NREL is a national laboratory of the U.S. Department of Energy, 

Office of Energy Efficiency and Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Integrating Variable Renewable Energy 

in Electric Power Markets: 

Best Practices from International Experience

Jaquelin Cochran, Lori Bird, Jenny Heeter, and Douglas J. Arent

NREL/TP-6A00-53732 

April 2012
NOTICE

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iii

Abstract

Many countries—reflecting very different geographies, markets, and power systems—are 

successfully managing high levels of variable renewable energy on the electric grid, including 

that from wind and solar energy. This study documents the diverse approaches to effective 

integration of variable renewable energy among six countries—Australia (South Australia), 

Denmark, Germany, Ireland, Spain, and the United States (Colorado and Texas)—and 

summarizes policy best practices that energy ministers and other stakeholders can pursue to 

ensure that electricity markets and power systems can effectively coevolve with increasing 

penetrations of variable renewable energy. There is no one-size-fits-all approach; each country 

has crafted its own combination of policies, market designs, and system operations to achieve the 

system reliability and flexibility needed to successfully integrate renewables. Notwithstanding 

this diversity, the approaches all coalesce around five strategic areas: lead public engagement, 

particularly for new transmission; coordinate and integrate planning; develop rules for market 

evolution that enable system flexibility; expand access to diverse resources and geographic 

footprint of operations; and improve system operations. The study also emphatically underscores 

the value of countries sharing their experiences. The more diverse and robust the experience base 

from which a country can draw, the more likely that it will be able to implement an appropriate, 

optimized, and system-wide approach.
iv

Acknowledgments

The authors are greatly indebted to the many contributors to this study, in particular the Clean 

Energy Ministerial through the U.S. Department of Energy and the Australian Department of 

Resources, Energy and Tourism for funding this effort; and the Spanish Ministry of Industry, 

Energy, and Tourism for the development of the Spanish case study. 

For providing overall guidance, reviewing materials, and participating in stakeholder events, the 

authors thank the expert and advisory groups:

Expert Group

• Brian Parsons, National Renewable 

Energy Laboratory (NREL)

• Adam Brown, International Energy 

Agency (IEA) 

• Hugo Chandler, New Resource 

Partners, formerly IEA and Grid 

Integration of Variable Resources 

(GIVAR) project lead

• Hannele Holttinen, VTT Finland, IEA 

Task 25 

• Peter Jørgensen, Energinet.dk

• Peter Meibom, Danish Energy 

Association

• Craig Oakeshott, Sinclair Knight Merz 

(SKM) 

• Simon Mueller, IEA

• Mark O’Malley, University College 

Dublin 

• J. Charles Smith, Utility Variable 

Generation Integration Group

• David Pérez Méndez-Castrillón, 

Spanish Ministry of Industry, Energy, 

and Tourism 

• David Swift, Australian Energy Market 

Operator

Advisory Group

• Douglas Arent, Joint Institute for 

Strategic Energy Analysis/NREL

• Morgan Bazilian, United Nations 

Industrial Development Organization 

(UNIDO) and UN-Energy 

• Paolo Frankl, IEA 

• Ben Hobbs, Johns Hopkins University 

• David Hurlbut, National Renewable 

Energy Laboratory (NREL) 

• Christine Lins, Renewable Energy 

Policy Network for the 21st Century 

(REN21) 

• Michael Liebreich, Bloomberg New 

Energy Finance 

• Eric Martinot, Institute for Sustainable 

Energy Policies/Japan

• Hugh Outhred, University New South 

Wales

• Mark Radka, United Nations 

Environment Programme 

• Ethan Zindler, Bloomberg New Energy 

Finance 

For participating in interviews and providing review, the authors thank Claudine D’Annunzio, 

formerly of Electric Reliability Council of Texas (ERCOT); Stephen Beuning, Xcel Energy; 

Andrew Hirscher, Australian Department of Resources, Energy and Tourism; Carsten HoyerKlick, Deutsches Zentrum für Luft- und Raumfahrt (DLR) Institute of Technical 

Thermodynamics; Warren Lasher, ERCOT; Ron Lehr, American Wind Energy Association 

(AWEA); Rob Reid, POWER Engineers; Michael Walsh, EirGrid; Paul Wattles, ERCOT; 

Veronica Westacott, Australian Department of Resources, Energy and Tourism; and Michael 

Milligan, David Kline, Jeff Logan, and Robin Newmark of NREL. 
v

For speaking at stakeholder engagement events, the authors thank additional contributions from 

Ron Benioff, NREL; Rick Duke, Office of Policy and International Affairs, U.S. Department of 

Energy (DOE-PI); Tom Plant, Center for the New Energy Economy, Colorado State University;

Graham Pugh, DOE-PI; and Rick Samans, Global Green Growth Institute.

For design and editorial assistance, the authors thank Erica Augustine, Joshua Bauer, Scott 

Gossett, and, most especially, Mike Meshek of NREL.
vi

List of Acronyms and Abbreviations

AC alternating current

AEMO Australian Energy Market Operator

AWEA American Wind Energy Association

BNetzA Bundesnetzagentur Startseite (Federal Network Agency for Electricity, Gas, 

Telecommunications, Post and Railways, Germany)

CAISO California ISO (independent system operator)

CEM Clean Energy Ministerial

CHP combined heat and power

CREZ competitive renewable energy zone

DCENR Department of Communications, Energy and Natural Resources (Ireland)

DLR Deutsches Zentrum für Luft- und Raumfahrt (Germany)

DNSP Distribution Network Service Providers

DOE U.S. Department of Energy

DPS Drift Planlaegnings (Operational Planning) System (Germany)

DS3 Delivering a Secure Sustainable Electricity System

DWEA Danish Wind Energy Association

EIM energy imbalance market

ENTSO-E European Network of Transmission System Operators for Electricity

ERCOT Electric Reliability Council of Texas

ESIPC Electricity Supply Industry Planning Council (South Australia)

EUR euro

EWIS European Wind Integration Study

EWITS Eastern Wind Integration and Transmission Study

FERC Federal Energy Regulatory Commission

FIT feed-in tariff

GEMAS maximum admissible wind generation (Spain)

GIVAR Grid Integration of Variable Resources (IEA)

GW gigawatts
vii

GWC Global Weather Corporation

GWEC Global Wind Energy Council

GWh gigawatt-hour

HVDC high voltage, direct current

Hz hertz

IDAE Institute for Energy Diversification and Saving

IEA International Energy Agency

IEEE Institute of Electrical and Electronics Engineers

IPCC Intergovernmental Panel on Climate Change

ISO independent system operator

ITVC Interim Tight Volume Market Coupling

IWEA Ireland Wind Energy Association

KfW Kreditanstalt fuer Wiederaufbau (Germany)

LaaR Load Acting as a Resource

LMP locational marginal pricing

MWh megawatt-hour

n.d. not dated

NCAR National Center for Atmospheric Research

NDP National Development Plan (Australia)

NEL National Electricity Law (Australia)

NEM National Electricity Market (Australia)

NERC North American Electric Reliability Corporation

NOIS Nordic Operational Information System 

NREL National Renewable Energy Laboratory

NTNDP National Transmission Network Development Plan (Australia)

OCGT open-cycle gas-turbine

PUCT Public Utilities Commission of Texas

R&D&I research and development and innovation
viii

REE Red Eléctrica de España (Spain)

REFIT Renewable Energy Feed-in Tariff 

REN21 Renewable Energy Policy Network for the 21st Century

RETD Renewable Energy Technology Deployment

RETI Renewable Energy Transmission Initiative (California)

RIT-t Regulatory Investment Test – transmission

RTO regional transmission organization

SEM Single Electricity Market

SEMO Single Electricity Market Operator

SKM Sinclair Knight Merz

SONI System Operators Northern Ireland

TNSP Transmission Network Service Providers

TWh terawatt-hour

TSO transmission system operator

UNIDO United Nations Industrial Development Organization

WSAT Wind Security Assessment Tool

WECC Western Electricity Coordinating Council

WFES World Future Energy Summit
ix

Executive Summary

Many countries—reflecting very different geographies, markets, and power systems—are 

successfully managing high levels of variable renewable energy (RE) on the grid, such as from 

wind and solar energy. This study documents the diverse approaches to effective integration of 

variable RE among six countries—Australia (South Australia), Denmark, Germany, Ireland, 

Spain, and the United States (Colorado and Texas)—and summarizes policy best practices that 

energy ministers and other stakeholders can pursue to ensure that electricity markets and power 

systems can effectively coevolve with increasing penetrations of variable RE. 

The cases studied reveal there is no one-size-fits-all approach; each country has crafted its own 

combination of policies, market designs, and system operations to achieve the system reliability 

and flexibility needed to successfully integrate variable RE. Notwithstanding this diversity, the 

approaches coalesce around five strategic areas of intervention.

A. Lead Public Engagement, Particularly for New Transmission

Installing transmission that may be required to accommodate new RE can be challenging; 

stakeholders may express concerns over land use changes, environmental damage, 

decreased property values, or health concerns. A foundational component of siting new 

transmission is public engagement—a two-way exchange of information.

Action to Improve Public Support: lead public engagement to 

communicate to the public why new transmission is essential

Examples: public stakeholder exchange in Texas and Germany; burying of 

high-voltage grid in Denmark

B. Coordinate and Integrate Planning

Planning comprises an inherently complex set of activities that are undertaken by 

multiple groups and jurisdictions for a given power system. Variable RE can be 

accommodated by integrating the planning of generation, transmission, and system 

performance; ensuring institutions and markets are designed to enable access to physical 

capacity; and building from local and regional planning to better integrate and coordinate 

information across jurisdictions.

Actions to Improve Planning: share best practices and guidelines for 

adapting advanced planning capabilities; support capacity of institutions 

to increase integration, complexity, and coordination of—and stakeholder 

participation in—planning; and provide vision for how to move from 

analyses and recommendations to actions

Examples: market-based guided development in Australia; centralized 

planning in Texas

C. Develop Rules for Market Evolution that Enable System Flexibility

Higher penetrations of variable RE require increased flexibility from the power system. 

Flexible generation can be encouraged by implementing sub-hourly scheduling and 

dispatch intervals (5- or 15-minute) and shorter gate closure periods; establishing 

capacity and other ancillary services markets; and developing zonal or nodal pricing. 
x

Markets that encourage flexible storage and demand response can support the integration 

of variable RE through load shifting, balancing, and frequency and regulation.

Actions to Support Flexibility: lead the development and innovation of 

market designs; encourage market operators to adopt rules to improve 

system efficiency; and play a leading role in negotiating a framework for 

integration that optimizes flexibility across regions 

Examples: market design that encourages system flexibility through 

expanded power markets, fast market design, combined heat and power

(CHP), and negative prices in Denmark; National Electricity Market 

operation in Australia; encouragement of storage in Germany; demand 

response participation in Texas

D. Expand Access to Diverse Resources and Geographic Footprint of 

Operations

Integration studies have consistently found that expanding access to diverse resources 

aids the integration of high penetrations of variable RE. This can be achieved in two 

ways: enlarging effective balancing areas, and diversifying the location and types of RE 

generation. By enlarging balancing areas, the relative variability and uncertainty in both 

the load and RE generation will be lowered. Greater geographic distribution of renewable 

resources reduces the variability of RE because weather patterns are less correlated, 

reducing the magnitude of output changes. Regional market pricing, RE zones, and 

hybrid market solutions that allow reserve sharing are some of the approaches to 

encourage diversity. 

Actions to Expand Diversity: support the study and evaluation of options 

to diversify resources and enlarge balancing areas, and convene 

stakeholder discussions to overcome institutional challenges in merging or 

increasing cooperation among balancing areas

Examples: expanding regional integration in Ireland; proposed Energy 

Imbalance Market in the Western U.S.

E. Improve System Operations

Integrating advanced forecasting techniques into fast market operations, the control room, 

and other standard operating practices can help predict the amount of RE available to the 

system. Grid codes—rules that govern how power plants connect to and support the 

grid—help ensure that variable RE is compatible with, and can help contribute to the 

stability of, the power grid. A necessary first step is to evaluate existing rules to 

determine whether new approaches to planning, design, and operation are needed for high 

penetrations of variable RE.

Actions to Improve System Operations: support development of national 

or regional forecasting systems and work with regulatory commissions to 

evaluate model grid codes, recommend changes, and implement 

recommendations
xi

Examples: market use of advanced forecasting in Australia; system 

operator use of multiple and advanced forecasting in Denmark; creation 

of the innovative Control Centre for Renewable Energies in Spain

This study emphatically underscores the value of countries sharing their experiences. Any 

country’s ability to successfully integrate variable RE depends on a wide array of factors: 

technical requirements, resource options, planning processes, market rules, policies and 

regulations, and institutional and human capacity. The more diverse and robust the experience 

base from which a country can draw, the more likely that it will be able to implement an 

appropriate, optimized, and system-wide approach. This is as true for countries in the early 

stages of RE integration as it is for countries that have already had significant success. Going 

forward, successful RE integration will thus depend upon the ability to maintain a broad 

ecosystem perspective, to organize and make available the wealth of experiences, and to ensure 

that there is always a clear path from analysis to enactment.
xii

Table of Contents

Abstract..........................................................................................................................................iii

Acknowledgments.......................................................................................................................... iv

List of Acronyms and Abbreviations............................................................................................. vi

Executive Summary....................................................................................................................... ix

Table of Contents.......................................................................................................................... xii

List of Figures.............................................................................................................................. xiv

List of Tables ................................................................................................................................ xv

List of Text Boxes........................................................................................................................ xvi

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

Approach......................................................................................................................................... 1

Background..................................................................................................................................... 1

Five Areas of Intervention to Accommodate High RE Penetration ............................................... 5

A. Lead Public Engagement including Facilitating New Transmission ..................................... 6

B. Coordinate and Integrate Planning ......................................................................................... 9

C. Develop Rules for Market Evolution that Enable System Flexibility.................................. 13

D. Expand Access to Diverse Resources and Geographic Footprint of Operations................. 19

E. Improve System Operations.................................................................................................. 22

System-wide Approach to Areas of Intervention.......................................................................... 27

Costs of Integrating High Penetrations of Variable RE................................................................ 28

Conclusion .................................................................................................................................... 28

References................................................................................................................................. 29

Appendix A. Introduction to the Case Studies.............................................................................. 34

References................................................................................................................................. 38

Appendix B. Case Study: Australia (High Wind Energy Penetration in South) .......................... 39

Background ............................................................................................................................... 39

Coordinate and Integrate Planning............................................................................................ 41

Enable Markets to Facilitate Variable Generation .................................................................... 44

Motivate System Flexibility...................................................................................................... 46

Promoting Diversification of Location and Type of Renewables............................................. 46

Developing and Integrating Advanced Forecasting Techniques into Grid Operations ............ 49

Supporting Model Grid Codes.................................................................................................. 50

Political Environment, Initiatives, and Incentives .................................................................... 52

Conclusions............................................................................................................................... 52

References................................................................................................................................. 53

Appendix C. Case Study: Denmark.............................................................................................. 54

Introduction ............................................................................................................................... 54

Context ...................................................................................................................................... 55

Key Factors with Bearing on Variable RE................................................................................ 56

Potential for Learning in Other Countries................................................................................. 66

Conclusions............................................................................................................................... 67

References................................................................................................................................. 68

Appendix D. Case Study: Germany.............................................................................................. 70

Introduction ............................................................................................................................... 70

Context of Integration ............................................................................................................... 71

Key Factors with Bearing on Variable RE................................................................................ 74
xiii

Potential for Learning in Other Countries................................................................................. 84

Conclusions............................................................................................................................... 84

References................................................................................................................................. 86

Appendix E. Case Study: Ireland.................................................................................................. 89

Introduction ............................................................................................................................... 89

Background ............................................................................................................................... 90

Five Areas of Intervention to Accommodate High RE Penetration.......................................... 91

Replication of Efforts by Other Countries ................................................................................ 96

Summary and Conclusions........................................................................................................ 96

References................................................................................................................................. 98

Appendix F. Case Study: Spain .................................................................................................. 100

Coordinated and Integrated Planning...................................................................................... 100

Enabling Larger Balancing Areas or Markets to Help Manage Variable Generation ............ 104

Developing and Integrating Advanced Forecasting Techniques into Grid Operations .......... 105

Supporting Model Grids.......................................................................................................... 107

Conclusions............................................................................................................................. 108

References............................................................................................................................... 109

Appendix G. Case Study: United States—Western Region (Colorado and Texas).................... 110

Introduction ............................................................................................................................. 110

Background ............................................................................................................................. 111

Five Areas of Intervention to Accommodate High RE Penetration........................................ 112

Replication of Efforts by Other Countries .............................................................................. 118

Summary and Conclusions...................................................................................................... 118

References............................................................................................................................... 120

Appendix H. Summary of Stakeholder Feedback....................................................................... 122

World Future Energy Summit (WFES). Abu Dhabi (January 17, 2012)................................ 122

Paris (January 25, 2012) and Davos (January 28, 2012)......................................................... 123

New Delhi (CEM-3 Prep Meeting) February 1, 2012............................................................. 123

Washington, DC March 5, 2012.............................................................................................. 126
xiv

List of Figures

Figure 1. Key activities in transitioning from low to high RE penetration..................................... 5

Figure 2. Example of interrelationships among areas of intervention.......................................... 27

Figure A-1. Percentage of electricity generation by type, 2010 ................................................... 34

Figure A-2. Non-hydropower generation (billion kWh) in Australia, 2001-2010 ....................... 35

Figure A-3. Non-hydropower generation (billion kWh) in Denmark, 2001-2010 ....................... 35

Figure A-4. Non-hydropower generation (billion kWh) in Germany, 2001-2010 ....................... 36

Figure A-5. Non-hydropower generation (billion kWh) in Ireland, 2001-2010........................... 36

Figure A-6. Non-hydropower generation (billion kWh) in Spain, 2001-2010............................. 37

Figure A-7. Non-hydropower generation (billion kWh) in the United States, 2001-2010........... 37

Figure D-1. Percentage of installed capacity in South Australia, by technology ......................... 40

Figure C-1. Collaboration of Nordic and Central and West Europe Markets through the Interim 

Tight Volume Market Coupling........................................................................................ 61

Figure C-2. Number of power plants in Denmark, 1980 and 2010 .............................................. 64

Figure C-3. Active power control abilities of Danish offshore wind farms ................................. 66

Figure D-1. Development of electricity generation from RE in Germany since 1990................. 71

Figure E-1. Cumulative installed wind capacity in Ireland to 2011 and indicative targets from 

2010–2020......................................................................................................................... 90

Figure F-1. RE in primary energy consumption in Spain, 2010................................................. 102

Figure F-2. RE in electricity consumption in Spain, 2010 ......................................................... 103

Figure F-3: Main Control office in CECRE ............................................................................... 107

Figure G-1. Percentage of energy from wind in ERCOT, monthly, 2002–2010........................ 111

Figure G-2. ERCOT load acting as a resource responsive reserve deployment, 

February 26, 2008 ........................................................................................................... 115
xv

List of Tables

Table B-1. Statistical Summary of Population and Energy for South Australia .......................... 40

Table B-2. Time and Volume-Weighted Prices for Renewable and Fossil- Fuelled Generation in 

South Australia ($A/MWh).................................................................................................. 48

Table D-1. Shares of Wind and Solar PV Generation in Total Electricity Generation in Germany 

since 1999 (GWh)................................................................................................................ 72

Table D-2. Maximum Ratio of Wind and Solar PV to Load, by TSO, in Germany in 2011 ....... 72

Table E-1. Key Aspects of Ireland’s System................................................................................ 89

Table E-1. Summary of Key Studies ............................................................................................ 92

Table G-1. Key Aspects of Texas and Colorado Related to Renewable Integration.................. 111

Table G-2. Future Renewable Energy Development in Texas and Colorado............................. 112
xvi

List of Text Boxes

Text Box 1. Terms Used in this Study ............................................................................................ 4

Text Box 2. Example of Approach to Public Engagement—Texas ............................................... 6

Text Box 3. Example of Approach to Facilitating New Transmission—Germany ........................ 7

Text Box 4. Example of Approach to Public Engagement—Denmark .......................................... 8

Text Box 5. Example of Market-based Approach to Planning—Australia .................................... 9

Text Box 6. Example of Centralized Approach to Planning—Texas ........................................... 10

Text Box 7. Grid Integration Studies ............................................................................................ 12

Text Box 8. Example of Approach to Market Design—Australia................................................ 13

Text Box 9. Example of Approach to Market Design—Denmark ............................................... 14

Text Box 10. Example of Approach to Flexible Storage—Germany ........................................... 17

Text Box 11. Example of Approach to Flexible Demand—Texas ............................................... 17

Text Box 12. Example of Approach to Diversification—Denmark ............................................. 19

Text Box 13. Example of Approach to Enlargement of Balancing Areas—Ireland .................... 20 

Text Box 14. Example of Approach to Enlargement of Geographic Footprint of 

Operations—U.S. West ........................................................................................................ 20

Text Box 15. Example of Approach to Improvement of System Operations—Denmark ............ 23

Text Box 16. Example of Approach to Advanced Forecasting—Australia.................................. 24

Text Box 17. Example of Approach to Improvement of System Operations—Spain .................. 25

Text Box C-1. Congestion Management through Market Splitting .............................................. 61

Text Box C-2. The Interim Tight Volume Market Coupling ........................................................ 62
1

Introduction

Economic, environmental, and security concerns associated with conventional fuel supplies have 

strengthened support for clean energy technologies among governments and the private sector on 

a global scale; yet, questions about how to effectively integrate large amounts of variable 

renewable energy (RE)

1 generation persist. RE accounted for nearly half the estimated 194 

gigawatts of new global capacity in 2010—an investment equal to $211 billion (REN21 2011). 

Variable renewables, in particular, have achieved significant penetration in many countries, and 

issues associated with grid integration are increasingly gaining attention among a broad range of 

stakeholders.

The depth of experience in various countries—situated in diverse geographical and market 

contexts—provides insights for decision makers interested in increasing the penetration of 

variable RE into the power sector. This study documents the diverse approaches to effective 

integration among six countries, and it summarizes policy best practices that energy ministers 

and other stakeholders can pursue to ensure that electricity markets and power systems can 

effectively coevolve with increasing penetrations of variable RE.

Approach

Many countries—reflecting very different geographies, markets, and power systems—are 

demonstrating success in managing high levels of variable RE on the grid, such as from wind 

and solar. The Clean Energy Ministerial,2 which seeks to advance clean energy globally, 

identified the value in learning from this diverse set of experiences, so that these lessons can be 

applied elsewhere. The energy ministers participating in the Clean Energy Ministerial requested 

a review of the approaches taken by these countries, lessons that can be learned, and actions that 

energy ministers and other stakeholders can take to create supportive markets, institutions, and 

power systems.

The cases selected for this study—Australia (South Australia), Denmark, Germany, Ireland, 

Spain, and the United States (Western Region: Colorado and Texas)—all have relatively high 

penetrations of RE but reflect different power system and market characteristics.

Background

Variable RE presents an opportunity to exploit local renewable resources and reduce emissions. 

However, variable RE is often perceived as incompatible with base load needs and a secure 

electricity grid because of its inherent uncertainty in availability. Commonly cited concerns 

include technical, financial, geographical, and institutional concerns.

Technical Concerns

Higher penetrations of variable RE require increased flexibility from the power system to 

manage the variability and uncertainty of the generation. Also, although many RE generators 

 1 Variable renewable energy is defined as renewable energy that is not stored prior to electricity generation: it 

includes primarily wind and solar PV energy technologies but also technologies such as tidal power and run-of-river 

hydropower. 

2 The Clean Energy Ministerial, launched in 2010, is a high-level forum to promote policies and programs that 

advance clean energy technology, to share lessons learned and best practices, and to encourage the transition to a 

global clean energy economy. For more information, see http://www.cleanenergyministerial.org/.
2

now have technologies that support grid reliability,3 a misperception persists that they cannot do 

so.

Financial Concerns

Variable RE, with low to zero marginal costs, can impact the wholesale price of power and in 

turn the revenues and returns on investments for other generators. Also, timescale misalignment 

between transmission and generation planning and construction necessitates financial risk (e.g., 

RE investors may build generation in advance of transmission, and thus face revenue risk, or 

alternatively generators may have to pay for transmission in advance of generation coming on 

line). Finally, RE curtailments, which might increase in frequency at higher penetrations of RE, 

could cause unexpected revenue shortfalls.

Geographical Concerns

Variable RE is not necessarily generated where load is. Adding new variable RE may increase 

both transmission bottlenecks and the need for new transmission lines to remote areas.

Institutional Concerns

Regulatory and legislative barriers reduce access to optimal solutions. Compounding such 

difficulties is the need to coordinate across many jurisdictions and agencies (e.g., markets, 

balancing areas, planning entities, forecasters) to comprehensively address RE integration. 

Finally, integrating RE may require an educational or cultural shift among stakeholders to 

address the need for operational changes and increased flexibility needed to manage high 

penetrations of renewables on the grid.

Existing studies and tasks address many of these concerns:

• The IEA Grid Integration of Variable Resources (GIVAR) project seeks to better 

understand the technical and market characteristics of a power system that facilitates

integration of variable RE. For example, the Phase 2 report, Harnessing Variable 

Renewables (IEA 2011), proposes a tool to assess how much renewable energy can be 

added to existing systems.

• Task 25 of the IEA Wind Implementing Agreement establishes and shares best practices 

for increasing wind energy penetration.

• The Intergovernmental Panel on Climate Change (IPCC) Special Report on Renewable 

Energy (IPCC 2011) includes an assessment on integrating large amounts of renewable 

energy and recommended policy best practices.

• The North American Electric Reliability Corporation (NERC)’s Accommodating High 

Levels of Variable Generation (NERC 2009) outlines the state of knowledge and further 

research needed to integrate variable RE.

• Various Institute of Electrical and Electronics Engineers (IEEE) power and energy task

forces investigate technical concerns about integration (ongoing).

• Integration studies (see Text Box 7) evaluate opportunities, actions needed, and 

associated costs to integrate wind and solar energy to the grid.

• Alstom Grid Inc.’s Strategies and Decision Support Systems for Integrating Variable 

Energy Resources in Control Centers for Reliable Grid Operations (Jones 2011) identifies 

 3 Such technologies include active voltage control and regulation, primary frequency regulation, controlled ramping, 

interaction with system operators, and fault ride-through capability.
3

global trends in how system operations are responding to increased wind penetration, and 

their perspectives on effective approaches and future needs.

This report draws from both these studies and the compendium of case studies selected for this 

study (Appendices A-G) to synthesize lessons on effective policies, regulations, planning, and 

practices to encourage integration of significant RE penetration into electricity systems. Text 

Box 1 explains terms related to the integration of variable RE used in this study.
4

Text Box 1. Terms Used in this Study

• Balancing area includes all generation, transmission, and load within a metered area. The balancing 

authority maintains the balance (a period spanning minutes to days) of demand, generation, and net 

flows of power to adjacent balancing areas.

• Curtailment, or restriction on output of variable RE generation, can result in lost revenue for 

generators, but is sometimes used to support system flexibility. Curtailment can provide more time 

for other plants on the system to ramp down if there is a sudden imbalance of high supply and low 

demand. Curtailment can also be used to require an RE generator to generate at reduced levels so that 

it can ramp up quickly to balance a system. 

• Fault ride-through capability refers to the ability of generators to operate through low and high 

voltages or low and high frequency events. Historically variable RE generators, such as wind

generators, were required to disconnect when, for example, the voltage dropped at the wind turbine 

due to a fault in the grid. With increasing penetrations of variable RE, the power system is more 

reliable as generators can continue to operate and support the power system in these circumstances. 

Thus, variable RE generators are increasingly required to have fault ride-through capabilities.

• Flexibility refers to how quickly a resource can respond to expected or unexpected changes in 

demand or supply. Historically, flexible resources have been pumped storage, hydropower, and gas 

peaking plants. The amount of system flexibility depends not only on technical aspects (e.g., extent 

of interconnection, storage, forecast errors, and speed of response of resources) but also on 

institutional and market aspects (e.g., market rules that allow for short gate closure times, demand 

response programs). Net flexibility refers to system flexibility minus flexibility requirements 

necessary for grid operation.

• Gate closure refers to the future time at which the market commits to deliver electricity. 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.

• Net load refers to electricity demand minus electricity supplied by variable RE and hence the 

electricity that must be supplied by other resources. The concept of net load helps grid operators 

assess the required response from conventional energy supplies to balance the system; ramping might 

be smoothed when RE resources such as solar complement demand, or more likely, they might be 

made more severe when RE supply fluctuates independent of demand.

• Reactive power (also referred to its unit of measurement, “vars”) helps maintain voltage in the 

transmission system needed to circulate “active” power. Modern wind turbines can provide this 

voltage control. 

• System frequency reflects the balance between demand and supply; a decreasing frequency indicates 

demand has increased above supply. A stable power system does not allow frequency to deviate more 

than a small fraction (~0.03 Hz) from the 50 or 60 Hz target. As with fault ride-through capabilities, 

the power system is more reliable when variable RE generators can provide frequency response.

• System inertia—Inertia, the rotating energy stored in the system, helps maintain system stability 

against sudden frequency changes (e.g., changes that occur due to imbalances between system load 

and generation). Synchronous generators help maintain system inertia and therefore system 

frequency. Higher penetrations of RE increase the likelihood of sudden changes and could be of 

particular concern if new generating technologies cannot contribute to system inertia.
5

Five Areas of Intervention to Accommodate High RE Penetration

Analysis of the results from the case studies conducted for this study reveals a wide range of 

mechanisms that can be used to accommodate high penetrations of variable RE (e.g., from new 

market designs to centralized planning). Nevertheless, the myriad approaches collectively 

suggest that governments can best enable variable RE grid integration by implementing best 

practices in five areas of intervention:

A. Lead public engagement, particularly for new transmission

B. Coordinate and integrate planning

C. Develop rules for market evolution that enable system flexibility

D. Expand access to diverse resources and geographic footprint of operations

E. Improve system operations.

Figure 1 illustrates, within each of these areas, when actions typically need to be implemented as 

a country transitions from low to high RE penetration. For each of the five areas of intervention, 

the following sections describe in detail the rationale, best practices, diversity of approaches as 

revealed through the case studies, and challenges and actions to implementing best practices. 

Additional details on the case studies can be found in Appendices A-G. Cochran et al. (2012) 

summarize this study for policymakers.

Figure 1. Key activities in transitioning from low to high RE penetration
6

A. Lead Public Engagement including Facilitating New Transmission

Rationale

High penetrations of variable RE may require expanded transmission capacity—to accommodate 

diverse RE locations and locations far from load, to enlarge balancing areas, to reduce nodes of 

transmission congestion, and to fully access flexible resources (generation, storage, and demand 

response). Installing this transmission, however, is a challenge; stakeholders may express 

concerns over land use changes, environmental damage, decreased property values, or health 

concerns. Further, who should pay for transmission investments—and how these costs are 

allocated among ratepayers, stockholders, and others—can be an issue in some cases. 

Negotiating the balance between new transmission projects and the potential conflicts that arise 

often requires political leadership.

Text Box 2. Example of Approach to Public Engagement—Texas

Competitive renewable energy zones (CREZ) exemplify a quick process for gaining public support 

for new transmission. In implementing CREZ, the Public Utilities Commission of Texas (PUCT) 

authorized transmission improvements to serve 18.5 GW in new generation capacity—an equivalent 

to nearly 3,000 miles of high-voltage transmission lines. The PUCT identified transmission 

providers, who in turn designed each route—a 1-1.5 year approval process; some contested cases 

involved more than 1,000 landowners (Lasher 2011). Mandatory open houses for the public allowed 

developers to explain, for example, the purpose and need for the project and environmental and 

engineering constraints. Landowners were able to inform developers of siting considerations not 

available in the public record, such as locations of public landing strips and cemeteries, and to 

provide suggestions on unobjectionable routing locations (Reid 2012). In addition to the open houses, 

a multi-page questionnaire sought landowners’ feedback on, for example, their understanding of the 

need for the project and relative importance of various factors in siting considerations. Letters sent to 

county commissioners, judges, farm bureaus, federal agencies, and others allowed for additional 

feedback, such as locations of planned schools. All stakeholders could also offer testimony in 

hearings, which formed the basis of the final siting decision by the PUCT.

As an example outcome of this process, the PUCT required that Oncor, which is building more than 

1,000 miles of transmission, use monopole structures in places to reduce land impacts, and that 44% 

of routing be parallel to existing lines (Doan 2010). According to Oncor, "The grassroots attendees 

who started as protesters applauded when the routes were selected, which is proof that the process 

works" (Doan 2010).

According to the latest schedule for CREZ, all transmission is to be energized by the end of 2013, 

eight years after the state legislature initiated the CREZ in 2005. A few additional factors helped 

expedite the process: 

• Most of the routing was over private lands; other locations in the United States often involve 

federal land, a greater range of stakeholders, and compliance with the National Environmental 

Policy Act.

• Initial selection of CREZ locations was based on confidential information provided by wind 

energy companies. ERCOT chose locations based on significant interest and did not allow citizen 

input into this process.

• The purpose of the CREZ-designated lines was not allowed as an issue of intervention, reducing 

public input to decisions on location, not need.
7

Best Practices

Public engagement and a two-way 

exchange of information are foundational 

components of siting new transmission; 

transmission developers can explain why 

new transmission lines are needed and the 

public can offer feedback on siting 

locations (e.g., planned locations for new 

schools) and other information not 

available in public records.

California’s Renewable Energy 

Transmission Initiative (RETI)4 is often 

cited as a model for building public 

support for new transmission. The 

objective of RETI is to facilitate siting and 

permitting for renewable energy 

generation and transmission projects. A 

30-person Stakeholder Steering 

Committee for RETI represents diverse 

constituencies, including utilities, 

generators, state and federal officials, 

environmental groups, consumers, 

military, and American Indian Tribes. 

Committee members commit to engage 

and incorporate feedback from diverse 

stakeholders, work in good faith to 

achieve consensus on key issues, and 

publicly support outcomes. RETI assesses 

and selects CREZ locations based on cost 

and environmental impact, and it prepares detailed transmission plans for each zone; regulatory 

authorities issue final licensing decisions. By ensuring that the Stakeholder Steering Committee 

reflects a diverse range of interests, the active support for RETI decisions from all members 

provides credibility to its proposals, minimizes opposition, and facilities decision-making by 

regulatory authorities.

