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Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

Technical Report

NREL/TP-6A20-72578

January 2019

An Introduction to Grid Services: 

Concepts, Technical Requirements, 

and Provision from Wind

Paul Denholm, Yinong Sun, and Trieu Mai

National Renewable Energy Laboratory
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Technical Report

NREL/TP-6A20-72578

January 2019

An Introduction to Grid Services:

Concepts, Technical Requirements, 

and Provision from Wind

Paul Denholm, Yinong Sun, and Trieu Mai 

National Renewable Energy Laboratory

Suggested Citation 

Denholm, Paul, Yinong Sun, and Trieu Mai. 2019. An Introduction to Grid Services: 

Concepts, Technical Requirements, and Provision from Wind. Golden, CO: National

Renewable Energy Laboratory. NREL/TP-6A20-72578. 

https://www.nrel.gov/docs/fy19osti/72578.pdf.
NOTICE

This work was authored by the National Renewable Energy Laboratory, operated by Alliance for Sustainable 

Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. Funding 

provided by the U.S. Department of Energy Office of Energy Efficiency and Renewable Energy Wind Energy 

Technologies Office. The views expressed herein do not necessarily represent the views of the DOE or the U.S. 

Government.

This report is available at no cost from the National Renewable 

Energy Laboratory (NREL) at www.nrel.gov/publications.

U.S. Department of Energy (DOE) reports produced after 1991 

and a growing number of pre-1991 documents are available 

free via www.OSTI.gov.

Cover Photos by Dennis Schroeder: (clockwise, left to right) NREL 51934, NREL 45897, NREL 42160, NREL 45891, NREL 48097, 

NREL 46526.

NREL prints on paper that contains recycled content.
iii

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Acknowledgments

The authors would like to thank the following individuals for their contributions. Editing and 

graphics support were provided by Al Hicks, Devonie McCamey, and Katie Wensuc. Helpful 

review and comments were provided by Sam Baldwin, Philipp Beiter, Dan Bilello, Aaron 

Bloom, Alex Breckel, Paul Donohoo-Vallett, Vahan Gevorgian, Patrick Gilman, Debbie Lew, 

Brian Palmintier, and Rich Tusing. 

Finally, we gratefully acknowledge funding for this work from the Wind Energy Technologies 

Office (WETO) of the U.S. Department of Energy (DOE) Office of Energy Efficiency and 

Renewable Energy. We especially thank Patrick Gilman of DOE for his support. This work was 

authored by the National Renewable Energy Laboratory, operated by Alliance for Sustainable 

Energy, LLC, for the U.S. Department of Energy under Contract No. DE-AC36-08GO28308. 

The views expressed in the article do not necessarily represent the views of the DOE or the U.S. 

Government. The U.S. Government retains a nonexclusive, paid-up, irrevocable, worldwide 

license to publish or reproduce the published form of this work, or allow others to do so, for U.S. 

Government purposes.
iv

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List of Acronyms

AC alternating current

BA balancing area

CAISO California Independent System Operator

CC combined cycle

CT combustion turbine

DC direct current

ERCOT Electric Reliability Council of Texas

ERS essential reliability service

FERC Federal Energy Regulatory Commission

FFR fast frequency response

FRCC Florida Reliability Coordinating Council

FRO frequency response obligation

GW gigawatt

IFRO interconnection frequency response obligation

ISO independent system operator

ISO-NE ISO New England

kW kilowatt

LCOE levelized cost of electricity

MISO Midcontinent Independent System Operator

MW megawatt

MWh megawatt-hour

NERC North American Electric Reliability Corporation

NYISO New York Independent System Operator

OATT open access transmission tariff

O&M operation and maintenance

NREL National Renewable Energy Laboratory

PFR primary frequency response

PV photovoltaics

ROCOF rate of change of frequency

RTO regional transmission organization

SERC Southeastern Electric Reliability Council

SPP Southwest Power Pool

TW terawatt
v

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Executive Summary

As the role of wind energy grows in the U.S. power grid, there is increased interest and 

requirement for it to provide “essential reliability” services or ERSs (historically often referred to 

as “ancillary” services). These services are critical to maintaining the reliability and stability of 

the grid, and historically were provided by large “synchronous”1 generators, mainly fossil-fueled 

and hydroelectric generators. To help evaluate the potential role of wind in providing these

services, this report provides an overview of services provided to the grid, including their 

technical requirements, quantities currently procured, and some estimates of costs. The report 

also summarizes the technical and regulatory issues around wind providing these services.

Numerous grid services are required in the U.S. electric power system to support reliable grid 

operations and respond to the inherent variability and uncertainty of electricity supply and 

demand. Although specific definitions and terms vary by market and region, these services can 

be categorized as illustrated in Figure ES-1. The first category includes energy and capacity

services, which represent the vast majority of costs to the system. The ERS category 

encompasses the remaining set of grid services discussed in this report. We further subdivide 

ERSs into two categories: operating reserves and other essential reliability services. One purpose 

of this report is to provide a structured explanation of the conceptual and technical differences 

between these widely varying grid services, with a particular focus on ERSs.

Energy and 

Capacity

Other 

mS S Min Hr Day Month Year

Energy

Firm Capacity

Regulating Reserves

Ramping Reserves

Contingency Reserves

Voltage Support

Black-Start Capability

Category of 

Service

Frequency Responsive Reserves

Timescale

mS S Min Hr Day Month Year

Operating 

Reserves

Essential Reliability 

Services

Figure ES-1. Main services procured in the U.S. power system.

 1 A synchronous generator is electrically synchronized to the grid, meaning it rotates in lock-step to all other 

generators and is therefore able to respond to grid conditions.
vi

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Table ES-1 provides a brief description of the ERSs discussed in the report. The first group of 

services described in the table are operating reserves, which are used to maintain system 

frequency. Operating reserves are provided by a set of resources with different technical 

characteristics that are deployed at different times; typically, the resources are deployed in order 

of response speed, from very fast to slow (and with corresponding costs that range from more to 

less expensive). Each type of resource in Table ES-1 is described in order of deployment. This 

cascade of resources is designed to minimize costs while maintaining reliability. In some cases, 

not all types of reserves are needed to return the grid to its normal state, depending on the 

severity and length of an event. In the main body of the report we provide additional details, 

including the technical requirements a generator must possess to provide the service.

Other ERSs—namely black-start and voltage support—are qualitatively different from operating 

reserves and so are considered in their own category. 

Table ES-1: Essential Reliability Services Discussed in This Report

Operating Reserves

FrequencyResponsive 

Reserves

Services that act to slow and arrest the change in frequency via rapid 

and automatic responses that increase or decrease output from 

generators providing these services. Traditionally provided by 

synchronous generators, these services include inertial response and 

primary frequency response (PFR). An emerging product is “fast 

frequency response,” which can be provided by multiple generator 

types and demand response and may replace some fraction of 

traditional inertia/PFR. 

Regulating 

Reserves

Rapid response by generators used to help restore system frequency. 

These reserves may be deployed after an event and are also used to 

address normal random short-term fluctuations in load that can create 

imbalances in supply and demand.

Contingency 

Reserves

Reserves used to address power plant or transmission line failures by 

increasing output from generators. These include spinning reserves,

which respond quickly and are then supplemented or replaced with 

slower-responding (and less costly) non-spinning/replacement 

reserves.

Ramping 

Reserves

An emerging and evolving reserve product (also known as loadfollowing or flexibility reserves) that is used to address “slower” 

variations in net load and is increasingly considered to manage 

variability in net load from wind and solar energy.

Other ERSs

Black-Start Capacity that can be started without either external power or a 

reference grid frequency, and then provide power to start other 

generators.

Voltage Support Used to maintain voltage within tolerance levels and provided by local 

resources.
vii

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In addition to describing the types of grid services, we also report the amount of each service 

procured in recent years for all regions of the conterminous United States, including the seven 

market and three non-market regions. The reported data reveals regional variations due to 

differences in size (i.e., annual and peak demand), generation mix, network topology, and market 

rules and/or system planning decisions. Figure ES-2 shows the total capacity requirements for 

operating reserve requirements for the 10 regions examined. For all regions, capacity needed to 

meet operating reserves comprises only 3%–12% of capacity needed for energy requirements, 

which are represented by 2017 peak demand for each region in the figure.

Figure ES-2. Total capacity for reserve requirements.

