over the amount bid into the prior year auction (EMC 

Development Company 2012), representing 9.6% of total cleared capacity (Bowring 2013). Currently, 

some of the PJM products allow limitations on demand response’s availability (e.g., number of events 

per year). To make the quality of demand response participation equal to thermal generation, demand 

response could be required to meet the same performance obligations, i.e., no limits on number of 

events, for example by bundling multiple demand sites that can be aggregated to provide unlimited 

interruptions (Bowring 2013). 

It should be noted however that stringent measurement and validation of demand response is required 

for market participation, and demand response does not resolve all issues related to flexibility, system 

stability, or incentives for retaining some amount of thermal generation. Demand response is discussed 

more extensively in Section 4. 

3.1.3 Variable Renewable EnergyImpact on Adequacy

With high penetrations of variable renewable energy from wind and solar, the expectation is that 

the inherently low marginal costs of these generators will lower average wholesale energy prices 

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13 

(see Figure 3). Conventional generators, which will be displaced more often and sell energy at 

lower prices when they are selected, are therefore likely to run at lower (and less predictable) 

capacity factors and earn less revenue from the energy markets (Milligan et al. 2012; Bauknecht 

et al. 2013). In these markets, energy prices might be zero for extended periods of time, and 

generators risk receiving average energy revenues that fall short of their average costs (Stoft 

2002). In markets with capacity payments, capacity prices will increase as net revenue from 

energy markets decreases. In energy-only markets, if scarcity pricing is insufficient, then 

generators might need supplementary sources of revenue for their continued provision of 

services that enable the power system to maintain sufficient reliability (Bowring 2013). 

Furthermore, the type of capacity that the system requires in the long-term to ensure a reliable 

system becomes more important. Although generation planning has typically been about the 

energy (e.g., peak MW) capacity—and capacity alone—that new resources would add to the 

system, future planning could require system participants to offer certain traits or capabilities, 

such as flexibility. In doing so, incentives must be in place to ensure that new capacity brings 

with it these traits. The following new market designs represent approaches to address these 

topics. 

Figure 3. Mean diary [daily] market prices based on wind penetration levels

(Spanish hourly data, 2007–2012, provided by Red Eléctrica de España) 

3.1.4 Capabilities Markets 

Understanding that undifferentiated capacity markets, even over long time horizons, would be 

insufficient to create investment incentives for the right types of resources, the Regulatory 

Assistance Project (RAP) has proposed a capabilities market that addresses the quality of the 

capacity (Hogan 2012). RAP suggests two approaches. For markets without capacity markets, it 

proposes an enhanced services market mechanism, which would create periodic forward auctions 

to procure the required mix of balancing capabilities from new and existing generators. For 

markets with existing capacity markets, RAP suggests restructuring them to apportion the 

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14 

requested capacity over tranches of varying quality. RAP cites PJM’s early version of its 2006 

market design as an example of possible tranche types: Dispatchable (“rampable”), flexible 

cycling (fast and frequent stopping and starting), supplemental reserves, and all others. This 

approach necessitates prioritizing the type of capacity needs and establishing appropriate metrics.

The value in having a differentiated capacity mechanism depends in part on whether energy and 

ancillary services markets alone create sufficient incentives for flexibility (e.g., through ramping 

products; discussed in Section 3.2). 

3.1.5 Capacity Provision by Renewable Resources 

Variable renewable energy resources such as wind and solar power can contribute to resource 

adequacy, but typically do so at a lesser fraction of their installed capacity as compared to 

conventional resources such as coal or gas. Biomass and geothermal can contribute to long-term 

planning close to their rated capacity as long as there are no significant fuel-supply constraints 

(long-term fuel adequacy for biomass, heat constraints for geothermal). The capacity 

contribution of wind power ranges from about 5% to 40% of rated capacity (Holttinen et al. 

2013).9 The wide range is a result of differing levels of correlation between wind energy delivery 

and load level. The capacity value of a variable resource starts to decline at greater penetrations, 

when the events with low variable generation start to dominate the peaks in the net load. Work 

on solar energy is emerging. 

Other approaches are under development for differentiating the value among generation options. 

For example, Text Box 6 describes the approach that Mexico is taking to include environmental 

externalities in merit order dispatch as a way to stimulate new investment in renewable capacity.

Text Box 6. Mexico: Incorporating Environmental Externalities in Electricity Dispatch10

Incorporating the value of environmental or social externalities into power generation is one of the key 

challenges of a 21st century power systemreducing the health and environmental impacts of 

electricity service while maintaining the traditional motivation of improving reliability and costeffectiveness of electricity service. The Mexican Power and Climate Change legal framework mandates 

the federal government and the national utility, Comisión Federal de Electricidad (CFE), to incorporate 

the value of environmental and social externalities into the pricing of electricity.

Until recently this mandate was performed by CFE, the Secretariat of Energy, and the Secretariat of 

Public Finance as part of a cost-benefit analysis of selected renewable energy projects, and not included 

in the initial stages of sector planning when technologies are evaluated against each other on a cost 

basis. This limited the transformative impact on sector planning. Since 2012, the federal government 

began revising the framework for a new externalities policy, with a protocol that includes not only the 

cost-benefit analysis from CFE, but which also incorporates externalities into merit-order dispatch and 

planning for new investments by CFE. The Transversal Strategy for Productivity 2013–2018, published 

on August 30, 2013, mandates “Establishing prices and tariffs of energy that incorporate environmental 

externalities and promote its efficient use,” which addresses the need to provide market-based 

 

9 The low end of the range reflects situations where, for example, wind generation occurs primarily during non-peak 

hours, but is also affected by other factors such as total installed wind capacity.

10 This text box was contributed to the report by José María Valenzuela of the Secreteriat of Energy in Mexico.

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
15 

mechanisms for achieving such goals, and which includes private investors.

Some of the main challenges to implementing the protocol and other policies that value externalities

include the need for significant investment in research infrastructure and human resources, as well as 

coordination among environment, health, and energy sectors. But even if externalities are properly 

valued, there is the need to choose adequate implementation mechanisms to enable transformative 

consequences.

Renewable energies—both conventional and unconventional—are included in dispatch entirely due to 

their low marginal generation costs. Hence, developing an externalities policy for dispatch only 

modifies the merit order among fossil-fuel generation, providing a competitive edge for natural gas 

versus heavy fuel oil, on the short term. Yet, the system capability to increase power generation from 

gas is limited by gas supply infrastructure. Therefore, commitment to an externalities policy fosters 

new, cleaner investments if public and private investors receive adequate pricing signals on future 

developments. While CFE is mandated to include the value of externalities in the levelized generation 

cost for its technologies, private actors are not required to make such a commitment. 

Carbon pricing directly or indirectly through a tax on fossil fuels would provide such a price indication 

for global pollutants. Nevertheless, schemes for pollutants of local and regional impact shall remain in 

place to complement the externalities policy system, leaving the incorporation of externalities into the 

dispatching merit tables as the more certain tool.

3.2 Energy

Wholesale energy markets comprise the central transaction platform in power markets. Although 

some details in energy markets can vary, as discussed below, in all cases energy markets attempt 

to arrive at an economic allocation of generator dispatch that meets demand and satisfies security 

constraints. 

In the United States, the energy markets run by RTOs/ISOs consist of two-settlement markets, 

where electricity is procured in a day-ahead market, followed by a real-time market, which meets 

any imbalances that occur. The locational marginal price (LMP) is the price paid to generators, 

and is set by the marginal cost to serve load in a particular location. If congestion restricts 

sending lowest-cost electricity to a particular location, higher-priced electricity is dispatched and 

the higher price is reflected in the LMP. Generators have financial schedules in the day-ahead 

market that are paid the day-ahead LMP, and any additional generation they are asked to provide 

in real time is paid the real-time LMP. If they reduce output relative to schedule, generators pay 

back that portion of the amount committed day-ahead at the real-time LMP. Most of today’s U.S. 

energy markets are co-optimized with ancillary services markets, and incorporate transmission 

constraints into the price setting. Generators and loads have the option to settle outside the 

market, through bilateral contracts. The congestion costs that occur between them, however, 

must still be paid through contracts for differences. LMPs allow a close alignment between 

market schedules and real-time dispatch.

Most European markets offer day-ahead and intraday markets. In Europe, the power systems and 

energy markets are operated separately; the market clears a dispatch order, which then can be 

adjusted to accommodate transmission constraints. Germany, for example, with its extensive 

bilateral market contracts, requires longer gate closures to allow the TSO to conduct load-flow 

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16 

calculations and coordinate with neighboring TSOs, which in turn requires significant redispatch to resolve transmission constraints (Miller et al. 2013).11 Nord Pool offers zonal pricing. 

Increased penetrations of variable renewable energy affect the energy markets in three primary 

ways. 

1. The frequency and magnitude of changes to net load increase, which in turn require that 

the system have capabilities such as fast ramping and frequent on-off cycling. 