5

Other best practices for public engagement include:

1. Involve from the outset of planning public stakeholders that reflect many perspectives; 

engage them throughout the process

 4 For more information on RETI, see www.energy.ca.gov/reti. 5 Unpublished work by David Olsen, Western Grid Group

Text Box 3. Example of Approach to 

Facilitating New Transmission—Germany 

Germany enacted two new laws to facilitate new 

transmission. The 2009 Power Grid Expansion Act 

(EnLAG) gives priority to extra-high voltage 

transmission projects that reduce north/south 

congestion. The 2011 Grid Expansion Acceleration 

Law (NABEG) intends to shorten planning and 

permission processes from the current ten years to 

four years by consolidating responsibilities at the 

federal government level and allowing for early 

public participation (BMU 2012). 

To further facilitate transmission development, 

TenneT, one of four transmission system operators 

(TSOs) in Germany, has requested higher allowable 

rates of return from BnetzA (the federal network 

regulator) in order to attract investors. TenneT has 

also proposed a joint direct current network operator 

to build the dc line for offshore connections (TenneT 

2012). BnetzA is considering a host of reforms,

including whether to remove the current two-year 

waiting period that grid companies face before they 

are able to recover costs. 

To facilitate public engagement, the TSOs in 

Germany have developed a website to educate the 

public on the decision-making process for new 

transmission; in-depth public consultation will be 

held and municipalities may be compensated for 

hosting new transmission corridors.
8

2. Use a transparent process for 

developing routing options6

3. Explain the objectives for grid 

expansion, especially as it relates to 

public concerns (e.g., reliability, 

electricity prices, RE goals, 

employment)

4. Present alternative solutions and their 

trade-offs 

5. Clearly describe the types and 

distribution of costs and benefits, as 

well as costs of inaction or 

suboptimal actions (REALISEGRID 

2011)

6. Create a publically approved, 

transparent process for evaluating 

property values and compensation 

levels

7. Create a regulatory approach that is accessible to the public and minimizes burdens on 

applicants

8. Require support from national political bodies for international projects to proceed; 

authorization for such projects could follow a simplified process, possibly at only the 

national level (REALISEGRID 2011)

Text Boxes 2-4 provide examples from the case studies of additional approaches to engaging the 

public and facilitating new transmission.

Challenges to Implementing Best Practices

Integrating the meeting-intensive stakeholder process that drives decisions at the local level with 

a streamlined and expedited process for approving large transmission projects—especially 

international projects—represents a challenge.

Actions to Improve Public Support

1. Lead public engagement and communicate with the public about why new transmission is 

essential.

2. Encourage the adoption of approaches that can facilitate new transmission builds

 6 Tools such as Structured Public Involvement offer a process for quantifying community values (Jewell et al. 2009). 

Text Box 4. Example of Approach to Public 

Engagement—Denmark 

To address public concerns about aesthetics and 

impacts on land uses, Denmark intends to bury its 

entire high-voltage grid.

A Cable Action Plan prepared by Energinet and its 

regional partners analyzed the undergrounding of the 

entire 132 kV– 150 kV transmission grid and all new 

400 kV lines by 2030. The committee also suggested 

that it is probable that the entire distribution network 

(6 – 60 kV) would be buried in this timeframe. 

(Danish Electricity Infrastructure Committee 2008)

The cost of undergrounding the 132 kV – 150 kV 

transmission grid was estimated to be $2.0 billion, 

while the cost of burying the distribution grid was 

estimated to range from $1.7 billion to $2.0 billion. 

(Danish Electricity Infrastructure Committee 2008).
9

B. Coordinate and Integrate Planning

Rationale

Planning is a critical element of all power 

systems, but this is especially the case with 

variable RE, which requires a flexible 

system—one that can respond to expected 

and unexpected changes in demand and 

supply. Coordinated and integrated planning 

helps decision makers anticipate how 

variable RE might impact the grid and its 

operations, and what options would 

optimize costs across a system. Planning 

that is segregated by type (generation, 

transmission, and system performance) or

geography adversely impacts the ability to 

employ best practices to accommodate RE, 

including diversifying RE locations, 

enlarging balancing authorities, and 

increasing system flexibility. Plans for 

ensuring physical capacity are also often 

considered independent of alternative 

institutional or market structures. These 

alternatives, however, could significantly 

increase access to existing and planned 

capacity, and they could lower the overall 

costs of accommodating variable RE.

Best Practices

Planning comprises an inherently complex set of activities that are undertaken by multiple 

groups and jurisdictions for a given power system. The approach to planning differs widely—

Australia (see Text Box 5) uses market-based cost differentials to guide development while

Texas (see Text Box 6) draws on its clear jurisdictional authority to centrally plan. Each 

jurisdiction, however, can benefit from a few key principles that help accommodate variable RE:

1. Integrate the planning of generation, transmission, and system performance

2. Ensure institutions and markets are designed to enable access to physical capacity

3. Build from local and regional planning to better integrate and coordinate information 

across jurisdictions

Integrate the planning of generation, transmission, and system performance

Planning that optimizes resources across an entire network—generation, transmission, and 

system operation—better anticipates and minimizes system flexibility needs to accommodate 

variable RE. For example, an aspect of system performance—line rating—can be made more

Text Box 5. Example of Market-based 

Approach to Planning—Australia

Australia uses market-based cost differentials to 

guide generation and transmission development, and 

draws from a national, rather than regional, 

examination of network development. The 

Australian Energy Market Operator (AEMO) 

develops a National Transmission Network 

Development Plan (NTNDP) to inform developers of 

the most economically efficient locations or 

configurations for new projects, but there are no 

requirements to build in the areas identified by the 

NTNDP. The NTNDP incorporates benchmarked 

and accepted new technology and network 

development costs. While the generation 

development path is only indicative, it highlights 

regions where development is expected to be 

economically efficient. Market-based prices provide 

further signals on economic efficiency. Spot market 

prices include a location-specific multiplier on the 

regional price that is applied to all connection points 

within each region to reflect losses. Connection costs 

and congestion-based pricing through the spot 

markets provide additional price signals to new 

generation. One challenge to this approach, however, 

is that developers may not always choose the most 

economically efficient locations or configurations.

(See Appendix B for details.)
10

accurate through sensors or dynamic line 

ratings, which account for the positive 

correlation between wind generation and 

greater transmission capacity7 due to cooler 

lines, and can offer a potential capacity 

increase of up to 50% (IPCC 2011). A study 

of ERCOT’s use of dynamic ratings in 

Texas concludes that the ratings can reduce 

congestion constraints and the number of 

uneconomical generators necessary to 

alleviate congestions, and thereby lower 

overall rates (Hur et al. 2010).

Significant to increasing RE penetrations is 

to align the planning timescales for 

generation and transmission to allow the 

two to develop in coordination. For 

example, renewable energy zones can be 

used to try to plan transmission to areas 

where there are high quality renewable 

resources (see Text Box 6), alleviating the 

need to construct generation prior to the more time-consuming transmission. 

Finally, planning, which has historically been based on snapshot analyses of periods of greatest 

system risk, could better account for variable RE by looking at how risk varies at different times 

in the year and accounting for correlations between RE resource patterns and daily and seasonal 

loads (IPCC 2011, building on analysis by Burke and O’Malley 2010).

Ensure institutions and markets are designed to enable access to physical capacity

Planning often focuses on physical capacity; yet changes to market and institutional structures 

may more readily access resources needed for system flexibility. For example, hourly dispatch 

pushes ramping to meet the next hour’s schedule into a 20-minute period. This in turn reduces

access to physical flexibility and increases the need for regulation. Shifting to sub-hourly 

dispatch can improve the efficiency of operations and reduce the need for regulating resources

(Milligan and Kirby 2010a). 

Similarly, physical transmission rights can prevent the efficient use of a transmission asset by 

allowing an entity to own physical rights that are then inaccessible to other generators. 

Converting physical to financial transmission rights allows a market-based mechanism to access 

this capacity during congestion, reducing the need for new transmission.

Build from local and regional planning to better integrate and coordinate information 

across jurisdictions

A broad network expands transmission available for capacity and reliability needs, and reduces 

the need for reserves. Two challenges make integrated planning across a region difficult—

defining the planning objective and allocating costs from improved reliability. As an example of 

the first challenge, least cost system planning over a broad region could suggest new 

 7 Limits are set on line capacity to avoid overheating; lower ambient temperatures and wind can cool the lines, 

allowing higher limits during these periods. 

Text Box 6. Example of Centralized 

Approach to Planning—Texas 

In Texas, the need for new transmission was 

identified after heavy wind development occurred in 

an area with weak transmission, resulting in frequent 

curtailments. To increase capacity and accommodate 

revised renewable portfolio standard goals, in 2005, 

the Texas legislature passed a bill initiating the 

Competitive Renewable Energy Zone (CREZ) 

process, which made two key changes: 1) the Public 

Utilities Commission of Texas did not have to prove 

need, through financial commitments by generators, 

to certify new lines; 2) transmission developers do 

not absorb cost of lines if capacity is underused. 

Nevertheless, developing just-in-time transmission 

can be challenging. Wind development in Texas did 

not occur as planned due to many factors, including 

decreases in natural gas prices and an expected 

expiration of the federal production tax credit.
11

interconnections that in turn raise generation prices in historically low-price areas (as in 

Colorado), creating a conflict among jurisdictions about whether least cost planning should be

the objective. As an example of the second challenge, an integrated network with improved 

interconnections increases reliability, but many power systems lack a universally accepted way 

to allocate costs from infrastructure improvements that are located in one region but improve 

reliability for an entire network.

The case studies illustrate the significance of legal and institutional structures in formulating

approaches to regional integration. Ireland’s transmission system is state-owned; this has 

facilitated the shift in planning from local to national levels. Texas was able to make a legislative 

change authorizing the Public Utilities Commission of Texas to establish renewable energy 

zones and approve transmission lines to serve these areas, in advance of generation 

commitments. In contrast, the western United States, which lacks a regional transmission 

organization (RTO), must navigate regional planning through the Federal Energy Regulatory 

Commission, state planning commissions, and the Western Electricity Coordinating Council 

(WECC).8 Europe has made efforts to overcome their jurisdictional overlap by creating the 

European Network of Transmission System Operators for Electricity (ENTSO-E), which is 

obliged to prepare ten-year network development plans (non-binding) that include all of Europe. 

Also, a coalition of grid operators and environmental groups has established the RenewablesGrid-Initiative, which seeks a 100% RE grid by building public support and establishing pilot 

projects.9

The U.S. Department of Energy has supported a coordinating process by providing regional 

grants to develop long-term generation and expansion models that reflect increased complexity 

and scope. WECC, ERCOT, and the Eastern Interconnection were able to analyze impacts on 

cost, dispatch, ramping, transmission use, operational reliability, for example, across each of 

their interconnections from changes to policies, planning horizons, and grid improvements. As 

part of this support, U.S. DOE also provided money to state regulatory bodies within the 

interconnections to interface with the studies.10 An important early step towards interconnectionwide planning is to coordinate base case models across utilities, RTOs, and independent system 

operators (ISOs), including information from neighboring systems.11 Text Box 7 provides an 

overview of grid integration studies.

 8 WECC has been tasked with determining the cost allocation of broadening interconnections, despite that WECC 

was institutionally designed to ensure that NERC reliability standards are implemented.

9 For more information, see www.renewables-grid.eu 10 For more details on WECC and ERCOT, see pages 71-72 in Osborn, D. et al. (2011). “Driving Forces Behind the 

Wind.” IEEE Power & Energy. (9:6). 11 See, for example, FERC Order No. 890 on interregional planning requirements.
12

Challenges to Implementing Best 

Practices

• Coordinating multiple jurisdictions, 

especially when planning objectives 

and impacts of integration differ

across a region

• Ensuring that each institution has the 

capacity to communicate with and 

integrate planning materials from 

multiple jurisdictions

• Reconciling the planning for a 

specific generation target (e.g., 20% 

wind) while also planning for 

transmission that reflects a range of 

possible outcomes (e.g., 30% wind 

with its added flexibility 

requirements)

• Translating analyses12 into action, 

particularly when legal framework 

prevents change

Actions to Improve Planning 

Coordination

1. Share best practices and guidelines for adapting advanced planning capabilities to 

accommodate high penetrations of variable RE

o Enhance capacity of institutions to increase integration, complexity, and coordination 

of—and stakeholder participation in—planning

o Provide vision and empower leadership to realize how to move from analyses and 

recommendations to actions

2. Convey to all stakeholders the need to review existing rules and methods for planning, 

design, and operation to accommodate higher penetrations of variable RE; including:

o Utilities, RTOs, and others: Adapt or develop tools that enable system planning to 

incorporate requirements for flexibility and present recommendations13

o Regulatory commissions: Use rewards and punishments (e.g., rate recovery, rules) for 

coordination

 12 Such as final reports of NERC’s integration task forces 13 See, for example, NERC Integration of Variable Generation Task Force 1.4, Flexibility Requirements and Metrics 

for Variable Generation: Implications for System Planning Studies.

Text Box 7. Grid Integration Studies

• Europe: Towards a Successful Integration of 

Large Scale Wind Power into European 

Electricity Grids. (EWIS 2010). 

• Germany: Grid Study II – Integration of 

Renewable Energy Sources in the German 

Power Supply System from 2015 – 2020 with an 

Outlook to 2025. (Dena 2011). 

• Ireland: All Island Grid Study. (DCENR and 

DETI 2008). 

• Ireland: TSO Facilitation of Renewables Studies. 

EirGrid and SONI (2009). 

• United States: Western Wind and Solar 

Integration Study. (National Renewable Energy 

Laboratory 2010). 

• United States: Eastern Wind Integration and 

Transmission Study. (National Renewable 

Energy Laboratory 2010).

• For additional integration studies, see the Utility 

Variable Generation Integration Group’s wind 

integration library: 

http://www.uwig.org/opimpactsdocs.html
13

C. Develop Rules for Market Evolution that Enable System Flexibility

Rationale

Markets help minimize power system costs, and for systems using variable RE in particular, they 

can facilitate access to a range of options that increase system flexibility. Higher penetrations of 

variable RE require increased flexibility from the power system to manage the variability and 

uncertainty of the generation. Flexibility can be achieved through changes in market operations, 

increased transmission, or the addition of flexible resources to the system, such as more flexible 

generating units, storage, and 

demand response. While flexibility 

is of high value to the system and 

can reduce the need for new 

capacity, it may come at a cost to 

power suppliers. Increased ramping 

of units that are not adequately 

designed for cycling can result in 

maintenance issues or reduce the 

lifetime of units. Also, conventional 

generators may experience profit 

margins that are insufficient to 

maintain their long-term financial 

viability if variable generators 

depress wholesale market prices and 

generators are only compensated for 

energy production. Therefore, 

market rules and operations may 

need to be modified over time to 

achieve operational efficiency in 

systems with increasing penetrations 

of variable RE.

Best Practices

Use markets to support the most 

cost-effective solution to increasing 

flexibility, which could include:

Flexible Generation

Encourage sub-hourly scheduling 

and dispatch intervals (5- or 15-

minute) and shorter gate closure 

periods to improve system efficiency.

Markets using hourly scheduling or 

areas without organized markets that 

rely on bilateral contracts with fixed 

hour energy delivery can be 

problematic with higher penetrations 

of RE. Fast, sub-hourly markets that operate on 5-minute or 15-minute intervals, such as in 

Australia (see Text Box 8), are preferred for integrating variable generation because they can 

Text Box 8. Example of Approach to Market 

Design—Australia 

Australia’s National Electricity Market (NEM) covers 92% 

of Australian electricity demand and uses a complex spot 

market pricing signal to reward contributions to flexibility—

beyond what can be offered through an energy-only price. 

The NEM pricing signal values diversity, alignment of 

generation with load profiles, and location (e.g., distance 

from load; reductions in congestion). 

NEM has been operating since 1998, before wind farms 

came online in Australia. Key principles of market operation, 

which have been consistent over time, help accommodate 

variable renewable energy, though they were not explicitly 

designed to do so. NEM is a fast market; it is a selfcommitment market with 5-minute dispatch. Offers can be 

changed any time prior to dispatch, and there is a 5-minute 

regional clearing price and 30-minute settlement period. 

NEM also allows for a negative price of -$A 1,000 per 

MWh, which provides an incentive against oversupply.

NEM has been amended over time to incorporate variable 

generation. The rules of NEM were amended on the basis of 

evidence-based analysis, in consultation with industry and 

with support of, but independent from, State and Australian 

Governments. Previously, two dispatch categories 

(“scheduled” and “non-scheduled”) existed; wind was 

categorized as “non-scheduled.” A new category, “semischeduled” was created to incorporate variable generation. 

Semi-scheduled generators submit offers for their output and 

are included in constraints and market dispatch. If a wind 

farm is part of a binding network constraint, its output can be 

capped.

All market participants receive forecasts of total regional 

wind contribution, customer demand projections, and 

potential network constraints, enabling them to make output 

and commitment decisions to suit. (See Appendix B for 

details.)
14

more effectively address changes in the variable generation and the load (“net load”

14) (EWIS

2010). By dispatching the system in shorter increments, the movements of conventional 

generators needed to balance the system (i.e., regulation) can be reduced. Also, the system can 

run more efficiently and minimize 

reserve requirements.

In addition to moving to subhourly dispatch, reducing gate 

closure times—the point at which 

the market commits to deliver 

electricity—minimizes forecast 

errors and allows for trading at 

potentially lower cost than power 

that would otherwise be required 

for system flexibility. Germany

and Denmark have reduced their

gate closure times, e.g., Denmark 

to 15–60 minutes ahead of 

dispatch (see Text Box 9).

To increase system reliability, use 

capacity markets to help address 

concerns about declining 

wholesale electricity prices. With 

higher penetrations of variable RE 

generation, the market clearing 

price is lowered, as wind and solar 

will be dispatched first as the 

lowest marginal cost generators. 

The marginal units on the system, 

such as combustion turbine 

peaking plants, will experience

reduced numbers of operating 

hours and lower compensation, 

which could make the units

become uneconomic over time. 

However, these peaking units may 

be highly desirable for increasing 

system flexibility. Therefore, 

capacity payments or other 

financial incentives may be 

required to more fully compensate 

these generators for the benefits

they provide to the system. 

Capacity markets are one vehicle 

 14 Net load refers to electricity demand minus electricity supplied by variable RE and hence the electricity that must 

be supplied by other resources. 

Text Box 9. Example of Approach to Market Design—

Denmark

In Denmark, market design encourages system flexibility 

through expanded power markets, fast market design, CHP, 

and negative prices. 

• West Denmark joined the Nord Pool power market (which 

includes Norway, Sweden, and Finland) in 1999, followed 

by East Denmark in 2000. Electricity traded through Nord 

Pool has increased from 45% in 2006 to approximately 

75% (VTT 2007). In 2010, power markets were further 

connected with the establishment of the Interim Tight 

Volume Market Coupling (ITVC), which connects Nord 

Pool and the Central West European market. 

• Through faster market design, two markets, Elbas (an 

intraday market, with continuous trading up to 60 minutes

ahead of delivery) and the Regulating Power Market 

(operating up to 15 minutes before delivery), provide 

opportunities for producers, retailers, and consumers to 

provide short-term flexibility and remedy imbalance in 

trading positions. 

• Combined heat and power (CHP) plants, representing 

more than 55% of all electricity production (Danish 

Energy Agency 2011), support flexibility through direct 

participation in the power markets and as a source for 

flexible storage. CHP plants are required to participate in 

the spot power market, and around one-third of small CHP 

plants are active in the Regulating Power Market. When 

wind is high, CHP plants rely on their storage to continue 

to provide district heating, without needing to operate and 

compete with wind generation. When electricity prices are 

very low or negative, it is now cost effective to use cheap 

(wind) electricity to produce the low-temperature steam 

needed for district heating (Kiviluaoma and Meibom 

2010).

• In 2009, negative prices were permitted in the day-ahead 

market for the first time (previously there had been a price 

floor at €0/MWh). An alternative to arbitrarily curtailing, 

negative pricing provides an economically efficient way to 

reduce output during excess generation. Large consumers 

paying the spot price will also be encouraged by negative 

prices to shift consumption to these times.
15

for compensating needed generators to ensure that a sufficient amount of flexible generating 

capacity is available to serve the grid in current and future years. Additional services markets, 

which have yet to be fully implemented, include flexibility markets to reward generators with 

fast ramping, ramp rate control, and quick-start capabilities. This may incentivize generators to 

build-in sufficient flexibility needed by the system. 

Use zonal or nodal pricing to help manage congestion on the system and encourage development 

of resources where needed. Zonal or nodal pricing can send signals to the market about 

congestion and the need for resources in particular locations. For example, Australia’s use of 

nodal pricing and negative prices for hours when too much energy is on the system has created 

incentives to diversify the location of renewable generators. Because of negative prices in South 

Australia, where the wind is not well correlated with system peaks, wind developers are 

beginning to look to other locations to site projects. The use of nodal pricing is encouraging 

investment in regions with the highest prices over time (see Appendix B). The use of nodal 

pricing is also being considered in Germany to help address disconnects between the areas of 

renewable energy development and loads (see Appendix D). 

Develop equitable rules for curtailment of variable generators during periods of excess 

renewable generation on the system. Denmark has adopted a number of policies to deal with 

excess wind generation at night when loads are at their lowest levels. The Nordic power market 

allows negative pricing to occur on the system – meaning that a generator would have to pay to 

generate at times when the system does not need power. This dissuades wind generators from 

bidding in too much power at night when the system cannot handle it.15 Denmark has also 

established a policy precluding the curtailment of wind generators unless thermal units are being 

operated at minimum capacity. Land-based wind is compensated for curtailment; offshore wind 

farms, which may need to be curtailed for reliability reasons in the future, may not be 

compensated if notice is given the day ahead that curtailment will be needed. Offshore wind 

turbines are also subject to other types of controls, such as limits on ramps (see Appendix C). 

Australia and Germany, as described in Appendix B and D, have also implemented negative 

pricing.

Design imbalance payment rules so that they do not unduly penalize variable generators.

Because wind plants cannot predict their output—particularly in the day ahead market—utilities

or market operators, for example, may subject generators to imbalance penalties for deviating 

from their generation schedules. These penalties are typically designed to prevent market 

manipulation in organized markets, but in some cases may be unduly stringent for variable 

generation sources, making them uneconomic. In the Nordic market, wind generators only pay 

extra for imbalances during hours in which their deviations are in the same direction as the net 

system imbalance (see Appendix C). The extra cost assessed reflects the cost of generation used 

to balance the system during that hour. Additional fees are not levied on wind generators if their 

deviations are beneficial to the power system.

Consider hybrid market solutions to increase flexibility in areas without organized markets. For 

example, the Energy Imbalance Market, under consideration in the western United States, where 

there is no central organized wholesale market, is a partial market-based solution that would help 

the region manage higher penetrations of variable renewable generation. The proposed Energy 

 15 NERC’s (2011) Integration of Variable Generation Task Force 2.4 also recommends consideration of negative 

pricing. 
16

Imbalance Market would automate and speed up the process for transacting imbalance energy. It 

would also enable more efficient power system operations by enabling balancing areas to access 

the most cost effective resources in the region to balance the system and manage transmission 

congestion (see Text Box 14 and Appendix G).

Require flexibility in resource planning or provide financial incentives to ensure new capacity is 

as flexible as possible. In an integrated planning market, utilities can consider flexibility criteria 

when evaluating bids for new generation resources. This would ensure that generation added to 

the system would be as flexible as possible and enable the system to more easily accommodate 

higher penetrations of variable RE. Another way to promote flexible resources is to provide 

direct financial incentives to encourage resources to be more flexible. Germany has developed a 

fund to encourage new fossil-fired power plants to use the most flexible technology available to 

maximize their ability to ramp to meet the system’s balancing needs (see Appendix D).

Flexible Storage

Storage, such as pumped hydro, batteries, flywheels, and compressed air, contribute to system 

flexibility in three ways (NERC 2010):

1. Load shifting: Storage can absorb surplus RE power and reduce curtailments, and reduce 

the net flexibility required of conventional units; strategically placed storage can also 

reduce transmission congestion (IPCC 2011)

2. Balancing: Over a course of minutes to hours, storage can smooth net load and reduce the 

need for spinning reserves

3. Frequency and regulation: The cost-effectiveness of storage can be improved by allowing 

fast-discharge storage to participate in ancillary markets, such as regulation, demand 

following (ramping), and capacity (NERC 2010, Delille et al. 2010).

Ensuring the optimal use of storage, e.g., supporting the power system as a whole rather than 

dedicated to a single generator, further improves its cost-effectiveness (NERC 2010).

Resources that serve non-electric demand may be a particularly cost-effective and large source of 

storage and system flexibility (Kiviluaoma and Meibom 2010). Electric heat boilers, operating 

during periods of low to negative prices (due to very high winds), can store heat and reduce 

curtailments of wind generation. Combined heat and power (CHP) plants, which also offer heat 

storage but primarily from burning fossil fuels, are more likely to shut down during high winds 

when fossil fuel costs are uncompetitive. Shutting down allows more room for wind generation; 

yet CHP plants can continue to serve heat demand through thermal storage (Kiviluaoma and 

Meibom 2010).
17

Denmark uses the heat storage of CHP

plants, representing more than 55% of 

total electricity production, to 

complement variable RE (see Text Box 

9). CHP plants produce low-temperature 

steam for district heating, which allows 

for easier and more considerable storage 

than the high temperatures needed for 

industrial processes. When wind 

generation is high, storage is essential for 

enabling CHP plants to shut down and 

allow higher penetrations of wind 

generation. To further contribute to 

system flexibility, CHP plants are 

required to participate in the spot power 

market, and a third of small CHP plants 

participate in Denmark’s ancillary 

markets. Germany (see Text Box 10) is 

also considering incentives for CHP.

Flexibility of Load through Demand 

Response and Use of Smart Grid

Technology

Demand response, also referred to as load management, contributes to system flexibility in the 

same three ways as storage:

• Load shifting: Flexible loads can participate in capacity markets, and reduce the 

flexibility needed by conventional units. Loads, especially through incentives such as low 

and negative pricing, can shift to times of surplus RE power, thereby reducing 

curtailments.

• Balancing: Load has the potential to quickly offset large losses of power, as occurred in 

Texas in February 2008, when demand response reduced load by 1,108 MW in 10 

minutes (see Text Box 11). Load 

such as water desalination, ice 

production, electric vehicles, and 

thermal loads (e.g., water heating) 

are well-suited to this (IPCC

2011, Milligan and Kirby 2010b, 

Kirby 2007).

• Frequency and regulation: Load 

can participate in ancillary 

markets. Demand response for 

frequency regulation has been 

important for a small, isolated

system like Texas. For example, 

as part of demand response in 

Texas, load moves up and down 

Text Box 11. Example of Approach to 

Flexible Demand—Texas

Demand response participation provides ERCOT 

with flexibility at a low cost. After the introduction 

of retail competition, Texas wanted a mechanism to 

continue to draw on the interruptible load that had 

been participating in special tariffs. The restructured 

market allows demand response to participate in 

ancillary services markets. In February 2008, when 

anticipated wind and traditional generation fell short, 

and demand ramped up more quickly than 

anticipated, 1,108 MW of demand response were 

activated in 10 minutes (ERCOT 2008). Since 2006, 

demand response has been deployed 21 times in 

Texas (Wattles 2011). 

Text Box 10. Example of Approach to 

Flexible Storage—Germany 

Germany has implemented mechanisms to encourage 

energy storage. There is a €200 ($261) million 

budget for storage R&D up to 2014, and new storage 

facilities are exempt from grid charges and the EEG 

levy (BMU 2011). 

Germany has demonstration plants in operation that 

examine the benefits of using excess electricity 

production to produce hydrogen, and hence synthetic 

methane gas, which could be fed into (and so stored) 

in the gas grid (Netzentwicklungsplan Gas 2012). 

Germany is also considering mechanisms to 

encourage CHP. One option under consideration 

would provide an incentive to CHP plant owners for 

including additional thermal storage. A second 

proposal would provide grants covering 30% of the 

costs for additional heat storage, with the goal of 

increasing CHP power production from around 15% 

in 2010 to 25% in 2020 (Argus 2011).
18

automatically (within 1/3 second) to maintain frequency at 60 Hz; participates in nonstandard reserves by being able to ramp load in 30 minutes; and, as “spinning”

(responsive) reserves, must be able to respond within 10 minutes of a hotline call. 

ERCOT procures in the ancillary market 2,300 MW each hour, representing the 

equivalent of the two largest units (nuclear), in case they trip off-line. ERCOT caps 

load’s participation in this market at half (1,150 MW). Participating loads, which

generally bid at $0, allow generators to set the clearing price, with an average in 2010 at 

$20/MWh, reflecting low natural gas prices (Wattles 2011).

Both price signals and grid management rules can enable power systems to access load as a 

source of flexibility (NERC 2010). To be effective, adequate communication infrastructure 

between system operators and load is necessary (IPCC 2011).

Challenges to Implementing Best Practices

• Physical solutions to increase flexibility are straightforward; institutional, legislative, and 

market barriers will be the challenge

• Adjusting market rules is a time-consuming and stakeholder-intensive process. Various 

stakeholders have different economic interests, but it is important to develop solutions 

that lead to greater system efficiency overall while allowing regulatory flexibility to 

distribute gains equitably

• Implementing solutions for areas without organized wholesale electricity markets can be 

costly, and obtaining consensus among diverse stakeholders to implement partial marketbased solutions may be challenging.

Actions to Use Markets to Enable System Flexibility

1. Lead development and innovation of market design options for enabling higher 

penetrations of variable RE generation (e.g., commission studies to identify potential 

impacts of variable generation on electricity markets and generator compensation and 

identify needs) 

2. Encourage market operators to adopt rules to improve system efficiency with higher 

penetrations of variable RE. Work with regulators to educate stakeholders about best 

practices 

3. Play a leading role in negotiating a framework for integration that optimizes flexibility 

across regions 

4. Partner with the private sector to advance development and demonstration of 

technologies and tools that increase flexibility (e.g., fast ramping, storage, smart demand 

response), all in coordination with market design innovation 
19

D. Expand Access to Diverse Resources and Geographic Footprint of Operations

Rationale

One of the concerns about integrating variable RE is vulnerability of the power system to 

weather events. Integration studies have consistently found that expanding access to diverse 

resources reduces this vulnerability. This can be achieved in two ways: enlarging effective 

balancing areas and diversifying the location and types of RE generation.

By enlarging balancing areas, the relative variability and uncertainty in both the load and RE

generation will be lowered, smoothing out differences among individual loads and generators. 

This in turn reduces the need for reserves and lowers overall integration costs. Larger balancing 

areas may also provide access to a greater amount of flexible generation. 

Greater geographic distribution of renewable resources reduces the variability of RE because 

weather patterns are less correlated across large geographies, reducing the relative magnitude of 

output changes. Greater diversity of technologies similarly reduces the correlation among 

generators, and thus has an effect that is similar to that of increasing geographic diversity.

Best Practices

Creating larger balancing areas can help integrate higher penetrations of variable RE 

generation on the system. Larger geographic areas also tend to reduce aggregate forecasting 

errors (NERC 2011). Denmark, which has already achieved relatively high levels of wind energy 

penetration with 22% of its production from wind power in 2011, has benefitted from 

participating in the larger Nordic power market to manage the variability. In this way, Denmark 

can access flexible hydropower and other resources to provide reserves to accommodate the 

variability of wind. The pooled operation minimizes the need to curtail wind and reduces 

reserves required by the system (Holttinen et al. 2009). Denmark also has significant efforts 

underway to expand its electrical linkages to other nearby markets, including to Norway and the 

Netherlands. This is expected to help decrease power prices in other areas and enable Danish 

wind generation to access pumped storage hydropower resources (see Text Box 12). 

Interconnecting isolated, small systems with 

neighbors allows access to generation 

sources from larger grids. Systems can 

more effectively balance higher 

concentrations of variable generation if they 

can access additional balancing resources in 

other areas. For example, Ireland is a 

relatively small island system with few 

regional interconnections. However, Ireland 

has been taking steps to increase its 

interconnections to be able to handle a large 

amount of wind on its system. The EastWest connector, which is a 500 MW high 

voltage DC link to Wales, is currently under 

construction and is expected to decrease 

wind curtailment levels. Ireland has also 

taken steps to expand its electricity market, by creating a Single Electricity Market with Northern 

Ireland in 2007, despite the use of different currencies. This expanded market has created a 

Text Box 12. Example of Approach to 

Diversification—Denmark

Denmark has enlarged its balancing area through 

electrically linking to adjacent and nearby markets. 

East Denmark is part of the Nordic system, and 

while both East and West Denmark have long 

interacted through the Nordic power market, in 2010, 

they were electrically connected through a DC link, 

providing additional management options.

Electrically linking Denmark’s markets helps spread 

wind power production more widely, increasing its 

value, and enabling surpluses to be stored – for 

example, in Norwegian pumped hydropower 

facilities. 
20

larger pool of resources for balancing the 

system and has provided Ireland with more 

transmission connections to the United 

Kingdom (see Text Box 13). 

For areas without organized markets and 

with small balancing areas, using hybrid 

market solutions can achieve balancing 

area cooperation and reserve sharing.

These cooperative mechanisms can result in 

cost savings from sharing reserves without 

the need to create a fully organized market 

structure. Studies of the proposed Energy 

Imbalance Market (EIM, described in 

section C) in the western United States find 

that it would reduce the reserve 

requirements substantially if widely adopted in the region, resulting in significant cost savings

(King et al. 2011, WECC 2011). By expanding the balancing area, the EIM would also reduce 

the variability of the renewable generation by enabling access to renewable energy plants in 

different geographic locations. By managing imbalances over a broader region, the EIM can net 

out differences between generation and load across a broader area (see Text Box 14).

Because transmission access often 

influences where RE generators are located, 

renewable energy zone planning can help 

identify diverse areas of RE resources and 

encourage transmission planning to those 

resources. For example, renewable energy 

zones have been used in Texas and the 

western United States to facilitate the 

development of new transmission projects 

to serve areas with the greatest potential for 

developing renewables. In Texas, in 

particular, the use of renewable energy 

zones helped identify needed transmission 

paths, align the transmission and generation 

planning timelines, and streamline the 

process for approving transmission projects

(see Text Box 6). The zone efforts have 

been effective in rapidly bringing on-line 

new transmission projects and diversifying 

the development of wind to various areas of 

the state from an initial concentration of development in West Texas.

Incentives may be provided to encourage RE to be sited in diverse locations if this minimizes 

total system costs (i.e., the total cost transmission plus generation). Policies can encourage 

geographic distribution of resources, but this is only worthwhile when the increased cost of 

Text Box 13. Example of Approach to 

Enlargement of Balancing Areas—Ireland

Ireland has expanded its balancing area through the 

creation of a Single Electricity Market (SEM) with 

Northern Ireland in 2007. All electricity above 10 MW 

sold and bought in Ireland is traded through the central 

electricity pool of SEM through a market clearing 

mechanism. The mechanism is unique in that it is 

operating with dual currencies and jurisdictions. It was 

established through a series of agreements between 

regulators and transmission system operators in both 

countries. Ireland is also developing an interconnector 

with the UK, which is scheduled to be complete in 2012.