Along with quantity requirements, we also summarize technical requirements for grid services 

below and in detail in the main body of the report. Prices for each service depend in part on that

service’s technical requirements. For example, regulating reserve prices are often higher than 

those of spinning or non-spinning reserves due to the shorter timescales and more technically 

stringent eligibility requirements for regulating reserves. In 2017, reserve prices in the market 

regions averaged up to $29.23/MW-hr for regulating reserves, $10.13/MW-hr for spinning 

reserves, and $3.18/MW-hr for non-spinning reserves. In addition to the pricing data, we report 

2017 market settlement data for ISO-NE and PJM to compare grid services in a way that 

considers both market depth and prices. In these two markets, operating reserves and essential 

reliability/ancillary2 services comprise 2.3% and 3.1% of total settlements, respectively; the 

remainder of settlements are for energy, capacity, and transmission-related services. 

In addition to reporting the service requirement and pricing data, we also discuss the potential 

ability of wind energy to provide various grid services. Wind’s ability to provide energy and 

capacity is well understood in concept even if industry practices vary by region (e.g., different 

methods and approximations are applied to estimate wind capacity credit). What is not as 

broadly understood is the ability of wind technologies to provide ERSs, even as modern wind 

 2 We use the term ancillary services here as many market manuals and reports still use this term extensively.

0%

2%

4%

6%

8%

10%

12%

14%

16%

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Fraction of Annual Peak Demand 

Capacity Needed (MW)

Ramping

Nonspinning

Spinning

Regulation

PFR

Pct Peak Energy

Demand
viii

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turbines have necessary capabilities built in. While the cost of providing operating reserves is a 

small fraction of the total cost of grid services, this share could grow under increasing 

penetration of wind (or solar photovoltaics [PV])—and the provision of operating reserves from 

wind could grow as well. In fact, in certain regions, wind is required to provide some of the

reserve services even today. In this report, we provide a conceptual discussion of how wind can 

provide various grid services, as well as the technical and economic considerations and 

limitations for doing so. 

The ability of any generator to provide operating reserves is based on three factors: how much, 

how fast, and how long. “How much” refers to the headroom available for a generator, or the 

difference between its current output and maximum output. “How fast” represents the response 

rate, or the amount of time required to increase or decrease the output of a generator. “How 

long” means the length of time a generator is required to “hold” output at the increased or 

decreased level. For conventional generators not limited by fuel availability, “how much” and 

“how fast” are typically the most important factors for determining their ability to provide 

reserves.

The technical ability of wind (and other variable renewable) generators to provide services varies 

by service type, and the same three factors can be used to characterize it. A key element 

particularly related to “how much” reserve service wind can provide is the need for precurtailment. Pre-curtailment means reducing the output of the wind turbine below what it could 

provide at a given wind speed, which enables it to then increase output when needed to provide 

“upward” reserves. All upward reserve services from wind (except inertia, which can be 

extracted from the rotating mass of the blades, shaft, and generator) require pre-curtailment,

which will incur an opportunity cost of reduced energy sales. It is therefore only economically 

preferable for wind to provide reserves instead of energy when energy prices fall below reserve 

prices, given that the variable cost for wind is zero or near zero. In terms of “how fast,” wind can 

increase output more rapidly than most thermal generators; therefore, this factor is not a limiting 

constraint for wind to provide operating reserves. This also makes wind a candidate for provision 

of a fast frequency response product that is being introduced or under consideration as a partial 

replacement for traditional inertia and PFR. Finally, unlike thermal generators, “how long” the 

reserve service is needed is a more significant limiting factor for wind, given that wind resource 

has variable and more unpredictable output, particularly over longer durations. Figure ES-3 

conceptually depicts this limitation. For example, the long-duration requirement for non-spinning 

reserves may limit wind’s ability to provide this service.
ix

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Figure ES-3. The impact of variable output on the ability of wind to provide upward reserve 

services. 

Wind can also provide or potentially provide the two other ERSs discussed in this report: voltage 

support and black-start. The power electronics built into wind turbines are well suited to provide

voltage support (including reactive power). In fact, the Federal Energy Regulatory Commission 

(FERC) and many utilities and system operators already require wind to provide reactive power. 

However, voltage support is a localized service, and the dispersed nature of wind resources 

means that wind generation may not be available where reactive power support is needed. Wind 

does not yet provide black-start capability in the United States, although the capability has been 

demonstrated in other countries. Additional research is needed to assess the role of wind in 

providing black-start capability, including how this capability would be incorporated into system 

restoration procedures. 

In summary, wind power plants can provide many of the services needed by the grid to maintain 

reliable and stable operation; however, the intrinsic variability and uncertainty of wind, as well 

as the dispersed nature of wind resources, raise considerations that do not play as significant a 

role for conventional power plants. For example, longer-duration but slower operating reserve 

services are among the least technically demanding and lowest cost services for conventional 

generators to provide, but are less suitable for wind. With power electronics, wind power plants 

can respond rapidly, but whether the wind resource will be available over the duration the 

reserves are needed is critically important. Furthermore, as the provision of many reserve 

products would require pre-curtailment, the opportunity cost to provide reserves becomes a more

significant issue for wind compared to thermal generators with more sizable fuel and variable 

operations and maintenance (O&M) costs. These opportunity costs highlight that the technical 

considerations need to be weighed with the economic factors for providing grid services, and

that—at least under current systems and markets—the need for and value of energy and capacity 

far exceed those of operating reserves and other ERSs.
x

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Table of Contents

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

1.1 Geographical Scope and Regions Analyzed ................................................................................. 1

2 Current Grid Services .......................................................................................................................... 3

2.1 Energy and Capacity ..................................................................................................................... 3

2.1.1 Regional Requirements.................................................................................................... 4

2.1.2 Energy and Capacity Costs and Prices............................................................................. 5

2.2 Operating Reserves ....................................................................................................................... 7

2.2.1 Frequency-Responsive Reserve Requirements.............................................................. 13

2.2.2 Regulating Reserve Requirements and Costs................................................................. 15

2.2.3 Contingency Reserve Requirements and Costs.............................................................. 17

2.2.4 Ramping Reserve Requirements.................................................................................... 20

2.2.5 Total Reserve Requirements .......................................................................................... 20

2.3 Other Essential Reliability Services............................................................................................ 21

2.3.1 Black-Start...................................................................................................................... 22

2.3.2 Voltage Support.............................................................................................................. 22

2.4 Relative Total System Costs ....................................................................................................... 23

3 Provision of Services from Wind ...................................................................................................... 25

3.1 Energy and Capacity ................................................................................................................... 25

3.2 Operating Reserves ..................................................................................................................... 26

3.2.1 Frequency-Responsive Reserves.................................................................................... 29

3.2.2 Regulating Reserves....................................................................................................... 31

3.2.3 Ramping Reserves.......................................................................................................... 31

3.2.4 Contingency Reserves.................................................................................................... 31

3.3 Other Essential Reliability Services............................................................................................ 32

3.3.1 Voltage Support.............................................................................................................. 32

3.3.2 Black-Start Capacity ...................................................................................................... 32

3.4 Summary ..................................................................................................................................... 32

4 Conclusions and Research Needs.................................................................................................... 34

References................................................................................................................................................. 35
xi

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List of Figures

Figure ES-1. Main services procured in the U.S. power system................................................................... v

Figure ES-2. Total capacity for reserve requirements. ...............................................................................vii

Figure ES-3. The impact of variable output on the ability of wind to provide upward reserve services..... ix

Figure 1. NERC regional entities.................................................................................................................. 1

Figure 2. Map of regions analyzed................................................................................................................ 2

Figure 3. Main services procured in the U.S. power system......................................................................... 3

Figure 4. Energy price variation in the ERCOT and PJM day-ahead market during the week of July 1-7, 

2016.......................................................................................................................................... 7

Figure 5. The three characteristics of operating reserves.............................................................................. 8

Figure 6. Timescales of operating reserve requirements. ............................................................................. 9

Figure 7. Reserve deployments after a contingency event.......................................................................... 10

Figure 8. Total capacity for energy and reserve requirements.................................................................... 21

Figure 9. The impact of variable output on the ability of wind to provide upward reserve services.......... 28

List of Tables

Table 1. Regions Analyzed ........................................................................................................................... 2

Table 2. U.S. Power System Historical Peak and Annual Energy Demand ................................................. 4