2. The possibility of forecast errors increases the difficulty in anticipating market outcomes, 

increasing the relevance of intraday markets (where available). 

3. The proportion of fully dispatchable supply could decrease as the low marginal costs of 

renewable energy displace them from the market.

Although wind turbines can serve as a fast ramping, flexible, dispatchable resource, wind energy 

and other variable resources, such as solar photovoltaics, have less predictability and availability 

than conventional energy supplies.12 The following market mechanisms are examples that could 

improve the ability of markets to accommodate these changes and better value flexibility. 

3.2.1 Dispatch Resolution

Energy markets that consist of short-dispatch intervals (e.g., 5-minute dispatch intervals), which 

already have been adopted in many restructured markets, improve system flexibility by more 

closely matching the changes in variable generation and load (“net load”) economically. As net 

load changes, the dispatch optimization responds as well—cost-effectively optimizing 

generation. Short-dispatch interval markets also reduce the required levels of regulating reserves

needed, which are the automatic resources that can respond to minute-to-minute fluctuations and 

are the most expensive ancillary service (Smith et al. 2010). High energy prices during the ramp 

periods also could provide an incentive for flexible supply. All generation receives the energy 

market clearing price in an energy market, as opposed to markets with ramp products, described 

below. 

3.2.2 More Frequent Markets

A two-step market with unit commitment in the day-ahead timescale will leave significant 

forecast errors to be resolved during real-time balancing. The balancing resources acting on the 

timescale of a few minutes can be relatively expensive (Kirby 2007). An alternative is to have 

some form of intraday market that enables participation from power plants with intermediate 

lead/start-up times (Kiviluoma et al. 2012). 

For example, the Iberian market already has a considerable share of variable generation. The 

market structure consists of a day-ahead market followed by six sessions in the intraday market. 

 

11 Gate closure refers to the future time at which the market commits to deliver electricity. Typically, gate closures 

that occur close to the actual delivery time (e.g., 5 or 15 minutes in advance) can help minimize the magnitude of 

forecast errors and associated reserves and allow for trading at potentially lower costs than power that would 

otherwise be required to balance day-ahead schedules (Cochran et al. 2012). 12 Wind generation can serve as a dispatchable resource by operating at reduced outputs, such as in response to a 

dispatch to ramp down, or in anticipation of a dispatch to ramp up. For example, MISO offers a Dispatchable 

Intermittent Resource Program, which allows wind to bid into energy markets.

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17 

The gate closure in the intraday market is 3 hours and 15 minutes. The intraday market is at 

times followed by a deviation management market, which is used when a deviation of more than 

300 MWh is expected to last several hours. A tertiary regulation market is used to recover 

secondary regulation reserves in the intra-hour timescale.

In the Nord Pool Spot, there is a day-ahead market followed by an intraday market, which 

matches bids continuously until one hour before the hour of delivery. This decreases liquidity in 

comparison to the Iberian intraday market, which has sessions that concentrate the trades. The

Iberian intraday market, however, has a longer delay between the trade and delivery. 

Consequently, in Nord Pool there is no need for a market between the intraday and tertiary 

regulation market, which is called the regulating power market in Nord Pool (and the real-time 

market in the two-step markets). Nord Pool’s regulating power market requires activation in 15 

minutes and also is used to meet operating reserves.

3.2.3 Ramp Products 

Ramp products, akin to proposals for flexible ramping and ramp capability products in the 

CAISO and MISO markets, respectively, are designed to periodically complement the fast 

energy market by providing for operational flexibility to meet load more reliably and efficiently, 

as well as incentivizing the specific resources that provide the flexibility to do so. The ramp 

product market price can have supplemental payments that are provided only to those resources 

providing the ramping support. Ramp products therefore reward only the flexible generation and, 

during these flexibility-scarce periods, do not reward inflexible resources. The ramp capability 

price would be zero during most hours, when ramping capacity in the energy dispatch mix is 

sufficient to follow load (Ela et al. 2012a). When ramping is neededwhether due to expected 

variability, or uncertainty in meeting the net load in future intervalsand not provided by the 

energy market, the price would reflect the marginal cost of providing that ramping capability, 

incentivizing flexible resources.

To add ramp capability and ensure sufficiently fast response, the Spanish TSO in May 2012 

implemented a new market for the management of additional upwards reserves (Ministerio de 

Industria Energía y Turismo 2012). EirGrid, the TSO in Ireland, also has proposed a new 

ramping product to respond to imbalances that occur over the minutes-to-hours timeframe, such 

as from changes in demand, wind generation, and interconnector flows. The TSO anticipates a 

broad range of resources to supply this service, including wind and photovoltaic (PV) plants that 

have been dispatched down, conventional generators, storage, and demand (EirGrid and SONI 

2012). 

3.2.4 Negative Pricing

Negative pricing can occur when serving the next increment of demand would actually save the 

system money; that is, the marginal cost to serve load is negative. For example, negative pricing 

can occur due to a lack of flexibility within the system. This might be due to limited transmission 

capacity creating location-specific negative pricing, minimum generation periods during which 

resources (e.g., coal, nuclear, hydro) cannot be shut down, and other reasons. Negative prices 

also can occur during periods of high variable renewable energy generation and low loads. In 

general, this can happen either due to resources setting the price with negative cost offers (e.g., 

due to production credits), or because of reduced capability to reduce generation and increase 

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18 

load (e.g., due to self-scheduled resources). Incorporating negative pricing into market design 

facilitates balancing and provides a financial incentive to increase system flexibility for several 

reasons. 

• Negative pricing can discourage generators, such as wind (unless tax incentives 

encourage production), nuclear, and coal from providing too much power when demand 

is low. 

• Negative pricing sends a strong signal to generators to be more flexible and reduce 

constraints on flexibility. In Denmark, the minimum running capacity of some older coalfired power plants has been reduced from 30% to 10% of maximum capacity due to 

dynamic and negative pricing (Blum 2013). 

• Negative pricing can encourage greater diversification in the location and types of 

variable renewable energy, especially in transmission-constrained areas. 

• Negative pricing can encourage the use of storage to absorb excess production, and load 

to increase demand. 

• Negative pricing can provide a transparent mechanism for curtailment of renewable 

resources via market means rather than out-of-market procedures. 

One concern about negative pricing in the United States is that with the production tax credit—

which in 2013 offers wind generators a $0.023 subsidy for each kilowatt-hour of energy 

produced—wind energy can still generate revenue when prices have become negative. They then 

can offer negative prices representing this “effective” cost of generating. This subsidized bidding 

can distort the clearing price and impact the rest of the generation fleet. A second concern with 

negative pricing is that it makes revenue streams more difficult to calculate, and therefore can 

deter investors from participating in energy markets.

When implementing negative prices, it is important for markets to coordinate with neighbors 

with respect to the use of administratively defined minimum price levels. At present these 

minimum price levels differ, for example, between Germany and Denmark, where flows from 

Germany to Denmark have been observed when Danish prices were negative and extra power 

was not needed, but German prices were even more negative. For example, this occurred in 

December 2012, when Danish bids were curtailed to achieve market equilibrium above the 

minimum price level, but even cheaper German power was imported anyway. Currently, 

measures are under consideration to avoid this occurrence in future. As already occurs in 

Denmark, individually negotiated compensation for offshore plants could be designed to 

eliminate fixed feed-in compensation during hours of negative prices to relieve stress on the 

power system, and this could be extended to include compensation from all wind power 

production. 

3.2.5 Forecast Integration

All U.S. RTOs/ISOs, all European TSOs with significant wind (e.g., Germany, Denmark, Spain, 

Portugal, Sweden), and most provincial dispatch centers in China forecast wind power 

production. The use of these forecasts, however, varies considerably from region to region 

(Porter and Rogers 2009). TSOs in Germany are mandated to trade wind power in day-ahead 

(and intraday) markets (where feed-in tariff support mechanisms apply). In other countries (e.g., 

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19 

Finland, Sweden, Norway), market participants must make their own forecasts for the portfolio 

they are bidding. In the United States, most RTOs/ISOs use a centralized day-ahead wind power 

forecast in the reliability unit commitment model, but not in the day-ahead market unit 

commitment model. This ensures that the RTO/ISO will have enough capacity to meet the 

forecasted demand with consideration of the forecasted wind power, but might not necessarily 

mean that it will be done in the most efficient manner. Power production forecasts are also used 

to improve situational awareness. 

Integrating advanced, centralized forecasts into market operations could increase market 

efficiency and provide additional opportunities for wind and solar resources to participate in 

electricity markets. A challenge in many countries is how to set up the most efficient forecasting 

modela mechanism to dynamically improve forecasting using both central and project based 

forecasting could be the way forward. Text Box 7 describes forecasting advancements in China. 