An auction management platform that will allow 

participants to trade across the interconnector is 

being developed. 

Text Box 14. Example of Approach to 

Enlargement of Geographic Footprint of 

Operations—U.S. West 

In the western United States, there is not an 

organized wholesale electric market. In order to 

facilitate trading without creating a full wholesale 

electricity market, the Energy Imbalance Market has 

been proposed. The EIM would allow balancing 

areas to cooperate, thus resulting in operational cost 

savings, because fewer reserves would be needed to 

manage the system. The Western Electricity 

Coordinating Council helped develop a high-level 

design specification and evaluation of the EIM 

proposal, but the EIM will need support from state 

public utilities commissions in order for utilities to 

be confident that they will get cost recovery for 

participation in the EIM. Technical studies have been 

partially funded by the Department of Energy.
21

diversifying to poorer resource areas is less than the savings associated with reduced costs for 

transmission upgrades to better resource areas. 

Project bid evaluations could include an assessment of the location of the resource and its 

potential impact on the system, thereby encouraging a mix of resources on the system. In 

markets where integrated resource planning is used, the location of the renewable energy and its 

potential impact on the system could be examined in the bid evaluation process. This could 

ensure that not all variable generation is located in the same region where it is affected by the 

same weather events. 

Challenges to Implementing Best Practices

• There are significant institutional challenges to achieving balancing area cooperation or 

consolidation. Many stakeholders with different objectives and concerns about 

consolidation may be involved. 

• Another challenge for areas with multiple balancing areas and without organized markets 

is shared telemetry. There is a need to determine what information is shared, what is 

automated, and how to address the cost.

• Diversifying locations may necessitate operating in regions that are not as cost-effective 

(i.e., projects in less windy areas).

Actions to Expand Access to Diverse Resources

1. Support study and evaluation of methods to increase balancing area size or balancing area 

cooperation, particularly for areas with small or disaggregated balancing areas

2. Convene stakeholder discussions to evaluate options and identify needs for overcoming 

institutional challenges in merging or increasing cooperation among balancing areas

3. Support cooperation among TSOs16

4. Lead the renewable energy zone planning process for transmission to different resource 

zones; this could be done to encourage diversity

5. Ensure resource assessment is state-of-the-art for all RE resources

6. Encourage utilities to consider and evaluate the location of new RE generators and 

encourage diversity through the bid evaluation process

 16 For example, Europe’s creation of the ENTSO-E, which is creating a ten-year network development plan. The 

ENTSO-E has significantly increased common network planning among European TSOs.
22

E. Improve System Operations

Rationale

Beyond market and institutional changes to system operations described in earlier sections (e.g., 

faster scheduling, enlarged balancing areas), system operations can be improved by adopting

advanced forecasting techniques and changes to grid codes. Using advanced forecasting 

techniques helps reduce the amount of system flexibility needed to integrate variable RE 

generation. Renewable energy generation can be variable, changing with the time of day and 

weather patterns, and uncertain because of the inability to predict the weather with perfect 

accuracy. Using forecasts in grid operations can help predict the amount of wind energy 

available and reduce the uncertainty in the amount of generation that will be available to the 

system. 

Revising grid codes to address issues related to variable generation (e.g., concerns about 

frequency control and other disruptions to network stability) both allows hardware and 

procurement agreements to be designed in advance to support the power system and reduces the 

financial burdens of retroactive requirements. Creating a model grid code can serve as a guide 

for each system to evaluate what changes are needed.

Best Practices

Advanced Forecasting

Integrate forecasts into fast market operations, the control room, and other standard operating 

practices of the system operator or market operator. Forecasts are more accurate the closer they 

are to real time. System operators use accurate forecasts to determine unit commitment and 

reserve requirements; this can minimize ramping requirements of fossil plants and the need for 

reserves—a cost savings. For example, the Western Wind and Solar Integration Study found 

significant savings with the use of advanced forecasting techniques in the western United States

(NREL 2010). Denmark integrates forecasts into system planning up to 2 hours ahead of the time 

of operation, but is moving toward 5 minutes (see Text Box 15). 
23

Text Box 15. Example of Approach to Improvement of System 

Operations—Denmark

Energinet has greatly enhanced its Energy Management System (EMS) to monitor realtime performance of the power system. This includes real-time estimates of wind power 

to be fed into the grid. This is an important aspect as most wind power in Denmark is 

connected at the distribution level, which is passively managed, so it is not very visible 

to the system operator.

Energinet, Denmark’s system operator, uses multiple and advanced forecasts. Forecasts 

are used in planning of system operation, day-ahead (cross-border) congestion 

management, the commitment and economic dispatch of controllable power plants, 

contingency analysis, the assessment of grid transfer capacity, and the need for 

regulating power.

Energinet’s Drift Planlaegnings (Operational Planning) System (DPS) tool integrates 

forecasts of wind and CHP output into system planning up to two hours ahead of 

operation—and in the near future up to five minutes. The DPS also provides the 

operator with a view of power flows between the Danish system and those of Germany, 

Norway, and Sweden. All power plants greater than 10 MW must provide five-minute 

updates of power production. Wind generators receive financial compensation for 

producing what is forecast and sold in the day-ahead market.

Grid codes were revised in 1999 to require wind turbines on the high voltage grid 

(mainly off-shore wind) to remain connected to the grid so that they can support the grid 

in case of fault. Given that 90% of wind turbines are connected at the medium voltage 

(60 kV) level and below, similar grid codes now apply at that level also. New 

regulations allow off-shore wind farms to be controlled, if necessary, by placing a 

ceiling on output, reducing output over a fixed period, smoothing the rate at which 

output increases, or reducing output by a fixed amount over time.

Ensure RE plants continually provide updated data on power, wind speed, and turbine 

availability to system operators to improve the accuracy of the forecasts they use. Frequently 

updated and comprehensive data are needed for system operators to use forecasts in real time. 

One important data issue is that system operators need to be aware whether turbines are offline 

for maintenance; a lack of turbine availability data significantly impacts the quality and 

usefulness of the forecast data. Comprehensive data on power output, wind speed, and turbine 

availability are needed on a real time basis. Also, the data used for forecasting wind plants needs 

to be able to adequately capture differences among individual turbines at the plant, particularly 

for large plants with mixed terrain. A small wind farm may be adequately captured by data from 

a single tower, while large projects may need multiple sources of wind speed data (Grant et al. 

2009). The ability for wind farms to reliably transmit this information frequently to grid 

operators is important. For example, Australia requires all transmission-level wind farms to 

provide a set of forecasts from five minutes to two years (see Text Box 16).
24

Text Box 16. Example of Approach to Advanced Forecasting—Australia

Early in the development of wind power in South Australia, the importance of 

forecasting was recognized. However, a number of forecasting proponents were 

significantly concerned about funding and continuously operating individual forecasting 

systems. The South Australian Electricity Supply Industry Planning Council and the 

market operator initiated working groups and engaged the Australian Government as a 

potential source of funds. As a result, a forecasting model was developed that 

incorporates inputs from, e.g., individual wind farm or turbine outputs, on-ground 

automatic weather stations, and satellite imagery. In order to drive efficient outcomes, 

the market operators use the wind forecast, along with a future demand forecast and 

advanced generator bids to provide a forward price projection up to seven days ahead. 

Generators use the price forecasts to decide when to commit their plant. Near-term 

plans for improvement focus on developing large ramp forecasts. (See Appendix B for 

details.)

Using multiple forecasts can be beneficial for system operations. The use of balancing area and 

project-level forecasts can improve accuracy and encourage better decision making by generators 

(in bidding) and system operators. Having project-level and balancing area forecasts improves 

how transmission flows are managed on the system. In addition, many forecasting systems use a 

blend of several forecasts instead of a single forecast to help address uncertainty and to improve 

accuracy. State-of-the-art forecasts today generally use a combination of statistical and physicsbased atmospheric models. Short-term forecasts (up to 6 hours) often use statistical methods 

based on recent data from the wind plant or locations nearby. Longer-term forecasts generally 

rely more on numerical weather prediction models, which forecast weather based on physical 

properties of the atmosphere. Combining methods can reduce forecast errors. Also, the level of 

accuracy increases when combining forecasts for larger areas (Holttinen et al. 2009). 

Continued evaluation and improvement of forecasting methods can facilitate more efficient 

operations and help address higher penetrations of variable generation. One area of 

improvement has been the development of ramp forecasts, which can be important for managing 

system operations. Because wind ramps can be affected by a variety of weather events, it can be 

a challenge to provide meaningful information to grid operators, but advancements are being 

made and more systems are incorporating ramp forecasts (Holttinen et al. 2009). For example, 

Australia is improving its centralized forecasting program by developing large ramp forecast 

capabilities (see Text Box 16). Also, ERCOT, the grid operator for Texas, recently implemented 

a ramp alert system to help prepare for large and sudden changes in wind energy output.

Grid Codes

As wind and other variable sources increase in penetration, their ability to support the grid during 

moments of grid instability becomes increasingly important. Grid codes, which are rules 

established by the system operator to govern how generators connect to grid, help ensure that 

variable RE is compatible with, and can help contribute to the stability of, the power grid (IEA 

2011). A necessary first step is to evaluate existing rules to determine if new approaches to 

planning, design, and operation are needed for high RE.

As an example of this first step, the NERC created a roadmap of system reliability requirements 

based on an integrated review of needs and capabilities. The Integration of Variable Generation 

Task Force, which created this roadmap, had goals of: 1) understanding the operational and 
25

planning landscape of systems with variable RE; 2) identifying new approaches to planning, 

design and operations; and 3) mapping these approaches against existing NERC’s reliability 

standards to identify gaps (Lauby et al. 2011). The task force produced its summary report, 

Accommodating High Levels of Variable Generation in 2009, and suggested work plans for 

ongoing investigation. The working groups then created recommendations for NERC to 

consider.

Some of the technical recommendations for grid codes that emerged from this and other studies 

include:

• Require fault ride-through capabilities. For example 97.5% of wind farms in Spain are 

able to continue to contribute electricity to the power system during faults (Holttinen et 

al. 2011). Germany and the US, the latter through FERC Order 661-A (2005), also

require fault-ride through capabilities (IPCC 2011).

• Require turbines to provide reactive power, and, in some cases, voltage and frequency 

control (see Text Box 17).

Text Box 17. Example of Approach to Improvement of System 

Operations—Spain 

Spain has created several procedures to address some of the technical challenges to grid 

security in accommodating RE on an isolated grid. The innovative Control Centre for 

Renewable Energies (CECRE) monitors RE installations on the basis of real-time 

information availability. RE installations must provide real-time telemetry each 12 

seconds as well as voltage control following orders of the TSO. CECRE uses a 

Maximum Admissible Wind Generation tool to determine whether the present 

generation scenario is acceptable for system operations. 

The TSO is responsible for granting access and connection permits for systems 

connecting to the high-voltage network; the TSO cannot prohibit access for reasons 

other than the system’s operation security, and even in such case, the regulator is in 

charge of solving the problem.

A procedure for responding to voltage dips was approved in 2006. Wind farms with 

capacities greater than 10 MW must provide reactive power support; this was extended 

to solar PV installations with capacities greater than 2 MW in 2010. A power factor 

range was also established for RE, with penalties for non-compliance and potential 

bonuses for maintaining a favorable range.

A new operational procedure to maintain optimal voltage control has been proposed. 

CECRE has made it possible for more than 50% of electricity demand to be met by 

wind energy over the course of several hours—a particular challenge for a country with 

an isolated grid)

When evaluating grid code needs, it is important to distinguish between what needs to be 

addressed at the project level (e.g., wind plants) from what needs to be addressed at the generator 

level.
26

To further strengthen system operations, grid operators have also identified several changes that 

they can implement in the short-term, independently of new regulations and policies, such as 

visualization of system conditions and automated decision support tools (Jones 2011).

Challenges to Implementing Best Practices

• The use of forecasts requires operational change. Grid operators need to be aware and 

convinced of the benefits of integrating forecast data in daily operations.

• Optimal grid codes to accommodate variable RE require sophisticated analysis capability

and communication infrastructure. Decision-making systems need to be updated, and new 

programs are required to develop institutional capacity.

• Although codes set in advance minimize retroactive requirements to generators, codes set 

when penetration is low can unnecessarily burden variable RE technologies. Striking a 

balance in this timing represents a challenge in providing sufficient notice of new code 

requirements.

• Using new codes that reflect state-of-the-art engineering-based practices may be better 

than building from existing codes that draw from older or out-of-date practices.

• Every system is different, which prevents a uniform recommendation and adoption of a 

model grid codes. System-specific analyses are still needed.

• Jurisdictions have differing standards (e.g., in the United States, NERC requires one 

standard, WECC might require a higher standard, and a small balancing area can be even 

stricter). This lack of uniformity challenges manufacturers to serve multiple areas.

Actions to Implement and Improve System Operations

1. Develop national or regional forecasting systems:

o Identify advanced forecasting methods and their benefits

o Provide public support for research and development to improve forecasting methods 

and put them in the public domain

o Support outreach on forecasting benefits and training on best practices for grid 

operators

o Encourage efforts to research and continually improve forecasting techniques

o Work with regulators to require that all generators participate in forecasting, which 

necessitates that generators provide frequently updated data

2. Lead development of codes and standards that meet interregional and international needs 

to enable greater penetration of variable RE generation:

o Support work with regulatory commissions to evaluate model grid codes, recommend 

changes, and implement recommendations
27

System-wide Approach to Areas of Intervention

Areas of intervention are distinct but interrelated; taking a system-wide approach will ensure that 

not only are individual interventions more effective but also that the system as a whole will be 

more robust. Figure 2 shows one example of how each area of intervention might relate to others.

Figure 2. Example of interrelationships among areas of intervention
28

Costs of Integrating High Penetrations of Variable RE

Calculating the cost of integrating high penetrations of variable RE is very difficult; however, 

recent integration studies have demonstrated that the costs are manageable (Bird and Milligan 

forthcoming). Integration costs can be divided into three categories: those that relate to 

transmission extension and reinforcement (not including the cost of linking to the grid); those 

incurred in the balancing of increased volatility in the power system; and those that may be 

incurred to maintain the adequacy of the power system (i.e., its ability to cover peak demand). 

Milligan et al. (2011) note that all generation sources, including non-renewable sources, have 

associated integration costs. 

Several studies, including the Eastern Wind Integration and Transmission Study (NREL 2011), 

the European Wind Integration Study (EWIS 2010), and the Greennet Study (summarized in 

Holttinen et al. 2009) have examined integration costs. The Eastern Wind Integration and 

Transmission Study found that among various scenarios, the interconnection-wide costs 

excluding transmission costs for integrating large amount of wind were less than $5 per 

megawatt-hour (MWh). The European Wind Integration Study examined both costs and benefits 

of incorporating high penetrations of wind, finding that the costs of managing the variability of 

wind ranged from €2.1to €2.6 ($2.7 to $3.4) per MWh, less than 5% of the calculated wind 

energy benefits.

The Greennet study estimated wind power balancing costs in Denmark at 28% market share 

amounted to €1-€2 ($1.3-$2.6)/MWh (Holttinen et al. 2009). The estimated values are similar to 

real world experience in West Denmark, where costs have been €1.4-€2.6 ($1.8-$3.4)/MWh at 

24% wind penetration. These real world costs actually overestimate the balancing costs because 

the system operator collects more revenues than are actually required to pay the balancing 

resources used by the system, but nevertheless they are indicative of the magnitude of these 

costs. The Greennet study determined that additional balancing costs in Germany, at around 10% 

penetration, would be around €2.5 ($3.3)/MWh (Holttinen et al. 2009). 

Conclusion

The cases reviewed for this analysis illustrate considerable diversity, not only of the electricity 

systems—and their supporting markets, institutions, and renewable resources—but in the actions 

each country has taken to effectively integrate high penetrations of variable RE. The cases reveal 

that there is no one-size-fits-all approach; each country has crafted its own combination of 

policies, market designs, and system operations to achieve the system reliability and flexibility 

needed to successfully integrate RE. Notwithstanding this diversity, the approaches coalesce 

around five strategic areas of intervention:

• Engage with the public, particularly in developing new transmission

• Optimize features of the power system over a broad geographic area through system wide 

comprehensive planning and the use of markets

• Adopt market designs that help support system flexibility

• Expand the diversity of resources—both in type and through expanded effective 

balancing areas

• Improve system operations, including integration of advanced forecasting to reduce the 

impact of RE variability, and grid codes that ensure system reliability.
29

The best practices associated with these five strategic areas benefit all power systems, not just 

those with high penetrations of variable RE. Yet these strategies are particularly instrumental in 

accommodating variable renewables where they minimize the impact of RE’s variability and 

allow more options to cost-effectively strengthen the ability of a power system to respond to 

change. Advancements in energy efficiency and smart grids, when conjoined with higher RE 

integration, further strengthen the efficacy of any power system.

The study also emphatically underscores the value of countries sharing their experiences. Any 

country’s ability to successfully integrate variable RE depends on a wide array of factors—

technical requirements, resource options, planning processes, market rules, policies and 

regulations, institutional and human capacity, and what is happening in neighboring countries. 

The more diverse and robust the experience base from which a country can draw, the more likely 

that it will be able to implement an appropriate, optimized, and system-wide approach. This is as 

true for countries in the early stages of RE integration as it is for countries that have already had 

significant success. Going forward, successful RE integration will thus depend upon the ability 

to maintain a broad ecosystem perspective, to organize and make available the wealth of 

experiences, and to ensure that there is always a clear path from analysis to enactment.

References

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34

Appendix A. Introduction to the Case Studies

The following appendices present case study examples from six countries (Australia, Denmark, 

Germany, Ireland, Spain, and the United States) that have seen high penetrations of renewable 

energy. Appendix A provides an overview of the electricity mix in each country. Each country 

has a unique energy mix; of the countries examined, Denmark, Spain and Ireland saw the 

greatest percentages of wind generation in 2010, while Germany and Spain had the greatest 

percentages of solar, tide and wave generation (Figure A-1).17

Figure A-1. Percentage of electricity generation by type, 2010

Source data are from EIA (2012).

Data from 2010 provide only a snapshot in time. Figures A2 through A7 present growth in nonhydropower renewable generation from 2001 to 2010. Each case study country has seen different 

levels of non-hydro generation. In Denmark, Germany, and Spain, solar, tide and wave energy 

saw the largest growth rates from 2001 to 2010, though other sectors (wind or biomass and 

waste) contributed most on a generation basis in 2010. In Australia, Ireland, and the United 

States, the wind sector saw the greatest growth in percentage terms, and wind also contributed 

the most generation in 2010. 

 

17 EIA aggregates solar, tide and wave generation into a single category; however, it is likely that solar constitutes 

the majority of generation in this category

Nuclear

Hydroelectric

Geothermal

Wind

Solar, Tide and Wave

Biomass and Waste

Total Conventional 

Thermal

United States

Denmark Germany

Spain

Australia

Ireland

34
35

From 2001 to 2010, wind generation in Australia increased from 0.2 billion kWh to more than 

3.6 billion kWh, representing a compound annual growth rate of 33% (Figure A-2).

Figure A-2. Non-hydropower generation (billion kWh) in Australia, 2001-2010

Source data are from EIA (2012).

In Denmark, wind has continued to play a strong role, and biomass and waste resources 

increased from 2.0 billion kWh in 2001 to 4.8 billion kWh in 2011 (Figure A-3). 

Figure A-3. Non-hydropower generation (billion kWh) in Denmark, 2001-2010

Source data are from EIA (2012).

0

2

4

6

8

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Electricity Net Generation 

by Type (Billion kWh)

Geothermal Wind Solar, Tide and Wave Biomass and Waste

0

5

10

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Non-hydro Generation by 

Type (Billion kWh)

Geothermal Wind Solar, Tide and Wave Biomass and Waste
36

In Germany, solar has seen the largest growth from 2001 to 2010 (Figure A-4), though there has 

been strong growth in wind as well. The share of PV increased from 0.1% in 2003 to 1.9% in 

2010, representing 11,683 GWh (BMU 2011, Eurostat 2011). 

Figure A-4. Non-hydropower generation (billion kWh) in Germany, 2001-2010

Source data are from EIA (2012).

Ireland’s renewable energy development is almost exclusively wind, which has seen compound 

annual growth rate of 24% from 2001 to 2010 (Figure A-5).

Figure A-5. Non-hydropower generation (billion kWh) in Ireland, 2001-2010

Source data are from EIA (2012).

0

20

40

60

80

100

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Non-hydro Generation 

by Type (Billion kWh)

Geothermal Wind Solar, Tide and Wave Biomass and Waste

0

1

2

3

4

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Non-hydro Generation by 

Type (Billion kWh)

Geothermal Wind Solar, Tide and Wave Biomass and Waste
37

Spain provides a second example of where, in addition to wind, the solar sector has seen large 

growth (Figure A-6). Solar increased from 0.02 billion kWh in 2001 to 6.3 billion kWh in 2010, 

representing compound annual growth rate of 75%. 

Figure A-6. Non-hydropower generation (billion kWh) in Spain, 2001-2010

Source data are from EIA (2012).

In the United States, the greatest growth has come from wind generation, which increased from 

6.7 billion kWh in 2001 to more than 94 billion kWh in 2010 (Figure A-7). 

Figure A-7. Non-hydropower generation (billion kWh) in the United States, 2001-2010

Source data are from EIA (2012).

0

10

20

30

40

50

60

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Non-hydro Generation by 

Type (Billion kWh)

Geothermal Wind Solar, Tide and Wave Biomass and Waste

0

50

100

150

200

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Non-hydroGeneration by 

Type (Billion kWh)

Geothermal Wind Solar, Tide and Wave Biomass and Waste
38

References

BMU (Federal Ministry for the Environment, Nature Conservation and Nuclear Safety) (2011).

Renewable Energy Sources in Figures, National and International Development. Berlin. July.

Eurostat (2011). Online Eurostat database. Accessed 30th January 2011.

EIA (Energy Information Administration) (2012). International Energy Statistics. 

http://205.254.135.7/cfapps/ipdbproject/IEDIndex3.cfm?tid=2&pid=2&aid=12 Accessed April 2, 

2012.
39

Appendix B. Case Study: Australia (High Wind Energy Penetration in 

South)

Author: Craig Oakeshott, Principal Consultant, Sinclair Knight Merz (SKM)

Editor: David Swift, Executive General Manager, Australian Energy Market Operator

Background

The National Electricity Market (NEM) has been operating continuously in Australia since 

December 12, 1998. The NEM covers 92% of Australian electricity demand, and provides a 

common market structure, under the National Electricity Law (NEL), and single market operator, 

the Australian Energy Market Operator (AEMO), for the interconnected states: Queensland, New 

South Wales, Victoria, Tasmania, and South Australia. Generators, Transmission Network 

Service Providers (TNSP), Distribution Network Service Providers (DNSP) and retailers all have 

defined, non-overlapping, roles in the NEM and may, or may not, be privately owned. The 

TNSPs and DNSPs receive a regulated rate of return for the cost of operating the network and on 

investments that pass a market benefits test. Network fees are charged primarily to customers as 

part of their retail energy price. The NEM design is technology neutral. All generation is 

dispatched based on its market offers. The NEM offers open access to generators and, as such, 

there is no central planning directing generator investment in the NEM. Rather the size, 

configuration, fuel source, timing, and operational role of all generator investments are made by 

the proponent based on its own economic assessment. Market dispatch and network congestion 

provide pricing signals. Enhanced locational incentives within a region are provided by 

modifying regional prices with network losses and by imposing the cost of connection to the 

network on the proponent. Renewable energy targets and subsidies all act to change the 

economics of the decision to invest, but these occur independently of the energy market. See 

AEMO (2010) for a broad introduction to the NEM.

The NEM has been characterised by its clear governance structures and a strong adherence to 

sound market principles. South Australia has been part of the NEM since its inception and has a 

low population density. A number of long term wind studies in the mid 1980s showed that South 

Australia had a very attractive wind resource and provided a guide for identifying good 

locations. The introduction of a growing renewable generation obligation on retailers in the NEM 

from 2001 triggered the start of grid connected wind generation in South Australia. This 

obligation on retailers, to purchase a regulated percentage of renewable energy, provides an 

additional revenue stream to qualifying generators.

Table B-1 lists the population and key energy statistics for South Australia. Figure B-1 shows 

percentages of installed capacity in South Australia by generation type.
40

Table B-1. Statistical Summary of Population and Energy for South Australia

South Australian population (30 June 2011)a 1,657,000 

Customer sales (Estimate for 30 June 2011) 13,045 GWh

Peak demand (actual uncorrected 30 June 2011) 3385.42 MW

Average demand (actual uncorrected 30 June 2011) 1543.04 MW

Load factor 45.57%

Wind installed and operating at 30 June 2011 1150.35 MW

Wind energy production per capita 1807 kWh/person

Installed wind capacity per capita 694 W/person

a Australian Bureau of Statistics (2011)

Figure D-1. Percentage of installed capacity in South Australia, by technology

Calculated from statistics published in the AEMO 2011 Electricity Statement of Opportunities.

Wind Turbine, 21%

Gas / Steam subcritical, 23%

Coal / Steam subcritical, 14%

Gas / OCGT, 10%

Gas / CCGT, 9%

Gas or Diesel / 

OCGT, 4%

Gas / CCGT 

cogeneration, 3%

Diesel / OCGT, 2%

Diesel / Compression 

reciprocating engine, 

1%

Interconnectors, 

12%

 
41

Coordinate and Integrate Planning

The current electricity market planning arrangements were initiated following a review by the 

Council of Australian Governments. Their decision significantly enhances the original 

arrangement, recognising that the original jurisdictionally based approach was unlikely to deliver 

a truly national examination of grid expansion options, or result in the most economic national 

transmission network development. However, national planning remains an information resource 

only. Network planning and development is focussed primarily on reliably meeting customer 

demand as opposed to providing transfer capacity to support generators or meet renewable 

energy targets. While the majority of network investment has focussed on meeting the reliability 

standards, the planning approach does assess the expected future level of constraint in the 

network and does identify augmentations that deliver net market benefits.

The NEM provides a competitive wholesale electricity generation market and open access to the 

transmission network. Subsidies and targets for renewable energy affect the economics of 

investment decisions made by the generators but do so outside NEM operation and settlement. 

Investors may develop new generation projects at any location, time, and with any technology in 

response to their interpretation of market signals. The planning process may inform the investor 

of issues or opportunities, but there is no mechanism to force any particular outcome and any 

decision to invest in new generation is entirely the responsibility of the investing party. Most of 

the generators in the NEM, and particularly the renewable energy generators, are privately 

owned. Investments therefore will be driven by commercial imperatives, and they should be 

viable although they may not be the most economically efficient outcome from a national 

perspective. 

AEMO publishes a range of reports that seek to inform the market about potential opportunities 

for generation investment and network development, now, and into the future. 

AEMO’s annual Electricity Statement of Opportunities (2011) lists current operating plant, new 

projects that are at different stages of development, and a forecast of the year in the future when 

the anticipated load growth will exceed the level of available capacity needed to maintain the 

market reliability standard.

AEMO’s National Transmission Network Development Plan (NTNDP) specifically delivers a 

forecast of the network and market development over the next 20 years. The plan seeks to deliver 

the lowest-cost solution by optimising the expansion of both the network and generation and the 

mix of existing and future technologies employed. Integrating renewable generation into this 

planning process has been, thus far, relatively simple. The NTNDP analysis uses market 

simulation tools that incorporate reasonable cost estimates for all technologies. These costs are 

independently researched and verified in consultation with industry. The carbon price and the 

value of renewable energy certificates are applied to the resource costs and they therefore affect 

the relative costs between technologies over time.

While the generation development path from the NTNDP is only indicative, it highlights regions 

of the NEM where development is expected to be the most economically viable. The NTNDP 

informs participants about the potential generation mix in each state in the NEM, a view of 

network constraints and the potential lowest-cost network development path. However, project 

developers are driven by many factors that cannot be modelled, and they may not always choose 

the most economically efficient locations or configurations. The 2011 NTNDP explored the 

operational and constraint challenges that may arise if the significant levels of renewable energy 
42

generation in the NEM that were forecast in the 2010 NTNDP occur. 18 The NTNDP also 

provides the Australian Energy Regulator with an independent reference on future market 

development to assist in its examination of regulated network development proposals from the 

TNSPs.

While development of intermittent19 renewable generation, such as wind, could be aided by a 

central planning body developing large-scale transmission to areas with suitable resources, in an 

environment where most of the players are commercial organizations, such a decision would 

require “picking winners”. Project proponents pay for the connection assets between their plants 

and the shared network, but all customers pay for the cost of the shared transmission network 

and its development. Justifying which states, what locations and which resources should be 

developed would be problematic, as it would always result in winners and losers in the 

generation sector. At this stage, the total capacity of the renewable energy projects being 

discussed exceeds the existing targets, and there has been no shortage of projects that could be 

effectively developed close to the existing network. There is also at least one, privately proposed, 

large-scale transmission project being considered that would facilitate significant remote 

renewable generation and load development. The market benefits of these projects are yet to be 

assessed. Proponents can elect to pay for the removal of a constraint or partially fund an 

augmentation to the shared network. However, at this stage, the network capacity made available 

by such an investment is still subject to open access, and could be used by any participant. 

Generation investors cannot obtain rights over transmission capacity.

Development of capacity in the shared network relies on the TNSP, independently or in response 

to enquiries from a proponent, identifying a potential need and follows a formal justification 

process. This formal process is a market benefits test, known as the Regulatory Investment Test 

– transmission (RIT-t)20. RIT-ts are performed for each project to identify the solution that 

provides the maximum market benefits by examining appropriate transmission, generation, and 

demand-side projects that could relieve the network constraint. Costs and benefits considered in 

the test include reliability and potential competition benefits as well as total fuel, capital, 

operating and maintenance costs for all plant and equipment in the network.

Amendments to the NEM were proposed to enable a group of proponents to request a network 

solution to deliver power from a cluster of generation projects distant from the shared network 

and to realise the potential economies of scale through developing a common facility. Under the 

proposal, TNSPs would initially fund the required infrastructure for the proponents by an 

increase in transmission charges on customers. As proponents actually connect to the new assets, 

each would repay its share of the total cost of funding, offsetting future charges. This proposal 

was not ultimately implemented and the task of developing of a suitable alternative has been 

included in the current Transmission Framework Review.

 18 Three packages of work were published by AEMO. Lessons learned from international wind integration studies: 

http://www.aemo.com.au/planning/0400-0051.pdf, wind integration in electricity grids market simulation studies: 

http://www.aemo.com.au/planning/0400-0056.pdf and wind integration in electricity grids historical wind data 

analysis: http://www.aemo.com.au/planning/0400-0057.pdf. 19 In Australia, solar and wind power are known as intermittent because of the intermittent nature of their "fuel" 

resource. 20 The final Regulatory Investment Test determination and guidelines can be found at 

http://www.aer.gov.au/content/index.phtml/itemId/730920.
43

A Transmission Framework Review is currently underway to address potential deficiencies in 

the longer-term development of the national transmission system. This review is designed to 

address perceived barriers to investment in transmission, national cost/benefit allocation between 

states, improved mechanisms to resolve network congestion and cost allocation for remote 

transmission development. These initiatives could improve the clarity of economic signals for 

development without compromising the market objective or promoting specific technologies and 

targets. 

Community Support and Land Use Planning by State Governments and Local 

Councils

South Australia has large areas of land suitable for renewable energy deployment and relatively 

sparse population outside of the capital city. While surveys show a majority of the community 

supports renewable energy development, some incorporated groups now oppose development in 

more populated areas.

The land use planning approval processes, run by local councils and state governments, includes 

community engagement and feedback on the acceptability of specific developments. Proponents 

can obtain planning approval from local government or obtain state sanctioned special project 

status and a streamlined approval process through state government. Large wind farm developers 

can choose either approach, and there have been successes and failures for both alternatives. 

Ultimately, the approvals process can become highly politicised, and it may be governed by a 

range of issues in addition to local concerns. The Australian Government, while the architect of 

the renewable energy target, has no control over development approvals. 

Public information from planning bodies, such as the South Australian Electricity Supply 

Industry Planning Council21 (ESIPC), informed the wind developers of wider state and NEM 

issues through dedicated public forums and the annual planning publications. These mechanisms 

provided the public, proponents, governments, and regulators independent analysis of market 

opportunities, operational requirements, and responsibilities with respect to development costs. 

For example, the ESIPC presented information on the balance between the project connection 

costs and the available wind resource. This highlighted the advantage of building wind farms in 

areas with existing transmission capacity and a good wind resource, rather than in areas with 

exceptional wind resources but no grid. 

Gaining acceptance of wind development by the community remains a challenge for developers 

in South Australia and nationally. Active community engagement, through public fora and 

sponsored events in communities affected by the development of new wind farms are used to 

garner local support. Landholders that have turbines located on their properties are typically 

provided annual compensation per turbine. While long-term local employment opportunities are 

potentially limited to a few individuals, the additional money circulating in the community has 

many long-term benefits. On a larger scale, many of the major developers have run media 

campaigns to publicize the environmental benefits of their renewable energy activities and to 

promote their green energy products to consumers. Concerns about visual amenities have led to 

 21 The ESIPC was established after the privatization of the South Australian electricity industry. All South 

Australian participants, including the network service businesses, were sold to private companies. The ESIPC 

provided the South Australian government with a formal “observer” with the responsibility for liaising between 

industry, the market operator and the government. It particularly provided an oversight on transmission planning to 

ensure that issues important to the development in the state were raised, discussed and resolved appropriately.
44

the development of new state government guidelines for the siting of wind farms with respect to 

local communities and housing.

Many new renewable energy generation technologies are being investigated in areas where the 

renewable energy resource is rich but there is no transmission network. While the South 

Australian and the Australian Government may provide some seed capital and development 

incentives, no government in Australia to date is offering to build transmission infrastructure 

with public funds. This approach of not “picking winners” is designed to maintain a level playing 

field for development and drive projects with the lowest overall costs first. 

A number of published studies have investigated the cost of transmission to deliver renewable 

energy from remote resources and potential additional benefits from augmented interconnection 

between NEM regions. At the core of these assessments is the comparison between the cost of 

generating and delivering energy from a higher quality remote resource to the cost of generating 

and delivering energy from a poorer resource close to the load centre. 

Lessons Learned

• A well-designed framework for government land use approvals provides a streamlined 

and efficient process to balance community issues with project development that 

facilitates development and manages local support. 