Table 3. U.S. Power System Peak Capacity Requirement Estimates ........................................................... 5

Table 4. U.S. Power System Energy Requirements...................................................................................... 6

Table 5. Primary Frequency Response Obligation ..................................................................................... 14

Table 6. Regulating Reserve Requirements................................................................................................ 16

Table 7. Spinning Contingency Reserve Requirements.............................................................................. 17

Table 8. Non-Spinning Contingency Reserve Requirements ..................................................................... 18

Table 9. Ramping (Flexibility) Requirements by Region........................................................................... 20

Table 10. 2017 ISO-NE Market Settlements Summarya

............................................................................. 23

Table 11. 2017 PJM Market Settlements Summarya .................................................................................. 24

Table 12. 2016 Wind Energy Provision...................................................................................................... 25

Table 13. Capacity Credit by Market Region ............................................................................................. 26

Table 14. Key Parameters for Provision of Operating Reserves for Thermal/Hydro Resources and Wind27

Table 15. Terms Applied to Frequency-Responsive Services.................................................................... 30

Table 16. Grid Services and Provision from Wind..................................................................................... 33
1

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1 Introduction

There is growing interest in wind energy providing a variety of services to maximize its value to 

the grid. To help evaluate the potential role of wind in providing grid services, this report

provides an overview of services provided to the grid, with a focus on essential reliability 

services. We discuss the technical requirements and quantity of these services procured in 

various regions and provide some estimates of costs. The report also summarizes the technical 

and regulatory issues around wind providing these services.

1.1 Geographical Scope and Regions Analyzed

Our analysis is focused on the lower 48 (conterminous) United States. Within the conterminous 

United States, there are (very loosely) four main geographical levels of the grid: interconnection, 

North American Electric Reliability Corporation (NERC) regional entity, balancing area (BA), 

and utility service territory.

The U.S. grid consists of three electrically connected interconnections (the Western 

Interconnection, Eastern Interconnection, and Electric Reliability Council of Texas [ERCOT]) 

and eight NERC regional entities (i.e., large regions used for reliability planning). Figure 1

provides a map of NERC regional entities and subregions. 

Figure 1. NERC regional entities.

The U.S. grid consists of 66 BAs that are responsible for grid operation. There is significant 

overlap between NERC planning regions and several large BAs. The U.S. Eastern 

Interconnection has 31 BAs, while the U.S. Western Interconnection has 34 BAs, and the 

ERCOT interconnection also serves as a BA (Hoff 2016). Many BAs are operated by the 

wholesale market operator (an independent system operator [ISO] or regional transmission 

operator [RTO]). Areas with restructured markets serve about two-thirds of U.S. electricity 

demand (ISO/RTO Council 2018a). BAs in non-RTO regions are typically run by large utilities. 

At the finest level there are over 3,200 utilities; most of these are relatively small and are not 
2

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responsible for providing “bulk” grid services (DOE 2016b).

3 Figure 2 provides a map of regions 

studied in this analysis. It includes the seven U.S. ISO/RTO market regions, with the remaining 

BAs in the non-CAISO West and Southeast largely aggregated.

Figure 2. Map of regions analyzed.

Table 1 lists the regions and their approximate size measured in terms of demand and population. 

Note we use the term “regulated regions” for those areas not served by wholesale markets 

(FERC 2015).

Table 1. Regions Analyzed 

Region Estimated Electric Demand

(TWh / % of U.S.)

a

Estimated Population 

(million / % of Total)

b

Market Regions

CAISO 228 / 6% 30 / 9%

PJM 759 / 19% 65 / 20%

ERCOT 357 / 9% 23 / 7%

ISO-NE 121 / 3% 14.5 / 4%

NYISO 157 / 4% 19.5 / 6%

MISO 656 / 16% 48 / 15%

SPP 246 / 6% 18 / 6%

Regulated Regions

Non-CAISO WECC 654 / 16% 52 / 16%

FRCC 231 / 6% 16 / 5%

SERC 673 / 16% 39.4 /12%

a Data sources: see Table 2

b NERC 2018a; ISO/RTO Council 2018b

 3 Many of these are “distribution” utilities whose primary responsibility is operating and maintaining the distribution 

networks.
3

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2 Current Grid Services

In this section, we define and describe several general categories of grid services and quantify 

the amount of each service procured in the U.S. electric power system.

Figure 3 illustrates the set of services currently procured in the grid. We separate energy and 

capacity services into one category and group the remaining services into a general essential 

reliability service (ERS) category. ERSs are further subdivided into operating reserves and other 

ERSs. Each of the following subsections discusses these three groups of services—energy and 

capacity, operating reserves, and other ERSs—in detail.

Energy and 

Capacity

Other 

mS S Min Hr Day Month Year

Energy

Firm Capacity

Regulating Reserves

Ramping Reserves

Contingency Reserves

Voltage Support

Black-Start Capability

Category of 

Service

Frequency Responsive Reserves

Timescale

mS S Min Hr Day Month Year

Operating 

Reserves

Essential Reliability 

Services

Figure 3. Main services procured in the U.S. power system.

2.1 Energy and Capacity

Energy and capacity are the major services provided by the electric system assets. Capacity is 

measured in terms of power (e.g., megawatts [MW] or gigawatts [GW]), while energy is 

measured in terms of the power generated over a period of time (e.g., kilowatt-hours [kWh], 

megawatt-hours [MWh], or gigawatt-hours [GWh]). 
4

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2.1.1 Regional Requirements

Table 2 summarizes the historic peak demand and energy requirement for each region. 

Table 2. U.S. Power System Historical Peak and Annual Energy Demand

Region Peak Demand (GW) Annual Energy (TWh)

2016 2017 2016 2017

Market Regions

CAISO 46.2a 50.1a 228.8 b 228.2b

PJM 152.2c 145.6c 776.1d 758.8d

ERCOT 71.1e 69.5e 350.7f 357.4f

ISO-NE 25.6g 24.0g 124.1h 121.1h

NYISO 32.1i 29.7i 160.3j 156.8j

MISO 121.0k 120.6k 664.5l 656.3l

SPP 50.6m 51.2m 248.4n 246.0n

Regulated Regions

Non-CAISO WECC 110.8o 106.0o 650.2p 653.8p

FRCC 47.7q 46.6q 235.7r 230.6r

SERC 129.0s 132.2s 672.7s 673.3s

Totalt 786 775 4,111.5 4,082.3

a CAISO 2018, 31

b CAISO 2018, 32 c Monitoring Analytics 2017, 22

d Monitoring Analytics 2017, 22; Calculated as the average real-time load multiplied by 8,760 hours e ERCOT 2017a, i

f Potomac Economics 2018a, 74

g ISO-NE 2018a, 5 h ISO-NE 2018a, 5; Calculated as the average real-time load multiplied by 8,760 hours i Potomac Economics 2018b, 6

j Potomac Economics 2018c, 8; Calculated as the average real-time load multiplied by 8,760 hours k Potomac Economics 2018b, 6

l MISO 2018; Sum of monthly average load m SPP 2017, 18

n SPP 2017, 20; System energy usage

o WECC 2018

p WECC 2018

q FRCC 2018, 1

r EIA 2018, Table 861

s EIA 2017; The year 2016 is actual data; 2017 is estimated data

t Simple sum of rows. These values roughly match national totals reported in EIA form 411 and the EIA electricity 

data browser. Sum of peak demand is non-coincident total.

Each region is required to maintain sufficient capacity to meet the peak demand plus additional 

capacity to address outages or unanticipated increases in demand. Regions use a variety of 

methods to determine the additional capacity requirements, but a common metric is the “reserve 

margin” or percentage of capacity above the anticipated peak demand (NERC 2017b). Table 3
5

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lists the estimated peak demand in 2020, along with the NERC estimated reserve margin. It also 

lists the total estimated peak capacity requirement and the estimated reserve margin in 2020 

based on anticipated retirements and plants under construction (NERC 2017b). It shows that all 

regions of the United States are expected to have adequate generation capacity to meet peak 

demand in the near future.