Text Box 7. Forecasting Advancements in China

In China, the State Grid’s Jibei Electricity Power Company Limited has been using a new energy 

forecasting tool from IBM in phase I of its 670 MW solar-wind energy facility. As a response to utility 

requirements, IBM created the Hybrid Renewable Energy Forecasting (HYREF) solution that performs 

advanced data analysis to improve predictions of wind turbine output. Using multiple data sources, 

including wind turbine sensors, weather forecasts, and images of clouds, the software can forecast 

power output for as brief a period as 15 minutes and as much as a month in advance. The combined 

weather and demand forecasting system has increased wind integration by 10%, powering 14,000 

additional homes. 

As important as the technology solution demonstrated in China is for renewables, it was the change in 

system operation rules and market design that provided the catalyst. Over the last decade, the massive 

deployment of wind in China has stressed the transmission and distribution system at key areas, 

increasing curtailment and other non-optimal outcomes. In 2011, China’s energy ministry and regulator 

issued a new forecasting requirement imposed on all renewable energy projects interconnecting to 

China’s grid. It is now law for every interconnecting wind, solar, and other utility-scale renewable 

project to provide day-ahead weather and energy forecast to the operator. This critical operations and 

policy change spurred the development of the 670-MW demonstration project by increasing market 

demand for more accurate and higher resolution forecasting capabilities for renewable energy plants. 

This issue of policy creating market demand for private-sector investment is not trivial. For example, 

the misalignment between actual renewables output and system demand stretches from up to 4 hours 

daily for wind and to up to 1.25 hours daily for solar. Matching renewable supply to demand could be 

worth up to $733 million globally (Dehamna 2013). 

3.2.6 Allowing Variable Renewable Energy to Participate as 

Dispatchable Generation

Wholesale power markets historically have treated variable renewable energy generation 

similarly to nonresponsive load in its dispatch optimization—a price taker with zero price 

elasticity (Ela and Edelson 2012). This worked with low penetrations, when market operators

wanted to maximize the amount of this low, marginal cost generation. Increasing penetrations of 

wind and greater instances of negative energy prices mean that a more efficient solution is to 

allow wind generation to make schedule and price offers (usually zero, reflecting marginal 

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20 

production costs) into the market akin to other generators, based on their most recent forecast. 

Similarly, enabling the operator to order the wind plant to ramp down temporarily to relieve 

congestion can allow plant dispatch to be optimized at the system level, can increase overall 

reliability and efficiency, and can ensure that curtailments are not conducted manually (Ela and 

Edelson 2012). In Europe, wind can—and in some cases must—bid into day-ahead markets and 

some intraday markets (closing one hour before delivery), but is not included in real-time 

markets. Many of the U.S. RTOs/ISOs now allow wind plants to submit offers for energy in the 

day-ahead markets. The New York ISO was the first to permit bids from wind plants, followed 

by PJM and MISO. In 2010, MISO introduced its “dispatchable intermittent resources” program, 

which allows wind plants to bid into the real-time market and update those bids based on subhourly forecasts.

The inclusion of renewable energy in markets affects revenue risks and project economics (e.g., 

from curtailments and imbalance charges) (Miller et al. 2013). In markets such as MISO, some 

contracts between wind generators and off-takers have required revision to reflect changes to the 

formal classifications of curtailments causes, which in some cases has shifted from reliability to 

economic. Although evaluating such rules in terms of project economics is beyond the scope of 

this report, markets can be designed to shift the responsibility for flexibility from specific plants 

to the system, such as through measures described above (e.g., intraday markets, short gate 

closure, better forecasting) (Bauknecht et al. 2013). 

3.3 Ancillary Services 

Grid reliability under conditions of significant instantaneous (e.g., 20% or greater13) renewable 

energy penetrations remains a particular concern of system operators. Although numerous 

studies have shown the impacts of integrating these renewables at the levels realized to date to be 

modest (GE Energy 2008; CAISO 2010a; EnerNex Corporation 2010; GE Energy 2010; Danish 

Energy Agency 2013), there are still outstanding questions on the best ways to integrate them 

reliably and efficiently, and also how to do so at greater levels of penetration. 

Ancillary services, as defined by the Federal Energy Regulatory Commission (FERC) and 

NERC, are those services necessary to support the transmission of capacity and energy from 

resources to loads while maintaining reliable operation of the transmission service provider’s 

transmission system in accordance with good utility practice. Ancillary service markets typically 

include spinning, non-spinning, and regulation reserves (Hirst and Kirby 1997). Other ancillary 

services, such as voltage control, reactive power, and black start are serviced through cost-based 

mechanisms and do not have markets (Rebours et al. 2007). The ancillary service markets are 

simultaneously cleared with the energy market in the two-settlement system. Prices are 

uniformly cleared based on the marginal value of that service. The price could include an 

availability cost as well as a lost opportunity cost. The lost opportunity cost is the revenue that a 

resource can forego in a separate market in order to provide capacity for that ancillary service. 

Ancillary services also have administratively set scarcity pricing, where the price reflects a 

shortage of the particular service. Some ancillary services also have location constraints, but they 

typically are not as strict as transmission constraints in the energy markets. 

 

13 The threshold for “significant” is system-dependent, and can be much greater in some jurisdictions before 

penetration levels become a concern. 

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21 

Variable renewable energy can affect the design of ancillary services markets in three key ways. 

1. The variability and uncertainty of wind and solar energy increases requirements for 

various ancillary services, affecting the scheduling and pricing of those services.14 

2. Their impacts vary depending on system conditions, which makes the ancillary service 

demands difficult to generalize across timescales and systems. 

3. Allowing variable renewable energy to participate in ancillary service markets can offer 

more supply to the market, but could offer challenges based on the unique characteristics 

of the variable resources in question. 

The aggregate impact of significant variable renewable energy on the grid suggests the need for 

modifications to current ancillary service market designs and rules, and the potential for new 

separate ancillary service markets. Some of these possibilities are reviewed below.

3.3.1 Dynamic Reserve Requirements (Secondary and Tertiary Reserves)15

Some of the recent renewable integration studies (EnerNex Corporation 2010) analyzed the 

effect that variable renewable resources would have on operating reserve requirements (see also

Text Box 8). The most recent studies have all concluded that the requirements should not be 

static, but in fact should change based on the actual and predicted conditions of the system (Ela 

et al. 2012a). The quantity of required reserves is proposed to vary hourly—which is not 

typically found in current operating-reserve requirements. Allowing reserves to vary by time of 

day and system conditions can better target the high-risk periods of significant change in the 

wind resource and reduce integration costs (Smith et al. 2010). By having a requirement that 

changes each hour based on predicted conditions, market participants would have to plan ahead 

to understand what the ancillary services demand might be, similarly to how they anticipate the 

load demand (Ela et al. 2012a), which again makes it more relevant to have a market for these 

services. 

One method of implementing a time-varying system reserve requirement is to have a reliable 

forecast of every unit, in near real time and crossing both balancing authorities and multi-utility 

system operating boundaries. Although RTOs/ISOs have some level of this capability now and 

receive forecast data, real-time visibility and access to, for example, meter-level data for 

aggregate demand-side forecasts, is extremely rare on a global basis. Generally speaking, the 

distribution-level power system does not exhibit sufficient sensing, monitoring, and real-time 

computational power to provide the level of reliability that operators expect from conventionally 

powered units. As demonstrated in the forecasting example in the previous section, mandatory 

rules—such as a requirement that changes each hour based on predicted conditions—can be a 

powerful change agent and accelerate development of the technological solution to the 

 

14 Contingency reserves, based on the size of the largest generator, remain constant if the renewable generator is not 

the largest plant.

15 Nomenclature for reserves varies widely (Rebours et al. 2007). In this report, primary reserves refer to the 

automated droop response of governors. Secondary reserves refer to synchronized resources that can respond rapidly 

to automatic control signals from the system operator to move up or down. Tertiary reserves refer to the resources 

that respond to non-automated dispatch commands that respond to planned and unplanned events, such as 

forecasting errors and outages.

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22 

operational problem. In other words, the technologies for “smarter energy” systems can meet the 

challenges put forth by greater renewable energy integration. What is required is a balance 

between three (sometimes competing) policy and regulatory objectives in the wholesale power 

markets worldwide, namely: (1) a non-negotiable reliability requirement, (2) dynamic and 

negotiable energy policies, and (3) a non-dynamic and deliberately paced regulatory rule-making 

methodology. 

Text Box 8. Impacts of Wind on Reserve Requirements: Experience of Spain

Balancing services in Spain are primary reserves, secondary reserves, tertiary reserves, and imbalances 

management. Primary reserves are not influenced by wind-power penetration, and non-dispatchable 

generation is planned to contribute to this reserve. The use of secondary reserves is affected slightly by 

wind-power ramping, but the required level of reserves remains unchanged. Tertiary reserves are 

influenced by wind power variability when wind power ramps are opposite to load ramps but, even so, 

the required level of reserves has only marginally been increased due to wind. Conversely, the use of 

and the required levels of imbalances management have experienced a significant increase due to wind 

power uncertainty. These reserves are offered in day-ahead markets as a function of wind power 

forecast error, guaranteeing balancing reserves from day-ahead to real time.