• Maintaining community support, particularly in areas where the wind resources are good,

is an ongoing issue and needs to be actively managed through direct community 

involvement.

• The regional pricing and congestion signals calculated in the NEM and the cost of 

connection on proponents have encouraged development in areas well serviced by 

transmission capacity and not in areas where major transmission augmentation and 

connection costs would be required.

• A market benefits test assessment of transmission augmentations ensures that consumers 

pay only for developments.

• Analysis shows that there may be efficiency advantages if suitable schemes can be 

developed to realise the economies of scale possible in connecting new generation 

clusters remote from the grid.

Enable Markets to Facilitate Variable Generation

While some minor modifications to the NEM objective have occurred, it has remained 

effectively constant since the inception of the market and throughout the period of renewable 

energy development. The market objective is:

“to promote efficient investment in, and efficient operation and use of, electricity 

services for the long term interests of consumers of electricity with respect to –

price, quality, safety, reliability, and security of supply of electricity; and

the reliability, safety and security of the national electricity system.”

(AEMO n.d.)
45

Market operation is based on the premise of simplicity and transparency.

Key principals of the market operation that have remained constant since the inception of the 

market are:

• Gross pool with mandatory participation of all larger generators (> 30MW)

• Energy-only market based on security constrained optimised dispatch

• Energy dispatch and pricing co-optimised with market ancillary services

• Self commitment market with 5-minute dispatch on the basis of the latest offers

• Offers can be changed any time prior to dispatch

• 5-minute regional clearing price, 30-minute settlement period

• Dispatch optimisation includes impacts of network constraints and capability

• Network constraints affect price

• Single regional market price referenced to each generator’s connection point by the 

inclusion of losses

• Market price is collared (-$1030/MWh to $12,870/MWh) where negative prices provide 

strong incentives against oversupply

• Single market operator directly controls all significant generation on the interconnected 

network, allowing the optimal use of the power system whilst maintaining system 

security

• The market has no cross-temporal optimisation but a great deal of forward information 

with respect to forecast prices and demand is provided to participants to assist their 

planning in every timeframe

No wind farms existed in Australia on the shared network at the start of the market in 1998 and 

no consideration had been given to this form of generation making a significant contribution to 

the future energy needs of the customers. 

The rules of the market have been amended to incorporate intermittent generation but in a 

manner that is consistent with the market objective and the existing market model. The necessary 

changes were determined by evidence-based analysis, in consultation with all participants in the 

industry and with the support of, but independent from governments. Investments made in the 

past were not been required to meet new requirements but rather were been grandfathered.

Integrating Intermittent Generation

Integrating wind generation into the operation of the market focused on technology neutrality 

and ensuring power system security, especially security against the risk of cascading failures. 

The original market design considered only two dispatch categories: “scheduled” and “nonscheduled” generation. Wind was initially registered in the “non-scheduled” category, and 

consequently its output was not subject to central control or optimization, leading potentially to 

stability and security issues. A third category, “semi-scheduled” generation, was established for 

intermittent generation that maintained the obligations for control and the information provisions 

from the “scheduled” category but was tailored to better match the character of intermittent 
46

generation and to facilitate the integration of wind into market systems. This included providing 

a verified energy conversion model to convert forecast wind speed into power.

Generators in the semi-scheduled category submit offers for their output (dollars for megawatts 

dispatched) and are included in constraints and market dispatch. Forecasts of the output of each 

wind farm are incorporated into the market systems, and if a wind farm is part of a binding 

network constraint, depending upon their bid price compared to other generators in that 

constraint, its output can be capped. Forecasts of the total regional wind contribution, customer 

demand projections, and potential network constraints are provided to all market participants. 

Other forms of generation are therefore aware of the opportunities and can make their own 

decisions as to when to commit plant and the price and quantity of generation to offer.

Wind generation, as a semi-scheduled generator, also pays a share of ancillary service costs 

calculated on a “causer pays” basis. This calculation summates the contribution each generator 

makes to the need for system frequency control. 

Lessons Learned

• A stable market design that can evolve to help integrate variable renewable generation 

has reduced sovereign risk and provided some security for existing and proposed 

developments. Providing a simple, clear and transparent market-operating environment 

from which market signals are evident is imperative and significantly aids integration.

Motivate System Flexibility

The NEM provides incentives for greater flexibility in the behaviour of generators. As the 

proportion of wind generation in the South Australian region has grown, the frequency of low 

and negative pool prices has increased. Low prices occur when there is significant surplus of 

generation, such as when wind output is high and demand is at average or low levels. This has 

provided:

• Incentives for wind generation to reduce output in periods of negative prices, assisting 

through market signals to resolve a potential situation of excess generation

• Incentives for other plant to increase its flexibility with changes to control systems and 

operating arrangements to allow generators to optimise their behaviours to match the 

opportunities in the market 

o In South Australia, older coal fired generators with steam bypass capabilities are now 

using these facilities to reduce their output to levels below their normal minimum 

stable operational point to avoid negative prices during periods of excess supply.

The NEM is an energy-only market with close to real-time pricing. While prices in South 

Australia can be low, even negative, when supply is high relative to demand, prices can also rise 

quickly when wind output falls and other generation needs to ramp up its output or start

generating. The NEM has therefore also provided an incentive for new flexible, fast-start 

generators to enter the market allowing future investments to manage their risk and maximise 

their earnings potential. 

Promoting Diversification of Location and Type of Renewables

The Australian approach has been to allow market signals to drive new investment to the extent 

possible. All of the developers of new generation projects in Australia are privately owned, and 
47

their investment decisions are likely to be based on delivering commercial rates of return and 

should account for the location, technology, timing, and anticipated market role of the proposed 

generator. 

The NEM is a regional market and regional wholesale market electricity prices are set, as part of 

the dispatch process, in every dispatch interval. The price at every connection point is derived 

from the regional reference price modified by a locational-specific multiplier that reflects the 

incremental network losses to that point. The multiplier, the cost of connection to the network, 

and the likelihood of constraints in the network all act as signals for new generation investments. 

These are all part of the normal operation of the market and are not specific to a generation 

technology. Market participants are well aware of these factors and are careful to understand the 

potential exposure that their project may have during the feasibility stage of development.

Regional Pricing

Each state or region in the NEM has a nominal “load centre” known as the Regional Reference 

Node. The market dispatch process establishes a regional price at each regional reference node in 

every dispatch interval. The performance of each nominal interconnector between the regional 

reference nodes is represented by a mathematical equation. These mathematical equations are 

used in the dispatch process to rank the relative price of an additional megawatt of capacity over 

the interconnector as compared to one generated locally. Over time, generation investment will 

be biased toward those regions with the highest price and hence greatest need for generation.

• Based on discussion with the wind proponents, the occurrence of negative prices in South 

Australia clearly factor into their decisions for ongoing investment. The frequency of low 

prices is also affecting the forward contract prices for both wind farms and fossil-fuelled 

generation. 

• Wind proponents are not advancing their projects until power purchase contracts have 

been finalized.

• While the number of wind farms under consideration is still considerable, a number of 

conventional open cycle gas turbine generation projects are also progressing and the 

transmission network service provider is actively investigating additional interconnector 

capacity.

The pattern of half-hourly prices over a year provides a very sophisticated price signal. The 

generation weighted average price for any particular generation pattern reflects the earnings for 

that generator. South Australia experiences a relatively uniform wind regime across the state. As 

wind generation in the state has grown, the market earnings of those wind generators has fallen 

in relative terms. During periods of high wind, the wholesale market price is significantly 

depressed because of the relative abundance of supply. Consequently, wind farm earnings during 

the periods when their output is the greatest is low. During calm periods, the relative scarcity of 

supply is higher and market prices are higher. It can be clearly shown that wind generators in 

South Australia earn a lower volume-weighted average price than other generation in the region 

and as the penetration of wind has increased the gap between the volume and time weighted 

prices received by the wind farms compared to fossil fired generation has grown.

Table D-2 highlights the growing difference between these earnings prices. 
48

Table B-2. Time and Volume-Weighted Prices for Renewable and FossilFuelled Generation in South Australia ($A/MWh)

Financial 

Year

Renewables Fossil Fuels South Australian 

Market

Full year 

TimeWeighted

Full Year Summer Full Year Summer Full Year Summer ($A/MWh)

($A/MWh) ($A/MWh) ($A/MWh) ($A/MWh) ($A/MWh) ($A/MWh)

2003/04 33.09 40.56 39.96 50.43 43.85 61.09 32.57

2004/05 38.47 56.72 44.56 67.5 44.61 67.92 33.33

2005/06 32.57 39.59 43.91 67.5 43.26 65.78 34.34

2006/07 49.69 51.55 58.71 67.21 58.35 66.43 62.95

2007/08 63.31 63.94 102.01 149.92 98.46 142.32 55.95

2008/09 46.39 91.8 70.5 165.34 67.16 155.12 38.76

2009/10 47.39 77.43 86.69 140.98 80.17 131.01 28.44

2010/11a 22.82 29.75 50.78 91.74 45.17 78.60 27.63

a Pro rata assessment for July 1, 2010 to 31 March 31, 2011

The price signal can be seen to encourage diversification in location, wind resource, and 

technology of generators. South Australian wind is not as well correlated to peak demand 

periods. Developers are now considering wind generation in other regions of the NEM where the 

correlation of output to periods of higher demand is greater, increasing the potential market value 

of their output. There are also potential benefits to other forms of intermittent renewable 

generation that can generate when the wind output is lower. Solar power could offer such 

diversity and has a higher correlation to peak demand, which could be expected to improve the 

generation-weighted price it obtains. At this stage, despite potentially higher returns and the 

renewable energy credits, the only large-scale solar projects being actively pursued are in other 

states, and they rely on significant additional Australian government subsidies. 

Marginal Loss Factors within a Region

Within a region, the marginal loss factor represents the losses between a connection point and the 

regional reference node. This is effectively a proxy for the relative balance between supply and 

demand at a location within the region with respect to the regional reference node. This signal is 

in the form of a multiplier to the regional reference price used in the dispatch process and in 

market settlements. Marginal loss factors for all generators and customers are calculated 

annually one year ahead based on known projects and forecast demand at each location.

Where local supply exceeds the proximal demand, the price received by the generators at that 

connection point is discounted to reflect the transmission losses incurred transferring the excess 

power to distant customers. The marginal loss factor discounts the market price received by the 

generators in that location providing a disincentive for further development at that location. 

Conversely, where local demand exceeds the proximal supply a marginal loss factor would 

provide an incentive for local supply investment. In a state such as South Australia, where there 

is such a large amount of suitable land with adequate wind resources, such a signal to relocate is 
49

not seen as limiting wind penetration. Rather, it provides a signal to explore appropriately sized 

opportunities close to load. Most developers incorporate this aspect into their investment 

decision. 

Network 

Developers negotiate with the transmission network service provider to determine the cost and 

capacity of their proposed connection. All generators are responsible for their “shallow” 

connection costs to the grid, providing an additional locational signal.

The negotiation of a satisfactory connection however, does not warrant any particular level of 

access to the shared grid. Network constraints, in the “shared network”, between the proponent’s 

project and potential demand centers may arise with new generation, especially in areas with 

good resources. In the NEM, congestion will be considered for removal but will not be 

eliminated unless an upgrade represents economically efficient solution to additional supply. 

This then drives developers to seek projects sited close to strong points in the network to 

minimise connection costs and congestion on the shared network. 

Developing and Integrating Advanced Forecasting Techniques into Grid 

Operations

The energy-only market design in Australia relies on the market operator using a forecast of 

future customer demand, wind production, and advanced generator bids in a simulated market 

dispatch to provide a forward price projection up to seven days ahead to drive efficient 

outcomes. The NEM has no inter-temporal optimisation and does not pay start-up or shut down 

costs. Generators use these price forecasts to make their own decisions on when to commit their 

plant. Wind generation is part of this prediction.

It was recognised early in the development of wind power in South Australia that without a stateof-the-art forecasting system to inform the NEM of the potential contribution of wind power to 

system operation and security would be adversely affected. It was seen as unnecessarily onerous, 

inefficient, and potentially inaccurate for each wind farm to attempt to forecast its own output 

over market operational and planning time frames. A number of proponents were significantly 

concerned about their ability to fund and continuously operate individual forecasting systems 

that would be suitable for market operation. The ESIPC and the market operator initiated 

working groups to examine the potential for the development of a national system and engaged 

with the Australian Government as a potential source of funds. Together, these bodies 

established a model22 to develop and deliver a suitable wind forecasting system, for all

participants, that would be fully integrated into the market dispatch and pricing process. Wind 

generators are obliged to provide information to the market operator as inputs to the national 

wind forecasting system. As a centrally coordinated system it incorporates inputs from a wide 

range of public and private resources, from individual wind farm or turbine outputs and onground automatic weather stations to satellite imagery. 

 22 A working group known as the Wind Energy Technical Reference Group provided an industry reference point for 

the Australian Wind Energy Forecasting System. Terms of reference for the reference group can be found at 

http://www.aemo.com.au/electricityops/0260-0005.pdf.
50

The system23 delivers forecasts of wind production for all wind generators. These are published 

in aggregate for all participants with the demand forecast and individual production profiles are 

provided to the appropriate market participants in all market time frames. 

The design of the forecasting system is such that it is also a platform for researchers to improve 

forecasting processes and will be able to accommodate other intermittent renewable generation, 

such a solar. 

The greatest risk to security and reliability of supply of wind generation is the potential for rapid 

changes in output caused by sudden changes in wind speed or by wind speeds above cut-off 

speeds. The forecasting process uses the average of the predicted wind speed outcomes from a 

series of different atmospheric models and performs well under stable atmospheric conditions. 

However, where the individual forecasts diverge, particularly during periods where atmospheric 

conditions are likely to change rapidly, predicting the timing and magnitude of these rapid 

change events is less reliable. In recognition of this situation, research24 into additional 

forecasting functionality was commissioned through the University of New South Wales and has 

delivered some potentially significant improvements in this area.

Lessons Learned

• A centrally funded and coordinated wind forecasting system has provided an integrated, 

reliable, scale-efficient, and world-best practice facility on which market dispatch 

systems and participants can depend. 

• Integration of the wind forecasting system into market systems has aided decision making 

by all market participants and the market operator.

• A central, commonly supported forecasting service ensures consistency and extends the 

potential for providing advanced warning of rapid change events by integrating inputs 

from wind farms, automatic weather stations and other meteorological sources.

• The central facility can be expanded to accommodate other forms of renewable energy,

providing an automatic reflection of new technologies into the market systems and 

dispatch processes and supporting industry research, supporting its longevity and 

constant improvement. 

• Putting obligations on all wind participants has ensured the consistency of information 

and has reduced participant overheads

Supporting Model Grid Codes

Just as the original market dispatch arrangements were not well matched for high concentrations 

of intermittent renewables such as wind farms, the technical standards were also poorly suited to 

intermittent renewable energy generators. The technical standards at the start of the NEM were 

designed around the capabilities of conventional gas, coal, and hydro-powered generation. The 

latest technical standard revisions have focussed on removing this technological bias and 

establishing more universal performance requirements. 

 23 A presentation describing the Australian Wind Energy Forecasting System can be obtained at 

http://www.aemo.com.au/electricityops/0260-0007.pdf. 24 For more information, see http://www.aemo.com.au/electricityops/0269-0001.pdf. 
51

Rapid development of wind farms in South Australia overtook national processes to adjust 

national technical standards. The South Australian Essential Services Commissioner and the state 

Energy Minister requested the ESIPC review the impact of wind generation on the price, 

reliability and power quality of wind generation. The ESIPC (ESIPC 2005) considered that a cap 

on installed wind capacity would be difficult to administer and inconsistent with the market 

philosophy, and it instead recommended a range of measures to integrate wind generation into 

the market, including higher technical standards for future wind farm connections. 

All generators in South Australia must be licensed by the Essential Services Commissioner 

before they are permitted to operate. The technical standards recommended by the ESIPC were 

imposed as special license conditions on new wind farms. These standards were, to the extent 

possible, consistent with the national generator standards but biased toward the higher end of 

requirements. Specifically, in South Australia, the standards required all wind farms to:

• Register and operate as scheduled generators until the national “semi-scheduled” 

classification came into existence

• Participate in the national forecasting initiative that was just commencing at the time

• At the connection point to the shared network the wind farm must: 

o Ride through a 170 millisecond two phase to ground fault,

o Provide voltage control,

o Be able to operate at ± 0.93 power factor (50% of this to be dynamic fast acting; the 

other 50% to be slow acting and, with the consent of the TNSP, it could be differed to 

a time in the future when it may be needed, and

o Provide full remote control capability for the local TNSP/market operator.

Significantly, the requirements focused on the performance of the wind farm at the connection 

point rather than on the turbines or individual components within the farm. It is particularly 

important that the reactive requirement be tested at the connection point. With equipment such as 

a STATCOM, a wind farm composed of less expensive, lower-performance turbines could 

comply with the requirements. The standards have delivered a stable and secure power system in 

South Australia with no recorded incidents despite occasions when more than 75% of the state’s 

power was supplied by wind generation. 

A review of the national Technical Standards provided greater flexibility for negotiation and 

incorporated some of the requirements identified by the ESIPC. Subsequently, the South 

Australian licence conditions were revised to align with specific clauses in the NEM technical 

standards but have not been significantly relaxed.

Opinion on these license conditions from the wind industry is polarised. Some proponents have 

praised their clarity and simplicity and have indicated that this mechanism has supported the 

ongoing development of the industry in the state by ensuring that each new wind farm will not be 

adversely affected by neighbouring farms. Others have indicated that the additional cost of 

compliance has adversely affected the financial viability of their projects. The ESIPC estimated 

that the additional cost of the license conditions added between two and three percent to the total 

capital cost of the wind farm projects.
52

The ESIPC’s approach of requiring each wind farm to install reactive plant at its connection 

point has been criticised for delivering an oversupply of reactive capability in areas where a 

number of closely spaced farms have been built. However, the approach was considered justified 

in the absence of a more comprehensive regime, or market, for the provision of reactive power.

Lessons Learned

• Providing a level playing field that maximises the potential development by minimizing 

impacts of one generator on another is very important. 

• Focussing on the performance at the connection to the network is more effective in 

managing that impact than predefining the performance of individual components.

Political Environment, Initiatives, and Incentives

The development activity based on Australia’s renewable energy targets has been high and has 

benefited from bipartisan political support. A high level of policy certainty is clearly required to 

underpin market-based investment.

South Australia has a stable political environment with well-defined processes for gaining 

planning and development approval for all projects, not just electricity or energy. To date, these 

processes have applied to the development of wind generation in South Australia. 

The national Mandatory Renewable Energy Target scheme imposed a requirement for retailers to 

purchase a given percentage of their energy from renewable generation sources. The obligation is 

met by acquiring tradable certificates, or renewable energy certificates, to the necessary level. 

This allows open competition between different forms of renewable generation anywhere in 

Australia. If retailers fail to purchase sufficient certificates to meet their obligations, they would 

be financially penalised. To date, compliance with the scheme has been higher than 99%. 

The Australian Government renewable energy scheme has been in place since 2001. Revisions 

have been made based on consultation and economic analysis, retaining the intention and design 

of the scheme without the destabilisation of radical redesign. The initial target for 2010 was 

relatively small, requiring only approximately an additional 2% of energy consumed be sourced 

from renewable energy generation. Investment in renewable energy began faltering in the face of 

a fully subscribed scheme. A change in the Australian Government in 2007 resulted in the 

renewable energy policy target being increased to 20% of electricity consumed by 2020 (or 

60,000 GWh of renewable energy).

The scheme has occasionally suffered because of other renewable energy policy initiatives both 

by the Australian Government and State Governments. In 2009, the renewable energy target was 

split to provide separate targets for renewable energy from small generation systems (especially 

rooftop photovoltaic solar) and that from large renewable generators such as wind farms.

The State Government also established ambitious renewable energy targets during this period 

and, while they provided no financial incentive, they clarified state government support for 

development. 

Conclusions 

Overall, South Australia has benefited from an electricity market and renewable energy 

incentives that have focused on creating economic drivers rather than selective incentives or 

selecting individual projects or technologies. National renewable energy targets, for which the 

incentive price is determined by its own market, have provided a technology-neutral subsidy that 
53

operates separately from the electricity market, and effectively delivered economically 

appropriate renewable energy generation. The location of these projects has been strongly 

influenced by regional and locational pricing signals from the real time electricity market 

dispatch and by the proponent bearing the cost of connection. By designing technical standards 

and performance obligations that are focused on the connection point rather than on the 

generating equipment, this has, at a minor increase in the cost of development, maintained a 

reliable and secure network that can support ongoing renewable energy development. 

Institutionalized market planning, based on socialised and accepted technology performance and 

cost data, provides unbiased information to all market participants. Generators gain insight into 

the relative potential of their chosen technology over the longer term; transmission companies 

obtain significant information about network constraints and the relative merit of their removal; 

regulators and other non-market bodies can clearly see potential market growth and reaction and 

benchmark the overall efficiency of their policies.

References

[AEMO] Australian Energy Market Operator. (2010). “An Introduction to Australia’s National 

Electricity Market.” Melbourne: AEMO. Accessed April 17, 2012: http://www.aemo.com.au/ 

corporate/0000-0262.pdf.. 

AEMO. (2011). “2011 Electricity Statement of Opportunities.” Accessed April 17, 2012: 

http://www.aemo.com.au/planning/esoo2011.html.. 

AEMO. (not dated). “Electricity Market.” Accessed April 17, 2012: http://www.aemc.gov.au/ 

Electricity/Electricity-Market.html. 

Australian Bureau of Statistics. (2011). “3101.0 - Australian Demographic Statistics, Jun 2011.” 

Accessed April 17, 2012: http://www.abs.gov.au/AUSSTATS/abs@.nsf/ 

allprimarymainfeatures/C521664B22CEE131CA2579CF000F9AF4?opendocument. 

[ESIPC] Electricity Supply Industry Planning Council. (2005). Planning Council Wind Report to 

ESCOS. http://www.escosa.sa.gov.au/library/050429-PlanningCouncilWindReport-ESPIC.pdf. 
54

Appendix C. Case Study: Denmark

Author: Hugo Chandler, New Resource Partners

Introduction

A key challenge for Denmark will be to attain its very ambitious target for wind energy: 50% of 

electricity production in 2020, up from 28% in 2011. Denmark is well located to achieve this 

level of ambition: the country is strongly connected to Germany and Scandinavian countries, 

which absorb the wind energy that spills over its borders. The share of wind energy over this 

larger area is much smaller than when the country is viewed in isolation. 

New transmission is less of a challenge in Denmark that it is in Germany, for example. Danish 

interconnections already amount to approximately 80% of the country’s peak power demand, 

and additional lines are under development. Rather, the challenge will be to find the right 

balance between addressing the wind power integration challenges with increased reliance upon 

power trading with neighbors that also have major wind energy ambitions, compared to 

introducing solutions within the Danish borders. 

Germany’s wind industry association believes an additional 25 GW could be installed on land 

and at sea by 2020, on top of the 29 GW today (GWEC n.d.). ENTSO-E estimates that in the 

Nordic region as a whole, meanwhile, wind capacity could rise to approximately 15–20 GW in 

the same year (ENTSO-E 2010), at which point less than half of Nordic wind capacity would be 

located within Danish borders.

Output throughout this northern region is likely to be highly correlated. This means that 

competition for flexible resources such as Norwegian hydropower, to balance these largely wind 

power ambitions, is going to increase. Denmark may need to increase its domestic flexibility. 

Focus of Case Study

The second section of this case study sets the scene for discussion of past and ongoing challenges 

in the system integration of variable RE. In Denmark, this equates to wind power. Solar PV and 

wave power deployment are still negligible.25 This section describes the status of wind power 

deployment in Denmark and summarizes policy development. Finally, it highlights best 

estimates of balancing costs in the literature. 

The third section of this appendix addresses the key areas wherein action has been taken to 

facilitate the deployment of wind power. It is divided as follows:

1. Integrated planning of transmission and variable RE deployment

2. Building public support for new transmission

3. Increasing the flexibility of the Danish power system

4. Making markets more amenable to variable RE

5. Advanced system operation and grid code development

 25 Solar PV currently shows very strong growth due to a very favorable support scheme and decreasing PV module 

prices. Hence, solar PV might become a significant electricity source during the summer period in Denmark in year 

2020.
55

The fourth section addresses the lessons that might be learned from the Danish case by other 

countries with similar system attributes; and the final section presents key conclusions regarding 

Danish experiences with wind power.

The term “flexibility” will be used a number of times in this appendix. Briefly, it is used to 

encompass all aspects of a power system that are complementary to variable (sometimes referred 

to as intermittent) production of electricity. Examples include controllable power plants (e.g., 

hydropower, gas, coal plants), energy storage (such as pumped hydropower), demand-side 

management and response, physical trade of electricity with neighbors, power markets that both 

enable and stimulate more liquid trading, and more dynamic operation of the power system.

Context

The Danish Wind Market

The share of wind energy in electricity production grew vigorously until 2004, when policy 

support tailed off with a change of government. It recovered in 2009 with the return of stronger 

political support, to reach 28% in 2011.26 Penetration is higher in the west of Denmark, 

amounting to 30% of annual power consumption in 2010, compared to 22% over the country as a 

whole.

Policy Support

Government support for wind energy in Denmark has a long history. One of the earliest 

important events was the establishment of a wind energy centre at Risoe National Laboratory, 

which pioneered the first wind speed atlases. In 1990, a feed-in tariff (FIT) was set for wind 

power plants, which was the primary driver for the industry. Also in 1990, the Third Danish 

Energy Plan set up the first national wind power target: 1,300 MW by 2000. In 1993, a new 

Ministry for Environment and Energy was set up, linking the two portfolios closely. In 2007, a 

new Ministry for Climate and Energy was created. 

On January 1, 2009, the Promotion of Renewable Energy Act (Lov om fremme af vedvarende 

energi) passed into law. It rebooted the installation of wind power with a strong feed-in premium 

paid to producers on top of the market price. The premium amounted to $44/MWh payable for 

22,000 full load hours in 2009 (Energinet 2009a). 

Calls for tender are used to set FITs for offshore wind farms, winners being decided based on the 

lowest tariff required (Energy Policy 2010, Energinet 2009a). This applies for a fixed period, 

after which the wind farm remains alone in the market place. For example, the Rødsand Two

offshore wind farm receives in total (premium plus market price) $0.11 per kWh. The premium 

applies to electricity production amounting to 10 TWh, for a maximum of 20 years (IEA/IRENA 

2011).

February 2011 saw the publication of Energy Strategy 2050, which resulted from the findings of 

the Danish Commission on Climate Change Policy. The strategy aims to increase the share of 

wind and biomass energy to 33% of all energy in 2020, up from 19% in 2009. In terms of 

electricity, wind power is to contribute 40%. This already ambitious target was increased to 50% 

by the new government that took power in Denmark in October 2011 (DWEA).

 26 The drop in 2006 reflects the fact that year saw below-average wind speeds; capacity installed remained 

unchanged.
56

Costs of Wind Power Integration

Integration costs can be broken down into three categories: those that relate to transmission 

extension and reinforcement (not including the cost of linking to the grid); those incurred in the 

balancing of increased volatility in the power system; and those that may be incurred to maintain 

the adequacy of the power system (i.e., its ability to cover peak demand).

In 2008, an Electricity Infrastructure Committee, including Energinet, estimated transmission 

needs up to 2030, including those resulting from wind power. From the broad range of 

technology choices it investigated, with different mixes of overhead lines and underground 

(more expensive) cables, the Danish Government selected the option with a cost attributable to 

wind power of $354/kWh, for 3.5 gigawatts of additional wind power. 

The Greennet study (see Holttinen et al. 2009) found that wind power balancing costs in 

Denmark at market share of 28% amounted to approximately $1.31–$2.62/MWh.27 These values 

are supported by real world experiences in West Denmark where costs have amounted to $1.8 -

$3.4/MWh at a 24% penetration (Holttinen et al. 2009).

Key Factors with Bearing on Variable RE

This section addresses challenges, actors, their actions, and outstanding issues related to 

integrating wind power into the Danish power system. 

1. Integrated Planning of Transmission and Variable RE Deployment

The high-voltage transmission grid in Denmark is fully owned by a public company, Energinet, 

under the Ministry of Climate and Energy. Consequently, reinforcement and expansion of it, as 

well as international link-ups, are driven directly by the strategic energy policy of the 

government. The value of Energinet as a driver of effective wind power integration and 

management in Denmark cannot be overstated. Indeed, in and of itself, Energinet is a principal 

reason the grid can be said to be limited barrier to wind power. 

For example, in the case of major power projects, including larger wind farms, Energinet will 

usually commence front-end work (such as design and consenting) ahead of the RE project 

consent. This practice is not regulated as such; the TSO can use its discretion as to timing.

Although it does not actually commence construction until the power plant is consented, this 

early action is likely to reduce the length of the integration process, which is important as 

reinforcement work can take two to three years to complete (Eclareon 2011). 

In March 2009, Energinet completed a Cable Action Plan in collaboration with regional 

transmission companies, which details the upgrading of the entire high voltage grid. This 

amounts to approximately 3,200 kilometers (1,998 miles) of line to be replaced with about 2,900 

kilometers (1,802 miles) of new cables (Energinet 2009b). The action plan addresses not only 

wind power; it is a coherent plan for the needs of the system as a whole. Work that benefits wind 

power deployment also substantially benefits the wider system, and vice versa. 

East and West Denmark are part of distinct grid systems. The Jyland Peninsula is part of the 

continental European system, while East Denmark–comprised of the islands–is part of the 

Nordic system. While both have long interacted through the Nordic power market, they were 

 27 Greennet Study led by the Energy Economics Group of the Technical University of Vienna and summarized in

Holttinen, et al. (2009)
57

finally electrically connected in 2010 via the “Great Belt” direct current link, providing 

additional management options for surplus wind power in the west. 

International Transmission Efforts

Significant efforts are underway to electrically link Denmark more closely to adjacent and 

nearby markets, and some links have already been made. These links help spread inexpensive 

wind power production more widely, increasing its value, while decreasing power prices in the 

areas to which it flows. They also enable surpluses to be stored (e.g., in Norwegian pumped 

hydropower facilities). In an average year, imports and exports of electricity to and from 

Denmark amount to the equivalent of nearly one third of total consumption. 

Additional interconnector links to Norway the Netherlands, both of them marine cables, are 

being developed. Skagerrak 4 is an additional 600-MW high-voltage direct current (HVDC)

connection with Norway across the stretch of sea with that name, scheduled for operation in 

2014. The final investment decision regarding the Cobra 700-MW HVDC link between Jyland 

and the Netherlands is planned to be made in the end of 2014.

Coordinated Planning and Connection of Variable RE Plants

Denmark and Germany are planning an important technological innovation that may prove to be 

the first step taken toward an international, truly offshore grid.28 It may be an efficient way to 

share the output of large wind farm clusters among sponsor countries, while also increasing the 

capability of power to flow between the latter when the wind is not blowing. The wind farm 

cluster will be located at Kriegers Flak in the Baltic Sea, between the sponsor countries. 

Grid Connection

Most land-based wind power in Denmark is connected to the distribution grid. Under the 

Electricity Supply Act, the distribution system operator is obliged to connect any new power 

plant meeting pre-established technical requirements. The Act also gives priority to RE plants. 

However, the precise connection procedure is not codified in law, which can lead to delays. 

The distribution system operator is obliged to reinforce the grid if necessary, in consultation with 

Energinet, and the distribution system operator pays. The cost is passed on to the consumer 

through a levy, the Public Service Obligation. This is significant as the connection cost usually 

represents less than 10% of the total integration cost (RETD 2008). Wind energy, specifically, 

gets further financial help under the Promotion of Renewable Energy Act, which specifies that 

the developer and the distribution system operator share the cost of connection. RE plants are 

also exempt from charges on the use of the transmission system (Eclareon 2011). 

Energitilsynet, the energy regulator, must be consulted if the development of the grid at the 100-

kV level or higher is concerned; it must balance RE deployment ambitions with least cost to the 

consumer. The regulator is not obliged to set a deadline for this procedure, but again, the delays 

encountered do not appear to be significant. Indeed, a recent study (Wind Barriers 2010) found 

that the average time required for a grid connection permit in Denmark was an order of 

magnitude less than in the wider European Union.

29

Developers in offshore development areas bear no integration costs outside the wind farm itself, 

the boundary of which is usually measured as one rotor’s width from the turbines. The link to the 

 28 Sweden had also been involved in the initiative but withdrew in 2010. 29 According to Wind Barriers (2010), the connection lead time in Denmark averages 2.1 months, compared to an 

average of 25.8 months in the European Union.
58

grid—including the transformer station, cable to shore, and any reinforcement required of the 

land grid—is considered integral work to the grid, and is therefore met by Energinet and passed 

on to the consumer (Van Hulle et al. 2009).

Variable RE Planning

The more than 5,000 onshore wind turbines installed in Denmark to date have resulted from no 

centralized spatial planning process. Local decision-making has driven their distribution, quite 

evenly, over Denmark, although concentrations of turbines are higher in the west (Jyland) and 

coastal regions. 

Since 2010, a Wind Turbine Secretariat has assisted municipalities in the entire planning process.

Energy Strategy 2050 suggests combining this decentralized approach with new, more holistic, 

planning tools. For example, the strategy includes a proposal to locate turbines nearer roads and 

railways; however, doing so is currently hindered by distance requirements. The strategy targets 

some 1,800 MW of new onshore wind plants and estimates that some 500 MW of this additional

capacity will be brought about by this improved planning approach (Danish Government 2010).

For specific areas identified through a screening process, the government steers the location of 

new offshore farms through public calls for tender. The youth of offshore wind technology is 

such that any development outside zones designated by government calls for tender would be 

prohibitively expensive, as developer would have to bear any integration costs. 

Specific targets for additional offshore wind power include two calls to develop 600-MW wind 

farms at Kriegers Flak in the Baltic Sea and at Horns Rev in the North Sea, and an additional 400 

MW of smaller, near-shore installations. And, plans may be afoot to open new offshore 

development zones to meet the recently announced 50% wind target for 2020 (RECHARGE 

2011).

No action has been identified that was specifically taken by Danish actors to diversify location of 

wind power in order to achieve geographic smoothing of aggregated output. This is perhaps

because Denmark is too small for much gain to be made, and plants are already widely spread 

(see Figure C-2). 

2. Building Public Support for New Transmission

Very strong public support exists for RE in Denmark, but it does not necessarily stretch to the 

additional transmission infrastructure that wind power implies. Moreover, as in most 

Organisation for Economic Co-operation and Development countries, grid infrastructure in 

Denmark is aging and in need of routine upgrading.