Table 3. U.S. Power System Peak Capacity Requirement Estimates

Region 2020 Estimated 

Peak Demand

(GW)a

NERC Estimated 

Reference Margin 

Level (%)b

2020 Estimated Total 

Peak Capacity 

Requirement (GW)

2020 Estimated 

Reserve Margin

(%)

Market Regions

CAISO4 53.6 16.14 62.3 20.6

PJM 147.5 16.60 172.0 28.0

ERCOT 73.7 13.75 83.5 18.0

ISO-NE 26.3 16.90 30.3 23.8

NYISO 32.1 15.00 36.9 25.0

MISO 121.4 15.80 140.6 19.4

SPP 52.5 12.00 58.8 28.9

Regulated Regions

Non-CAISO 

WECC 110.0 range of 14.17 to 

16.38 136.0 23.7 (range of 

22.6 to 27.7) 

FRCC 45.8 15.00 52.7 22.5

SERC 131.2 15.00 150.9 23.1

a Total demand minus existing demand response resources

b NERC 2017b

2.1.2 Energy and Capacity Costs and Prices

The majority of the costs associated with power system generation are the fixed and variable 

costs associated with providing capacity and energy.

It is very difficult to summarize energy and capacity market prices with a single or limited set of 

metrics. The energy prices reported by ISO/RTO markets are the locational marginal prices 

(LMPs) at a specified location on the grid, or the incremental cost of serving an additional unit of 

energy (FERC 2015). These prices largely represent the variable cost of generation; however, all 

markets have some degree of scarcity pricing, which allows the price of energy to rise above the 

variable cost of generation. This allows some of the costs of capacity to be captured in the energy 

price (FERC 2015). However, price caps and other factors typically require additional costs of 

capacity (i.e., “missing money”) to be captured via other mechanisms, including resource 

adequacy payments and/or capacity markets (Frew et al. 2016).5 For non-market regions,

individual BAs report system lambdas, which are “system-wide” marginal costs of generation 

 4 Actually the CAMX region, which includes nearly all of California plus a small northern portion of the Baja 

California Peninsula in Mexico. As a result, the load in this region is larger than that of CAISO. 

5 ERCOT is the only “energy only” market in the United States.
6

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

(FERC 2018).6 In addition, most regions in the United States have more capacity than is needed 

for resource adequacy/planning reserve targets, which tends to suppress capacity market prices 

(NERC 2017b). 

Table 4 summarizes average market energy and capacity prices in the United States. 

Table 4. U.S. Power System Energy Requirements

Region Average Energy Price ($/MWh) Capacity Market Price ($/kW-month)a

2016 2017 16/17 17/18

Market Regions

CAISO $33.1b $33.3b N/A

PJM $29.68c $30.85c $1.81c $3.66c

ERCOT $24.62d $28.25d NA

ISO-NE $31.74e $35.23e $3.15e $7.03e

NYISO $31.32f $34.62f Summer: $1.73g

Winter: $5.77g

Summer: $1.25g

Winter: $6.49g

MISO $26.80h $29.46h NA

SPP $22.43i $23.43i NA

a DOE 2016a

b Blanke 2018, 19; Simple average of day-ahead prices c Monitoring Analytics 2017, 24; Load-weighted average day-ahead LMP

d ERCOT 2017a, Figure 2; ERCOT-wide load-weighted average real-time LMP e ISO-NE 2018a, 5; Load-weighted average day-ahead LMP f Potomac Economics 2018c, A-3; Load-weighted day-ahead price for Zone J – New York City g These are strip prices for 2016 and 2017.

h Potomac Economics 2018b; Load-weighted real-time energy price (page i and page 2); day-ahead premium 

averaged $0.52/MWh (page 26)

i SPP 2017, 87; Simple average of day-ahead LMP across years

Figure 4 provides an example of the significant temporal and regional variation in energy prices. 

It shows the average energy locational marginal pricing (average LMPs) in ERCOT and PJM

from July 1–7, 2016. It shows that prices typically peak in the late afternoon and are lowest in 

the early morning. This has significant implications for the value of wind, as discussed in Section 

3.1. 

 6 These are typically “true” marginal costs that do not include scarcity pricing.
7

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

Figure 4. Energy price variation in the ERCOT and PJM day-ahead market during the week of July 

1-7, 2016.

2.2 Operating Reserves

Operating reserves are defined as “that capability above firm system demand required to provide 

for regulation, load forecasting error, equipment forced and scheduled outages, and local area 

protection” (NERC 2018b).

While operating reserves consist of numerous services and market products, they all represent 

the ability of a generator or aggregated set of generators to increase output (providing “upward” 

reserves) or decrease output (“downward” reserves). The distinctions between different reserve 

services can be characterized by three factors: how much, how fast, and how long. This means 1) 

the difference between the current capacity setpoint and a desired one (or maximum or minimum 

output) (“how much”); 2) the response rate or how quickly the plant can move from one setpoint 

to another, which is a combination of the time needed to initiate a response to the reserve event 

and ramp rate (“how fast”); and 3) the duration for which the plant must hold the new output 

(“how long”). This is illustrated in Figure 5, which shows the output of a generator operating 

below maximum output. It can increase output based on its headroom and at a rate limited by 

response rate. The duration reflects how long it can hold its output at this higher level. 

0

20

40

60

80

100

120

0 12 24 36 48 60 72 84 96 108 120 132 144 156 168

DA Average System Price ($/MWh)

Hour of Week

ERCOT

PJM
8

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

Figure 5. The three characteristics of operating reserves.

It is important to emphasize that there are no uniform definitions for various operating reserve 

products. U.S. ISOs and utilities use different terms with different product definitions, and there 

are different terms used in the United States and internationally. Wherever possible, we use 

terms and definitions used by NERC (2018b). For ease of discussion we consider the four 

general classes of operating reserve products introduced previously in Figure 3 and further 

broken down by subcategory illustrated in Figure 6. Figure 6 also includes an approximate 

measure of two timescale elements. The first is captured by the left side of the bar, which 

represents the time between the request and the time the reserve must start responding (one 

element of “how fast”). The second is the duration (“how long”) captured by the righthand side, 

with the fade in color illustrating the significant variation in how long services are actually 

required based on grid conditions.
9

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

Regulating Reserves

Spinning Reserves

Non-spinning Reserves

Primary Frequency Response

mS S Min Hr Day

Inertial Response

Economic Dispatch

Replacement Reserves

Ramping Reserves

1. Frequency

Responsive

Reserves

3. Contingency

Reserves

5. Normal operation

provided by “energy

and capacity”

2. Regulating

Reserves

4. Ramping

Reserves

Services 

currently

not 

procured 

via markets

Proposed 

or early 

adoption 

market 

services 

Currently 

procured 

via markets

Fast Frequency Response

mS S Option Min 3 Hr Day

Timescale

Figure 6. Timescales of operating reserve requirements.
10

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

For greater clarity, this sequencing is often shown in response to an “event” (Ela, Milligan, and 

Kirby 2011). Figure 7 provides an example of this, where a subset of reserve products are 

deployed in response to a contingency such as a power plant failure that leads to a decline in 

system frequency and could result in a system blackout unless operating reserves are used to 

slow, arrest, and restore the frequency.

Figure 7. Reserve deployments after a contingency event

Resources with different technical characteristics are deployed at different times; typically, they 

are deployed in order of response speed, from very fast to slow (and with corresponding costs 

that range from more to less expensive). This cascade of resources is designed to minimize costs 

while maintaining reliability. In some cases, not all types of reserves are needed to return the grid 

to its normal state, depending on the severity and length of an event. Some reserves are typically 

only used to respond to events such as contingencies, while others are used to as part of normal 

operation. Each type of resource is described in order of deployment below:

1. Frequency-Responsive Reserves

A. Inertial Response. Historically, nearly all grid capacity has been provided by 

synchronous generators all rotating in lock step. These rotating generators have 

stored kinetic energy, also known as inertia.

7 When there is mismatch in the 

supply and demand for electricity, the frequency of the grid will begin to change, 

but the inertia of the generators on the grid will resist any changes in frequency. If 

there is too little generation, the frequency declines, but kinetic energy will be 

extracted from generators, instantaneously and without operator intervention, 

delaying how quickly the system slows down. The rate at which the frequency 

changes is determined by the magnitude of the imbalance between load and 

generation and the total inertia of the system. Inertial response injects stored 

 7 More accurately, inertia can be defined as a measure of a generator’s resistance to changes to its rotational speed, 

and the amount of inertia depends on the amount of kinetic energy stored in the rotating generators.

Econ. Dispatch

Inertia

Frequency

(Hz)

Time (approx.)