Text Box 9 describes the market-based approach used in India to maintain grid frequency. 

Text Box 9. Indian Mechanisms for Grid Disciplinethe Unscheduled Interchange

Since 1994, frequency discipline in India has been managed through the “unscheduled interchange” 

mechanism. The unscheduled interchange specifies a price curve linked to frequency, such that 

participants in the power system (both generators and load-serving entities such as utilities) face 

financial incentives to maintain grid frequency. Generators that deviate from their scheduled supply, 

for example, could either benefit or be penalized depending on whether the deviation is in the direction 

necessary to maintain grid frequency. So if the grid is operating above 50 Hz, and the generator undersupplies relative to its schedule, it incurs no penalty; rather it saves on fuel cost. If the grid is operating 

below 50 Hz and the generator delivers less power than scheduled, it pays a penalty linked to the 

deviation and the frequency rate at the time. Thus, there is a strong financial incentive to reduce 

generation (or increase demand) during high-frequency times, and to increase generation (or decrease 

demand) during low-frequency times (Bhusan 2005).

3.3.2 Primary Frequency Response

Although secondary reserves (also called regulation and secondary frequency control) help 

control frequency by maintaining balance, more immediate frequency control is accomplished by 

governors in the immediate seconds following a disturbance. This autonomous response is what 

stabilizes the frequency and helps avoid the triggering of under-frequency and over-frequency 

relays or instability that could lead to machine damage, load-shedding, and—in the extreme 

case—blackouts. Because conventional generators provide this service as part of interconnection, 

and because there was, at least in the large synchronous interconnections of the continental 

United States, more than enough frequency response in supply, this service was not explicitly 

compensated through cost-based measures or market designs (Ela et al. 2012a). 

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23 

The move to organized energy markets might have made the provision of frequency response a 

disincentive, however. This is because its provision could reduce plant revenue by requiring 

plant operation at somewhat less than maximum output to provide capacity to support frequency 

response, and because generators can be penalized for schedule deviations that might be needed 

to provide frequency response (Ela et al. 2012b). Several modifications could provide positive 

incentives for frequency response, including adding frequency response characteristics to other 

ancillary services markets, adding this service as a requirement for interconnection, or adding a 

new separate market product holding its own specific characteristics and schedules and prices 

(Ela et al. 2012a). Once the need for frequency response is recognized and made an incentive, 

emerging technologies which might not inherently have these capabilities will have the 

motivation to create innovative ways of attaining them (Miller et al. 2011). 

3.3.3 System Inertia

Variable renewable energy lacks inherent inertial response, which helps the system remain stable 

in the initial moments after a disturbance, before the automatic response by governors. 

Simulations by the Western Electricity Coordinating Council have shown that frequency 

response degrades during periods of high wind and low load, when conventional generators 

comprise a small share of the dispatch mix (Ela et al. 2012a).16 The simulations also show that it 

is technically possible for wind to sufficiently emulate this inertial response by connecting to a 

power electronic converter; some load and storage also can supply similar capability. Inertia is 

an inherent part of synchronous generation, therefore it has no added cost other than being 

online, and so a market similar to the other ancillary service markets, with changing schedules 

and prices, might not be the best approach. If some resources do provide the service, and others 

do not, however, then some sort of compensation might be required. 

3.3.4 Voltage Control

Reactive power, which supports voltage control, does not travel far due to high inductive 

impedances. It therefore is very localized which, in turn, inhibits a broad competitive market. 

Challenges for reactive power markets are further compounded by rules governing the 

procurement and use of reactive power capabilities. In general, all generators except wind plants 

are required to be capable of providing reactive power within a power factor range defined in 

their interconnection agreement, although in Spain new operating procedures are being studied to 

require wind turbines to provide voltage control (Ministerio de Industria Energía y Turismo 

draft). Compensation for provision of this service varies by transmission provider. In the United 

States, there is no requirement to compensate generators for reactive power within the power 

factor range unless the transmission provider is compensating its own generators. Generators 

typically are paid for fixed costs as well as opportunity costs; that is, any costs it foregoes in the 

energy markets because of constraints on providing reactive power (Federal Energy Regulatory 

Commission 2005). Yet, market simulations demonstrate potential for a competitive reactive 

power market. For example, simulations assert that in an optimal market, nodal reactive power 

prices would remain at zero, except during contingencies, when prices would be low (Thomas et 

al. 2006). This pricing scenario still would meet long-term average costs due to the low cost of 

investment in reactive power supply. The complexities of solving the market models with a 

 

16 The Western Electricity Coordinating Council is a regional forum that promotes electric service reliability in 

western Canada and the western United States. 

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24 

reactive power provision—which would require solving the full alternating current power flow 

problem at intervals of as little as 5 minutes17—remains impractical, even though there can be 

significant benefits from a reactive power market (Hogan 1993; Cain et al. 2012). 

3.3.5 Co-optimization

The co-optimization of energy and ancillary services has improved the market efficiency of 

scheduling and dispatch (Hirst and Kirby 1997; Singh and Papalexopoulos 1999). Nevertheless, 

exceptions to co-optimization might be necessary to ensure a broad base of supply for ancillary 

services. Load is ill-suited to co-optimization, for example, because the opportunity cost for 

participation includes factors beyond energy price, and participation particularly depends on the 

duration of response (Ela et al. 2012a). Storage, with its limited energy, also is not suitable for 

co-optimization. NYISO changed its market rules to exempt storage from co-optimization in the 

energy market (Smith et al. 2010). 

3.3.6 Ancillary Service Provision by Renewable Resources 

Although much research has focused on how variable renewable resources could increase the 

need for ancillary services, variable renewable resources also can be used to provide these 

ancillary services (Miller and Clark 2010; Miller et al. 2011; Ruttledge and Flynn 2011). 

Currently, rules do not allow this provision in most of the ancillary services markets. In 

Germany, auctions for frequency control reserves occur six days in advance, which effectively 

precludes wind energy from bidding due to forecasting uncertainties (Holttinen et al. 2012). 

Variable generation, however, can provide great flexibility. Variable renewable generators can 

have fast electronically controlled ramp rates, zero minimum generation levels, and no start-up 

time needs. With increased penetrations, it might be more economical to utilize variable 

renewable resources to provide these services for both consumers (in terms of reduced 

production costs) and for variable renewable generators (in terms of increased profits) (Kirby et 

al. 2010). Text Box 10 describes the provision of ancillary services in some markets by demand 

response. 

 

17 Today’s real-time markets typically use a DC power flow, which ignores reactive power and variations in voltage.

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25 

Text Box 10. Provision of Ancillary Services by Demand-side Resources

Demand-side resources increasingly are providing ancillary services to the grid, in roles that require 

faster and more verifiable performance than traditional uses of energy efficiency. Demand-side 

resources long have been employed in ways that only require several hours of lead time, such as 

“interruptible load” for emergency peak shaving (Pfeifenberger and Hajos 2011) or to increase 

nighttime load during off-peak price periods. Yet, provision of ancillary services occurs on much 

shorter timescales, typically seconds to minutes. Such fast-acting demand response is employed in 

several U.S. wholesale markets including ERCOT, PJM, and MISO (Pfeifenberger and Hajos 2011). 

System security requires that such systems ensure rigorous performance characteristics (response time 

and minimum load size), special contractual and compensation mechanisms, robust measurement and 

verification methodology, and high-speed communications interface to enable automatic control. As 

such, industrial sources have predominated in providing ancillary services. Pilot and demonstration 

projects are underway to aggregate residential and commercial resources to provide ancillary services

(Navigant 2012), but significant legal and technical barriers remain to ensure adequate performance 

characteristics.

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26 

4 Bridging Opportunities Between Wholesale Markets 

and Emerging Technologies

Bridging opportunities between wholesale markets and emerging technologiessuch as demand 

response, distributed generation, and distributed storagehas the potential to reduce system 

costs, including costs at the distribution level, where these resources can address congestion, 

losses, and inadequate infrastructure (Sioshansi et al. 2012). The distinct characteristics of these 

resources, however, particularly distributed resources, present challenges to creating nondiscriminatory access in the wholesale market. This section reviews wholesale market 

considerations specific to each of these types of resources. 

4.1 Demand Response

Increasing the price responsiveness of electricity demand, either through voluntary reaction to 

price signals or through contractual commitments to change demand in response to system 

events, holds promise for reducing system peaks and adding significant flexibility to the grid. 

The technical potential for demand response is growing. Globally, some analysts estimate that 

55% of all meters globally will be “smart” by 2020 (Navigant 2012). This widespread 

deployment of smart meters enables residential and commercial demand response to be more 

widely integrated in power markets, but various technical obstacles remain. For example, the 

reliability with which demand response can directly cushion the variability of renewable energy 

depends on its characteristics. From a flexibility perspective, prized qualities include: direct 

dispatchability to either increase or decrease demand; little or no advance notification; fast 

response; ability to be called upon frequently; and verifiable visibility to the operator (Cappers et 

al. 2012; Cutter et al. 2012). 