Denmark plans to take radical action to remove public objections—mainly aesthetic objections—

to new transmission needs. In February 2008, political agreement was reached on the need for 

cabling (i.e., placing lines underground), with the selection of one of six options for grid 

development prepared by an Electricity Infrastructure Committee. Energinet and its regional 

partners subsequently prepared a Cable Action Plan, and presented it to the ministry in March 

2009. The plan includes the undergrounding of the entire 132-kV to 150-kV grid by 2030, and all 

new 400-kV lines by 2030. The committee also suggested that the entire distribution network (6–

60 kV) might be buried in this timeframe. The cost of undergrounding the 132-kV to 150-kV 

grid was estimated to be $2.0 billion, while the cost of burying the distribution grid was 

estimated to range from $1.7 billion to $2.0 billion (Danish Electricity Infrastructure Committee

2008).
59

3. Increasing the Flexibility of the Danish Power System

Energinet sees electricity as the principal energy carrier in the future, increasingly covering the 

energy needs of the heating and transport sectors (Energinet 2012a). If this were indeed the case, 

increased electric heat and transport would represent very important temporal buffers against the 

variability of wind and solar PV. 

Combined Heat and Power Production

All combined heat and power (CHP) plants must participate in the spot power market (Power & 

Energy 2009). Consequently, their power output reflects the electricity price to a greater extent 

than in the heat-load-following mode that is more usual for CHP plants. This is possible because 

most CHP plants in Denmark produce low-temperature steam for district heating, representing a 

considerable heat store (Frontier Economics 2010), rather than high temperature heat for 

industrial processes, which is harder to store.

Given that nearly all of Denmark’s thermal electricity production—more than 55% of all 

electricity production (Danish Energy Agency 2011)—is from CHP plants, this market 

participation represents considerable additional flexibility. In addition, approximately one third 

of small CHP plants are active in the regulating power market, contributing to ancillary system 

services (Power & Energy 2009).

In 2008, the tax levied on the use of electricity for heat production at CHP plants was reduced. 

As a result, when the price of electricity is low, or negative—as happens when wind output is at 

maximum—using this (wind) electricity to produce heat, instead of burning oil or gas, is cost 

effective. So, electricity production from fossil fuels can be reduced, providing downward 

flexibility when it is most needed to accommodate wind power (Power & Energy 2009, 

Energinet 2009a) while in addition, more of the latter finds a local use.

Additional Sources of Domestic Flexibility

Electric cars may serve as a source of system flexibility; if effort is made to correlate their 

charging times with times of electricity surplus—when wind is at maximum—they can serve as a 

store. Parked vehicles might also return power to the grid when the wind falls away. Electric cars 

are tax free in Denmark (Energinet 2009a), and the Energy Strategy 2050 includes $40 million to 

support the deployment of charging stations.

Energinet is participating with other Danish and international partners in a project known as 

EcoGrid EU that will demonstrate the ability of the island of Bornholm to provide itself with 

50% renewable electricity, mainly wind power, with active management of the distribution 

system, electric vehicles, and technology and price incentives to enhance demand side response. 

The intention is to demonstrate, on a small-scale, approaches that could be scaled up (Energinet

2012b).

The Energy Strategy 50 also contains the intention to prepare a “smart grid” strategy. The Danish 

government is seeking an agreement with the distribution companies (of which there are 80), to 

install intelligent electricity meters when consumers install heat pumps or vehicle recharging 

stations. The level above which intelligent meters must be installed will be reduced from 

100,000 kWh to 50,000 kWh in 2013.30 All meters replaced after 2015 must be replaced with 

intelligent meters, to enable greater response from the demand side. 

 30 Roughly ten times the consumption of the average domestic consumer
60

To reinforce consumers’ incentives to respond to more volatile electricity prices resulting from 

higher wind share, a range of new initiatives is being developed. These include flexible 

settlement systems, a data hub (Energinet 2012c), and efforts toward hourly settlement.

4. Making Markets More Amenable to Variable RE

Energinet and the other Nordic TSOs are responsible for developing the Nordic power market 

design. Thus, the organization partly responsible for overall market efficiency is also the 

organization with a strategic objective to integrate more variable RE. From an institutional 

perspective, this is a very complementary arrangement. 

An Ever-widening Power Market

In the 1990s, the newly deregulated markets in the Nordic region began to integrate. Crossborder tariffs were removed, and a common power exchange, Nord Pool, was established 

originally for only Norway and Sweden. All four Nordic national system operators, including the 

Finland TSO and Energinet, now jointly own Nord Pool. West Denmark joined in 1999, and East 

Denmark joined in 2000. Text Box C-1 explains briefly how the exchange manages the flow of 

electricity across national borders. 
61

Text Box C-1. Congestion Management through Market Splitting

A key aspect of this collaboration is the efficient allocation of cross-border transmission 

capacity (a task known as “congestion management”). In the Nordic market, allocation 

is implicit in the spot market trade of electricity; traders need not subsequently acquire 

the right to use cross-border transmission in an “explicit” auction. 

The exchange does this through market “splitting.” This has a similar effect to the 

Central and West Europe market “coupling” to the south, in that flows across borders 

are optimized without being explicitly assigned to any particular trade. Variations in 

price can develop in the different control zones of the Nordic Market,1 which result 

from transmission bottlenecks distorting the system price. When this occurs, the system 

operator—through the day-ahead market—will buy electricity in the cheaper area and 

sell it in the more expensive area, causing power to flow from the low price area toward 

the high price area, at the same time reducing the price difference between them. 

Figure C-1. Collaboration of Nordic and Central and West Europe Markets through 

the Interim Tight Volume Market Coupling

The success of Nordic collaboration is reflected in the fact that trade over the area increased by a 

factor of 3.5 from 1975 to 2006, while demand for electricity only doubled. Approximately 75% 

of all Scandinavian electricity is traded in Nord Pool, up from 45% in 2006 (VTT 2007). 

Participation in the exchange is not mandatory, but only through it can agents trade over the 

entire Nordic area; bilateral trades are limited to the control zone.31 

Increasing international trade therefore increases the liquidity of the exchange. This not only 

brings benefit in terms of wider system efficiency and cost reduction; it means that increasingly 

large amounts of controllable power are available, so that greater amounts of wind power can be 

accommodated efficiently and securely. 

 

31 Denmark consists of two bidding areas: East and West Denmark. 
62

In 2010, another step was taken toward a 

single European power market, with the 

establishment of the Interim Tight Volume 

Market Coupling of the Nordic and Central 

and West Europe markets,32 which enlarged 

the area over which electricity can be 

exchanged (Text Box C-2). 

The Interim Tight Volume Market Coupling

functions on the day-ahead time scale (i.e., 

intra-day and shorter-term trades remain 

within the Nordic area) although Germany 

also participates in the Nordic Intraday 

market. As its name implies, the Interim 

Tight Volume Market Coupling is intended 

to be a step toward deeper integration of the 

two markets. A permanent version of the 

coupling is hoped for by the end of 2012 

(Energinet 2012a).

Nordic Market Design

Renewable electricity has priority dispatch under the Electricity Supply Act. Although there are 

no trading rules specifically for variable RE in the Nordic market, it has been encouraged to 

evolve to make more efficient use of ever-growing amounts of wind power. Indeed the evolution 

of the market is continuous, with important steps toward flexible operation seen regularly. 

The core of the market is a day-ahead platform, Elspot, where the bulk of electricity is traded, 

from 12 hours up to 36 hours ahead of delivery. This is quite a good timescale for thermal plants, 

providing plenty of time to ramp production up or down, but it is less suited to fluctuating and 

less-certain wind power production. 

When trading has closed on Elspot, it can continue through the intraday market, Elbas, with 

continuous trading up to 60 minutes ahead of delivery.

33 Though the volume of power traded on 

Elbas is very much smaller (approximately 1% of exchange traded power), it is increasing (Ea 

Energy Analyses 2011), which reflects a growing share of uncertain wind power production in 

the market place. This in turn represents a growing challenge to system operators for whom 

planning of system operation will be increasingly time-constrained.34 

A regulating power market operates up to 15 minutes before delivery.35 This is not part of the 

Nord Pool exchange; offers to provide (or reduce consumption of) power are made directly to 

Energinet, which passes them on to the Nordic Operational Information System , along with 

offers from the other TSOs. Because of the Nordic Operational Information System, therefore, 

providers of short-term flexibility—which includes consumers who can offer to reduce their 

 

32 Estonia is included. 33 German participants, from April 1, 2011, have been able to trade on Elbas up to 30 minutes ahead of delivery to 

give them greater opportunity to remedy imbalance in their trading positions.

34 ENTSO-E 2010 35 There is also a reserve-capacity market, though payments are presently extremely low, given large supply and 

reduced demand for that service.

Text Box C-2. The Interim Tight Volume 

Market Coupling 

In August 2008, the Electricity Market Coupling 

Company was founded as a joint venture of Nord 

Pool Spot, the European Energy Exchange (EEX), 

Nord Pool Spot AS, the German TSOs 50Hertz 

Transmission GmbH and Tennet TSO GmbH, and 

Energinet. 

The Electricity Market Coupling Company 

established a coupling of Danish and German 

markets in 2008, an improved version of which was 

launched in 2009. This in turn was developed into 

the Interim Tight Volume Market Coupling. The 

Electricity Market Coupling Company encourages 

optimum electricity flows over the coupling based on 

the transmission that is available to carry electricity 

at any given moment, which information is provided 

by the TSOs; and the trading of electricity for that 

moment, which information is provided by the 

exchanges. 
63

consumption (Bjørndal 2002)—can be shared over the whole Nordic area. In addition, Energinet 

is pursuing opportunities to open a Europe-wide balancing market (Energinet 2012a).

Between them, these three markets provide considerable ability for producers, retailers, and 

consumers to calibrate and recalibrate their trades in the face of the increasing variability and 

uncertainty resulting from a larger wind power share.

Negative Prices

In 2009, negative prices were permitted for the first time in the day-ahead market, in which 

previously there had been a floor price of $0/MWh.36 Negative prices may occur, for example, 

when wind turbines are at full power but electricity demand is low. At present, they occur for 

about 20–100 hours per year in Denmark. Even more so than by a zero price, electricity 

producers are encouraged to reduce their production at such times or be in the perverse situation 

of having to pay to generate. 

The intention is to use the price signal to encourage participants to be more ready to respond to 

market needs. This includes wind power producers, who are also encouraged to reduce their 

production at a certain point. Additionally, large consumers that pay the spot price will be 

encouraged by negative prices to shift consumption to these times if they are able.

5. Advanced System Operation and Grid Code Development

Energinet is the sole operator for both parts of Denmark, following the statutory merger of the 

smaller TSOs, ELTRA and ELKRAFT, in December 2004. This is likely to have increased the 

coherency and efficiency of management of the whole. The challenge of managing the Danish 

power system has grown enormously over the last 30 years; Figure C-2 shows the number of 

power plants in 1980 compared to 2010. Nevertheless, Denmark has not suffered any major 

system contingencies resulting from wind power.

 36 Negative spot prices were introduced in the Elbas Intraday market in April 2011.
64

Figure C-2. Number of power plants in Denmark, 1980 and 2010

Source: Energinet (2009a)

Energinet has greatly enhanced its energy management system to monitor real-time performance 

of the power system.37 This includes real-time estimates of wind power to be fed into the grid. 

This is an important; because most wind power in Denmark is connected at the distribution level, 

which is passively managed, it is not very visible to the system operator (Jones 2011).

Energinet uses multiple, advanced forecast tools, resulting from rolling innovation of wind 

output forecasting tools in Denmark over 20 years. Energinet has played a central role in this 

innovation, which has included Danish power industry and universities also. Forecasts are used 

to plan system operation, day-ahead (cross-border) congestion management, the commitment and 

economic dispatch of controllable power plants, contingency analysis, the assessment of grid 

transfer capacity, and the need for regulating power.

Energinet developed the Drift Planlaegnings (Operational Planning) System tool for integrating 

forecasts of wind and CHP output into system planning up to two hours ahead of the time of 

operation. To better manage more wind power, Energinet is in the process of pushing this 

horizon up to five minutes (Jones 2011). The tool also provides the operator with a view of 

power flows between the Danish system and those of Germany, Norway, and Sweden. 

Energinet requires all power plants of greater than 10-MW capacity to provide automatic updates 

every five minutes of their power production. Combined with its own estimates of wind power 

and small CHP output, this allows Energinet to track the output of the complete range of power 

plant on the Danish system (Jones 2011). 

The increasing share of wind power, resulting in a greater but less predictable need for shortterm flexible resources, has been a principal driver of closer cooperation among Nordic TSOs, 

 37The report Strategies and Decision Support Systems for Integrating Variable Renewable Energy Resources in 

Control Centers (Jones 2011) provides an excellent overview of system management practices in Denmark. 
65

which seek to better manage and share their flexible resources. In 2004, the Nordic Operational 

Information System (NOIS) was established; it is based at Energinet. NOIS provides common 

understanding of the status of interconnections, and usable operating reserves over the Nordic 

area. 

Higher-Resolution System Operation

The Nordic day-ahead market is dispatched in hourly blocks, a practice that is less well suited to 

variable output producers than, for example, fifteen minute blocks are. The latter allow greater 

fine-tuning of trades to account for variability and uncertainty. Smaller individual blocks of 

power fit better with the more volatile net load,38 reducing scheduling inefficiencies encountered 

when longer blocks are used. Though this increases complexity, it may also result in a reduced 

need for short-term balancing resources. 

In the long-term, ENTSO-E considers that markets also will need to move to fifteen minutes 

periods, in order to provide greater incentive to balancing resources to respond to system needs 

(ENTSO-E 2010). 

Incentivizing Variable RE Forecast Accuracy

Before 2003, wind turbine owners had no responsibility to produce according to their forecasts. 

Then, policy changed to require wind turbines to pay the costs of being out of balance (i.e., for 

producing more or less than what is forecast and sold in the day-ahead market). To compensate 

for this, wind warm operators can claim a refund of $3.9/MWh (IEA 2012) on top of the feed-in 

premium, under the Promotion of Renewable Energy Act. Thus, the operator of a wind farm has 

incentive to minimize the divergence from forecast output, while being compensated to some 

extent, the cost of which is spread among all consumers.

Grid Codes

The Nordel Grid Code, launched in 2007, applies across the whole Nordic area. In addition, 

Denmark has its own requirements. The earliest version was applied in 1999, and it required 

wind turbines to be able to disconnect from the grid during abnormal voltage and frequency 

events. In 1999, a new code was published that applied to wind farms on the high voltage grid 

only, mainly targeting offshore wind farms.

This new code required the opposite of wind turbines: that they remain connected and delivering 

electricity during the same kinds of events; in other words, from then on, wind farms were 

expected to support the grid in case of fault, not to disconnect at the first sign of trouble. It was a 

world first, with several other requirements of wind farm owners, including that new wind farms 

at this voltage level should be controllable remotely so that they can be curtailed if necessary 

(Energinet 2009a). 

Given that 90% of wind turbines are connected at the medium voltage (60-kV) level and below, 

similar grid codes now also apply at that level. The grid code is revised to keep pace with 

development of wind turbine technology, as wind technology becomes better able to provide 

other such ancillary services to support the power system. 

Curtailment

Curtailment rules prefer RE sources, meaning that only after fossil-powered plants have been 

reduced to minimum can curtailment of wind power be done. Curtailment is required relatively 

rarely, when storm conditions occur during cold periods (driving high CHP output) with low 

 38 Demand, minus variable RE output, in megawatts
66

electricity demand. It applies to turbines that can be controlled centrally. Until 2007, curtailment 

was not compensated (Van Hulle et al. 2009), but Energinet now pays compensation to landbased owners. 

However, the Promotion of Renewable Energy Act took into consideration that the need to 

curtail may increase, particularly with the advent of very large wind farms offshore. Under the 

Act, the output of certain offshore wind farms may be curtailed if required for security reasons.39

This is only compensated by Energinet if the decision is taken as a result of a sudden fault. If 

notice is given day-ahead, no compensation is paid (Energinet 2009a). 

Offshore wind farms may be required to control their power output in several ways, some of 

which are captured in Figure C-3. These highlight the capabilities of modern wind turbines. In 

the first case, a simple ceiling can be placed on the output. In the second, it is ordered to reduce 

to a fixed level for a certain period, while in the third, the rate at which output increases (i.e., 

according to the wind speed) can be artificially smoothed. In the fourth graph, actual output has 

been reduced by a fixed amount over time, with the result that during that period, a certain 

amount of additional power is available if required by the system operator for balancing; in 

effect, the wind turbine has itself become a source not only of downwards flexibility, but also 

upwards flexibility. 

Figure C-3. Active power control abilities of Danish offshore wind farms

Source: ENTSO-E 2010

Potential for Learning in Other Countries

All power systems are different, and the great success in terms of wind power deployment

witnessed in Denmark does not mean all countries could easily have the same wind power share.

Denmark is a small system, heavily interconnected with both Scandinavian neighbors in the 

Nordic power market and Germany to the south, with a transfer capacity equal to approximately 

80% of its peak demand. In other words, surpluses and deficits of power production resulting 

from a large variable RE share can relatively easily be compensated for. Other systems are likely 

to have a far smaller potential to trade, relative to their size.

Denmark’s experiences with increasing the flexibility of CHP power plants could be exported to 

other countries where cogeneration of heat and power can be decoupled to a considerable extent, 

as is possible in Denmark because of the high proportion of CHP plants linked to district heating 

systems. 

Danish system operational experience, particularly in the design and use of forecasting tools, 

represents best practice that should be embraced by countries seeking a large share of variable 

RE. Similarly, the market practices, transparency, and collaboration of Denmark with its 

 39 Only those wind farms that have been developed under a call-for-tender
67

neighbors provide an example to other countries of how to share flexible, controllable balancing 

resources in order to manage wind power. 

Conclusions

Denmark has a strong transmission grid that is monitored and maintained closely by a single 

owner, Energinet, which is managed directly by the Ministry of Climate and Energy. 

Consequently, Energinet’s efforts very closely align with strategic government policy, including 

policies regarding wind power deployment. In 2009, Energinet developed a holistic plan for the 

complete overhaul of the high-voltage grid to enable Denmark to meet the 50% wind power by 

2020 target. The plan, when implemented, will also address the single greatest non-economic 

barrier to wind power, public antipathy to new grid infrastructure, by undergrounding much of 

the high-voltage grid.

Grid connection is, at worst, only a slight barrier to variable RE deployment in Denmark, as grid 

companies have taken swift action to expedite connections. Deployment of wind turbines on land 

has been managed in a decentralized manner, but this is changing to best use remaining sites and 

reach the 50% wind power target by 2020. Tender processes have steered offshore wind farms 

into pre-screened zones. Denmark is also, with Germany, planning the first offshore grid in the 

Baltic Sea, which will connect a cluster of offshore wind farms to the two countries.

Denmark’s embedded position in the Nordic power market is her greatest wind integration ally. 

Consequently, Denmark is taking important steps to reinforce this position, with a new cable to 

Norway and a new link to the Netherlands to the south. Trading of controllable power resources 

to complement variable RE output can be traded across the entire Nordic market. This ability to 

share resources extends right up to the time of operation, through a shared regulating power 

market.

Wind producers are exposed to the market; they sell their power into it, and if they are out of 

balance at settlement time, they incur costs. This encourages them to keep as close as possible to 

their output forecast, and they are compensated to some extent with flat payments on top of the 

feed-in premium. On land, wind curtailment is a measure of last resort, and is compensated. New 

offshore wind farms may receive notice to control their production in several ways.

Domestic flexibility is being enhanced with more flexible operation of—very common—CHP 

plants, plans for electric vehicles, and large-scale deployment of smart meters. Using negative 

prices in the spot markets adds incentive to controllable and variable power plants alike, to give 

more consideration to the needs of the market. Offshore wind turbines can be not only curtailed 

but also operated below maximum so that they can provide up regulation40 if needed.

System operation is overseen by a single TSO, Energinet, and it has become significantly more 

complex over the last 20 years. Energinet and the Danish power producers have pioneered 

practices to manage this complexity. Denmark was the cradle of output forecasting techniques, 

and it continues to lead the development of system operation planning tools.

 40 Up regulation is when reserves are needed to provide additional energy to balance the system.
68

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Energinet. (2012c). “DataHub.” Accessed April 16: 2012: http://energinet.dk/EN/El/Datahub/

Sider/DataHub.aspx.

ENTSO-E. (2010). “Impacts of Increased Amounts of Renewable Energy on Nordic Power 

System Operation.” Brussels: ENTSO-E.
69

Frontier Economics. (2010). “Study on Flexibility in the Dutch and NW European Power Market 

in 2020.” Prepared for Energinet.

[GWEC] Global Wind Energy Council. (no date) “Germany: Total Installed Capacity. Accessed 

April 16, 2012: http://www.gwec.net/index.php?id=129.

Holttinen, H; Meibom, P.; Orths, A.; van Hulle, F.; Lange, B.; O’Malley, M.; Pierik, J.; Ummels, 

B.; Tande, J.O.; Estanqueiro, A.; Matos, M.; Gomez, E.; Söder, L.; Strbac, G.; Anser Shakoor; 

Ricardo, J.; Smith. J.C.; Milligan, M.; Ela, E. (2009). “Design and Operation of Power Systems 

with Large Amounts of Wind Power. Final report, IEA WIND Task 25, Phase One 2006–2008.” 

Vuorimiehentie, Finland: VTT. http://www.vtt.fi/inf/pdf/tiedotteet/2009/T2493.pdf

IEA/IRENA. (2012). IEA and IRENA Policies and Measures Database. http://www.iea.org/

teieaxtbase/pm/?mode=re&action=detail&id=4425. Accessed February 3, 2012.

Jones, L.E. (2011). “Strategies and Decision Support Systems for Integrating Variable 

Renewable Energy Resources in Control Centers: Global Best Practices, Examples of 

Excellence, and Lessons Learned.” Prepared by Alstom Grid for the U.S. Department of Energy. 

Washington, DC: Alstom Grid.

Klinge Jacobsen, H.; Zvingilaite, E. (2010). “Reducing the Market Impact of Large Shares of 

Intermittent Energy in Denmark.” Energy Policy. 

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Target.” Accessed April 16, 2012: http://www.rechargenews.com/energy/wind/

article284551.ece.

[RETD] Renewable Energy Technology Deployment. (2008). “Innovative Electricity Markets to 

Incorporate Variable Production,” Prepared by IPA Energy and Water Economics for the IEA 

Renewable Energy Technology Deployment Implementing Agreement.

Van Hulle, F.; Tande, J.O.; Uhlen, K; Warland, L. ; Korpås, M.; Meibom, P.; Sørensen, P.; 

Morthorst, P.E.; Cutululis, N.; Giebel, G.; Larsen, H.; Woyte. A.; Dooms, G; Mali, P-A; 

Delwart, A.; Verheij, F.; Kleinschmidt, C.; Moldovan, N.; Holttinen, H.; Lemström, B.; UskiJoutsenvuo, S.; Gardner, P.; van der Toorn, G.; McLean, J.; Cox, S.; Purchala, K.; Wagemans, 

S.; Tiedemann, A.; Kreutzkamp, P.; Srikandam, C.; Völker, J. (2009). “Integrating Wind: 

Developing Europe’s Power Market for the Large-Scale Integration of Wind Power, Results of 

the TradeWind Project, coordinated by the European Wind Energy Association, Brussels.

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[VTT] Technical Research Centre of Finland. (2007). “Optimising the Market Integration of 

Electricity from Renewables.” Holttinen, H.; Korenoff, G.; Lemström, B. Helsinki, Finland: 

VTT. 
70

Appendix D. Case Study: Germany

Author: Hugo Chandler, New Resource Partners

Introduction

Challenges of Integrating Variable RE

Germany must manage very large flows of wind energy into and around its grid area. Until 

recently, with the scaling up of solar photovoltaic power plants (PV) in the south of the country, 

almost all variable renewable energy (RE) generation (i.e., wind power) has been in the middle 

and north if the country. The lack of balance between rural areas with high wind energy shares 

and principal consumption areas all over Germany has led to transmission congestion between 

these different areas.

The challenge is likely to be compounded by growing flows of variable electricity from outside 

Germany’s borders. Germany’s immediate neighbor to the north is Denmark, which targets 50% 

wind power. Moreover, wind penetration is likely to be highest in the Jutland Peninsula, which is 

part of the same power system as Germany (i.e., the synchronous grid of continental Europe). 

Instantaneous shares in Jutland can already rise above 100% today. Grid congestion in the border 

region during times of high wind is likely to increase without reinforcement. 

In addition, flows of electricity from Germany to and through Eastern neighbors are already 

challenging, to the extent that eastern neighbors are considering remedial measures.

Finally, fast-growing, distributed solar photovoltaic (PV) installations in the south of the country 

will increase the complexity of the system operation task, particularly because the distribution 

grid is managed passively.

Focus of Case Study

The second section of this case study sets the scene for discussion of past and on-going 

challenges in the system integration of variable RE. It describes the status and likely 

development of the market for wind and solar PV, and it summarizes the history of policy 

development in the country. Finally, it highlights best estimates of system integration costs in the 

literature. 

The third section addresses the key areas wherein action has been taken to remedy barriers to the 

deployment of variable RE. It is divided as follows:

1. Coordinating planning initiatives

2. Building public support for new transmission

3. Increasing the flexibility of the power system

4. Making markets more amenable to variable RE

5. Promoting diversification of location

6. Advanced system operation and grid code development

The fourth section addresses lessons that might be learned from the German case by other 

countries with similar system attributes—such as characteristics related to the grid, RE resources,
71

and flexibility (see below)—and, the last section presents key conclusions regarding the German 

experience of variable RE.

“Flexibility” will be referred to a number of times in this appendix. Briefly, the term is used here 

to encompass all aspects of a power system that complement variable generation. Examples 

include dispatchable power plants (i.e., those than can be turned up or down to greater or lesser 

extents, energy storage, demand-side management and response, trade, dynamic operation of the 

power system that enables it to better manage uncertainty in variable RE output forecasts, and 

markets that both enable and stimulate more iterative trading of electricity).

Context of Integration

Wind and Solar PV Penetration of Electricity Supply

Since the implementation of the first major renewables legislation in 1991, renewable energy in 

Germany has diversified away from a purely hydropower base to include significant quantities of 

wind, biomass and, more recently, solar PV generation (Figure 1).

Figure D-1. Development of electricity generation from RE in Germany since 1990

Source: BMU 2011a

Table 1 shows the average annual share of wind power in total electricity generation increasing 

from 1% in 1999 to 6% in 2010. Solar PV, from a much later start, reached nearly 2% in 2010. 

While these figures seem still quite modest, instantaneous shares can be very challenging.
72

Table D-1. Shares of Wind and Solar PV Generation in Total Electricity Generation in 

Germany since 1999 (GWh)

Year Wind 

(GWh)

Solar PV 

(GWh)

Total 

Electricity 

Generation

Wind Share 

(%)

Solar PV 

Share (%)

1999 5,528 42 556,300 1.0 0.0

2000 7,550 64 576,543 1.3 0.0

2001 10,509 76 586,406 1.8 0.0

2002 15,786 162 586,694 2.7 0.0

2003 18,713 313 606,719 3.1 0.1

2004 25,509 556 615,287 4.1 0.1

2005 27,229 1,282 620,574 4.4 0.2

2006 30,710 2,220 636,761 4.8 0.3

2007 39,713 3,075 637,100 6.2 0.5

2008 40,574 4,420 637,232 6.4 0.7

2009 38,639 6,583 592,464 6.5 1.1

2010 37,793 11,683 627,918 6.0 1.9

Sources: BMU 2011a, Eurostat 2011

Table 2 shows the maximum ratio of solar PV and wind power output to power demand in 

Germany as a whole and in the four TSO control areas into which it is divided (See Figure 2). 

Perhaps surprisingly, given the modest annual figures above, penetration reached over 60% on 

Sunday May 8 at 1:00 p.m., when demand dropped to a low on a quiet, sunny afternoon. At the 

same time, in the area managed by TenneT, which stretches from the north to the south of the 

country—picking up power both in the windy north and in the sunny south—penetration reached 

160% of the entire demand of the area. Eastern Germany saw similarly little activity at 6:00 a.m.

on January 1, 2011, and the system operator (50Hertz) had to manage wind output amounting to 

124% of the area’s demand.

Table D-2. Maximum Ratio of Wind and Solar PV to Load, by TSO, in Germany in 2011

50Hertz Amprion

EnBW 

TNG TenneT Germany

Date and hour 01/01/2011 

06:00

07/09/2011 

14:00

25/04/2011 

13:00

08/05/2011 

13:00

08/05/2011 

13:00

Wind and solar PV (MW) 6,383 3,921 1,847 11,021 20,697

Wind 6,383 2,404 54 5,034 8,070

Solar PV 0 1,517 1,793 5,987 12,627

Load (MW) 5,145 11,082 4,617 6,876 34,435

Maximum ratio of variable 

RE to load (%)

124% 35% 40% 160% 60%

Source: Prognos 2011

Policy Support

The German government strongly supports renewables deployment and is a main driver behind 

variable RE deployment. It contains strongly supportive cooperating ministries and agencies. 
73

Chief among these, from the point of view of RE, are the Federal Ministry for the Environment, 

Nature Conservation and Nuclear Safety (BMU), which was established after the Chernobyl 

nuclear reactor event of 1986; and the Federal Ministry of Economics and Technology, which is 

responsible for legislation over the wider electricity industry, including the grid. The German 

Energy Agency (DENA), half-owned by the Federal Republic of Germany and half by financial 

institutions,

41 provides expertise with respect to renewable energy, energy efficiency, and 

intelligent energy systems, while the Federal Networks Regulator (BNetzA), under the Federal 

Ministry of Economics and Technology, regulates energy supply networks.

Ahead of most other countries, in 1989, the BMU introduced the Market Stimulation Programme 

for installation of 250 MW of wind power. Among other incentives, this guaranteed a fixed 

payment per kWh of electricity produced. It closed in 1995, by which time the BMU had 

introduced the Federal Electricity Feed-In Law (Stromeinspeisungsgesetz) in 1991. It also 

featured production-based support, and it was replaced by the 2000 Renewable Energy Sources 

Act (EEG, Erneuerbare Energien Gesetz).42

An important feature of the EEG is comprehensive monitoring of results, on which basis 

modifications to the law are made regularly (approximately every three years). The EEG is a 

good example of comprehensive legislation. The feed-in tariff (FIT) is valid for 20 years in most 

cases,

43 stepped over time to help manage upfront investment costs, banded according to the 

maturity of the technology (i.e., more support for younger technologies). Later applicants get less 

support than early-movers do, as FIT rates reduce from year to year (a process known as 

degression). 

Digression is intended to encourage technology cost reduction, but sometimes it can prove 

difficult to keep pace with the latter, as when solar PV costs more than halved from 2009 to

2011, faster than the rate of digression in the FIT. When this happens, there is a risk of 

inappropriate return to developers and cost to the consumer. 

Digression also accelerates deployment, encouraging developers to move more quickly to take 

advantage of earlier (higher) tariffs. The cost of the FIT is borne by the consumer via the four 

system operators who market EEG electricity on behalf of the consumers.

The Market Stimulation Programme has provided grants since 2000. These initially included the 

power sector, but they are now exclusively for the heat sector. Another important driver is the 

public bank, Kreditanstalt fuer Wiederaufbau (KfW).44 KfW provides long-term, fixed, low 

interest investment loans, and loan guarantees, to projects, amounting to some €10bn by 2008

(RETD 2008). Recently KfW announced EUR 5 billion ($6.6 billion) of loan guarantees to 

offshore wind projects up to 2020 (Platts 2011). In 2010 alone, it provided EUR 11 billion ($15.5 

billion) “for the construction of facilities using renewable energies,” including heat)45.

Deployment targets are important to both signaling required investment volume and deploying 

new grid assets. The BMU has developed and regularly updated targets, the most recent of which 

 41 KfW Bankengruppe, Allianz SE, Deutsche Bank AG, and DZ BANK AG 42 http://www.erneuerbare-energien.de/files/pdfs/allgemein/application/pdf/eeg_2012_bf.pdf. 43 15 or 30 years for hydropower plants 44 KfW (Reconstruction Loan Corporation) is owned 80% federally and 20% by the länder (state). 45 “Evaluation of KfW programmes for renewable energies: important contribution to the energy turnaround,” 

November 21, 2011. Kfw press release. http://www.kfw.de/kfw/en/KfW_Group/Press/Latest_News/PressArchiv/

2011/20111121_54587.jsp
74

are part of the September 2010 Energy Concept and the EEG (2012). There is no specific target 

for particular technologies. The Energy Concept targets are as follows:

• 18% of energy consumption by 2020; 30% by 2030; 45% by 2040; and 60% by 2050 

• 35% electricity consumption by 2020; 50% by 2030; 65% by 2040; and 80% by 

2050.

These targets are highly ambitious. The Energy Concept was updated in summer 2011 following 

the government’s decision to phase out nuclear power by 2022, which represented approximately 

23% of German capacity in 2011, after the events at the Fukushima Daiichi nuclear plant in 

Japan in March 2011. The change of policy resulted in additional promotion of renewable 

electricity as well as conventional options such as coal power.

Costs of Balancing Wind Power

Integration costs can be broken down into three categories: those that relate to transmission 

extension and reinforcement (not including the cost of linking to the grid); those incurred in the 

balancing of increased volatility in the power system; and those that may be incurred to maintain 

the adequacy of the power system (i.e., its ability to cover peak demand).

A recent study, which modeled balancing costs in a number of European countries46, found that 

in Germany, additional balancing costs of wind power at approximately 10% penetration of 

electricity (i.e., more than present penetration) amounted to approximately EUR 2.5 per MWh 

wind). 

Key Factors with Bearing on Variable RE

This section addresses factors related to the integration of variable RE (i.e., to date, wind and 

solar PV power) in the German power system.

1. Coordinating Planning Initiatives

Under the Energy Concept, Germany has begun a process to holistically plan the evolution of its 

entire energy system—a task so large that its complexity is only beginning to be understood. The 

process considers the transmission needs of the whole power sector, conventional and renewable, 

as well as other needs that will arise from a changed power portfolio, such as changes to the 

operation of existing power plants, and the extent to which other system resources can be used to 

manage variability and uncertainty.

The Energy Concept sees three trends that run contrary to the historical German model: 

increasing generation of electricity in coastal and offshore plants (rather than near the principal 

inland demand centers), increasing distributed generation from biomass and PV plants (rather 

than from multi-gigawatt conventional plants), and increasing interchange of electricity with the 

wider European area.

Before the Energy Concept, the transmission needs of wind power were assessed and managed 

somewhat separately from the remainder of the system. For example, a study by the German 

Energy Agency (DENA) in two parts (2005 and 2010) assessed the need for additional grid 

reinforcement and extension solely for wind power. 