60

Event

Occurs

0 s 10 s 30 s 5 m 10 m 30 m 1 hr

Contingency

Reserves

Non-Spinning / Replacement

Spinning

Regulating Res.

PFR Frequency Responsive

Reserves
11

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

kinetic energy into the system, slowing down the decline in frequency to provide 

time for other reserve products (including primary frequency response (PFR),

which is the next stage of reserve deployment) to detect those changes and 

respond accordingly.

B. Primary Frequency Response. PFR (along with regulating reserves) is one of 

two parts of the “cruise control” of the electric power system. PFR (sometimes 

known as governor response)8 detects changes in frequency and automatically—

without action from the system operator—and adjusts operations of online 

generators to maintain frequency within the desired range. 

C. Fast Frequency Response. Inertial response and PFR are legacy terms based on 

systems designed largely on synchronous generators. It has been recognized that 

these terms may not be suitable when deriving reserves from non-synchronous 

generators. An example is the provision of frequency-responsive services from 

battery storage (or wind, as discussed in Section 3). Battery storage injects real 

energy into the grid through an inverter which converts stored energy into AC 

power. The power electronics in the inverter can measure system frequency in a 

manner similar to a generator governor and respond accordingly, rapidly 

increasing or decreasing output. This response rate can be very fast, faster than 

PFR from a conventional generator, and can be programmed to respond in a 

manner similar to the inertial response from a conventional generator.9 Fast

frequency response (FFR) has emerged as the term that describes the general 

capability of any resource that can detect and rapidly respond to changes in 

frequency, supplementing or replacing some amount of conventional inertial

response and PFR.

2. Regulating Reserves

Also commonly referred to as “regulation,” regulating reserves10 provide several services 

to the grid responding to both event conditions and normal operations. During normal 

operation, reserves are still required to meet random variations in net load. This is 

because economic dispatch (as fast as 5 minutes) is too slow to respond to normal 

variability and uncertainty in load and variable generation supply, and additional capacity 

may need to be committed to meet intra-hour variability. In general, regulation is used to 

meet very short-term variability (seconds to a few minutes). This variability can result in 

either changes in frequency or unscheduled flow of power into or out of the region where 

local generation is not matching load. Systems measure these imbalances and signal 

generators in that area to modify their output as needed via a signal from the system 

operator. Under these conditions, regulating reserves require generators to both increase 

and decrease output. Regulating reserves are also deployed in a similar manner during 

events. While inertial response and PFR occur system-wide and work automatically to 

prevent large frequency deviations, additional actions are needed locally to restore the 

 8 Governors measure the rotating speed (frequency) of the generator and automatically adjust the speed if it is 

greater or less than the target frequency.

9 The latter service has sometimes been called “synthetic inertia,” but the current trend appears to use FFR, as 

discussed in more detail in Section 3.

10 While regulating reserves are sometimes referred to as “frequency regulation,” the NERC glossary defines

frequency regulation to include both governor response (PFR) and the service described in this section.
12

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

system to its “pre-event” state—spinning at 60 Hz with all generators operating as 

scheduled. Regulating reserves are the second part of the “cruise control” of the power 

system that works to reset the system to “normal” conditions. Regulating reserves are 

traditionally provided by generators that are synchronized to the grid (spinning) and have 

spare capacity to either increase or decrease output in response to signals from the system 

operator and rapidly ramp (i.e., begin changing output within seconds and reach the new 

desired setpoint within minutes). 

3. Contingency Reserves

A power plant or transmission line failure is often referred to as a “contingency.” When a 

contingency occurs, the “cruise control” systems listed above take action to correct and 

restore frequency and power flows. Systems do not typically have enough PFR capacity 

and regulating reserves to handle large contingencies. Furthermore, the use of these 

services depletes their effectiveness for further response to another contingency or other 

unscheduled variation in supply or demand. System operators address large contingency 

events using a dedicated class of reserves known as contingency reserves. These reserves 

are often sized to address the failure of the single largest power plant or transmission line 

in the system. Contingency reserves are an upward-only reserve product and are often 

divided into two (or sometimes three) types of reserves deployed sequentially, so that 

reserves can be restored and be able to respond to another event.

A. Spinning Reserves. Spinning reserves are traditionally provided by generators 

that are synchronized to the grid (spinning) and have spare capacity (meaning 

they have headroom or ability to increase output). Spinning reserves have also 

been provided by demand response. They typically are required to begin 

responding quickly (within seconds) and with full response in 10 minutes or less.

They are required to continue providing energy for up to 60 minutes (30 in most 

markets).

11

B. Non-Spinning/Supplemental Reserves. Typically used to replace or supplement 

spinning reserves, non-spinning reserves are typically fast-starting units that can 

begin providing energy within about 10 minutes. They may be required to 

continue providing this service for several hours. In some regions, non-spinning 

and supplemental reserves are separate categories, where replacement reserves are 

provided by longer-starting units.

4. Ramping Reserves

Ramping is the least well defined of the reserve products and is not yet a common market 

product.

12 One definition is a regulation-like product but over longer timescales; for 

example, regulation is used to meet very short-term variability (seconds to a few 

minutes), while ramping reserves are used to meet variability in the minutes to tens of 

minutes timescale. Another definition is a reserve product used to meet normal loadfollowing requirements, particularly in markets that (historically) did not include 5-

 11 See table 3-14 in EPRI (2016). 12 The NERC glossary does not include a definition for ramping, load-following, or flexibility reserves. However, 

NERC ERS documents (NERC 2014, NERC 2016a) include ramping as a category of ERS within the general 

category of frequency support and operating reserves.
13

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

minute economic dispatch. Other definitions of this product focus primarily on reserves 

needed to address normal variability and uncertainty of VG resources. Ramping reserves 

are not shown on Figure 7 because they are typically used for normal operation as 

opposed to addressing contingency events. For additional discussion, see Ela, Milligan, 

and Kirby (2011). From this point, we use “ramping” as an abbreviation for this general 

category of reserves, while acknowledging the different and evolving nomenclature 

among various regions. 

5. Economic Dispatch (Normal System Operation) 

All reserves are eventually replaced by the normal economic dispatch of conventional 

generators as the system is restored to a pre-contingency state. This is not considered an 

operating reserve or ERS and is provided by generators delivering energy and capacity 

services described in Section 2.1.

Each of the following four subsections describes in greater detail the current grid requirements 

for each major class of reserve product in today’s grid (“how much”), and estimates of market 

prices where available.

2.2.1 Frequency-Responsive Reserve Requirements

Frequency-responsive reserves traditionally consist of two services: inertial response and PFR. 

To date, there has been little detailed estimation of inertial response requirements in the United 

States. This is because in a synchronous-generator dominated system, inertia is inherently 

provided and does not need to be committed or otherwise procured. However, with increasing 

penetration of non-synchronous generators, there has been growing analysis of the potential need 

to procure inertial response services. To date, only ERCOT has studied the amount of inertia 

potentially “required” in their system. This requirement (the “how much” component) of inertia 

is unlike that of all other operating reserves. For all reserve products other than inertia, the 

requirement is measured in units of power (MW, GW). This means that a system must have a 

certain number of MW available of “spare capacity” in an upward or downward direction. For an 

individual generator, the “how much” is based on the generator’s headroom or the difference 

between its current operating capacity and its maximum (or minimum for downward reserves) 

output level. 

For inertia, the requirement is measured in energy, or how much energy can be injected rapidly 

into the system. This is often measured in GW-seconds. The inertia provided by an individual 

generator (measured in MW-seconds) is determined by the amount of stored kinetic energy. This 

also means there is no “headroom” component of inertial response and that the amount of inertia 

that can be provided by a generator is independent of instantaneous power output. This is 

because inertia is the product of the generator’s physical mass and rotation speed. Rotation speed 

is essentially constant regardless of power output, and mass varies in proportion to generator size

and by generator technology type. 
14

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

The inertia of a typical generator is in the range of 2 MW-seconds to 6 MW-seconds per MW of 

capacity.13 ERCOT has identified 100 GW-second as a “critical” inertia level for its system

(NERC 2017b). This implies that ERCOT would require between 20 GW and 33 GW of online 

synchronous capacity (not generation). The actual minimum amount of generation is based on 

the system dispatch, including how low the generators can reduce output.14 The amount of inertia 

in the ERCOT grid has dropped to as low as 130 GW-seconds during periods of low load when

wind has displaced conventional synchronous generation. With wind expected to displace even 

more synchronous generation in the future, ERCOT is exploring mechanisms to ensure reliability 

under low-inertia conditions, such as increased procurement of additional frequency-responsive 

reserves including both PFR and an emerging FFR service mentioned above and discussed later 

in this section.