Beyond the technical obstacles, institutional barriers also inhibit demand response—in the 

residential sector in particular—from fully participating in wholesale markets. Two critical

institutional barriers are regulatory and customer-related barriers, but some market rules also 

represent barriers in many locations. 

4.1.1 Regulatory Barriers

Current regulatory structures are the greatest barriers to increasing the potential for demand 

response (Kirby et al. 2011). These structures typically reflect the traditional demarcation

between wholesale power markets and retail rates and programs, and often are ill-suited to 

demand response, which straddles the wholesale-retail divide. In the United States, for example, 

RTOs and ISOs under the regulation of the Federal Energy Regulatory Commission operate 

wholesale power markets and maintain reliability, and they can design energy and ancillary 

markets to include demand response. The extent to which RTOs/ISOs can integrate demand 

response is limited, however. Retail rates are the jurisdiction of the states, and RTOs/ISOs are 

not structured to interact with small customers or to determine demand baselines. 

In most settings, regulated utilities (i.e., load-serving entities, distribution system operators) 

directly serving customers are the main intermediary for retail rates and customer interaction. 

This means that retail customers are not legally allowed to “cut out the middle-man,” 

participating directly in wholesale power markets and gaining direct exposure to variability in 

reliability and price. Instead, LSEs, with regulatory approval, serve the function of creating price 

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27 

and event signals and interacting with retail customers, but their institutional options also are 

limited. Many LSEs, for example, have programs that curtail individual loads to reduce peak 

demand. If aggregated, such individual load control also could potentially be sold in the 

wholesale market as an ancillary service product, although at the time of this writing such an 

arrangement has not been demonstrated at full scale. The LSE could face various local regulatory 

restrictions, however; for example, on the number of times it can curtail load, thus eliminating 

the option of frequent but short-duration spinning reserves. In the PJM Interconnection in the 

United States, where the RTO/ISO coordinates demand response, some LSEs view PJM as a 

competitor in aggregation services (Greening 2010). 

Another source of customer-related complexity that varies across different regulatory 

environments is the legal treatment of third-party aggregators on the customer-side of the meter. 

Third-party aggregators—in locales where they are allowed to operate—can develop demandresponse programs without prior approval and restrictions by regulators, although the ability of 

these aggregators to set prices and demand response-event thresholds and frequency might be 

unclear, thereby limiting investment.

This disjointed regulatory structure gives rise to a situation in which federal regulators can 

require system operators to implement demand-response programs that impose costs on local 

utilities, but these utilities must seek approval from local regulators to recover costs from 

customers (Greening 2010). These persistent disconnects between distribution and transmission 

systems pose a variety of challenges to the integration of distributed resources and raise issues 

such as data sharing and systems control. These and other broader concerns are becoming 

increasingly important for grid planning and operations. 

In many ways, the regulatory obstacles to demand response revive the conversation about retail 

electricity market reform—a process that has been less widespread than wholesale market 

reform.18 The question is whether residential demand response could emerge more quickly in a 

competitive retail market arrangement than in fully integrated monopoly arrangement. In 

Denmark, a national smart-grid strategy seeks to finalize the rollout of retail smart meters by 

2015, in time for a new model of variable (hourly) pricing schemes at the retail level, connected 

to the planned wholesale accounting system (Danish Ministry of Climate, Energy, and Buildings, 

2013). In the European Union, four different task forces on smart grids recently have been

working to clarify appropriate market models (Eurelectric 2013). Regulatory reforms that have 

been suggested include recalibrating the roles of RTOs/ISOs, LSEs, and third-party aggregators 

based on their roles in providing information. For example, RTOs/ISOs could provide a market 

platform, with information on price elasticity associated with bids; LSEs and aggregators could 

provide market research and information to customers on risks and benefits (Greening 2010). 

Also proposed is the unbundling of utility services—restricting utilities and LSEs to incentive 

programs and price and event signals (the utility side of the meter)—and allowing other market 

providers to offer services on the customer side of the meter (Cappers et al. 2012). This type of 

structure is in use in Finland, where demand response aggregators are market participants and 

DSOs only are allowed to provide indiscriminate aggregator access to the smart meters.

 

18 Retail electricity market reform will be discussed in greater detail in a future 21st Century Power Partnership 

report. 

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28 

Over the next several years, these important regulatory questions could be translated into action 

in countries that have plans to launch comprehensive energy-market reform, for example Japan, 

India, and Mexico. Generally speaking, all three countries are starting from scratch in the 

wholesale energy and capacity markets, as well as in the definition of—and demand-side 

participation in—retail markets. After a long period of vertically integrated, monopolistic market 

design, the Japanese power sector is moving towards both unbundling and retail competition 

(Ministry of Economy Trade and Industry 2013). The new energy reforms recently approved by 

the Japanese Cabinet primarily focus on unbundling the generation, transmission, and retail 

sectors by breaking the DSO’s into private-sector actors, with a second phase planned to spur 

retail competition. 

Similarly, India is considering pathways to increase the fiscal health and efficiency of retail 

DSOs, while simultaneously seeking to integrate increasing amounts of wind energy, and reduce

the widespread incidence of involuntary load-shedding. Leaders in the Indian power sector seek 

a more market-based approach to load management, based on voluntary response to dynamic 

tariffs (ISGAN 2013a). Smart meters, which will support this dynamic tariff scheme, still are in 

early stages of deployment, but there are plans to dramatically increase deployment. Enacting 

operational rules that clarify the interaction between retail demand response, wholesale energy, 

and ancillary services markets could be important in the emerging Indian regulatory framework.

In Mexico, smart-meter deployment has been piloted in various communities by the national 

utility, CFE, as a means to increase reliability and to reduce operating costs and non-technical 

losses (ISGAN 2013b). The president of Mexico recently proposed broad restructuring of the 

power sector, with a near-term focus at the wholesale level. At the same time, significant new 

wind generation is expected in Mexico. Looking forward, some of the flexibility necessary to 

integrate this wind might be accessible from demand response at the retail level, providing that 

the regulatory framework is made clear. 

4.1.2 Customer-related Barriers

A second major barrier to incorporating demand response is customer willingness and ability to

participate in ways that provide clear system benefits. In most cases, this means allowing

equipment to be dispatched automatically, either by the system operator or a third-party 

“aggregator” participating in wholesale markets. To best serve as a resource for grid integration 

and respond to year-round variability and uncertainty, dispatchable equipment should be 

available all year (e.g., water heaters as opposed to air conditioners), and at a range of timescales 

(Cappers et al. 2012). 

Communications standards are needed to enable secure load control, accurate metering, and a 

platform for transacting data with individual customers. Nevertheless, some customers have 

expressed concern about smart meters and outside control of appliances, and regulators are 

navigating the questions about who should pay the extra costs of automation equipment and the 

marketing of demand-response programs. Additionally, in many settings retail customers also 

hold long-standing expectations of flat electricity prices. 

Several proposals have been made to reduce these barriers, including rate-based recovery of 

infrastructure investment, marketing efforts that illustrate potential savings under dynamic rate 

structures, incentives and rebates for smart appliances, and the encouragement of third-party 

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29 

aggregators, particularly if utility services are unbundled (Greening 2010; Cappers et al. 2012). 

Designing an appropriate mix of these measures requires attention to promoting customer 

participation within specific technology, market, and regulatory scenarios (Greening 2010). 

Some European projects investigate both technological and social acceptance issues, such as the 

Ecogrid.eu project (2011–2014), in which 2,000 private customers located on the island of 

Bornholm, Denmark—which is supplied by 50% renewables—can participate in the real-time 

market. The participants’ houses are being equipped with devices that use remote control and 

intelligent control to promote flexible demand. The customers can see the real-time prices and 

set their individual automatic flexible demand. Experience with different types of smart metering 

and social acceptance is being gathered in this project. 

Similarly, in the United States, a series of consumer-behavior study projects initiated in 2010 aim 

to investigate the impact of both technology and pricing variables on smart-grid deployments. 

The studies investigate the demand impact of various technology packages—smart meters plus a 

range of in-home informational devices—together with variable pricing plans, such as prices 

pegged to real-time wholesale prices versus tiered prices linked to critical peak hours

(Department of Energy 2011). 

Across jurisdictions there is an emerging view that, regardless of individual consumer behavior, 

it is important to create the right market structures to allow third-party aggregators to innovate 

new products and arrangements to control a large number of load devices, such as water heaters, 

heat pumps, or electrical vehicles. The city of Kalundborg, Denmark, for example, has provided 

an open platform and incubator program for companies to test business models for controlling

electricity, water, heating, transport, and buildings (Smart City Kalundborg 2013). 