 46 Greennet Study led by the Energy Economics Group of the Technical University of Vienna, summarized in 

Holttinen, et al. (2009).
75

A narrow view will miss the benefits to the wider system of such developments, as well as the 

relevance of other—perhaps unexpected—energy events. For example, the policy decision to 

phase out nuclear power may increase imports of electricity from France,

47 altering flows 

throughout the German network with decreasing nuclear generation in the south and increasing 

wind generation in the north.

Coordination is also seen at the European level. An interconnected European grid existed before 

the beginning of large-scale deployment of variable RE in Europe. Collaboration among 

European TSOs already allows for, at least in theory, the transmission of up to three gigawatts 

across any network node from the Iberian Peninsula to Scandinavia, to provide reserves in case 

of unexpected events. 

In addition, and as a result of the EU’s 3rd Liberalisation Directives, the European Network of 

Electricity TSOs must prepare 10-year network development plans, biannually, covering the 

whole of Europe. The transmission needs highlighted in this case study are not legally binding on 

the European Network of Electricity TSOs, but they nevertheless highlight where investment is 

needed. Germany’s importance in the heart of Europe is reflected by the fact that it is included in 

four of the six regional groupings.

48 The next edition of the 10-year network development plan 

will be delivered in June 2012.

Accelerated, Coordinated Deployment of New Transmission

Germany has led analysis of transmission needs to manage variable renewables. Part One of the 

DENA wind integration study in 2005 assessed the needs resulting from government targets.

49

This was a landmark study, and it has sparked similar analysis around the globe. But, by the end 

of 2010, only 90 kilometers (km) of the 460 km extensions called for by the study had been 

completed of; and Part Two of the study, published in 2010, published additional needs. The 

latest DENA analysis estimates high voltage expansion needs of 3,600 km by 2020.

The German government has legislated to combat these delays. In 2009, it published the Power 

Grid Expansion Act (Energieleitungsausbaugesetz). This, which gives additional priority to 

extra-high voltage “electricity highway” projects to ease north/south congestion. In August 2011, 

the government published the Grid Expansion Acceleration Law 

(Netzausbaubeschleunigungsgesetz), which also aims to accelerate grid expansion. The law is 

supposed to shorten planning and permission processes from ten years to four years by bundling 

responsibilities at the level of the federal government and allowing for early public participation

(BMU 2012).

Spurred by the European rolling transmission plan being developed by the European Network of 

Electricity TSOs, the German Energy Industry Act (Energiewirtschaftsgesetz) was recently 

amended to require the development of a 10-year plan for Germany. This plan will be based on 

annual submissions from the four TSOs, and it would serve as the basis for a legally binding 

Federal Requirement Plan for Transmission Networks (Bundesbedarfsplan 

Übertragungsnetze/Bedarfsplang.

 47 Although in February 2012 the opposite occurred; Germany exported more electricity to France. 

(http://www.reuters.com/article/2012/02/14/europe-power-supply-idUSL5E8DD87020120214) 48 The four areas are: North Sea; Baltic Sea; Continental Central South; and Continental Central East. The remaining 

two are Continental South West, and Continental South East

49 These amounted to 274 km to 2007, plus 552 km to 2010, plus 416 km to 2015, including both extensions and 

upgrades.
76

Incentives for Grid Investment

TenneT faces the majority of offshore integration costs. It has stated that no more than the nine 

offshore wind farms currently in the development pipeline can be connected because it does not 

have resources do more (Platts 2011). TenneT has requested that BNetzA increase the allowable 

rates of return on investment to attract investors; in October 2011 it was agreed to cut the rate 

from the present 9.29% to 9.05% for the period 2014–2018.

50 Additionally, TenneT has 

proposed the foundation of a joint direct current network operator to build the direct current line 

for the offshore connections (TenneT 2012). Since then, grid connection of offshore wind farms 

to support German offshore wind energy development is of much interest on the political agenda. 

In this context, BMU and Federal Ministry of Economics and Technology have set up a working 

group on accelerating offshore connections.

Additionally, grid companies have had to wait for two years until they are able to charge for the 

use of the line, and so recover their costs. BNetzA is considering whether to remove what is in 

effect a disincentive to invest. 

Other measures under consideration by BNetzA include:

• The provision of loans to cover the cost of new lines

• Permission for higher use of system charges in new extra-high voltage transmission 

highways, or lines featuring innovative technologies such as those described below, 

Section 2

• Quality criteria and mechanisms for rewarding innovative grid expansion. 

In the light of delays in transmission investment, some have suggested that unbundling of 

transmission and generation assets under the EU Liberalisation drive may have resulted in an 

unexpected side effect. Large multinational financial institutions, some of whom are based 

offshore, now hold a significant part of transmission assets. In addition to meeting regulations, 

the latter will emphasize the need to maximize returns for their shareholders, which may make 

them less inclined to make large capital investments in the system—when needed to meet purely 

national government objectives—than might be the case with domestic, public or private owners.

Nodal pricing of electricity is one tool that might accelerate grid upgrades in Germany. At 

present, the entire country is one price area. This means that a surplus of electricity in one area 

while supply is tight in another is not signaled by corresponding low or high prices. Such price 

differences are an important signal to potential investors who, if they were to reinforce 

connections between two neighboring areas, would stand to profit from resulting flows. 

Coordinated Planning and Connection of Variable RE Plants 

Under the 2000 Renewable Energy Sources Act (EEG), developers of renewable plants on land 

pay only for linking to the nearest substation; the TSO is obliged to pay all deeper reinforcement 

costs. It then passes these on to consumers. The cost burden is different for offshore plants; grid 

costs outside the wind farm itself are borne by the system operator, i.e., the expensive cable link 

to the onshore sub-station. 

The EEG commands priority and guaranteed grid connection for RE plants, which is an very 

important driver for deployment, particularly as most of the grid is not state-owned. Also, the 

 50 For instance, the Bundesverband der Energie und Wasserwirtschaft (BDEW) energy lobby cites the 10% level in 

other EU countries.
77

EEG includes provisions that define the actual process of connection and the commitment for 

grid operators to enhance their grid capacity if a new plant has to be connected to the grid. 

However, ambiguity in the latter has led to costly delays. For example, the local distribution 

system operator and the developer disagree about what constitutes the most suitable grid 

connection point. The 2011 amendment of the EEG aims to reduce these delays by requiring the 

distribution system operator to provide a connection schedule within eight weeks of an 

application (Eclareon 2011). 

Under the Energy Industry Act, a TSO is obliged to ensure that a connection for an offshore 

wind farm is in place by the time it is ready to generate electricity. However, delays have 

resulted when neither party was able or willing to start construction before the other: the 

developer because financing proves elusive before cable construction has commenced, and the 

TSO because the wind farm has not yet secured financing. To address this “chicken and egg” 

problem, the networks regulator, BNetzA, issued a non-binding but effective “position paper” 

that clarified the procedure, with which, according to a recent study by Eclareon, the majority of 

stakeholders appears to be largely satisfied (Eclareon 2011).

To reduce offshore connection costs, Part One of the DENA study proposed that four offshore 

transmission hubs take precedence in planning over potentially duplicative, individual on-shore 

links. This hub approach has been embraced in the Energy Concept. It is hoped that this will 

facilitate the process and reduce the costs of offshore connection.

Within the Energy Concept, the German government has amended the Offshore Installations 

Ordinance (Seeanlagenverordnung) to significantly simplify and accelerate the approval process 

for installations in the German offshore exclusive economic zone (outside territorial waters). The 

amendment transfers the entire permitting procedure for offshore wind power plants in these 

waters to a single agency: the Federal Agency for Maritime Shipping and Hydrography. This is 

expected to minimize inter-institutional delays.

Federal Cooperation with the States (Länder)

The 2010 Energy Concept includes a “Government-Länder Initiative on Wind Energy,” which 

intends to improve cooperation between federal and state levels in the search for higher quality 

wind resources on land. This is particularly important as the majority of the best resources may 

already have been exploited. The initiative will include an analysis of wind energy potential and 

will be an important tool in the ongoing process of identifying and designating suitable new sites 

for onshore wind (BMU 2012). This site designation process will in turn facilitate earlier 

planning of additional grid resources in those areas.

2. Building Public Support for New Transmission

The fact that the German population generally favors RE, and is consequently, more willing to 

pay for it, does not mean that public support can be counted on for the new transmission that

clean energy may imply. 

The four system operators in Germany have developed three scenarios of grid expansion 

footprints, which are included on a special website launched by the TSOs to engage the public in 

the decision-making process (Lang and Mutschler 2011) before presenting the first grid 

development plan in June 2012.

Development of the Federal Requirement Plan for Transmission Networks will feature in-depth 

public consultation, and it aims to emphasize the need for transmission upgrades in the mind of 
78

the population. Possible incentives include compensating municipalities hosting new 

transmission corridors.

The Energy Concept 2010 announced that a publicity campaign, “Grids for environmentally 

sound energy supply,” would be launched to build public support for new transmission projects.

New Technology to Reduce Visual Impact of Grid Upgrades and Extensions

In its 2010 study, DENA considered the use of new technologies that enable increased transfer 

capacity on discrete line lengths without major visual impact. Flexible line management based on 

dynamic monitoring of line temperatures enables the operator to get more carrying capacity out 

of a specific line at the very time it is needed—during high wind speeds—because high winds 

tend to occur with lower temperatures, at which carrying capacity increases.

Replacing existing lines with high temperature lines made of aluminum instead of copper also

reduces the need for landscape disturbance, allowing up to 50% greater capacity while retaining 

existing pylon size. Both technologies have been demonstrated in several applications, although 

costs are still relatively high. Flexible alternating current (AC) transmission system devices also 

can enable existing lines to carry more power, while wide-area monitoring can improve their 

management. Finally, cabling (i.e., running transmission lines underground) is an alternative, 

though more costly, to unsightly new overhead lines.

All these options have been demonstrated successfully in Germany and elsewhere, although their 

use has yet to become widespread. For example, flexible line management has been shown to 

increase the carrying capacity of specific lines by up to 50% in coastal regions, up to 30% in the 

rest of northern Germany, and up to 15% in the south of the country.

3. Increasing Flexibility of the Power System

Storage options under investigation

Part 2 of the DENA study extended this outlook to 2020, with scenarios featuring new storage 

facilities able to absorb 50% and 100% of surplus wind power generated, as well as the value of 

the demand-side flexible resource. The Energy Concept includes a EUR 200 million budget for 

storage R&D up to 2014. Under the amended Energy Industry Act, new storage facilities are 

exempt from grid charges. The same is true for the EEG levy (“EEG-Umlage”) (BMU 2011b).

The German energy agency and partners are examining the benefits of using excess electricity 

production to produce hydrogen, and hence synthetic methane gas, which can be fed into (and so 

stored) in the gas grid. Early demonstration plants are already in use. Direct hydrogen feed-in 

into the gas grid may require some technical adaptation. The German gas transmission system 

operators estimate the costs of integrating 10% of hydrogen (by volume) into the gas 

transmission grid to amount to about EUR 3.7 billion, excluding potential further costs related to 

other system components (e.g., gas storage and distribution grids, power plants, industry)

(Netzentwicklungsplan Gas 2012).

From 2009 to 2011, the German Space Agency, a national research center that provides a major 

contribution to energy research, in collaboration with several other institutes, completed the 

Leitstudie, a dynamic simulation of German electricity supply with a high share of renewables, 

including the importance of storage.

Flexible Power Plants

Discussions regarding adapting the regulations around combined heat and power generation to 

improve the flexibility of such plants are ongoing within the government. Providing an incentive 
79

to owners of such plants to include additional thermal storage is one option being examined. This 

would allow to some extent the production of heat and power to be “decoupled.” For example, 

when heat demand is high but a reduction in electricity output is desirable in order to balance a 

variable RE surplus, the heat may still be drawn off the storage, while the actual production can 

be reduced. The draft law presently under discussion considers the use of grants to cover 30% of 

the costs of the additional heat storage (Argus 2011). The law aims to increase the role of 

combined heat and power plants in power production from approximately 15% in 2010 to 25% 

in 2020.

The Energy Concept targets the completion of fossil-powered plants now under construction by 

2013, and an additional 10 GW of plant capacity by 2020. But, simultaneously the government 

has provided incentives in the form of a new fund to encourage this new capacity to take up the 

latest flexible technology, so that its output can better complement variable RE (BMU 2011b). In 

short, the intention is to maximize the speed at which plants can ramp up and down, resulting in 

minimal overlap with variable RE output (and consequently minimal unnecessary emission of 

CO2) and reliable support for system adequacy. 

Government and private sector partners have for many years worked on the concept of a virtual 

power plant—one that provides all the electricity services of a conventional power plant but 

consists of several different plants in different locations, each providing a part of this service. 

One of the most advanced developments in this area has been the combined power plant concept 

(Kombikraftwerk) developed by a consortium of variable RE producers (Kombikraftwerk 2 n.d.). 

This concept links wind, solar, biomass, and hydropower installations throughout the country. 

4. Making Markets more Amenable to Variable RE

In addition to the FIT, one of the more important driving forces behind renewables deployment 

in Germany has been the priority dispatch (EE-vorrang) accorded to renewable power, ensuring 

that as much of its output as possible is used. The significance of this is considerable; since 1991 

when priority dispatch was first introduced, all renewable electricity must be bought, even if this 

means base-load plants such as nuclear have ramp down (SOU 2007). 

Until quite recently, variable renewable power plants could ignore the power market. The 

electricity they produced would be bought by the system operator and sold directly to suppliers. 

But, this changed when the Equalisation Scheme Ordinance (AusglMechV) of 2009 stipulated 

that all EEG electricity was to be sold by the TSOs on the spot markets. In 2012, the logical next 

step came into effect, wherein under the 2011 July EEG, RE producers could choose a “Market 

Premium” option over the existing FIT. By implementing the Market Premium, the government 

wants to stimulate learning processes with regard to electricity markets in the RE sector and aims 

at a more demand-responsive generation of RE.

Producers choosing to adopt this support model will sell their production, themselves, in the spot 

market. New companies that organize the professional selling of RE production and which are 

setting up huge pools of plants have been established. Dispatchable renewable electricity 

generators such as biomass and geothermal power plants could then have access to a potentially 

important revenue flow—resulting from the flexible provision of more valuable balancing power 

in response to system needs—alongside typical spot market prices for energy. 
80

Protecting the Revenue of Existing Flexible Resources

As wind and solar PV electricity production increases, and because of their low marginal cost 

and priority dispatch, less production is needed from existing conventional plants, such as gas 

and coal, which have higher operating costs (mainly fuel). This is known as the “merit-order 

effect” (i.e., whereby conventional power plants are pushed down the order in which plants are 

used). 

This “missing revenue” problem may adversely affect the economics of those plants to the point 

that owners no longer consider their continued production to be profitable and retire them from 

service. If this would occur, it would not only reduce the amount of flexible power on the system 

able to balance fluctuating variable RE output, it might also undermine the adequacy of the 

system (i.e., its ability to meet its peak power requirements). At present, the discussion of this 

very important issue is stalled because the potentially resulting market intervention is deemed 

profound, and it may well be an academic discussion for now. As a next step, the issue will be 

discussed in the context of the biannual Power Plants Forum organized by Federal Ministry of 

Economics and Technology. Even if fossil-fueled plants are displaced to some extent by new 

variable RE output, they will be needed to compensate for the nuclear power plants already 

retired (nearly 10 GW), alongside imports of electricity from France. 

Unbundling of Generation and Transmission Asset Ownership

The on-going liberalization of the European Union’s electricity markets is driving the separation 

of production and transmission asset ownership. This was undertaken to address the disincentive 

on bundled utilities to provide access to their transmission assets, which would increase 

competition with their generation assets.

Until recently, the “Big Four” German utilities (E.ON, EnBW, RWE, Vattenfall) also owned and 

operated the high-voltage transmission system. However, E.ON sold its transmission assets to

TenneT, the state-owned Dutch system operator (which created TenneT TSO GmbH) in 2010; 

Vattenfall sold to Elia and IFC Infrastructure, an Australian Infrastructure fund, in 2010; and 

RWE sold 75% of Amprion in July 2011 to a financial consortium managed by Commerz Real 

AG, which consists of several European pension funds. In other words, system operators that do 

not own generation assets now control three of four of the TSO areas in Germany. In contrast, 

EnBW Transportnetze AG, in the southwest of the country, still belongs to EnBW, but EnBW is 

itself majority-owned by the state of Baden-Württemburg.

Widening the Market

For more than a decade, driven by EU liberalisation directives, European electricity markets 

have been moving toward greater interconnection and integration of markets. While the former 

has often met with very lengthy delays—new lines can take 15 years to accomplish—

consolidation of the markets that depend on this grid has continued apace, particularly in recent 

years. While the primary objective of this consolidation was never to benefit variable RE 

specifically—but rather to lower costs to the consumer in an even manner—it also benefits 

variable RE. This is because market consolidation makes possible the trading of less-expensive 

variable RE output over much larger areas; it enables valuable flexible resources to flow to 

where they are needed most; and, potentially, it allows greater complementarity of variable RE 

outputs from different resources (e.g., wind power in the northern Germany with non-correlated 

solar PV output from Spain).
81

Since November 2010, Germany has been an integral part of a single electricity market that 

includes France and Benelux countries through a process known as “market-coupling.” In 

essence, this means simply that cross-border transfer capacity no longer has to be acquired 

explicitly—through a separate arrangement from the actual acquisition or sale of energy—but is 

implicit in the trade itself, greatly reducing the time required to effect international trades. In 

effect, it encourages less-expensive (including variable RE output) electricity to flow toward 

higher cost areas where it will find a market; it also reduces price differences across borders. 

This Central and West Europe market is linked to the Nordic market via a similar mechanism, 

but one in which the coupling is activated only at a certain cross-border price differential, known 

as the Interim Tight Volume Market Coupling. This was developed by a joint venture of German 

Nordic TSOs, known as the European Market Coupling Company. 

Greater, Faster Trading of Power

Over the same period, spot markets (i.e., voluntary exchanges wherein electricity can be bought 

and sold on a range of timescales) have emerged and consolidated, providing further liquidity in 

the electricity market, which is beneficial to the balancing of variable RE. The European Power 

Exchange saw approximately 24% of German electricity trade in 2009 (Eclareon 2011), as well 

as trading of French, Swiss, and Austrian electricity. However, this means that in that year, three 

quarters of German electricity was still traded bilaterally, rather than through a pool.

51

The European Power Exchange includes a day-ahead spot market, as well as an intraday market, 

on which trading volume is growing rapidly; it grew from 1.6 terawatt-hours (TWh) in 2007 to 

approximately 10 TWh in 2010.

52 BNetzA announced in 2011 that henceforth balancing power 

needed against wind forecast uncertainty would be traded on the intraday market; this will 

further increase volume at the expense of the—less transparent—balancing market (Borggrefe et 

al. 2011).

Gate closure times in day-ahead and intra-day markets have been shortened to 15–75 minutes 

ahead of the time the electricity is actually generated and consumed. This increases the ability of 

the market to optimize the level of dispatchable plant output to complement the latest forecast of 

variable feed-in from wind and solar PV resources.

Opening up the Balancing Market

After the spot exchanges have closed, electricity required by the system operator to balance any 

remaining as well as newly occurring imbalances between supply and demand can be found 

through the balancing market. Historically, the balancing market has been rather opaque. This 

was particularly a concern before system operation was unbundled from generation ownership. 

Transparency has increased with the introduction of a compulsory Internet platform,

53 which was 

introduced following a July 2005 amendment of the Electricity Industry Act and which includes 

details of all tenders to the balancing market, nationwide. 

Between 2007 and 2010, tendering for balancing power was common to all four control or

balancing areas, though the actual balancing of these areas was done separately, meaning that 

simultaneously balancing of energy still occurred in contrary ways (e.g., one area ramping up 

 51 Including that paid for under the Renewable Energy Law, and traded directly between the system operators and 

suppliers. 

52 According to Weber (2010), there exists an intra-day market trading potential of some 17 TWh. The remaining 7 

TWh potential is unused because of transaction costs, market dominance, and trade-offs with the balancing market. 53 http://www.regelleistung.net/
82

supply while its neighbor ramped down). This was remedied to some extent in 2010, when 

BNetzA stipulated a common secondary reserve market with a standardized tender (Eclareon 

2011), but primary reserve (the shortest timescale) is still tendered separately in the four control 

areas.

In 2011, BNetzA specified new terms of tender for balancing energy to facilitate the market 

access of smaller energy suppliers, including consumer appliances that allow the capacity to be 

adjusted, electricity storage, and renewable energy systems.

• Primary system balancing, which must be provided in seconds to stabilize frequency 

deviations in the whole European network, is tendered for 1 week in advance (instead 

of 1 month as it was previously); the minimum tender quantity is 1 MW (instead of 

5 MW); and it is now possible to pool plants.

• Secondary system balancing, to control differences between the different balancing 

areas, is also tendered for 1 week (before: 1 months), and the minimum tender 

quantity is 5 MW (before: 10 MW) and it is possible to pool plants. 

Challenges for Neighboring Countries

Polish and Czech system operators are considering blocking action in the face of large windbased flows into and through their systems. Poland is considering installing devices to enable 

this (Platts 2011). Austria, for example, buys wind power to fill its pumped-hydropower

reservoirs, and 35% of electricity flowing from Germany to Austria passes through the Czech 

Republic.

5. Promoting Diversification of Location

Diversifying the location of variable RE plants has the effect of smoothing their aggregated 

output, as the solar and wind resources in different sites will fluctuate in an uncorrelated or only 

partially correlated manner. 

The support system in Germany includes a specification with regard to the FIT, depending on the 

wind potential available at a specific wind turbine site. To that end, a reference turbine 

(including a reference site) is introduced. The energy yield of the first five years of operation of a 

turbine is compared to its theoretical reference energy yield using a defined calculation method. 

In this way, the initial (high) FIT period, which usually lasts five years, can be extended (EEG 

2012). This mechanism was intended to enable wind energy development sites with lesser (but 

still valuable) wind resources. This may result in greater diversification of wind turbine sites, and 

thus, smoothing of aggregated output might result as a side effect of differentiated payments. It 

has probably not had practical consequences yet, though this might change with the growing 

willingness of the southern German states to designate site zones.

54

Planning at state level, including wind priority sites, is more important for diversification of wind 

plants. In the southern states (especially in Bavaria and Baden-Württemberg), not many wind 

priority sites have been identified, but this is changing.

55

6. Advanced System Operation and Grid Code Development

The task of TSOs, which manage the high-voltage grid in areas with very large shares of variable 

RE electricity, is increasingly complex. Very large amounts of data need to be managed and 

 54 Email communication with Prognos analysts, February 2012. 55 Ibid
83

continually updated, while more dynamic management of power plants, such as re-dispatching or 

using curtailment, requires high-speed decision-making. For example, in June 2011, 50Hertz, the 

system operator in eastern Germany, inaugurated a new control center, in large part to manage 

the increasing complexity of managing a power system with large amounts of wind power. In 

planning system operation, the center uses multiple wind output forecasts in combination, 

running up to a 96-hour forecast horizon. These are updated twice daily (Jones 2011).

In April 2011, the Federal Network Agency (BNetzA) amended rules relating to the ability of 

system operators to “redispatch” power plants. To alleviate congestion in a specific line, 

generators on either end may be instructed by the system operator to alter their output. As a more 

sustainable remedy, new transmission lines are necessary in the medium term. It should be noted 

that another driver behind the changed rules has been the nuclear phase out.

56

Curtailment

Serious delays to essential grid expansion work are also apparent in the increasing need to curtail 

wind plants in the north of the country. Though an important system management tool, the 

curtailment of power plants (or “feed-in management”) leads essentially to the waste of what was 

wanted in the first place (i.e., clean energy) so it should be minimized. Indeed, its use in 

Germany does have a “last resort” status. Nevertheless, curtailment in 2010 increased by up to 

69% over the previous year. Even if it only amounted to 0.2% - 0.4% (72–150 GWh) of total 

wind electricity,

57 in some northern wind farms as much as 25% of output was curtailed (Ecofys 

2011). Under the EEG, curtailment losses have mostly to be compensated by the system 

operator, which passes these costs on to the consumer.

Until it was amended in 2011, the EEG required wind and solar PV power plants (among others) 

with nominal capacity greater than 100 kW to be able to be curtailed remotely by the system 

operator in the event of electricity surplus, and to make information about the current electricity 

feed-in of an installation accessible to the system operator. Failure to provide this capability 

would in theory result in disqualification for the FIT. However, in practice, this requirement 

proved difficult to apply to PV systems. 

The curtailment requirement did not apply to power plants smaller than 100 kW. However, under 

the latest amendment of the EEG, remote control management of PV plants down to 30 kW is 

required (EEG 2012). It is optional for plants smaller than 30 kW, which may choose instead to 

have a reduced feed-in (Stetz 2011). In addition, the distribution system operator has certain 

other emergency powers to require curtailment by the plant owner under the Energy Industry 

Act.

Other Requirements of the Grid Code

From April 1 2011, all new power plants will need a certificate proving that they comply with 

requirements, collectively known as the “grid code.” 

In 2009, the German government issued a new rule (SDLWindV 2010) that requires certain other 

services of variable power plants, though to varying extents. These are usually referred to as 

ancillary services. For example, all wind power plants commissioned since 2009 must be able to 

remain on the grid, generating electricity to support it, in case of faults (this is known as “fault 

 56 It is also around such large centralized power plants that European grids have developed; they are not optimized 

for large volumes of distributed generation.

57 BNetzA 2010 reported 0.1%.
84

ride-through capability”). Plants must also be able to control the frequency of their output in 

order to protect the frequency (stability) of the network local to their connection. Plants 

commissioned since July 2010 are required to provide additional services. 

For older wind power plants, incentives are provided to encourage them to be refurbished in 

order to provide some of these services. Plants commissioned before January 2009 are offered a 

bonus of EUR 7/MWh for five years if they completed refurbishment to provide both fault ride 

through and frequency control by January 1,2016 (Fichtner 2010, section 66, paragraph 8).

The speed with which solar PV power has appeared in the German electricity system—although 

it still has only a 2% share—has resulted in additional requirements of it. This is partly because 

almost all the installed PV has appeared at the low and medium-voltage grid level. Typically, the 

lower voltage grid network, unlike the high voltage network, is not actively managed. Since 

2010, PV power plants connected to the medium-voltage grid (10 kV to 110kV) have had to 

comply with certain standards. These include voltage support and active power control; since 

2011, they include fault ride-through capability (Ellis 2009).

Potential for Learning in Other Countries

The transmission and distribution grid in Germany evolved to serve fewer (relative to today) 

large, gigawatt-scale, dispatchable power plants located close to centers of high consumption. 

The country is evolving to be better able to manage the output and needs of a very large number 

of additional, geographically dispersed variable output power plants at scales kilowatts to 

hundreds of megawatts. 

Germany has also been at the forefront of renewables deployment. It has iterated its transmission 

plans, connection rules, and grid codes, resulting in considerable learning and expertise. Its 

experiences in moving from a generator-owned, vertically integrated electricity system to one of 

mixed ownership and increasingly private ownership, while promoting significant use of RE and 

increased investment, should greatly interest most countries with power grids established by the 

latter half of the last century. 

The BMU has been the primary driving force behind variable RE deployment and integration 

from the outset. Countries where the preference is to leave energy matters entirely to the market 

will find the German model more difficult to emulate. However, German actors as a whole also 

understand the importance of regulated market forces. Progress toward market coupling, though 

initiated by Belgium, France, and the Netherlands, has been enormously reinforced by the 

German presence, not least of all, because it provides a link to the Nordic market.

German experiences may be less applicable to smaller developing countries that have neither a 

mature grid nor the wide market opportunities provided by Germany’s position at the 

geographical center of Europe. A fully interconnected grid may not be financially feasible in 

some cases. 

Conclusions

With the 2010 Energy Concept, and its update in summer 2011, the German government has 

embraced the complexity of a fundamental shift in energy production. Germany is moving away 

from nuclear power toward an energy future based in large part on a fundamentally different 

power portfolio. The Energy Concept is intended to capture and manage this complexity that 

includes: fluctuating, partially predictable output; diverse location of plants, some far offshore 
85

and many others embedded in the low-voltage grid; and the resulting need for a more flexible 

grid that is stronger at its extremities in order to harvest all this new resource. 

Germany has long been a test-bed for renewables deployment, and it has made considerable 

strides in integrating variable generation, though significant tasks remain. It remains to be seen 

whether the Energy Concept will solve the biggest challenge: rolling out and reinforcing the grid. 

Germany has shifted from wind-only transmission studies to the development of a legally 

binding Federal Requirement Plan for Transmission Networks that is hoped will resolve delays. 

Other factors will be important. Public support for new transmission is a principal barrier. Local 

incentives, a major information campaign, and new technology to reduce the impact in the most 

sensitive areas are all being tried. Investment needs to be found, too. Locational/nodal pricing of 

electricity to reflect where congestion is highest—and therefore guide investment to where it is 

most needed—could help. It may also be that higher regulated allowable returns on investment 

may be needed to attract investment.

The priority grid connection accorded by law to RE plants has been an enormous spur to 

investors, as has the allocation of costs—in the case of offshore, entirely—away from the plant 

developer. This procedure has caused delays, but the government has acted to resolve these. 

Again, results remain to be seen, but accelerated offshore deployment is anticipated. Recent steps 

to clarify jurisdictional issues outside of coastal waters may also help. Onshore, federal 

cooperation with the Länder is hoped to lead to additional efficient land-based deployment.

In addition to supporting the physical ability of output to flow to the user, Germany has done 

much to make marketing of that energy more flexible to suit its variable nature. The feed-in 

premium model to be launched this year is hoped to encourage more dispatchable renewables out 

from under the shelter of the EEG and into the marketplace, where they can be better used to 

balance variability. At the same time, storage, decoupled combined heat and power plants, more 

flexible conventional generators, and the virtual power plant concept target further increase in 

flexible resources. Priority dispatch ensures that the most variable RE possible is brought to 

market.

Transmission and generation ownership have been largely unbundled, with benefits for 

competition, though new owners may also prove difficult to convince when it comes to making 

new investments unless their returns increase. Enabling more fluid trade north and south through 

market coupling is facilitating management of local concentrations of variable output. Greater 

liquidity on the spot markets, particularly close to the time of operation, is bringing more flexible 

resources to bear, revealing their value and thus boosting investment.

As complexity increases, so does the task of operating the power system. Newly independent 

system operators are building new control centers to plan the operation of their areas using 

advanced forecasting techniques. Short-term balancing, particularly to cover uncertainties in 

these forecasts, has become more open. Collaboration has been greatly improved among the four 

control areas, with more efficient use of balancing resources, although they are still managed 

separately.

A good measure of the flexibility of the system is the extent of curtailment of variable RE output. 

Curtailment is on the rise as grid congestion increases. Given the strategic energy choices of 

government, it should in future be minimized, even if at small energy volumes it can be 

considered a useful source of flexibility. 
86

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89

Appendix E. Case Study: Ireland

Author: Jenny Heeter, National Renewable Energy Laboratory (NREL)

Introduction 

Increasing penetrations of variable renewable energy (RE) concern Ireland, as it has seen 

increasing curtailment of wind and will see greater penetrations of RE as the country ramps up to 

its target of 40% RE by 2020. Curtailment of wind generation in Ireland has become more 

prominent in recent years; in 2009, 0.2% of total wind energy was curtailed, while in 2010, 1.2% 

of total wind energy was curtailed (Holttinen et al. 2011). Curtailment concerns wind generators

in particular because although they are paid for what they would have generated by selling into 

the market, they are not compensated through Ireland’s support mechanisms (Rogers et al. 2010). 

In many ways, Ireland is ahead of the curve in preparing for integrating high penetrations of RE. 

Uniquely, the transmission operator in Ireland, EirGrid, is state-owned; for this reason, some 

policies discussed in this appendix may have been easier to implement. In addition, policy and 

market development may be less complex, given that Ireland is a small country where 

stakeholders are more likely to know one another. 

Ireland represents an example of a deregulated market, with few imports and exports. The small 

system has seen a high level of variable RE penetration. Table E-1 lists key aspects of Ireland’s 

system.

Table E-1. Key Aspects of Ireland’s System

Deregulated market

State-owned transmission operator

Isolated, small system

High level of penetration

This case study examines key areas where Ireland has acted to accommodate high penetrations of 

variable RE. After a brief background section addressing contextual factors to Ireland’s 

increasing penetration of RE, this appendix presents information on the following specific 

measures to accommodate high penetration of variable RE: 

1. Coordinate and integrate planning

2. Expand access to diverse resources

3. Lead public engagement including facilitating new transmission

4. Improve system operations 
90

Background 

Variable RE, primarily wind, in Ireland has been increasing dramatically. Wind generation in 

Ireland increased from 0.3 billion kilowatt-hours (kWh) in 2001 to 2.7 billion kWh in 2010 (EIA 

2012). At the end of September 2011, 1,585 MW of wind, 237 of MW hydropower, and 46 MW 

of smaller renewables58 were operating in Ireland (EirGrid 2011). On April 5, 2010, wind 

generation reached 53.5% of instantaneous electricity demand on Ireland’s system (EirGrid 

2012). 

The share of RE generation is planned to be 40% in 2020. The development of new RE is driven 

by EU Directive 2009/28 EC, which ensures that 16% of all energy (electricity, heat, and 

transport) come from renewable sources by 2020. To meet this directive, Ireland, in its National 

Renewable Energy Action Plan, set a target of 40% of electricity coming from renewable sources 

(DCENR 2011), which translates to approximately 4,600 MW of cumulative installed wind 

capacity in 2020 (Figure E-1). 

Figure E-1. Cumulative installed wind capacity in Ireland to 2011 and indicative targets from 

2010–2020

Source: Jones 2011

Renewable generation is facilitated by the Renewable Energy Feed-in Tariff (REFIT) scheme, 

which was introduced in 2006 and funded in 2007. REFIT initially was designed to support up to 

1,450 MW (Ireland 2010) and offered payments to onshore wind, landfill gas, biomass and small 

hydropower facilities (i.e., less than 5 MW of capacity). REFIT payments in 2010 ranged from 

€66 ($86)/MWh to €84 ($110)/MWh, depending on the technology (DCENR 2012). The first 

offering “REFIT 1” was closed at the end of 2009, but recently the European Commission 

indicated it intends to provide state aid clearance for a second REFIT round “REFIT 2”. REFIT 2 

will cover the same technologies as REFIT 1 and will be available to facilities that commenced 

construction after January 1, 2010 (DCENR 2012).