While analysis of inertial response requirements is limited, NERC has established minimum 

recommended standards for PFR for each of the three U.S. grids. Table 5 summarizes PFR

obligation by region. Each interconnection has a frequency response obligation (FRO) that is

defined as the amount of increase in generation that must occur per unit of frequency decline 

(MW/Hz). This interconnection FRO (IFRO) is further divided by BA in proportion to demand 

so that each region “shares” its obligation to the entire interconnection. Also established is the 

maximum delta frequency (MDF), or the decline in frequency that results in full frequency 

response. A single MDF is applied to all regions in each interconnection. The product of these 

two factors is the PFR (in units of MW) obligation by interconnection and BA. This amount 

represents the “how much” for this class of service, or the aggregated headroom needed across 

the set of generators providing PFR.

Table 5. Primary Frequency Response Obligation

Interconnection Region IFRO 

(MW/0.1Hz)a

MDF (Hz)b Requirement (MW / 

% of Peak Demand)

ERCOT ERCOT 381 0.405 1,543 / 2.2%

Western Western Total 858 0.28 2,402 / 1.5%

CAISO 196.5 550 / 1.1%

Non-CAISO 661.5 1,852 / 1.7%

Eastern Eastern Total 1015 0.42 4,263 / 0.8%c

FRCC 76.2 320 / 0.7%

SERC 303.6 1,275 / 1.0%

NYISO 49.9 210 / 0.7%

PJM 258.3 1,085 / 0.7%

ISO-NE 38.3 161 / 0.7%

MISO 210 882 / 0.7%

 13 Inertia scales with generator size because generators with larger capacity have more physical mass in the turbine, 

generator, and other rotating machinery. Differences in scale factor (referred to as the inertia constant) are based on 

factors including technology type.

14 For a discussion of minimum generation levels from conventional generators, see Denholm et al. (2018)
15

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

SPP 78.7 331 / 0.6%

Total 2,254 8,208 / 0.6%

a NERC 2016b; 2017 NERC BA-level frequency response obligation in MW/0.1Hz

b NERC 2017a; Maximum allowable delta frequency

c Requirement divided by noncoincident peak of Eastern Interconnection (the sum of peak demand in Table 2)

Neither inertial response nor PFR is a market product in any ISO/RTO market, so there are no 

historical prices (EPRI 2016).15 There have been a number of proposals to introduce an inertial 

response or PFR market, with the most significant efforts in ERCOT (EPRI 2016, Newell 2016). 

ERCOT’s efforts have included analysis of alternatives to inertial response and PFR, including 

introduction of an FFR market product. As discussed earlier, inertial response and primary 

frequency response are legacy products based on systems using synchronous generators. 

Alternative resources, including inverter-based generators (wind, PV, and storage) or demand 

response, can provide FFR that could supplement or replace some amount of conventional 

inertial response and PFR.

2.2.2 Regulating Reserve Requirements and Costs

Regulating reserves are a market product in each ISO/RTO and have the most technically 

demanding requirements of the various reserve products in terms of response rate and the need 

for nearly continual ramping of the plant providing this service. Because regulation requires 

nearly constant up and down changes in output, this produces additional wear-and-tear and less 

efficient operation, imposing additional costs. As a result, they are typically the most costly of 

the reserve services.16

Table 6 summarizes regulating reserve requirements for the regions evaluated. For the 

requirement in non-market regions, we multiply the percentage requirement of a large utility in 

that region by the total peak demand of the larger region in which it is located. This means that 

we use the requirements of a single utility as the proxy for the larger region as a whole. Average 

costs are also provided, including the average annual cost for market regions, or the open-access 

transmission tariff (OATT) for the selected utility. Note that the units for capacity-related 

services are typically in terms of capacity (e.g., kW or MW) over a certain time period (e.g., 

hour, month, or year)—so a MW-hr is a MW of capacity for an hour, as opposed to a MWh,

which is a unit of energy.

 15 They are also not compensated services, which has led to concerns about system operators having sufficient 

supplies in competitive markets. For more discussion, see Ela et al. (2011), Ela et al. (2014), and EPRI (2016).

16 For a discussion of the drivers behind the differing costs of reserve products, see Hummon et al. (2013).
16 

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

Table 6. Regulating Reserve Requirements

Market Regions Average Regulation Requirement

(% of Peak Demand / MW)

2017 Average Price ($/MW-hr)

CAISO Regulation Up: 0.64% / 320

Regulation Down: 0.72% / 360a

Regulation Up: $12.13

Regulation Down: $7.69b

PJM

Off-peak: 0.36% / 525

On-peak: 0.55% / 800c $16.78d

ERCOT Regulation Up: 0.48% / 318

Regulation Down: 0.42% / 295e

Regulation Up: $8.76

Regulation Down: $7.48f

ISO-NE 0.25% / 60g $29.23h

NYISO 0.73% / 217i $10.28j

MISO 0.35% 425k $9.74l

SPP Regulation Up: 0.92% / 470

Regulation Down: 0.63% / 325m

Regulation Up: $8.20

Regulation Down: $6.60n

Regulated Regionso (% of Peak Demand / Estimated 

Region Requirement in MW) Tariff ($/kW-month / $/MW-hr)

Non-CAISO WECC

(proxy utility: Arizona 

Public Service)

1.17% / 1,240p $7.41/$10.29

FRCC

(proxy utility: Florida 

Power & Light)

1.35% / 629q $4.8/$6.67

SERC

(proxy utility: Southern 

Company)

1.15% / 1,477r $4.2/$5.83

National (% of Total)s / Estimated Total 

Requirement Average Price ($/MW-hr)t

 0.90% / 6,000 MW $11.24

a CAISO 2018, 144; 2017 average day-ahead requirement

b CAISO 2018, 148; Weighted average day-ahead market clearing price c Monitoring Analytics 2017, 59

d Monitoring Analytics 2017, 59; 2017 weighted average clearing price for regulation e Potomac Economics 2018d 

f Potomac Economics 2018a, 39; Average annual ancillary service price g Tacka 2016; Estimate 

h ISO-NE 2018a, 180 i NYISO 2018a 

j Potomac Economics 2018c, A-26; Average day-ahead regulation capacity price for 2017 k MISO 2018; Summarized

l Potomac Economics 2018b, 38; Average real-time regulation price m SPP 2016; 2016 hourly requirements n SPP 2017, 104; Average day-ahead market-clearing price for regulation-up and regulation-down in 2017 o For regulated regions, the numbers here show only the requirement and tariff of representative utilities/balancing 

authorities. Different BAs have different values; the same representative BA is used for spinning and non-spinning 

reserve tables.
17

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

p Requirement numbers are a percentage of the transmission customers’ contribution to the coincident system peak. 

The WECC number comes from the regulation requirement of Arizona Public Service Company’s OATT files. Data 

in MW are calculated as an estimate using peak demand in Table 3 multiplied by the percentage requirement of the 

selected utility.

q Florida Power & Light Company 2016

r Southern Company 2018

s Calculated as the weighted average percentage requirement, weighted by peak demand of each region t Calculated as the simple average of regional price 

2.2.3 Contingency Reserve Requirements and Costs

Table 7 summarizes spinning contingency requirements. The actual quantity procured is 

typically greater than regulation requirements, but the price is typically lower due to the 

infrequent ramping requirements. Contingency events are relatively rare compared to the nearly 

continuous ramping required from regulating reserves, resulting in less wear and tear or degraded 

performance. 