4.1.3 Market Rules

Power markets evolved to accommodate conventional dispatchable generators. This makes it 

challenging to incorporate retail demand response, where participation is mediated by factors 

that include retail rate structures and limitations on duration and frequency. Changes to tariffs 

and reliability rules might better value demand response. 

Real-time pricing offers a direct avenue for mass-market participation in demand response 

markets by allowing customers to experience the variability in pricing and adjust their demand 

accordingly (Hogan 2010; Cappers et al. 2012). This would obviate the need for most demandresponse programs and the associated difficulties in designing market rules to allow their 

participation. Real-time and other scarcity pricing also could help demand response to mitigate 

market power by offering a means for moderating supply shortfalls and controlling price 

excursions. Price risks could be mitigated by allowing demand to participate in forward markets

(Greening 2010). Although real-time pricing could be structured as an optional alternative to 

regulated tariffs, this option nevertheless would require the support of state regulators, who 

historically have worked to insulate customers from variability.

Barring this approach, market rules would have to be designed specifically to include demand 

response in the bulk power system. Hogan (2010) described the difficulties in valuing demand 

response in energy markets as the difference between reselling something you have purchased, 

and selling something that you would have purchased, without actually purchasing it. One 

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30 

complication is establishing a baseline methodology, and this methodology can differ among 

forecasting, impact estimation, and billing (Cutter et al. 2012). Direct dispatch, however, or the 

option to dispatch via capacity payments, simplifies these calculations (Cutter et al. 2012). In 

FERC Order No. 745, the Commission described a net benefits test to identify the costeffectiveness of using demand response to balance supply and demand. This rule requires 

RTOs/ISOs to pay demand response at the LMP rate when the net benefits test shows that a 

demand-response resource is cost-effective. 

In Finland, part of the zonal Nord Pool spot market, sufficient electricity to cover demand is 

bought on the day-ahead market and the transaction is financially binding. In this market, 

demand response can be built into the bid with price and volume steps. At later markets, demand 

response will be offered as a deviation from the original schedule. At real time, any remaining 

deviation in the balance of the LSE is addressed using the regulating power market, which has a 

15-minute activation time. Demand response also can participate in that market.

Participation in ancillary markets might be more straightforward when automated demand 

response is relatively indistinguishable from generation, and new market rules are better at

valuing the speed and accuracy of demand response, which usually is faster than the typical 5- to 

10-minute services (Kirby et al. 2011).19 Nevertheless, changing utility business models and 

requirements of demand-response resources regarding, for example, attributes of performance 

and revenue availability, are some of the most effective ways to reduce barriers to participation 

in ancillary services markets (Cappers et al. 2013). 

Other proposed changes include separating regulation up from regulation down to be inclusive of 

loads that provide only unidirectional services (Cappers et al. 2012). Market-clearing software 

could better incorporate the participation of demand response by including individual operating 

constraints, such as duration, frequency, and notification times (Kirby et al. 2011). Forecasting to 

reflect uncertainty also would improve operations and long-term planning (Kirby et al. 2011). 

There also are concerns that prices for ancillary services could fall below sustainable levels with 

significant participation by demand response, which can have zero opportunity costs (Kirby et al. 

2011). Co-optimization with the much larger energy markets however, so far has limited the 

impact of new resources on prices (Cappers et al. 2013). In the Nordic power system, a large 

portion of the primary frequency reserve is served by industrial loads. The opportunity cost can 

be high, however, as this method often leads to short interruptions in the industrial processes. 

4.2 Distributed Generation

Distributed generation, which is generation located within distribution networks or on the 

customer side of the network (Ackermann et al. 2001), can help decrease transmission and 

distribution losses, and offset the need to upgrade infrastructure. In particular, microgrids—

which can dispatch and manage local generation and demand—have the infrastructure to interact 

with the wholesale power markets. Some types of distributed generation, such as combined heat 

and power, can readily participate in wholesale power markets. Other types, such as residential

 

19 See, for example, PJM’s new (October 2012) performance score to calculate compensation for regulation services, 

“Enhanced Certification, Measurement, Differentiation.” This service provides greater compensation for faster 

response.

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31 

PV, only will interact with the bulk power system as penetrations increase. Distributed 

generation’s potential negative impacts on the grid include voltage increases, power fluctuations, 

and unintentional islanding. 

Combined heat and power plants primarily use fossil fuels to produce both electricity and lowtemperature steam for district heating. In Denmark, these plants are required to participate in

wholesale power markets, and a third of the plants also participate in real-time energy markets.20

Their electricity generation therefore is optimized by the power markets—when competitively 

priced, combined heat and power produces electricity and its heat byproduct. When Denmark’s 

significant wind generation reduces prices, combined heat and power plants cease electricity 

production and rely on thermal storage to maintain heating (Kiviluoma and Meibom 2010). The 

thermal storage enables combined heat and power to complement wind power rather than 

compete with it. 

Residential PV currently remains primarily of interest at the distribution level. In the United 

States, states regulate residential PV through the LSEs and residential tariffs, and there is little 

interaction with the bulk power system. Residential PV in many jurisdictions is valued according 

to the retail rate its power offsets; therefore, it is valued higher than it would be through 

wholesale markets. As PV prices continue to fall, penetration likely will increase significantly. 

Structuring the wholesale power market to accommodate this generation without curtailment 

would create a disincentive for centralized (“curtailable”) PV. Increased penetrations also likely 

will lead to revisions in interconnection standards to require PV to provide reliability services—

such as reactive power support—mirroring the evolution in standards and expectations of wind 

generation as its penetration increased. Germany already has instituted low-voltage ride-through 

standards for grid-connected PV, even at the residential level (Passey et al. 2011). 

Economic signals and system operator controls on the distribution grid that are similar to 

wholesale power markets collectively could help integrate wholesale and retail markets

(Sotkiewicz and Vignolo 2006). Currently, there are no pricing mechanisms on the distribution 

grid due to the complexity involved. Having transparency on the distribution grid via prices

would both create economic opportunities for distributed energy resources and improve bulkpower operations on systems with variable renewable energy (Rahimi and Ipakchi 2012). 

4.3 Storage

Storage is an asset that can act as a generator, load, or alternative to transmission, and it can 

provide significant flexibility for the bulk power system. Except for storage that can be centrally 

dispatched, such as compressed air energy storage and pumped hydro, storage faces some of the 

same barriers to participation in wholesale markets as demand response, including incomplete 

valuation (e.g., by reducing costs of plant cycling), restricted access to markets (e.g., behind-themeter storage), and conflicting regulatory structures as described below (Sioshansi et al. 2012). 

Although some market products discussed above would be well suited for storage (e.g., ramping, 

voltage support), other characteristics of storage still would be inadequately valued. For 

example, distributed storage can alleviate distribution-related congestion, but LMPs reflect only 

 

20 In Denmark, real-time energy markets are called “regulating power markets.”

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32 

transmission congestion. Also, the energy in behind-the-meter storage (typical of customerowned thermal energy storage) cannot be dispatched and is limited to utility rates, which lack 

scarcity and variable pricing that could improve its economics. 

Regulatory structures also pose considerable challenges for complete valuation of storage 

(Sioshansi et al. 2012). Storage can provide generation, transmission, and distribution benefits, 

but in the United States it can only be classified as one type. Generation is valued in wholesale 

power markets, whereas transmission and distribution assets are rate-based. The FERC has not 

allowed rate-based transmission and distribution assets to participate in energy markets, and a 

full market-based approach would inadequately value the transmission and distribution services 

of storage. Both choices result in suboptimal use of storage. One way to get past this barrier is to 

disaggregate the services by allowing the storage owner to sell storage capacity to a third party 

(Sioshansi et al. 2012). 

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33 

5 Challenges to 21st Century Market Design

Market frameworks offer great promise for achieving 21st century power systems, insofar as they 

encourage innovation, minimize system costs, and facilitate access to a broad range of options 

that increase system flexibility. Yet, there still are ongoing challenges involved with the design 

of markets for enabling greater penetrations of variable renewable resources and other emerging 

technologies. A few of these challenges are listed below. 

5.1 Minimizing Complexity

Electricity markets have evolved into complex designs with the goal of integrating efficient 

economic principles with the engineering and physics of the electric power system.21 Complex 

market designs might be critical in helping achieve desired outcomes, but such designs also 

could make it difficult to attract extensive market participation.22 

In some cases, design elements introduced to meet emerging objectives, such as for flexibility, 

can amplify existing market complexity and cause undesired interactions with existing market 

designs. Flexible resources have numerous attributes including, for example, the ability to start 

and ramp quickly, cycle on and off, and absorb excess power. To achieve flexibility, market 

designs seek to value these multiple attributes at multiple timescales. Although the aim of 

electricity market designs is to be indifferent to resource type, this becomes difficult and 

complex when resources have different characteristics that are not easily compared in the market. 

Flexibility can be provided by generation, demand response, transmission, and storage resources, 

each with differing capabilities. The difficulty of rendering markets simple enough to achieve 

deep participation, and neutral enough to invite participation from emerging resources such as

demand response and storage, could be why new qualities such as increased flexibility might not 

be incentivized to the extent needed with high penetrations of variable renewable energy. 