 58 Small renewables are defined as small hydropower, land-fill gas, and renewable forms of combined heat and 

power.
91

Market and Technical Background 

It is important to recognize that Ireland is a small, island system that depends on energy imports 

(Bazilian n.d.). There is a minimal level of regional interconnection, with only three AC links 

(with Northern Ireland) with a capacity of 450 MW (Bazilian n.d.). Northern Ireland is 

connected to Scotland by a 500-MW HVDC link, and, as will be discussed later, a 500 MW 

HVDC link between Ireland and Great Britain should be completed by the end of 2012 

(Holttinen et al. 2011).

Ireland presents a case of a government that owns the TSO. The TSO in Ireland, EirGrid, is a 

state-owned company established after Ireland deregulated its power sector. The EirGrid board 

of directors is appointed by the Minister for Communications, Energy and Natural Resources,

and the company is regulated by the Commission for Energy Regulation. The System Operator 

of Northern Ireland (SONI), which cooperates with EirGrid, is regulated by the Northern Ireland 

Utility Regulator. 

Five Areas of Intervention to Accommodate High RE Penetration

This section discusses how Ireland has sought to coordinate and integrate planning; expand 

access to diverse resources; lead public engagement including facilitating new transmission; and 

improve system operations. Each topic area highlights a specific approach taken by key 

stakeholders to address the high penetration of variable RE.

1. Coordinate and Integrate Planning

Energy ministers in Ireland and Northern Ireland have supported planning; EirGrid, in 

cooperation with SONI, is leading follow-on work. A number of studies have been conducted to 

assess impacts of high penetrations on the all-island system (Table E-1).
92

Table E-1. Summary of Key Studies

Study Year 

Published

Primary Objective Primary Participants, Authors

All-Island Grid 

Study

2008 Examine a range of 

generation portfolios, 

ability of grid to handle 

various penetrations of 

RE, investment levels 

required, climate and 

security of supply 

benefits

Department of Communications, Energy and 

Natural Resources (Ireland), Department of 

Enterprise, Trade and Investment (Northern 

Ireland), ESB International, University College 

Dublin—The Electricity Research Centre, 

Risoe National Laboratory, University of 

Stuttgart, RAM-løse EDB, University of 

Duisburg-Essen, and TNEI Services Limited

All Island TSO

Facilitation of 

Renewables 

Study

2010 Identify potential 

technical issues and 

mitigation measures

EirGrid and System Operators Northern 

Ireland (SONI)

Delivering a 

Secure 

Sustainable 

Electricity 

System

Ongoing Implement technical 

solutions identified in the 

Facilitation of 

Renewables Study

EirGrid and SONI

Energy departments in Ireland and Northern Ireland recognized the need for transmission 

planning, and in 2005, collaborated on a preliminary all-island 2020 vision for RE. A resulting 

working group recommended completing an All-Island Grid Study. Completed in 2008, the AllIsland Grid Study was the first to examine future impacts of high penetrations of RE and was the 

result of multiple integrated work streams, including a resource assessment, network study, 

portfolio screening and dispatch studies, and an analysis of costs and benefits. The All-Island 

Grid Study acknowledged that there were limitations to the methodology and that future 

technical work was needed.59

Following the All-Island Grid Study, the Facilitation of Renewables studies demonstrated that 

significant changes would be needed to reach the renewable targets set by both governments. 

The Facilitation of Renewables studies were designed to identify potential technical issues 

related to high penetrations of renewables and develop mitigation measures to inform future 

operational policies, grid code and standards, and payment mechanisms for all generation 

(EirGrid and SONI 2009). EirGrid and SONI contracted with ECOFYS, Siemens-PTI, and Ecar 

to complete the work.

Most recently, EirGrid and SONI collectively established a work plan, Delivering a Secure 

Sustainable Electricity System (DS3) to implement the technical solutions developed in the 

Facilitation of Renewables study. The DS3 program includes 11 separate work streams: 

frequency control, voltage control, system services review, demand side management, grid code, 

performance monitoring, rate of change of frequency, model development and studies, renewable 

data, Wind Security Assessment Tool, and control center tools and capabilities. 

 59 For example, the studies used steady-state calculations, and for this reason, dynamic issues such as frequency 

stability and transient stability were not considered. 
93

DS3 has a built-in communications and stakeholder engagement plan that includes an advisory 

council, industry forums, and work with the existing Joint Grid Code Review Panels. 

Stakeholder engagement is planned throughout the DS3 process, with regular advisory council 

meetings, industry forums, and grid code review panels. In addition, the TSOs and regulatory 

authorities in Ireland and Northern Ireland are planning to meet three times in 2012.

Ireland’s planning efforts have progressed from studying the potential for renewables to taking 

concrete steps to addressing technical issues related to the high penetration of variable RE. 

Energy ministers in Ireland and Northern Ireland supported the initial study, the All-Island Grid 

Study. The TSOs in Ireland and Northern Ireland built on that work, and they are implementing 

technical solutions.

2. Expand Access to Diverse Resources: Creation of the Single Electricity Market 

and Interconnection to Great Britain

Expanding markets is a key way to decrease the operational challenges of integrating variable 

RE into the grid. Ireland and Northern Ireland established a common Single Electricity Market 

(SEM) in 2007 to unite the electricity markets of the island. The expanded market creates a 

greater pool for balancing and enables more transmission connection to Great Britain. 

SEM achieves these objectives as all electricity exceeding 10 MW sold and bought in Ireland is 

traded through the central electricity pool through a market clearing mechanism; no bilateral 

transactions are permitted outside the pool. According to the SEM Committee, SEM “promotes 

the interests of consumers by enabling greater competition through cost reflective prices, while 

also securing a diverse, viable and environmentally sustainable long term energy supply” 

(SEMO 2010). The SEM covers approximately 2.5 million electricity customers in Ireland and 

Northern Ireland (SEMO 2012).

Cooperation of regulatory agencies and transmission operators in Ireland and Northern Ireland 

was required to establish the SEM. The Single Electricity Market Operator (SEM-O), the 

organization that operates and administers the SEM, was developed through a series of 

memorandums of understanding. The first memorandum of understanding was signed in 2004 

between the regulatory bodies in both countries: Commission for Energy Regulation (Ireland) 

and the Northern Ireland Authority for Utility Regulation. In 2005, a memorandum of 

understanding was signed by EirGrid (then ESB National Grid) and SONI, the grid operators in 

Ireland and Northern Ireland. When SEM launched in November 2007, EU Energy 

Commissioner Andris Piebalgs said, “The Single Electricity Market is important not only for the 

island of Ireland, but also for the European Union. This is a significant contribution to the 

construction of the internal energy market. A regional initiative like SEM deserves to be widely 

copied (EU 2007).”

The SEM is the first market in the world to operate in multiple jurisdictions and dual currencies, 

the Euro and Sterling. The market operation has been deemed successful, with “no major issues 

with regard to the operation and oversight of the market under two jurisdictions” (Conlon 2009). 

SEM has been compared to the Nordpool Power Exchange and the Eastern Australian markets 

(Conlon 2009), though it is a small market with a spot market volume of 34.6 terawatt-hours 

(TWh) in 2009, compared to the spot market volume in Nordpool of 285.5 TWh in the same year 

(Nepal and Jamasb 2011). 
94

Addressing system curtailments was one of the most contentious issues, which was recently 

resolved by the SEM. A process was developed for which generators to curtail when the need to 

curtail wind generation arises. This issue was long and controversial primarily because wind 

generators receive an incentive payment based on the megawatt-hours they generate. The SEM 

considered equally distributing curtailment among all generators but ultimately ruled that the 

newest installed generators would be curtailed first (e.g., wind capacity installed in 2011 would 

be curtailed before wind capacity installed in 2010). SEM said this approach “should provide a 

signal to the marginal renewable plant in future years of whether it is viable to connect to the 

system (SEMO 2011, p. 17).” Once the 2020 RE targets have been reached, this process may be 

reevaluated. 

East-West Interconnector to the United Kingdom

Policymakers and grid operators have recognized the need to expand Ireland’s grid. Reasons for 

expanding go beyond accommodating higher penetrations of RE.

60 In 2006 and 2007, plans for 

an East-West interconnector linking Ireland to Wales developed. In 2006, the federal government 

requested the link be incorporated in the Commission for Energy Regulation’s energy policy 

(Edwards 2010), and in 2007, the government’s National Development Plan 2007–2013 called 

for an East-West connector (NDP 2007). The impact of export capability on wind curtailment 

levels at 38% wind penetration was modeled by EirGrid and SONI (System Operator for 

Northern Ireland), demonstrating that increased export capability would lower curtailment levels 

(EirGrid and SONI 2010). 

The planning process for the 500 MW line involved 2 years of marine surveys, route selection, 

public engagement, route amendments, and pre-application consultation (EirGrid 2009b). The 

European Commission awarded the project €110 ($144) million in stimulus funds in 2010.

Construction of the interconnector began in July 2010 and the interconnection is expected to be 

operational in Q3 2012. Unicorn Systems developed an auction management platform (AMP) to 

allow participants to trade across the interconnector, which went live in November 2011. During 

the AMP development, two workshops on access rules were held (October 2010 and November 

2011), and stakeholder comments were integrated into the final rules. 

3. Leading Public Engagement, including Facilitating New Transmission

Public engagement and facilitating new transmission development is particularly important to 

Ireland, as it is classified as an island system with little interconnection. 

Public engagement is led by EirGrid and supported by the Ireland Wind Energy Association 

(IWEA). EirGrid has two methods of engaging stakeholders: public education efforts and 

outreach for specific transmission projects.

EirGrid reaches out to schools in order to educate student about the benefits of wind power. The 

effort focuses on educating teachers and students, not about one specific transmission project, 

but rather about the energy sector and infrastructure projects generally. In this way, once a 

specific transmission proposal is developed, the public is already aware of the issues involved. 

IWEA operates a separate education effort using the KidWind61 curriculum developed by the 

American Wind Energy Association. 

 60 Other benefits cited include “enhanced security of supply, increased competitiveness, [and] reduced production 

costs” (EirGrid 2009a)

61 The KidWind curriculum can be found here: http://learn.kidwind.org/.
95

Communities in Ireland have expressed concern over both the aesthetic impacts of new 

transmission lines and the health impacts related to electro-magnetic radiation emissions. 

Community opposition continues to be a challenge – as construction on the East-West 

Interconnector began, protesters vowed to block roads, citing opposition to the final route 

selected (Independent 2010a). There has also been pushback against EirGrid’s paid media 

outreach campaign, because the company is a state-owned monopoly. In 2010, EirGrid ran 30-

second advertisements on television at an estimated cost of €600,000 ($785,000) for ad 

development and airtime (Independent 2010b).

Facilitating New Transmission

The existing Moyle interconnector connects Northern Ireland to Britain and serves almost 4.7% 

of total generation capacity in the SEM (Nepal and Jamasb 2011). The link has a capacity of 450 

MW (Edwards 2010).

Ireland’s national grid development strategy, Grid25, provides for grid expansion over the long 

term (through 2025) to support the Irish government’s target to increase renewable electricity to 

40% of generation. Grid25 was supported by the Irish Minister for Communications, Energy and 

Natural Resources, Eamon Ryan but developed by EirGrid, the state-owned transmission 

operator. A stated goal of Grid25 was to exploit Ireland’s wind and wave energy sources, as well 

as to facilitate transmission of RE, in line with the Irish government policy. In addition, the 

development of multiple lower-voltage lines could be avoided through advanced planning of a 

single higher-voltage line.62 Grid25 found that there was a need for about 1,150 km (715 miles)

of new circuits and 2,300 km (1,429 miles) in upgrades. 

To facilitate the development of new lines, EirGrid must scope out individual transmission 

projects, propose them to the public and key stakeholders, and then seek approval from the 

Commission on Energy Regulation. 

Recently, Ireland centralized the planning approval process from a local approval to a national 

approval. The Strategic Infrastructure Board was created under the National Planning Authority 

(An Bord Pleanála). The Strategic Infrastructure Board approves transmission plans on a national 

basis, so instead of a transmission developer needing approval from multiple local planning 

departments, only one approval is needed. Although some transmission developers may have had 

positive relationships with local planning boards that were supportive of development, the 

transition has been viewed favorably. 

4. Improve System Operations: Advanced Forecasting

EirGrid is improving system operations by deploying a Wind Security Assessment Tool (WSAT) 

in its control room. The WSAT was developed with Powertech Labs to assess the maximum 

amount of wind generation that the system can accept, by examining voltage and transient 

stability analyses of transfers during normal operation (Holttinen et al. 2011). WSAT was 

installed and officially launched in October 2010 at the National Control Center in Dublin. There 

are also plans to implement the tool in Northern Ireland.

Importantly, the early involvement of system dispatchers in the development of WSAT and 

EirGrid’s Wind Dispatch Tool resulted in faster integration of the tools into the control room 

(Jones 2011). 

 62 The report explains that one 400 kV line can carry three times the capacity of a 220 kV line.
96

Replication of Efforts by Other Countries

Ireland can serve as a prime example of how to plan for high penetrations of RE, expand markets 

and balancing areas, lead public engagement to facilitate new transmission, and improve system 

operations. It should be noted that each country has a unique set of circumstances that may make 

the actions discussed here relevant or not.

Ireland is a small, island system. Similar systems should look towards Ireland’s efforts to expand 

markets and balancing areas, if possible.

EirGrid, as a state-owned transmission operator, has been forward thinking and supportive of 

Ireland’s aggressive RE targets. EirGrid’s board is appointed by the Minister for 

Communications, Energy and Natural Resources.

Summary and Conclusions 

Ireland has set aggressive goals for RE development and is actively working to facilitate high 

penetrations of variable RE. Specific measures taken in Ireland include:

1. Coordinate and integrate planning. Planning began with the All-Island Grid Study 

(2008), which was supported by energy ministers in Ireland and Northern Ireland. The 

Study examined a range of generation portfolios, the ability of the grid to handle various 

penetrations of RE, the investment levels required, as well as the climate and security of 

supply benefits. In 2010, EirGrid and SONI completed the Facilitation of Renewables 

Study, which identified potential technical issues and mitigation measures. Currently, 

EirGrid and SONI are implementing technical solutions identified in the Facilitation of 

Renewables, through the Delivering a Secure Sustainable Electricity System work 

program.

2. Expand access to diverse resources: Creation of the Single Electricity Market and 

interconnection to the U.K. Ireland and Northern Ireland established a common Single 

Electricity Market (SEM) in 2007 to unite the electricity markets of the island. The SEM 

was established through a series of memorandums of understanding between regulatory 

agencies and transmission operators in Ireland and Northern Ireland. The SEM has been 

working well, and recently established a new process for curtailing wind; newest installed 

generators will be curtailed first.

To further expand access to diverse resources, Ireland is also constructing an 

interconnector to the U.K. The line will have a 500 MW capacity and is expected to go 

online in 2012.

3. Lead public engagement including facilitating new transmission. EirGrid’s education 

outreach promotes awareness of the needs and purposes of new transmission generally. 

More specifically, a national grid development strategy, Grid25, provides for grid 

expansion through 2025, and EirGrid must scope out individual transmission projects, 

proposed them to the public and key stakeholders, and then seek approval from the 

Commission on Energy Regulation.

4. Improve system operations: Advanced forecasting. EirGrid has improved system 

operations by deploying a Wind Security Assessment Tool (WSAT) in its control room. 

The involvement of system dispatchers in the WSAT development resulted in faster 

integration of the tool into the control room.
97

In the future, as Ireland’s penetration of RE increases, evaluating connections with the European 

grid will become important. As connection becomes feasible, changes will need to be made to 

the SEM.

Generally, policymakers might benefit from considering how policy goals are working together. 

For example, in Ireland, priority dispatch legislation, market systems prioritizing the most 

efficient dispatch, and production-based support payments can be in conflict with each other.

Through the SEM, Ireland has begun to address these issues; however, investors may not be 

satisfied by solutions that reduce support payments to wind generators.
98

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2012. 

Department of Communications, Energy and Natural Resources (DCENR) (2012). REFIT. 

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February 22, 2012. 

Edwards, N. (2010). Interconnection with the UK and the Role of Merchants Lines. EDF Energy. 

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DFEnergy.pdf Accessed February 7, 2012. 

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EirGrid (2009a). Executive Summary: Interconnection Economic Feasibility Report. 

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EirGrid and SONI 2010. “Executive Summary.” Accessed April 17, 2012:

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e=EN&guiLanguage=en Accessed February 7, 2012. 
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100

Appendix F. Case Study: Spain

Author: David Pérez Méndez-Castrillón, Ministry of Industry, Energy, and Tourism

Coordinated and Integrated Planning

Policy and Planning

Spain’s energy situation as well as the policies pursued in the last decades are the direct result of 

certain challenges: a high degree of energy dependence, a lack of sufficient interconnections (as 

it is almost an isolated electric system), high energy consumption per unit of gross domestic 

product, and high levels of greenhouse gas emissions (mostly due to a strong growth in 

electricity generation and to the energy demand in the transport sector). To face these challenges, 

energy policy in Spain (and in other European countries) has spun round three axes: security of 

supply, enhancement of the competitiveness of Spain’s economy and a guarantee of sustainable 

economic, and social and environmental development. 

The path followed by Spain rests on the development of policies, strategies, and instruments 

enabling progress all along the three challenges. In Spain, energy policy priorities have focused 

on market liberalization and transparency, the development of a flexible and diversified energy 

mix with adequate energy infrastructures, and the promotion of renewable energy (RE) and 

energy efficiency.

The RE energy policy proposed takes into account that Spain has one of the highest levels of 

energy dependence in Europe, and that the Iberian Peninsula makes up an electric system that is 

isolated from Europe. To this end, Spain has promoted policies enacted to support the generation 

and management of RE and has ended the regulatory and institutional barriers for developing 

RE.

The Spanish energy policy is set forth the Ministry of Industry, Energy and Tourism, with 

counseling by the Institute for Energy Diversification and Saving (IDAE)—a public business 

entity answerable to the Ministry through the Secretariat of State for Energy. The development 

of the RE sector in Spain is based on few but key issues: a proper policy; a mature business and 

industrial sector; a strong institution network; and technical support.

Implementing RE policy in Spain has been supported by: 

• Binding objectives established through energy planning that aim to set RE targets tailored 

to the renewable source potential of the country

• National renewable energy plans that were drafted to achieve these targets

• Economic regulatory framework and financing support schemes and programs that 

allocate economic incentives through a feed-in tariff system, with a view to helping 

achieve technological maturity in RE; this system has been in force for the last 30 years 

and has been subject to ongoing improvements and modifications customized to the 

breakthrough in technological development; it has helped achieve high levels of 

penetration in clean energy, with similar unit costs. 

• Technical regulatory framework that gives priority access to the electrical grid, and 

ensuring a suitable investment level in infrastructures (see “Supporting Model Grid,” 

below) 
101

• Binding planning infrastructure that has led to significant technological development, 

which has given way to an efficient operation of RE installations and their integration 

into a power system under a strict security level; the latter has involved adapting the 

operation of RE facilities to the safe operation of the electric network, and the running of 

a control center for RE (CECRE) to monitor these installations on the basis of real-time 

information availability; all of this accounts for the maximum integration of RE, in tune 

with the required level of security in the Spanish electricity system. 

• A business sector mature enough to undertake intensive investments and to be 

implemented quickly

• Institutional and technological support, provided by a strong institutional network 

leading to the development of capacity building programs; the national research,

development, and innovation support framework consists of research and development

programs and grants; besides, the establishment of technology platforms and public 

research and development infrastructures has enabled to achieve a leading position in RE;

this has also generated a major development in manufacturing and service companies and 

research centers of international prestige, such as the Center for Energy, Environment and 

Technology and the National Renewable Energy Center furthermore, 4-year national 

research and development and innovation (R&D&I) plans are programming instruments 

to define strategic actions spanning over priority sectors and technologies, including RE

technologies.

Spain is a good example of how a supportive public energy policy has helped drive technological 

advancement as well as business development by creating a mature industrial RE sector and 

allowing the integration of substantial amounts of intermittent RE in the electricity system.

Renewable Energy Plans

Implementing a comprehensive indicative energy planning (with suitable participation, 

transparency, and overall periodic revisions and follow-up) is the essential starting point for any 

consistent energy policy.

The beginning of the development of RE in Spain began shortly after the second international oil 

crisis with the enactment of Law 82/1980 on energy conservation. The Government, through the 

Center for Energy, Environment and Technology, opened the Almería Solar Platform in 1981. 

The Almería Solar Platform was the first center for solar technology research intended to show 

the technical feasibility of concentrating solar energy as a power source. 

These actions were followed by Law 54/1997 on the Electricity Sector, which deregulated the 

electric power market and made Spain the first European nation to introduce a legally binding 

renewable resource objective; 12% of the primary energy demand had to be met by 2010 using 

renewable sources. To this end, this law called for the preparation of a renewable energy 

development plan, which was approved in December 1999 as Plan 2000-2010 for the Promotion 

of Renewable Energies63. The plan analyzed the status and potential of these energies, fixed 

specific objectives for each technology and set up different measures and instruments through a 

 63 Royal Decree 436/2004; Royal Decree 2351/2004; Royal Decree 661/2007; Royal Decree Act 6/2009; Royal 

Decree Act 14/2010; Royal Decree 1614/2010. 
102

system based on strategic planning (including infrastructures), sources diversification, flexibility,

and monitoring.

When the 12% objective was seen as difficult to fulfill, Spain took further measures by 

approving the new Renewable Energy Plan 2005-201064 in 2005 as well as an action plan to 

improve energy efficiency in order to increase the speed at which renewable installations were to 

be put into service and therefore, curb the rising energy demand. The purpose of this revision 

was to maintain the 12% RE target by 2010, as well as add two additional targets, adopted within 

the European Union: 29.4% of electric power generation from renewable sources and a 5.75% 

increase in the use of biofuels for transport by 2010.

Drafting the RE plans has been a transparent and participatory process that embraced the 

autonomous communities of Spain65, the National Commission for Energy (the national 

regulatory body in Spain), the Ministries of Economy, Finance and the Environment, as well as 

manufacturers, business associations, and the public (e.g., trade unions, non-governmental 

organizations). 

The success of the national RE plans and integration of RE in Spain can be summarized in the 

following results:

• Energy Demand Coverage: At the end of 2011, RE covered 13.2% of final energy 

consumption and 33% of the total electricity production in Spain. On November 6, 2011,

Spain achieved a new record when wind power provided 59.6% of electricity demand; 

the previous peak was 54.0%. In 2010, RE covered 11.8% of final energy consumption 

and 33.3% of the total electricity production in Spain (see Figures F-1 and F-2).

Figure F-1. RE in primary energy consumption in Spain, 2010

Source: Institute for Energy Diversification and Saving

 64 Plan de Energías Renovables 2005- 2010. 

http://www.idae.es/index.php/mod.documentos/mem.descarga?file=/documentos_10359_Plan_de_Energias_Renova

bles_2005_2010_9da32b5e.pdf 65 Spain is organized by a decentralized administrative system divided into 17 Autonomous Communities, each of 

which has jurisdiction in regionally and locally policies.

Coal

6,3%

Oil

47,3%

Natural Gas

23,5%

Import - Export

-0,5%

Nuclear

12,2%

Hydro

2,8%

Wind

2,8%

Biomass and 

Waste

3,8% Biofuels

1,1%

Solar

0,8% Geothermal

0,02%

RES

11,3%

Total Primary Energy Supply in 2010: 132 Mtoe

RES share: 11.3%
103

Figure F-2. RE in electricity consumption in Spain, 2010

Source: Institute for Energy Diversification and Saving

• Security of Supply: In March 2011, and for the first time, wind produced more 

electricity than all other technologies and met 21% of the monthly demand, setting a 

monthly generation record of 4,738 GWh); such generation might meet the monthly 

consumption of a country like Portugal (Spanish Electric System Report 2011). 

• CO2 Emissions: The environmental benefits associated with RE are many. From 2005 to 

2010, electricity production from fossil fuels fell in Spain by 68.4% for coal and 26.35% 

for oil. The specific CO2 emissions by the electric sector fell by 40% in this period (from 

407 to 247 TCO2/GWh). Spain is very close to the required level to achieve the target 

allocated to Spain by the European Union (223 TCO2/GWh) (Institute for Energy 

Diversification and Saving).

• Entrepreneurial Activity: The renewable sector in Spain comprises more than 4,000 

companies of differing sizes and activities, some of which are internationally renowned 

for their operating capacity and proprietary technology production. This approach has led 

to a thriving RE industry in Spain, based on technological innovation and close 

cooperation with the public sector.

• Electricity Production Costs: Costs associated with developing RE, inclusive of 

premiums and the cost of the different support systems, involve a leverage action onto 

direct and measurable benefits deriving from RE, such as the reduction of imported fossil 

fuels, lowering of CO2 emissions, export of technology, and the creation of associated 

jobs. Additional benefits should that are more difficult to quantify include rural 

development. Renewable energy technologies are becoming cost-competitive and cost 

reductions in critical technologies such as wind and solar are set to continue.

Renewable Energy Plan 2000-2010 has been a success. Not only has it transformed Spain's 

energy model as planned, it has also helped develop an industry that has taken the lead in all the 

segments of the value chain at international level. 

Gross Electricity Consumption 2010

(year with high wind and hydro resources): 

291,903 GWh

RES share: 33,3% (29.2% after normalising 

hydro and wind productions)
104

Network Planning

The Ministry of Industry, Energy and Tourism has published on a four-year basis its official 

planning documents for the coming 10 years. These grid-planning studies are based on studies of 

load forecast and generation adequacy. Red Eléctrica de España (REE) — the TSO in Spain—

has developed planning tools to cope with the uncertainty of future RE generation in terms of 

production and location. 

• Generation Adequacy Studies in the 10-Year Horizon: High RE penetration levels 

imply that generation adequacy studies become more complicated than they are with 

fossil fuel power plants due to the intermittent nature of RE generation. Consequently, 

RE production planning requires the use of multiple scenarios. In Spain, 8,760 hours are 

simulated per year using past RE production series, which are up-scaled to the forecasted 

RE installed power. Using the forecasted demand data series, power production from 

conventional generation can be obtained and analyzed. The impact of high RE levels in 

the production required from conventional generation implies that thermal power plants 

must be able to cope with the variability of RE production. When this is not feasible, the 

TSO must rely on imports from, and exports to, neighboring systems. However, when the 

level of interconnection is not enough, as it is the case of Spain, RE curtailment will be 

the only solution. A main objective in the planning studies of the TSO in Spain is to 

propose mechanisms to minimize those RE curtailments. New pumping stations, new 

interconnections, and new fast response power plants (i.e., those using open-cycle gasturbine or OCGT technology) can be considered and evaluated.

• Grid Adequacy Studies in the 10-Year Horizon: Grid studies with high RE penetration 

are not conceptually different from those with only conventional power plants in the 

generation mix. Nevertheless, the distributed nature of RE in a country like Spain implies 

that the location of these plants is not as well-known as that of conventional power plants, 

which introduces even more uncertainties into the grid planning process. In Spain, the 

total RE installed capacity by technology is known, but its extent by region is not. To 

address this uncertainty, the TSO in Spain analyses the maximum capacity that can be 

installed on each bus and each significant electrical region of the grid, taking into account 

the potential simultaneity of RE production in different areas, identifying all significant 

potential congestion problems and selecting the best cost-benefit solutions.

Proper parallel grid planning is almost as important as setting objectives; in this sense, network 

planning in Spain aims to minimize the cutback on RE.

Enabling Larger Balancing Areas or Markets to Help Manage Variable Generation

Market integration is essential to achieving the goals of having a sustainable and secure 

electricity system with a great potential for renewables integration. The Spanish electricity 

market was merged with the Portuguese market in 2007, forming the Iberian electricity market 

(MIBEL). The internal bottleneck between Spain and Portugal is handled by splitting the market 

into Spanish and Portuguese price areas. Bilateral trading is only possible before the day-ahead 

market closes. With MIBEL, any consumer in the Iberian Peninsula can acquire electrical energy 

under a free competition regime, from any producer or retailer that acts in Portugal or Spain.

MIBEL has established a physical support platform for the Iberian regional market, supported by 

the development of transport infrastructures and the articulation of energy planning and transport 
105

networks. It also joins the legal and regulatory frameworks of the economic conditions to take 

part in MIBEL, as well as the system operational procedures. As interconnection capacities to 

neighboring countries are quite low, balancing has to occur mainly within the market area.

Moving gate closure nearer the corresponding operating period results in more accurate forecasts 

and better-performing schedules in systems with significant penetration of intermittent renewable 

sources. Various existing mechanisms help achieve shorter gate-closure terms in accordance with 

the large benefits available. Also, Spain has developed intraday markets, which help shorten the 

gate-closure period. This market design has facilitated the market integration of RE.

MIBEL largely contributes to the integration of larger amounts of intermittent renewable 

energies. It is a good example that may serve other regions in the world as a real and tested 

approach to market integration. 

Developing and Integrating Advanced Forecasting Techniques into Grid 

Operations

An important characteristic of the Spanish power system is it has dispatch priority in scheduling 

available power plants to meet system load requirements, even as RE production presents high 

levels of intermittency and uncertainty. In this context, the availability of flexible conventional 

power plants such as open cycle gas turbines or flexible combined cycle units has enabled the 

power system to respond to RE variability. 

However, the integration of RE production has also been conditioned by the particular 

characteristics of the electricity system in Spain. Isolation is one of its most relevant structural 

features. From an electric point of view, Spain has one of the lowest interconnection ratios in the 

European Union.

66 This lack of sufficient interconnection capacity has prevented the Spanish 

system from taking advantage of cross-border exchanges for the integration of RE, as crossborder exchanges enable electricity exports when the surplus of renewable production cannot be 

properly dispatched in the system, thus diminishing RE curtailments and increasing the overall 

efficiency. This means special attention must be paid to coordinating, aggregating, and 

controlling the overall production that is fed into the grid because a certain volume of non-RE 

units must also be dispatched to fulfill with security and technical constraints. That RE plants 

tend to be far more distributed and dispersed than conventional power plants complicates this 

task. 

In response to this challenge, the system operator in Spain established a control center of special 

regime, the Spanish Control Centre of Renewable Energies (CECRE), whose objective is to 

monitor and control RE production, maximizing its production while ensuring the safety of 

electrical system. CECRE was established in June 2006 as wind generation started to become a 

relevant technology in the Spanish electrical system. It is composed of an operational desk where 

an operator continuously supervises RE production.

Renewable energy control centers collect real-time information and channel to the CECRE. To 

minimize the number of points of contact dealing with the TSO, the renewable energy control 

center acts as the only real-time speaker with the TSO. The control center also manages the 

 66 The Iberian Peninsula has a very low electricity interconnection capacity compared with the rest of Europe. The 

existing interconnections between Spain and Portugal under the MIBEL framework do not facilitate the integration 

of intermittent generation produced in Spain (as Portugal is not interconnected to any other country). For this reason, 

interconnections between Spain and the rest of Europe through France are essential.
106

limitations established by set-points, and they are responsible for assuring than the nonmanageable plants comply with them.

The use of information and communication technologies has been a key factor to achieve the 

success of the control center. The great potential of information and communication technologies 

to monitor and control energy and to dematerialize physical equipment, represents both an 

immediate and long-term solution to coping with increasing world energy consumption and 

managing variable availability of renewable sources (in order to achieve an sustainable economic 

model).

These control and supervision schemes lead to improved security and effectiveness in system 

operation; they allow the substitution of permanent or long-lasting production hypothesis and 

preventive criteria for real time production control, and they thus allow higher energy production 

for the same installed capacity and a more efficient real-time operation of power plants.

Management Tool: The main tool used by CECRE’s operator to carry out these tasks is named 

GEMAS, the Spanish acronym for the maximum admissible wind generation that the power 

system can accommodate. GEMAS accesses the real-time information received in CECRE and 

uses it to determine whether the present generation scenario is admissible for the system due to 

each of the following criteria: 

• The fault ride-through capabilities of generation plants connected to the network through 

power electronics will not cause an inadmissible simultaneous disconnection of 

generation.

• Congestions that cannot be solved by reducing other types of generation do not appear, in 

either the base case or the N-1 case.

• System balance can be achieved while maintaining an appropriate level of downward 

reserves.

GEMAS was designed taking into account that the operator must be able to create, manage, and 

activate a plant rapidly as situations may arise in which returning the system to a balanced N-1 

secure state as soon as possible might be necessary. Because more than 800 wind parks are 

installed in the Spanish peninsular system, they must be as managed as automatically as possible.

The reliability of the tool is a crucial issue as the failure to deliver limitations to the RE control 

centers could result in a significant decrease of the security of supply.

Energy Forecasting tools, SIPREÓLICO and SIPRESOLAR: The SIPREÓLICO is REE’s 

internal wind prediction tool. It has been in continuous development since 2002, and its purpose 

is to generate hourly wind forecasts until hour 24 of day D+1 for each wind park connected to 

the system. These forecasts are also complied to obtain a wind forecast in each network node and 

region as well as the total wind forecast. Additionally the SIPREÓLICO generates a probabilistic 

forecast that is used to calculate the required level of running reserves and a 10-day forecast of 

the total wind energy production in the system. Its results are updated hourly. A complimentary 

tool to SIPREÓLICO allows modeling the wind power forecasts into future network scenarios in 

order to analyze and coordinate maintenance activities or to forecast the future power flows in 

the system, which depend greatly on the wind production. SIPRESOLAR is a solar forecasting 

tool that delivers hourly energy forecasts for the next 48 hours in every solar thermoelectric and 

solar photovoltaic plant installed in the system. It was recently put into service.
107

CECRE is the first national control center (Figure F-3) in the world devoted to monitoring and 

controlling RE, and it has been a key factor in maximizing RE integration while assuring the 

overall security of the electricity system. This worldwide67 pioneering renewable control center

has made it possible for more than 50% of electricity demand to be met in several hours only 

with wind energy contribution—an especially impressive feature in a country like Spain, with an 

isolated electricity system.

Figure F-3: Main Control office in CECRE

Source: Red Eléctrica Española

Supporting Model Grids

Revising codes to address concerns about variable generation (e.g., concern about frequency 

control and other disruptions to network stability) allows both hardware and procurement 

agreements to be designed in advance to support the power system, and reduces the financial 

burdens of retroactive requirements. Supporting a model grid code can serve as a guide for each 

system to evaluate changes that are needed. For these reasons, Spain has created several 

procedures to address some of the technical challenges in terms of grid security by 

accommodating RE. 

• Regulation of Access and Connection to the Network: RE technologies open the 

production market to new players, who must compete with incumbent energy producers;

as a result, objective access and connection network codes are needed to ensure the 

development of RE. In this area, REE, the Spanish TSO—an independent body from the 

companies operating in the electric sector (ownership unbundling model) that is 

responsible for granting access and connection permits to the high-voltage network, 

ranging between 230 kV and 400 kV—is noteworthy. Prohibition of access is strictly 

restricted to causes related to the system’s operation security; in case of conflict, the 

regulator is in charge of solving it. 