Table 7. Spinning Contingency Reserve Requirements

Market Regions Spinning Requirement (% of 

Peak Demand / MW)

2017 Average Price ($/MW-hr)

CAISO 1.60% / 800 MWa $10.13b

PJM 1.03% / 1,504.8 MWc $3.73d

ERCOT 3.76% / 2,616.8 MWe $9.77f

ISO-NE 3.75% / 900 MWg $2.96h

NYISO 2.20% / 655 MWi $5.00j

MISO 0.61% / 740 MWk $2.94l

SPP 1.14% / 585 MWm $5.25n

Regulated Regions (% of Peak Demand) / Estimated 

Region Requirement Tariff ($/kW-month / $/MW-hr)

Non-CAISO WECC

(Arizona Public Service) 1.50% / 1590 $6.26 / $8.69

FRCC

(Florida Power & Light) 0.43% / 200 $5.16 / $7.17

SERC

(Southern Company) 2.00% / 2,568 $4.2 / $5.83

National (% of Total)o / Estimated Total 

Requirement

Average Price ($/MW-hr)p

1.58% / 12,160 $6.15

a Blanke 2018, 146; Estimate

b Blanke 2018, 148; Weighted average of day-ahead market-clearing price c Monitoring Analytics 2017, 56; Average hourly required synchronized reserve requirement for RTO zone

d Monitoring Analytics 2017, 57; The year 2017 weighted average clearing price for Tier 2 synchronized reserve for 

all cleared hours in the RTO zone e Potomac Economics 2018d; The year 2017 ERCOT average responsive reserve requirement f Potomac Economics 2018a, 39; Average annual ancillary service price g Brunette 2013, 12; Ten-minute spinning reserve
18

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

h ISONE 2018, 169; Annual average 10-minute spinning reserve price i Potomac Economics 2018c, A-140

j Potomac Economics 2018c, A-16; Day-ahead 10-minute spinning price for the southeast New York zone. Note that 

the 10-minute spinning price equals the sum of the 10-minute spin component, 10-minute non-spin component, and 

30-minute component. k MISO/Manitoba Contingency Reserves, April 13, 2017

l Potomac Economics 2018b, 38; Average real-time spinning reserve price m Seel, Mills and Wiser 2018, 45 n SPP 2017, 106; Average real-time market-clearing price for spinning reserve in 2017 o Calculated as the weighted average percentage requirement weighted by peak demand of each region

p Calculated as the simple average of the regional price

The procurement requirement (total MW) for non-spinning reserves is typically similar to that of 

spinning reserves (because non-spinning typically replace spinning). They have the lowest 

technical requirements in terms of response rate and are therefore typically the least expensive of 

the market reserve products. Requirements and prices are summarized in Table 8. 

Table 8. Non-Spinning Contingency Reserve Requirements

Market Regions Non-Spinning Requirement (% of 

Peak Demand / MW)

2017 Average Price ($/MW-hr)

CAISO 1.60% / 800 MWa $3.09b

PJM 1.03% / 1,053.2 MWc $2.11d

ERCOT 2.21% / 1,534.5 MWe $3.18f

ISO-NE

10-minute total reserve: 5.98% / 1435

MW

30-minute operating reserve: 3.33% / 

800 MWg

10-minute non-spinning reserve: 

$0.89

30-minute operating reserve: 

$0.82h

NYISO

10-minute total reserve: 4.41% / 1310 

MW

30-minute reserve: 8.82% / 2620 MWi

10-minute non-spinning: $4.18

30-minute component: $4.01j

MISO 0.92% / 1,110 MWk $1.14l

SPP 1.43% / 730 MWm <$1n

Regulated Regions (% of Peak Demand)/ Estimated 

Region Requirement Tariff ($/kW-month / $/MW-hr)

Non-CAISO WECC

(Arizona Public 

Service)

1.50% / 1,590 $0.97 / $1.35

FRCC

(Florida Power & 

Light)

1.31% / 527 $4.83 / $6.71

SERC

(Southern Company) 2.00% / 2,568 $4.20 / $5.83

National (% of Total)o / Estimated Total 

Requirement Average Price ($/MW-hr)p

1.98% / 14,768 $2.92
19

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

a Blanke 2018, 146; Estimate

b Blanke 2018, 148; Weighted average of the day-ahead market-clearing price c Monitoring Analytics 2017, 57; Equals primary reserve requirement minus spinning reserve requirement for RTO 

zone

d Monitoring Analytics 2017, 58; The year 2017 weighted average price of all hours when market-clearing prices 

were above zero for secondary reserve

e Potomac Economics 2018d

f Potomac Economics 2018a, 39; Average annual ancillary service price g ISO-NE 2018b, 11; Summer 2017 requirement; 30-minute operating reserve (TMOR) is on top of 10-minute 

nonspinning reserve (TMNSR) h ISO-NE 2018, 169; Annual average TMNSR and TMOR prices i NYISO 2018c, 43; Potomac Economics 2018c, A-139

j Potomac Economics 2018c, A-16; Day-ahead 10-minute non-spinning price for southeast New York zone. Note 

that the 10-minute non-spinning price equals the sum of the 10-minute non-spinning component and 30-minute 

component.

k MISO 2017b, 3. l Potomac Economics 2018b, 38; Average real-time supplemental reserve price m Seel, Mills and Wiser 2018, 45. 

n SPP 2017, 106; Average real-time market-clearing price for supplemental reserve in 2017 o Calculated as the weighted average percentage requirement weighted by the peak demand of each region p Calculated as the simple average regional price
20

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2.2.4 Ramping Reserve Requirements 

These reserves are an emerging product with limited market data for analysis. Table 9

summarizes the ramping reserve requirements for two markets.

Table 9. Ramping (Flexibility) Requirements by Region

Region Requirement

CAISO

• Maximum flexible ramp up and down requirements are defined as the 2.5% 

and the 97.5% percentile of net load change

• Uncertainty threshold: 

o For the system in the 15-minute market: -1,200 MW in the 

downward direction and 1,800 MW in the upward direction;

o For the system in the 5-minute market: -300 MW and 500 MW in 

the downward and upward directiona

MISO

• Depends on the sum of the forecasted change in net load and an additional 

amount of ramp up/down (575 MW for now)

• Highest hourly average real-time ramp-up requirement: 1,554 MW

• Highest hourly average real-time ramp-down requirement: 1,614 MWb

a Westendorf 2018, 5

b Summarized from MISO 2018; Monthly Market Assessment Report ‘Hourly Average RT Ramp Requirement,’ 

calculated as the simple average across all months in 2017

2.2.5 Total Reserve Requirements

Figure 8a shows the total peak reserve requirements by region.17 For context, we also show the 

reserve requirements compared to the capacity requirements for meeting peak demand in each 

region (Figure 8b). This demonstrates that while reserves are an important part of reliable system 

operation, they are a relatively small fraction of total services. It should be noted that for the 

most part, these services are “mutually” exclusive, meaning that a generator cannot use the same 

MW of reserve capacity for multiple services. However, this chart assumes that PFR is additive 

to existing reserve products despite a lack of established market rules for PFR. It is possible that 

implementation of a PFR market product could reduce the need for other reserve products, or 

that a unit providing PFR could also be used for spinning reserves, which would reduce the 

overall quantity of reserve held compared to Figure 8. For additional discussion of this, see 

Newell et al. (2015).

 17 This chart assumes that PFR is additive to existing market products. 
21

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a) Reserve requirements 

b) Reserve and energy requirements

Figure 8. Total capacity for energy and reserve requirements.

2.3 Other Essential Reliability Services

There are a number of other ERSs, with two of the most important being black-start and voltage 

support. These services are different enough from operating reserves that they are not typically 

categorized as reserve services. A significant difference of these two services relative to most 

operating reserves is that they are typically acquired on a cost-of-service basis. In wholesale 

markets, most operating reserves are acquired on a competitive basis, meaning multiple units can 

bid, and the market operator will acquire the unit that can provide the service at least cost. For 

black-start and voltage support, specific technical and economic issues limit the effectiveness of 

operating a market. The best example is when services are required at a specific location. This 

0%

2%

4%

6%

8%

10%

12%

14%

16%

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Fraction of Annual Peak Demand 

Capacity Needed (MW)

Ramping

Nonspinning

Spinning

Regulation

PFR

Pct Peak Energy

Demand

0

20

40

60

80

100

120

140

160

Capacity Needed (GW)

Ramping

Nonspinning

Spinning

Regulation

PFR

Energy
22

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means that an existing unit at that location would have “market power” or the ability to set a 

price without competition (i.e., a monopoly), so out-of-market procurement becomes necessary.

2.3.1 Black-Start

Black-start represents capacity that can be started without external power and then subsequently 

provide power and energy to start other power plants. Black-start units are typically relatively

small power plants including certain hydroelectric facilities, diesel generators, or small gas 

turbines (FERC 2015).