Furthermore, to the extent that markets for capacity, energy, and ancillary services interact, 

design changes in one market could create a disincentive to operate in other markets, such as 

energy market rules inadvertently removing incentives for participation in certain ancillary 

service markets (Ela et al. 2012b). In more serious cases, these interactions could create 

opportunities for market power and market manipulation. Relatedly, too much complexity also 

could necessitate more frequent market revisions and could weaken transparency (SchleicherTappeser 2012). 

5.2 Encouraging Investment

In most wholesale markets, energy prices are based on the marginal cost of providing energy, 

and therefore do not include any of the capital costs of the resources. Investors calculate the risk 

adjusted returns of potential projects; and as energy prices decrease with increasing penetration 

of zero dispatch generation sources, other revenue sources become increasingly important, 

 

21 Economically efficient refers to providing the lowest-cost solution to meeting the objectivein this case, 

electricity demand subject to reliability rules.

22 Some physical factors of electricity systems, for example, reactive power supply and congestion on low-voltage 

distribution networks, have been deemed too complex to capture and meaningfully improve through market 

mechanisms. As such, these factors generally have been managed through non-market means.

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
34 

including scarcity pricing, capacity markets or payments, and bilateral, long-term power 

purchase agreements. There is debate as to the merit of each. 

Price volatility also can complicate cost recovery. Greater penetrations of variable renewable 

energy could both amplify price swings and make them more frequent (see Figure 4). The low 

marginal costs of wind and solar energy at times could result in extended periods of near-zero 

marginal prices over large areas, particularly during times when loads are relatively low and the 

wind and solar resources are plentiful. The variability and uncertainty of wind and solar also 

could lead to increased frequency of price swings between the near-zero marginal costs of wind 

and solar and the high price as determined by (a) the availability of transmission capacity, (b) the 

ability of the balancing authorities to smooth variable renewable supplies, (c) the ability of the 

balance of the generation fleet or load response to fill in gaps, and (d) the availability of peaking 

supplies, particularly simple-cycle gas turbines, to complete the response. In areas with 

significant penetration of variable renewable supplies, their low marginal costs over extended 

periods and over large areas impacts the recovery of capital costs for that area as well as for 

conventional supplies. 

Nevertheless, clear, long term, transparent policies might provide the strongest long-term 

investment signals (DB Climate Change Advisors 2009). Denmark for the last 40 years has 

maintained political agreement on the broad outlines of energy policy. The European Union has 

semi-certainty until 2020, but a 2030 framework currently is being discussed to send a clear 

signal about the direction of the energy and climate policy. 

Figure 4. Hourly wholesale prices, 2010 and 2030 (high variable renewable energy).

Poyry North-West European Intermittency Study (2011)

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35 

5.3 Harmonizing Across Timescales

A reliable and secure electricity supply requires sensitivity to multiple timescalesfrom system 

operations, where milliseconds matter, to capital investments, where decades matter. Electricity 

markets provide short-term price signals (seconds to days), which are effective at allocating 

available capacity. In contrast, few power markets provide any long term price visibility and are 

ineffective at incentivizing the optimal amount of long-term installed capacity to meet reliability

(Cramton and Stoft 2006). One difficulty of translating short-term price signals to long-term 

capacity is that energy markets cannot offer forward revenue certainty, which investors require to 

reduce risk and to cover fixed costs. Although debt investors remain reluctant to invest in new 

generation based on existing market products—such as short-term capacity markets—some 

equity investors are beginning to consider quasi-merchant renewable energy plants (partial 

power purchase agreement, partial market-based). Nevertheless, these investors require measures 

to mitigate market risks, such as minimum price levels or electricity or natural gas derivatives as 

a hedge. Increasingly, renewable energy is viewed as a hedge option against uncertainty

(Awerbuch 2006). The incremental investment in capacity is typically smaller than that of a 

conventional power plant, thus allowing investors to respond more quickly to short-term changes 

in price signals (Awerbuch 2006; Liebreich 2013). A challenge in market design is how to 

provide the right mix of market signals to encourage investments in new merchant generation 

(renewable or otherwise).

5.4 Ensuring Market Depth

As mentioned, market complexity can impede market depth, limiting the impact of market 

reforms. Yet, there also are many other forces working against market depth. In some markets 

(e.g., CAISO, MISO, Nord Pool, Central Western Europe Market Coupling), a significant 

amount of energy is sold through bilateral contracts, which provide long-term revenue certainty 

for the individual market participants, but remove generators from economic dispatch. Longterm power purchase agreements can be negotiated so that the average energy price allows for 

capital cost recovery. The implications for systems with high penetration levels of variable 

renewables but significant bilateral contracts are threefold. First, most energy delivery is 

purchased months to years in advance, locking in generation that could be inflexible,23 and 

leaving a small day-ahead and real-time market for new, innovative, and flexible supply. Second, 

spot-market prices might be inconsistent with marginal costs due to the limited supply of 

flexibility. Third, limited participation in the day-ahead and real-time markets can decrease 

market efficiency by reducing the potential for market software to optimize supply resources 

based on their bid costs (CAISO 2010b). 

 

23 Contracts could be modified to support increased flexibility, but this might expose both parties to spot-market 

pricing, which is inconsistent with the desire to lock-in revenue streams.

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36 

6 Market-Design Research As a Platform for 

International Collaboration

Market-design research increasingly is a fertile platform for international collaboration.24 Given 

the range of complex and unanswered questions in this area, it is useful to perform careful 

analysis of candidate market options prior to their implementation. This is especially important 

in developing countries that have the chance to construct their energy sector, market, and power 

system to take into account lessons learned from the rest of the world. Such analytical activities 

could include the development of the following. 

• High-fidelity models to simulate the impact of market design options on power system 

evolution across a range of timescales, ranging from the millisecond scale (e.g., transient 

stability analysis) to the decadal scale (e.g., investment-behavior analysis).

• Consultative processes to directly and transparently collect key stakeholder requirements 

and to provide a platform for ongoing feedback and refinement of market designs.

• Experimental economics studies to more accurately reflect human decision making and 

strategic behavior as they could influence market evolution (Zhao et al. 2010). Such 

studies can reveal unintended consequences, such as undesirable interactions driven by 

incentives or adjacent markets.

• Market performance metrics to guide market-monitoring activities that assess market 

performance after implementation. A process to revise the market structure should be 

considered for inclusion in case the market does not perform as desired.

Using these and other methods, several important unanswered questions invite greater near-term 

international collaboration. Generally speaking, these questions often can be categorized as 

either short-term (operational) or long-term (planning). Some candidate questions include the 

following. 

6.1 Short-term Operational Timescale

• Are market reforms needed to increase flexibility? If so, are such reforms needed only in 

some contexts, or is this a general need spanning most markets? To what degree do 

system characteristics, renewable energy penetration levels, and institutional constraints 

impact the shape of flexibility-focused market reforms?

• What are the criteria by which price and market mechanisms to reward flexibility are 

evaluated in an operational setting? Market designers must evaluate competing 

mechanisms. As an example, probability-weighted pricing has shown promise, and 

perhaps could internalize risk and flexibility into reserve pricing (Ela and O'Malley 

2012). The development of such criteria can guide rigorous evaluation of options. 

• How can institutional arrangements unlock, rather than stifle, technical flexibility? For 

example, to what extent does the presence of significant bilateral contracts impact 

 

24 Collaborative international efforts include a range of specific projects managed by, for example, the COMITES 

program of Massachusetts Institute of Technology and Instituto de Investigación Tecnológica Comillas; the 

Regulatory Assistance Project; and Task 25 of the IEA Wind Implementing Agreement. 

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37 

flexibility? There is some concern that such contracts—which are valued by investors—

might stifle access to technical flexibility. If so, what options exist that could increase 

flexibility through bilateral contracts that would not violate investor requirements? 

6.2 Long-term Planning Timescale

• Of the different types of markets and options (e.g., capacity markets, ancillary services), 

which fit best with investor requirements? Why? (Compare investor requirements to 

functionality and risk/certainty that different markets provide.) Are there new innovations 

that have not yet been adopted that could increase flexibility and meet investor 

requirements?

• How much capital is available to construct new projects under the current market 

structures? How does this amount change if new market components/structures are 

considered? What investor requirements constrain actions by market players? How do 

these differ by type of investor (e.g., debt vs. equity)? Which actions are constrained 

(e.g., contract requirements)? 

• How does the market behave in its steady state (no growth in variable generation)? If the 

share of variable generation is increasing, is there a mechanism that is needed to 

supplement short-run pricing information so that long-term signals can induce more 

flexibility in the future? 