 67 International Energy Agency (IEA). “Energy Policies of IEA Countries – Spain. 2009”.

http://www.iea.org/textbase/nppdf/free/2009/spain2009.pdf.
108

• Technical Operation: As participation of RE technologies in the generation mix

increases, technical requirements in the electric system operation must be strengthened. 

In Spain, requirements with respect to reactive power control and responses to voltage 

dips in the network were first required of conventional generation facilities, then more 

recently of the wind, and finally of the largest photovoltaic installations. To prevent 

possible loss in cascade of wind generation, a procedure for responding to voltage dips 

was approved in 2006; in 2010, this obligation was extended to photovoltaic installations 

of more than 2 MW; related to a range of reactive power control, a range of power factor 

is established for RE with penalties in case of no compliance. 

• Operation Security of the Electricity System: RE power plants with installed capacities

greater than 1 MW must provide real-time telemetry each 12 seconds to REE, and 

voltage control (or power factor control) following the orders of the TSO. The regulation 

also requires non-manageable RE generation to be connected to a generation control 

center and receive set-points from the TSO.

Red Eléctrica de España, which was created in the 1980s, has been important in providing 

access and connection to the network and guaranteeing third-party access to the grid under equal 

conditions.

Conclusions

After the successes of 2000-2010 in Spain, RE is no longer a minority element in the system but 

rather is one of its basic components. Spain is ready to comply with European commitments and 

go beyond its frontiers to cooperate in the deployment of clean energies. 

Having achieved a mature, qualified sector that can compete in domestic and international 

markets, energy policy in Spain is ready to ensure the most effective and optimal integration of 

renewable generation into the electricity system, and it is helping reduce emissions and increase 

energy independence.

To achieve a mature, qualified, and competitive RE sector, economic systems must be 

established to promote the cost reduction and competitiveness of RE technologies while boosting

distributed generation and consumption. For example, the Spanish Government is developing a 

regulation for deploying a net-metering68 system that will allow restraining energy demand on 

the system; this represent a re-focusing both generation and demand management rather than just 

generation.

Having supported deployment of the RE sector for nearly 25 years, Spain now has a mature, 

competitive RE sector. In fact, Spain is the leading thermal electric producer in the world; the 

third largest mini-hydroelectric power producer in Europe; the second largest installed-capacity 

wind-energy power in Europe and the fourth worldwide; and the second largest installedcapacity photovoltaic power both in Europe and in the world.

In short, Spain’s success with RE penetration has featured:

• Early promotion of RE, which helped win the race toward mature technology 

 68 Net-metering consists of an electricity balance system for renewable electric power to facilitate distributed 

generation for self-consumption from RE sources. The main objective of net-metering is that end users only pay for 

the energy they really consume
109

• Massive integration of renewable electricity into the grid under strictly controlled 

conditions, in an almost completely isolated country

• An essential role played by skillfully using information and communication technologies

and the latest technology, such as CECRE, which the Spanish system operator created

• Economic regulation through a feed-in tariff system, acting as a lever for investments

• Smart technical regulation that prioritizes RE access to the electricity grid

• Adequate investment in research and development activities

• Long-term transmission network planning and comprehensive coordination between the 

various administrations

• Development of a mature industrial sector

• Close institutional cooperation and development of capacity building programs

References

[IDAE] Institute for Energy Diversification and Saving. (2011). “Employment Associated with 

the Promotion of Renewable Energies.” Madrid: IDAE. Last accessed April 16, 2012: 

http://www.idae.es/index.php/mod.documentos/mem.descarga?file=/documentos_11227_e5_em

pleo_A_08df7cbc.pdf.

Spanish Electric System Report. (2011). Accessed April 16, 2012: http://www.ree.es/

sistema_electrico/pdf/infosis/Avance_REE_2011.pdf. 
110

Appendix G. Case Study: United States—Western Region (Colorado 

and Texas)

Author: Jenny Heeter, National Renewable Energy Laboratory (NREL)

Introduction 

Variable renewable energy generation strains grid operations; however, mechanisms exist to 

accommodate high penetrations of renewable energy. To date, regional experience in the United 

States has highlighted best practices in accommodating high penetrations of variable renewable 

energy (RE), but further action will be needed as RE penetrations increase nationwide.

Renewable energy generation in the United States is expected to increase by approximately 110 

million megawatt-hours (MWh) through 2020. The U.S. Energy Information Administration 

(EIA) forecasts that 250 million MWh of non-hydropower RE will be generated by the electric 

power sector in 2020 in the United States, compared to the nearly 140 million MWh that were 

generated in 2010 (EIA 2012).

69 However, the level of renewable penetration varies greatly 

regionally. This case study presents experience from Colorado, where renewable energy 

accounted for 7.0% of total generation in 2010, and Texas, where wind generation alone

represented 7.8% of total generation in 2010. (DOE 2011)

This case study highlights experience in two U.S. markets: the western United States (with 

emphasis on Colorado), and Texas. These jurisdictions provide examples of both deregulated 

markets (Texas) and traditionally regulated markets (Colorado). Examining these markets sheds 

light on four key actions described in the synthesis report. 

Following a background section describing the renewable and regulatory landscapes in the 

western United States and Texas, this appendix presents information on the following specific 

measures to accommodate high penetration of variable RE:

1. Coordinate and integrate planning

2. Lead public engagement, including facilitating new transmission

3. Develop rules for market evolution that enable system flexibility

4. Expand access to diverse resources

5. Improve system operations

 69 Based on EIA’s Annual Energy Outlook 2012 Early Release reference case, which generally assumes current laws 

and regulations but does not take into account potential future laws and regulations.
111

Table G-1 describes market structure, grid operation, and current renewable penetration in Texas 

and Colorado.

Table G-1. Key Aspects of Texas and Colorado Related to Renewable Integration

Texas Colorado

Deregulated market Regulated market

Few imports/exports Few imports/exports

Small system Part of large grid, but little balancing occurs

High level of penetration Medium level of penetration

Background

Texas and Colorado have seen high levels of RE penetration, and they project additional RE to 

come online in future years. In Texas, data on wind generation are available from the Electric 

Reliability Council of Texas (ERCOT), which covers 85% of the state’s load. Wind generation in 

ERCOT has grown from approximately 2.3 million MWh annually in 2002 to 24.7 million MWh 

in 2010. On a capacity basis, wind energy in ERCOT represented less than 2% of total energy 

through the mid 2000s. In 2010, monthly generation from wind reached more than 12% of total 

energy in ERCOT in April and November (Figure G-1). 

Figure G-1. Percentage of energy from wind in ERCOT, monthly, 2002–2010

Source data from ERCOT (2011)

In Colorado, Xcel Energy, the state’s major investor owned utility, announced that on October 6, 

2011, 55.6% of the electricity consumed in its service territory in Colorado came from wind. 

(Jaffe 2011) 

This case study highlights how increasing penetrations of RE have been accommodated under 

two different electric market structures. In Texas, markets are deregulated, while in the western 

United States and Colorado, markets are regulated at the state and federal levels. Deregulation in 

Texas began in 1995, when the Public Utility Commission of Texas required non-discriminatory 

access to the transmission network. Because ERCOT’s grid does not cross state boundaries, it is 

not subject to regulation by the Federal Energy Regulatory Commission (FERC). Colorado, on 

the other hand, has a traditionally regulated market. Investor-owned utilities (IOUs) in the state 

are subject to oversight by the Colorado Public Utilities Commission. IOUs in the state are fully 

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

Jan-02

Jul-02

Jan-03

Jul-03

Jan-04

Jul-04

Jan-05

Jul-05

Jan-06

Jul-06

Jan-07

Jul-07

Jan-08

Jul-08

Jan-09

Jul-09

Jan-10

Jul-10

Percent of energy 

from wind, monthly
112

integrated, supplying generation, transmission, and distribution to customers. Transmission 

activities that cross Colorado state boundaries are subject to FERC regulation. 

Five Areas of Intervention to Accommodate High RE Penetration

This section discusses how regions in the United States have sought to coordinate and integrate 

planning, lead public engagement including facilitating new transmission, develop rules for 

market evolution that enable system flexibility, expand access to diverse resources, and improve 

system operations. Each topic area highlights a specific approach taken by key stakeholders to 

address the high penetration of variable RE.

1. Coordinate and Integrate Planning: Creation of the Competitive Renewable 

Energy Zone (CREZ) Process

Competitive renewable energy zones (CREZ) in Texas highlight the importance of aligning 

timescales of generation and transmission. Texas’ advanced planning efforts helped foster 

development of wind in the state. Originally, wind developers identified the need for new 

transmission as an issue after heavy development in the McCamey area. The McCamey area had 

excellent wind resource, but it was served by weak transmission. In 2002, 758 MW of wind were 

interconnected to a substation with only 400 MW of transmission (Sioshansi and Hurlbut 2010). 

Wind developers began developing in other parts of the state and went to the state legislature to 

seek a solution.

Table G-2 compares expected future renewable energy development in Texas and Colorado.

Table G-2. Future Renewable Energy Development in Texas and Colorado

Texas Colorado

Renewable portfolio standard obligation Renewable portfolio standard obligation

2015 target of 5,880 MW already achieved 2020 target of 30% retail sales (IOUs) 2020

Goal of 10,000 MW Estimated to be ~2,700 MW in 2020

Additional low-cost wind likely to come online

To get transmission built, stakeholders identified two primary solutions: 1) delegate authority to 

a centralized institution to implement transmission planning and 2) align planning timescales for 

generation and transmission. A key component to aligning planning timescales for generation 

and transmission was the need for transmission developers to receive cost recovery assurance. 

The approach surfaces in multiple avenues. The Public Utilities Commission of Texas (PUCT)

identified the need for a CREZ approach but lacked the legal authority to implement the solution. 

They obtained this new legal authority through legislation. Key stakeholders included the PUCT, 

the state legislature, large industrial customers, wind developers, lobbyists and non-wind 

generators. Wind developers and their lobbyists advocated for a new process, while large 

industrial customers and non-wind generators resisted modifications because of cost. Stakeholder 

dialogue was important to identifying the need for a new process.

Ultimately, in 2005, the Texas legislature passed Senate Bill 20, establishing Texas’s renewable 

energy program and directing the PUCT to develop CREZs. The PUCT designated zones in 

2008, and a number of transmission projects were selected to transmit wind power from the 

CREZs to the eastern, more populated area of the state. The transmission projects are expected to 

transmit approximately 18,500 MW of wind (PUCT 2011). 
113

A key factor in the success of the CREZ process is the alignment of planning timescales for 

generation and transmission. Senate Bill 20 guaranteed that transmission lines did not need to 

receive a “used and useful designation” before being built and that transmission costs would be

absorbed by all ratepayers (spread over the whole load). As a result, transmission development 

could begin before wind generation, allowing transmission to be available for future wind 

development. 

No other approaches were considered; however, as the PUCT implemented the CREZ approach, 

there were discussions about the level of wind generation for which the CREZ process should 

plan. It was ultimately determined that the CREZ process would support approximately 18,500 

MW of wind development. CREZ transmission projects are expected to be complete by year-end 

2013.

The success of the CREZ process can be evaluated by considering the extent to which generation 

and transmission-planning timescales have been aligned. To date, more transmission capacity 

has been built than is being used by wind generation; however, the lack of wind development is 

due to many factors, including decreases in natural gas prices and an expected expiration of the 

federal production tax credit.

Because the CREZ process was a new, unique development in Texas, lessons have been learned. 

Other countries or regions seeking to replicate this model should seek to build transmission “justin-time” for wind development; if transmission is developed too quickly, ratepayers might lose 

support specifically for underutilized lines or generally for transmission development. A second 

challenge in the CREZ process is the planning horizon. Although transmission planning requires 

long planning horizons, as they become longer, more assumptions need to be made. Finally, 

ERCOT has seen that it is now spending resources to solve technical issues that industry 

traditionally solved. For example, ERCOT is analyzing sub-synchronous interactions from 

series-compensated transmission lines on power electronics-based devices, such as wind 

turbines, and is investigating the implications of operating large amounts of power electronics 

devices in areas with weak grids (Lasher 2012).

2. Lead Public Engagement, including Facilitating New Transmission

The CREZ process exemplifies a quick method for gathering public input into transmission 

siting. The law implementing CREZ in Texas specified that the PUCT must issue a final decision 

on an application for new transmission line serving a CREZ in six months. The transmission 

developer must propose alternative routes to the PUCT and host public meetings; the PUCT 

ultimately decides which route to approve. 

In a state such as Texas where land is primarily owned by private individuals, public input into 

route siting is important. The PUCT specifies that at least one public meeting must be held if 25 

or more people live within 300 feet of the centerline of a transmission project 230 or fewer kV, 

or within 500 feet of the centerline of a project greater than 230 kV. For many CREZ line 

proposals, multiple public meetings are held. 

The format for the public meeting is also important. Utilities in Texas found that input was 

gathered more effectively using an open house format in which several stations staffed with 

experts were set up around a room than with a general question and answer session. In Texas, the 

open house format gave private property owners an opportunity to learn about proposed routes, 

engineering designs, environmental concerns, and other issues, and allowed them to provide 
114

feedback on proposals through a multipage questionnaire and by interacting with staff. The open 

house format gave private property owners an opportunity to identify sensitive areas (e.g., 

private landing strips and cemeteries) not in the public records and suggest modifications. This 

interaction created a learning opportunity for transmission developers. 

With 3,000 miles of new CREZ transmission lines planned, certainly not every landowner would 

be satisfied with the final route selection, but everyone was given an opportunity to provide 

input. Landowners were able to become formal parties to transmission cases at the PUCT 

(“intervene”) or to file comments in either support of or opposition to a proposed line (“protest”). 

In one contentious case, more than 10,000 landowners intervened in a proposal for a new 

transmission line of fewer than 200 miles that ran through scenic hill country. Landowners in the 

region, many of whom were wealthy and politically connected, objected to the degradation of 

their land. Open houses for this line drew more than 3,400 people, and ultimately the PUCT 

approved a route following an interstate highway and required the use of monopoles near cities 

along the route (Doan 2011). 

The public outreach process in CREZ was expedited in part because the need for the lines was 

not allowed as an issue of intervention. Therefore, the public component was focused on where

the lines were to be built. Through legislative mandate, the line approval was accelerated to six 

months, but public open house style meetings provided the PUCT with evidence from public 

landowners to make a decision on route siting. 

3. Develop Rules for Market Evolution that Enable System Flexibility: Use of 

Demand Resources in Texas

Allowing demand resources to provide ancillary services can increase the flexibility of the grid. 

When the Texas market was restructured in 2002, stakeholders were looking for a way to 

continue to allow demand customers to participate in providing services. Previously, demand 

customers were operating on interruptible tariffs, but those tariffs were canceled due to 

restructuring of the market. Due to the large amount of industrial load in Texas, demand 

resources are plentiful, because industrial loads have large demand that may be flexible. 

ERCOT procures 2,300 MW of responsive reserves, though load participation is capped at 1,150 

MW. ERCOT is considered a leader in allowing demand response to participate in the ancillary 

services market, and it has been cited as being “as successful as any market in the integration of 

interruptible loads into markets for ancillary services” (Zarnikau 2010, p. 1537). 

In a February 2008 event, the successful use of demand response—then termed Load Acting as a 

Resource (LaaR)—was apparent when a net load event70 occurred. Within 10 minutes of the 

event, demand response supplied 1,108 MW; within 12 minutes, it supplied 1,200 MW (Figure 

G-2 and Ela and Kirby 2008). According to ERCOT (2008), “It appears to be the deployment of 

LaaRs which halted frequency decline and restored ERCOT to stable operation.”

 70 A “net load” event occurs when a gap grows between available supply and current demand.
115

Figure G-2. ERCOT load acting as a resource responsive reserve deployment, February 26, 2008 

Source: ERCOT 2008

The under-frequency relay response provides near-instantaneous response, such that when a 

large drop in capacity occurs, the grid recovers in less than one second in many cases (Wattles 

2011). Since 2006, demand response has been deployed 21 times (Wattles 2011). 

4. Expand Access to Diverse Resources: Proposal for an Energy Imbalance 

Market in the Western United States 

The design of electricity markets impacts the ability of systems to integrate high penetrations of 

variable RE. An energy imbalance market (EIM), currently proposed in the western United 

States, would re-dispatch energy on a regional, least-cost basis, with “energy imbalance” defined 

as the difference between actual and scheduled production and use. An EIM provides a number 

of benefits, including 1) reduced need for balancing reserves, resulting in operational cost 

savings and 2) decreased risk of one particular balancing authority depleting balancing reserves 

(Mariner 2011). Creating a larger geographic footprint would spread the variability of the wind 

across a larger area because variability declines when spread over a larger system. In addition, 

the creation of faster markets using EIMs could lower integration costs; In the United States, 

ISOs and RTOs that typically operate in sub-hourly markets see lower costs than do many nonISOs or non-RTOs, which schedule on an hourly basis (DeCesaro and Porter 2009).

71

 71 Benefits of balancing area cooperation are further addressed in the Western Wind and Solar Integration Study. 
116

The Western Energy Coordinating Council (WECC) helped develop a high-level design 

specification and evaluate the EIM proposal,72 but WECC is neutral as to the development 

decision or the organizational identity of the EIM market operator.73 Ultimately, the regulated 

utilities will need approval from state PUC regulators to address cost recovery for the EIM 

development.

Utilities have been involved with the development of the EIM; however, perspectives vary 

depending on the regulatory exposure of the utility, the level of RE penetration, and the current 

cost of energy. Generally, small public utilities served entirely or partially through a wholesale 

allocation from the federal power marketing administrations have resisted supporting an EIM 

more than large investor-owned utilities. This is possibly because many large investor-owned 

utilities have renewable portfolio obligations and are directly paying the cost of inefficient 

markets. 

The development of an EIM has required stakeholder dialogue, primarily to educate stakeholders 

about the effort. In addition, education has provided information to relieve fears about market 

development and FERC jurisdiction. Some utilities were concerned that expanding the wholesale 

market would subject them to additional regulation. In the United States, FERC has jurisdiction 

over interstate transmission and wholesale energy transactions in interstate commerce. FERC has 

tried to give reassurance that an EIM would not alter the fundamental regulated (or nonregulated) nature of wholesale market participants, but some small non-jurisdictional utilities 

remain uneasy.

Cost represents another concern about developing an EIM. A study by WECC attempted to 

calculate the costs of developing an EIM, but the calculated range was too large to allow for a 

meaningful comparison relative to benefits (Ravenscroft 2012). Southwest Power Pool and 

CAISO (California ISO) are developing new cost estimates at the request of state public utility 

commissions in the Western Interconnection, based on a strawman market design that 

stakeholders developed. An analysis of the benefits to individual balancing areas is also being 

developed by the National Renewable Energy Laboratory (NREL).

Another approach that could be considered is a full locational marginal pricing (LMP) market.

Southwest Power Pool has an EIM and is moving toward a full LMP market, but that was not 

seriously considered for the western United States. Given the operating culture and jurisdictional 

concerns in the western United States, getting people on board with an EIM should be easier than

it is with a full-blown RTO.

If an EIM is adopted in the western United States, its success will need to be evaluated. A new 

group, the Public Utility Commissions EIM Group, which has representatives from 12 western 

states, hosted three webinars in February 2012, in preparation for an in-person meeting in May 

2012. Not all PUC members are supportive of an EIM, though a few state commissioners have 

expressed interest. Although such results are anticipated, whether an EIM in the western United 

States would lower costs for RE integration remains to be seen.

An EIM could be implemented in other countries. Much like multiple states negotiating on a 

voluntary basis, multiple countries or regions could develop an EIM to link jurisdictions. An 

 72 In addition, the Department of Energy provided some funding for technical work. 73 WECC’s purpose is to ensure federal reliability standards, not to address market and cost recovery issues, which 

complicates the development of an EIM.
117

EIM may be most appropriate when trying to link regions without creating a full LMP market. 

When taking this action, other countries or jurisdictions would want to ensure there is support

from regulators early in the process. 

5. Improve System Operations: Development and Integration of Advanced 

Forecasting Techniques into Grid Operations

Developing advanced forecasting techniques and integrating them into grid operations can 

reduce the amount of system flexibility needed to integrate variable RE generation. In Texas, the 

specific need to integrate advanced forecasting into grid operations was highlighted during the 

net load event in February 2008.

It is important to note that forecasting ability in Texas was delegated to ERCOT after the PUCT 

identified that gaming was occurring by generators; some wind generators realized they could 

receive payments for backing down generation when transmission systems were congested 

(Zarnikau 2011). However, forecasting services were not integrated into ERCOT’s operations 

immediately. In February 2008, ERCOT called for an Emergency Electric Curtailment Plan due 

to an imbalance of generation and load. One component in the imbalance was the assessment of 

wind power availability; other contributors included the unexpected loss of conventional 

generation and the quicker-than-expected evening load ramp up (Ela and Kirby 2008). At the 

time, ERCOT was procuring forecast services that very accurately predicted wind power;

however, the wind forecast had not yet been integrated into ERCOT’s system (Ela and Kirby 

2008). The 2008 event prompted faster integration of the contracted forecasting service.

ERCOT improved forecasting methods by upgrading to a more advanced wind-forecasting 

model. In 2010, the ERCOT Large Ramp Alert System was implemented. ERCOT and AWS 

Truewind, a third party forecast developer,74 designed the tool to help prepare for large and 

sudden changes in wind production, like those that occurred in the February 2008 event.

Qualified scheduling entities are required to use the ERCOT day-ahead wind forecast for the first

48 hours of their current operating plans; consequently, the forecast is used in both day-ahead 

and hour-ahead reliability unit commitment studies. Qualified scheduling entities can provide 

lower values to adjust for any unreported availability, but ERCOT monitors this activity to 

ensure the best forecast is used (D’Annunzio 2012).

In Colorado, a slightly different approach was taken. The state’s largest utility, Xcel Energy, 

began working with the National Center for Atmospheric Research (NCAR), a federally funded 

research and development center, in 2008 to improve forecasting. The resulting forecasting 

system provides rolling 15-minute interval forecasts 3 hours into the future and hourly interval 

forecasts for the remainder of a 168-hour interval. The forecasting tool produces forecasts that 

are 35% better than those produced by former methods. In 2010 alone, the new forecasting 

system was estimated to save Xcel Energy $6 million (Snider 2011). The technology transfer 

company for NCAR, Global Weather Corporation (GWC), has contracted with Xcel Energy to 

provide forecasting services, and GWC markets the system to other interested parties. Key 

stakeholders in Colorado were a utility (Xcel Energy) and the federally funded research and 

development center (NCAR). 

 74 See Porter and Rogers (2010). AWS Truewind provides numerical weather model data and statistical prediction 

procedures to ERCOT.
118

Benefits of developing and integrating advanced forecasting can be seen in both Texas and 

Colorado. Both states considered the reliability benefits of advanced forecasting as well as the 

resulting cost savings from improved forecasting. To realize the benefits of advanced 

forecasting, other countries should ensure that new systems are fully integrated into grid 

operations; if grid operators cannot access advanced forecasts, they will be of little use to grid 

operations.

Replication of Efforts by Other Countries

Texas has been compared to both the United Kingdom and Australia due to its isolated nature. 

Because the grid in Texas is primarily isolated, it is not regulated at the federal level unlike other 

areas in the United States. Actions in Texas could be mimicked by other nations.

The western market in the United States is composed of many states, and regional market 

development is often similar to countries having to negotiate with each other. Because there is no 

central RTO in the western United States, any market changes must be made on a consensus 

basis. The role of an energy minister in such cases would be to develop diplomatic measures and 

aid in negotiating consensual frameworks. Regional collaboration can be essential, as some 

policies may not be of importance to all but would benefit regions overall. 

Summary and Conclusions 

Regional experience in the United States has highlighted best practices in accommodating high 

penetrations of variable RE. Specific measures taken in Texas, Colorado, and the western United 

States include: 

1. Coordinate and integrate planning: Creation of the competitive renewable energy 

zone (CREZ) process. After heavy wind development occurred in an area served by 

weak transmission, stakeholders developed the CREZ process to centralize transmission 

planning and align planning timescales for generation and transmission. It is important to 

note that ratepayers absorb all transmission costs without needing a “used and useful 

designation” by the PUCT. The process has been successful in developing transmission;

however, other countries developing transmission “just-in-time” for wind development 

should note that if transmission is developed too quickly, ratepayers might lose support 

for the underutilized lines specifically or transmission development generally.

2. Lead public engagement, including facilitating new transmission. The CREZ process 

established an accelerated time schedule for approving new transmission lines. Texas has 

requirements for public meetings, and transmission developers found that open houses 

were more effective at gaining feedback into siting proposals than were traditional 

question and answer sessions. In addition to participating in open houses, landowners can 

formally intervene in cases at the PUCT or provide comments in support of, or opposition 

to, proposed transmission lines. 

3. Develop rules for market evolution that enable system flexibility: Use of demand 

resources in Texas. After transitioning to a restructured market in 2002, stakeholders 

sought ways to continue to allow demand customers to participate in providing grid 

services. Because of the large amount of industrial load in Texas, demand resources are 

plentiful, as industrial loads have large demand that may be flexible. A Load Acting as a 

Resource (LaaRs) program was developed and successfully used during the February 
119

2008 net load event, when demand resources were able to supply 1,200 MW within 12 

minutes. 

4. Expand access to diverse resources: Proposal for an energy imbalance market in the 

western United States. An energy imbalance market (EIM), proposed in the western 

United States, would re-dispatch energy on a regional, least-cost basis, with “energy 

imbalance” defined as the difference between actual and scheduled production and use. 

Extensive stakeholder dialogue to educate stakeholders is occurring. WECC has 

facilitated initial discussions on developing the EIM, but the market development 

proposal might occur outside WECC and will include approval from state PUC 

commissioners. The Public Utility Commissions EIM Group is preparing stakeholders for 

a meeting in May 2012, by developing a strawman market design and coordinating 

studies of market costs and benefits.

5. Improve system operations: Development and integration of advanced forecasting 

techniques into grid operations. In Texas, the specific need to integrate advanced 

forecasting into grid operations was highlighted during a net load event in February 2008. 

New forecasting services have been contracted but not integrated into ERCOT’s 

operations. The 2008 event prompted quicker integration of the contracted forecasting 

service. In 2010, ERCOT implemented an additional tool, the ERCOT Large Ramp Alert 

System, developed by AWS Truewind and ERCOT.

In Colorado, Xcel Energy began working with NCAR in 2008 to improve forecasting. 

The new forecasting system provides 15-minute interval forecasts 120 hours into the 

future and produces forecasts that are 35% better. In 2010 alone, the new forecasting 

system was estimated to save Xcel $6 million (Snider 2011).
120

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Appendix H. Summary of Stakeholder Feedback

This appendix summarizes feedback from five stakeholder events to present results of this 

analysis.

World Future Energy Summit (WFES). Abu Dhabi (January 17, 2012)

1. Approximately 20 participants—mainly from technical institutes, governments, and 

international agencies—attended.

2. The value of this analysis of policy lessons and messages for ministers and their staff on 

high RE penetration was strongly endorsed.

3. Recommendations for enhancements to the analysis included:

o Address some of the key higher-level questions that governments have about high RE 

penetration (e.g., at what level can the grid easily accommodate RE, what is the cost 

of integrating intermittent resources)

o Develop concise and simple messages on these questions and the opportunity for 

increased RE use

o Cover all RE technologies, not just wind; especially need to explain the issues 

associated with higher levels of solar integration

o Dissect the role of feed-in tariffs versus feed in premiums

o Conduct more analysis of the role of storage (e.g., when and where in the system it is 

most needed, how to integrate it, what are the trends)

o Identify effective approaches for public education about the value and opportunity for 

increased RE use and the potential for scale up and how to overcome public 

resistance

o Include lessons from smaller–scale, isolated or mini grids and implications for 

smaller countries; highlight key lessons from very high level of RE penetration in 

some islands and elsewhere

o Describe interactions with natural gas and approaches to allow plans to incorporate 

gas and RE

o Share best available information on the costs of intermittency

o Examine policy roles at three levels of integration: grid, markets, and systems

o Evaluate and describe interplay with energy efficiency and demand response

o Make available the case studies for review and feedback

o Consider developing improved tools to simulate impacts of high RE penetration and 

optimize system design (could be an open source competition)
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Paris (January 25, 2012) and Davos (January 28, 2012)

All stakeholders were very complimentary of the work, and they believed it is valuable and 

important to both deliver key messages to the energy ministers at the third Clean Energy 

Ministerial (CEM) and to continue the work. Stakeholders strongly agreed the ministers should 

take a critical leadership role in engaging in a robust public process. Other suggested key 

messages included the following: some of the draft eight categories are overlapping, and 

oversimplification may be misleading but the interrelationships among key action areas are 

important; and the case studies offer considerable value. Some stakeholders recommended 

narrowing to the number of key actions from five to three such as

1. Commission comprehensive assessment of current technical, institutional, human capital 

and market status

2. Conduct visionary studies of high or higher RE penetration, including all the elements 

identified.

3. Invest in capacity building and institutional formation and learning through international 

partnerships for planning, analysis, market operations, regulation, among others

Additional suggestions included a systems solution, crosscutting initiative at the CEM-level and 

perhaps a larger international partnership on integrating renewable energy, including linkages 

with IEA, REN21, International Renewable Energy Agency, and others. Participants at the 

Davos meeting from China, India, South Africa, and the United Kingdom were uniformly 

complimentary of the work, and they emphasized the importance of ministers leading a robust 

public process and they uniformly supported an ongoing high-level international effort to share 

best practices. They suggested a strong linkage to Sustainable Energy for All75 was possible.

New Delhi (CEM-3 Prep Meeting) February 1, 2012 

Approximately 30 participants from CEM countries, international organizations, the private 

sector, and technical institutes participated in a roundtable dialogue on the analysis of policy best 

practices and lessons with measures for achieving high RE penetration in electricity systems. 

This included representatives from Australia, Brazil, Denmark, Finland, Germany, India, Spain, 

United Arab Emirates, United Kingdom, United States, IEA, International Renewable Energy 

Agency, NREL, and Brookhaven National Laboratory. The results of case studies of policies for 

high RE integration for Australia, Denmark, Germany, Ireland, Spain, and the United States were 

presented along with initial recommendations for actions that governments could take to further 

deepen RE penetration.

 75 For more information, see http://www.sustainableenergyforall.org/. 
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Comments and Recommendations from the Participants

Framing of Recommended Actions and Case Studies

• Present recommendations for action by governments, the private sector, and system 

operators 

• Describe how actions contribute to issues of greatest concern to Ministers (e.g., 

energy security, economic development). It will be especially important to identify 

how these actions can help enhance energy security. 

• Additional recommended actions should be provided at higher levels of penetration 

with this effort seeking to identify how leading countries can be even more ambitious 

in deepening renewable energy deployment

• Need to clarify what is meant by the low, medium, and high levels of penetration in 

the summary table

• Highlight the value and need for comprehensive and integrated approaches (e.g., 

goals and action plans, intergovernmental coordination, public-private collaboration, 

monitoring and evaluation). Such comprehensive approaches have been instrumental 

to success by the leading countries. The report should also present case studies of 

these integrated approaches for countries such as Spain, Denmark, and Germany.

Specific Comments on Proposed Actions

• Highlight also the need for transparency on electricity pricing for Independent Power 

Producers

• Along with establishment of goals and action plans, the report should also note that 

governments also need to clearly define who has authority for each of the key actions. 

• Describe the role for priming markets with subsidies that are then phased out in a 

transparent and timely manner

• Note the need for policies to be designed to be flexible to changes in prices and other 

market conditions

• Highlight the role of governments in partnering with the private sector to advance 

development and demonstrate of key technologies and tools (e.g., storage, 

forecasting)

Recommendations and Interests in on Ongoing Collaboration

• The CEM could help facilitate professional exchanges between countries (e.g., study 

tours), including exchanges for system operators and for policy officials. Denmark, 

Spain, and Germany already host many visitors and would be glad to further expand 

such peer learning. Australia also offered to share their experiences through such 

exchanges. 

• This effort could also establish networks of different types of actors (e.g., system 

operators, forecasters, grid code officials, private sector developers and suppliers) to 
125

share experiences and foster peer learning and also to inform policy officials of what 

types of actions are needed by governments.

• On-going collaboration will be most effective if ministers at third CEM meeting 

provide a clear mandate and communicate this to their key stakeholders 

• The government of Brazil would be glad to share experiences in Brazil with scaling 

up of wind generation and also would like to learn from others on how to manage 

higher levels of wind integration

• India is particularly interested in learning about effective approaches for development 

of transmission infrastructure and for integration of high levels of wind generation in 

the grid

• It is important to further define how this effort can be closely integrated with other 

CEM initiatives and related international projects on this topic and to develop a well 

structured collaborative framework that builds on these on-going activities. This 

includes for example further dialogue across Clean Energy Solution Center, 

International Smart Grid Action Network, and the Multilateral Solar and Wind 

Working Group on a collaborative approach. 

• This effort currently has a very broad scope. Any collaborative work proposed to 

continue after the third CEM meeting should have a well-defined scope and priority 

set of specific activities (e.g., initial activities on priority topics of common interest, 

which could then be expanded as appropriate in future years). 

Structure of Dialogue at the third CEM Meeting

• Need to consider whether the dialogue should request a specific mandate from 

ministers and if the recommendation will be an on-going collaborative project across 

current initiatives or a new initiative on this topic. Several at this meeting expressed a 

preference for a collaborative project rather than another new initiative. 

• In addition to a summary of the overall results, it would be helpful to have a couple 

leading countries provide very brief remarks (e.g., 2–3 minutes) each highlighting the 

most important success factors in their cases with high RE penetration.

• India expressed interest in sharing their experiences at the third CEM meeting with 

rapid ramp up of solar generation.

Comments on Other Issues

• The report should further describe key barriers to high RE penetration.

• The figure given for 30% of electricity generated from RE in Spain is incorrect and 

the source used for this figure is not reliable.
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Washington, DC March 5, 2012 

NREL convened a stakeholder forum on March 5 with the Department of Energy, International 

Energy Agency, Center for Strategic and International Studies, and World Economic Forum in 

support of the Clean Energy Ministerial High Penetration of Variable Renewable Energy 

analysis. The forum highlighted key lessons from the case study analysis on effective policies, 

regulatory programs, and market designs that countries can use to increase the penetration of 

variable RE into the power sector. Participants were supportive of the analysis and 

recommendations and voiced support for ongoing CEM led activities in the area of system level 

solutions.