• Are capacity markets desirable and necessary? If so, what designs exist today that are 

successful and how has this success been measured? The counter-argument for capacity 

payments or a capacity market is that scarcity pricing would be sufficient to induce 

needed investment to achieve resource adequacy. A related question concerning scarcity 

pricing is whether the limited hours and duration of price spikes could be alleviated with 

a very small number of suppliers, potentially causing enough market power that might 

result in self-collapsing prices. These are open questions whose answers have not been 

robustly demonstrated. 

• What is the most efficient division of roles between market and regulated components 

and which criteria should be used to evaluate this? For example, an RTO/ISO determines 

the need for capacity and the characteristics of that capacity. (How flexible does it need 

to be?) It then conducts a request for proposal, auction, or other competitive mechanism 

to acquire the capacity. Or would it be desirable (or even possible) to provide alternative 

levels of reliability to customers based on their willingness to pay?

• The recommended method for calculating capacity value is effective load-carrying 

capability (NERC 2009; Keane et al. 2011b). Are there simpler metrics that provide 

better transparency to market participants? If so, what are they and how do they 

benchmark against ELCC? How should ELCC be calculated in multi-area power systems 

with high share of renewable generation? 

• How might capacity markets or hybrid constructs be modified to include flexibility 

requirements?

• How could market designs better value diversity in the generation portfolio and balance 

low price with low risk? This is particularly an issue for future scenarios that rely heavily 

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38 

on flexible natural gas to complement variable renewable generation (for more on natural 

gas, see Text Box 11). 

• Opportunities to bridge wholesale market designs with emerging technologies, such as 

demand response, storage, and distributed generation, will depend in part on how utilities 

can earn profits. How might business models for utilities (or, more generally, electricity 

service providers) in competitive markets be restructured to more efficiently integrate 

renewables, demand response, and distributed generation and expand customer 

empowerment? In a role as “smart integrators,” namely a provider of wires, reliability, 

and integrator of net-metered distributed generation, how can utilities manage portfolio 

risks? Utilities might have to reevaluate their role for distribution activities just as they

did for generation (Brown and Salter 2011). 

Similar questions to those listed above could also be asked in regulated markets, where the utility 

is still vertically integrated and generation comes from the service provider. (Text Box 12

describes priority research questions for China.) 

• How can demand response, storage, and distributed generation be properly valued? 

• How can flexibility be better valued? 

• How can utilities and their regulators better manage risk? 

• What lessons can be used from regulated markets and provided to competitive electricgeneration supply markets? What lessons can be used from competitive markets and used 

in regulated generation electricity markets? 

Text Box 11. Alignment of Electricity Markets with Natural Gas Markets

The interactions between electricity and natural gas markets introduce a potential reliability concern, 

and thus have drawn interest from FERC, NERC, ISO-NE, and NYISO, among others. Gas generators, 

which could play a pivotal near-term role in providing system flexibility, must participate in both 

electricity and natural gas markets, but they cannot achieve economically efficient solutions in either 

market due to misalignment of scheduling (Tabors et al. 2012). 

Scheduling in natural gas and electricity markets is sequential and is conducted independently. 

Generators—for example, NYISO, ISO-NE, and PJM—must purchase gas before knowing its electric

operating schedule (Tabors et al. 2012). If generators miscalculate and require more or less gas, they 

have limited options in the illiquid intraday gas market, and likely will pay imbalance penalties. 

Generators are at even greater risk for scheduling errors around weekends, when gas markets are 

closed. 

Pipeline capacity constraints create further scheduling difficulties and risks to reliability. Pipeline 

options—a mix of firm and interruptible services—reflect the needs of traditional customers, the local 

distribution companies, and do not provide much latitude to gas generators, whose schedules are less 

certain (Lee et al. 2012). The reliance on interruptible service also suggests that gas curtailments, for 

example those due to weather, might complicate the rising role of gas generation to complement 

variable renewable energy. Facing pipeline constraints, Xcel Energy has added storage for natural gas 

to increase its ability to use combined-cycle plants to respond to forecast errors for wind. Short of 

aligning schedules, RTOs/ISOs might have to consider including gas deliverability in dispatch 

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39 

algorithms (Tabors et al. 2012). Also, financing and construction of new pipelines require firm 

transmission contracts, typically for 20 years, which are ill-suited for independent power producers 

operating in day-ahead markets. The gas industry might have to consider alternative approaches to 

regulating and financing pipeline expansion projects to accommodate the growing customer base of 

electricity generators (Lee et al. 2012).

Text Box 12. ChinaChallenges and Research Opportunities in Centrally-Managed Power 

Systems

Despite several pilot projects for electricity market introduction, the Chinese power system in general 

is a command-and-control system with a hierarchy of dispatch centers, and with long-term contracts for

both power production and use of interconnectors. Although such a system might be suitable in a 

situation with rapid expansion of conventional (thermal) power plants and little need for flexibility, the 

Chinese power system today is undergoing a rapid expansion of variable renewable energy. Renewable 

energy integration aside, various factors are contributing to the desire for a more cost-optimized 

dispatch of the whole system. Yet, if not solved, problems associated with integration of variable 

renewable energy—in particular flexibility—will be a major barrier to the Chinese government’s 

ambitions on efficient deployment of renewable energy. 

In this sense the challenges for the Chinese power system are similar to the challenges for other power 

systems that already operate through a competitive power market. Questions about adequacy, energy, 

and ancillary services currently are under consideration for the design of a control system for the 

Chinese power system. On top of these challenges, the Chinese system is facing transitional challenges

in switching from one control system to another. These primarily institutional and structural issues 

seem to be a severe hindrance for creating efficient and sustainable solutions. 

One high-priority research project would be to conduct detailed stakeholder analyses clarifying benefits 

and disadvantages (in terms of cost, loss of influence and power, etc.) for the different stakeholders and 

different control systems. Suggestions for practical first-step solutions should be examined and tested 

in pilot areas. It would be important to learn from international experiences—to not to copy but rather 

to leapfrog to a future market setup or control system, thus avoiding the errors and market failures of 

the present setup in countries with competitive power markets. 

Another relevant question for China is how to ensure coordination between grid planning and power 

expansion planning. This issue is closely related to incentives for establishing new power production 

and incentives for power system transformation in the future.

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
40 

7 Conclusion

Experience in many countries illustrates the value in using markets to access flexibility (Cochran 

et al. 2012). Well-designed markets encourage economically efficient and stable solutions, 

promote desired behavior, and minimize unintended consequences. Yet, many uncertainties 

remain about how to evaluate system requirements and effectively induce and sustain 

investments in appropriate resources. This report reviews market designs that help access 

flexibility, and it suggests that sources of revenue could shift away from energy toward tailored 

services. 

It is apparent that market design is a difficult task. Many competing objectives must be met, 

including using short-term price signals to incentivize long-term investments, minimizing market 

power, and providing incentives for suppliers for the many non-energy services that are needed 

to balance the grid. Wholesale markets in many locations are markedly uncorrelated with pricing 

mechanisms in the retail market. This means that participants in the wholesale markets have 

minimal ability to predict, plan, or account for consumer actions. Further, in some markets with 

scarcity pricing, spikes in wholesale prices serve only to increase total costs, and do not provide 

any incentives for consumers to change their behaviors to promote economic efficiency.

The challenge of appropriate market design becomes more apparent in emerging 21st century 

power systems. Assets such as variable renewable energy, demand response, storage, and 

distributed generation offer benefits that can be realized throughout the power system—

generation, transmission, and distribution—and therefore are difficult to capture in current 

markets and regulatory structures, which deliberately segregated generation from transmission to 

support utility unbundling. The power system may require a transformation from a system 

premised on a strict separation between wholesale and retail, or generation and distribution, to 

one that can integrate these markets, such that assets from across the system can contribute to 

flexibility and reliability.

Moreover, market solutions are not the only option. Various hybrid designs—combinations of 

regulations and competitive markets—might serve as alternatives. A key driver in any market or 

hybrid design is to start with the characteristics that maximize the value of the power system and 

ensure that the type and quantity of services that deliver economically efficient operation and 

design of the power system are understood. 

The power system is just that, a system, relegating various design and operational issues to 

entities that are uncoordinated, possess imperfect information, and possess varying degrees of 

market power. Moreover, these entities operate in a complex market with many economic 

externalities; thus economies of scope (e.g., coordination of transmission and generation 

planning) are difficult to achieve. On balance, however, markets can enable efficiency gains that 

emerge from competitive (or nearly competitive) markets in electricity. Nevertheless, market 

approaches remain just one option in a broader range of possible approaches, such as vertically 

integrated utilities. 

There is an acute need for international collaboration on wholesale market design questions. A 

platform for collaborative analysis and modeling will help to evaluate pathways to 21st century 

power systems. Proposed market or hybrid market-regulation paradigms should be rigorously 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
41 

tested to understand both technical and financial outcomes, but also the alignment with the 

public policy objectives that drive market design. The 21st Century Power Partnership aims to 

provide this platform, and the authors of this report sincerely hope that it lays the groundwork for 

future collaboration. 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
42 

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