18 Black-start has historically been procured on a cost-of-service basis, 

even in wholesale market regions (FERC 2017). Each region has specific technical requirements 

for the type and quantity procured. For reference, the total cost of black-start payments in PJM in 

2017 was $72 million or about 0.2% of total costs, while the cost in the New England ISO (ISONE) in 2017 was $12 million (0.1% of total) (PJM 2017, 28; ISO-NE 2018c, 21).

2.3.2 Voltage Support

Ensuring electric system reliability requires maintaining both frequency (maintained largely via 

provision of operating reserves, as discussed in Section 2.2) and voltage. While frequency is 

constant throughout the grid, voltage varies depending on location. To provide reliable service, 

power system operators continuously adjust voltage at various points on the grid to keep voltage 

stable or within a certain tolerance. As with frequency decay, voltage collapse is possible when 

there is insufficient voltage control to maintain steady voltage after an equipment failure on the 

grid.19 Devices that provide voltage control maintain appropriate voltage on the grid during both 

normal operating conditions and fault conditions. 

Voltage is controlled by different methods at different points of the grid. A key element of 

controlling voltage at each point on the grid is the ability to inject or absorb reactive power. 

Reactive power is a property of AC electrical current. It is the portion of current that is out of 

phase with voltage. Because only the portion that is in phase can do work like run motors, heat 

water, or turn the lights on, the additional current goes back and forth on the line without doing 

work, introducing added current that still must be generated. Too much or too little reactive 

power can reduce the flow of power and result in inadequate voltage. Reactive power cannot be 

transmitted over long distances.20 Therefore, voltage control is performed at each of the three 

major parts of the grid, including at the point of generation, at various points in the transmission 

system, and in the distribution network. Reactive power is provided by “active” devices such as 

synchronous generators or power electronics devices or by “passive” devices such as capacitor 

banks. 

Because provision of reactive power is very location dependent, it is typically provided on a 

cost-of-service basis. For an estimate of system costs, in 2017 PJM paid about $309 million for 

“Reactive services” (or about 0.8% of total billing), while ISO-NE paid about $20 million for 

“Volt-ampere-reactive capacity cost” (about 0.2% of total billing) (PJM 2017, 28; ISO-NE 

2018c, 21).

 18 The black-start units themselves need a source of energy to start, but the requirements are small enough to use 

something akin to a “scaled up” car battery. Larger power plants may require many kW or even MW of power to 

start. 

19 An example of an event caused by voltage collapse was the 2003 Northeast Blackout; see DOE (2004). 20 For additional discussion of reactive power, see FERC (2005).
23

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2.4 Relative Total System Costs

In total, the vast majority of generation-related costs are associated with the provision of energy 

and capacity; however, it is difficult to provide an exact breakdown of costs associated with each 

service. Before the advent of restructured markets, there was little attempt to precisely allocate 

the costs of individual services. In most cases generators provide multiple services, and 

allocation of costs among those services was (and still is) challenging. The best example is the 

challenge of differentiating between the cost of energy and capacity in wholesale markets, where 

the cost of capacity is partially captured via energy payments (FERC 2015). Likewise, the cost of 

operating reserves is captured through the variable costs of operating reserve provision, which 

may not entirely capture the cost of capacity needed to provide reserves. 

Despite these challenges, market data, such as that presented in previous sections, can provide 

some idea of the relative value of the various grid services. Table 10 and Table 11 summarize the 

market settlements for ISO-NE and PJM for the year 2017. The data shows that the energy, 

capacity, and transmission costs represent about 97% to 98% of total system costs, with 

operating reserves and other ancillary services accounting for less than 2%. This follows 

historical “bottom up” analysis that estimates that the cost of reserves is typically less than 2% of 

the total cost of grid services (Hummon et al 2013).

Table 10. 2017 ISO-NE Market Settlements Summarya

Billing 

($ Million) Percentage

Energy markets total 4,522 49.50%

Forward capacity market payments 2,244 24.56%

Regional network service 2,163 23.68%

Reserve markets total 70 0.77%

Net commitment-period compensation 52 0.57%

Regulation market 32 0.35%

Financial transmission rights (FTRs) 20 0.22%

Black-start 12 0.13%

Volt-ampere-reactive capacity cost 20 0.22%

Demand-response payments 1 0.01%

Total $9,136 100.00%

a ISO-NE 2018c
24

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Table 11. 2017 PJM Market Settlements Summarya

Billing 

($ Million) Percentage

Energy market 21,087 52.49%

Capacity 9,103 22.66%

Transmissionb 8,739 21.75%

Scheduling 366 0.91%

Reactive services 309 0.77%

Regulation market 104 0.26%

Black-start 72 0.18%

Operating reserves 68 0.17%

Synchronized reserve market 49 0.12%

Day-ahead scheduling reserve market 34 0.08%

Other 241 0.60%

Total $40,172 100.00%

a PJM 2017

b This includes the cost of congestion and losses.
25

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3 Provision of Services from Wind

3.1 Energy and Capacity

More than 1,000 MW of wind generation capacity has been deployed in each of the regions 

analyzed, with the exception of SERC and FRCC. Table 12 summarizes the installed capacity 

and energy production from wind in 2017, along with estimated fraction of demand met by wind.

Table 12. 2017 Wind Energy Provision

Region Installed Capacity (MW) Annual Energy (GWh) Fraction of Demand

(%)

Market Regions

CAISO 6,296 12,823 6.0

PJM 8,141 20,714 2.7

ERCOT 21,704 62,193 17.4

ISO-NE 1,401 3,444 2.6

NYISO 1,826 4136 2.7

MISO 17,000 50,535 7.7

SPP 17,591 58,874 23.2

Regulated Regions

Non-CAISO WECC 16,766 43,967 6.7

FRCC 0 0 0

SERC 237 514 0

Total 87,331 225,585 5.5

The value of the energy and capacity provided by wind is impacted by the variable nature of the 

resource. Wind tends to be somewhat negatively correlated with demand patterns over the 

diurnal and seasonal cycle. This means that wind may be often less valuable than the average 

prices seen earlier in Table 4 (DOE 2018). It also has somewhat limited capacity value based on 

its capacity credit.21 Capacity credit is the actual fraction of the generator’s installed capacity that 

could reliably be used to meet peak demand (or offset conventional capacity), which is typically 

measured as a value (e.g., kW) or percentage of nameplate rating. 

There is considerable literature on methods to estimate generation capacity credit, and the 

various approaches to estimating capacity credit differ in complexity (NERC 2011). However, 

they generally assess the probability of a plant being available during periods of highest net 

demand, which is typically during hot summer afternoons throughout most of the United States. 

Most ISO/RTOs and large utilities with substantial wind deployments have performed capacity 

credit analysis of wind. Table 13 summarizes the capacity credit assigned to wind resource in the 

regions analyzed. It demonstrates that for nearly all regions of the United States, a capacity credit 

 21 Following Mills and Wiser (2012), we use the term “capacity credit” to represent physical capacity, and we use 

the term “capacity value” to represent the monetary value of this capacity.
26

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of significantly less than 50% is applied to wind, with capacity credits well under 20% applied in 

many cases.

Table 13. Capacity Credit by Market Region 

Region Capacity Credit

Market Regions

CAISOa Summer values of about 27%.

PJMb Initially applies 13% of nameplate; after three years of operation, historic 

performance over seasonal peak periods determine unit’s capacity credit.

ERCOTb

Based on average historical availability during the highest 20 seasonal peak load 

hours for each season (2009–2016). Values recalculated after each season with 

new historical data. Current contribution: 58% coastal and 14% noncoastal 

(summer); 35% coastal and 20% noncoastal (winter).

ISO-NEb Summer values average to approximately 13.2% of nameplate rating.

NYISOc Onshore: summer 10%; winter 30%

Offshore: 38%

MISOd

2016 15.6%

2017 15.6%

2018 15.2%

SPP

5% assumed for first three years if the load-serving entity (LSE) chooses not to 

perform the net capability calculation during the first 3 years of operation, after which 

the net capability calculations are applied by selecting the appropriate monthly MW 

values corresponding to the LSE’s peak load month for each season.

Regulated Regions

Non-CAISO 

WECC

Varies. For example, Xcel Colorado uses 16%.

e Portland General Electric uses 5%–

15% for wind resources located in the Pacific Northwest.

f

FRCC Not applicable.

SERC Varies.

a CAISO 2018

b NERC 2017b, Table 10

c NYISO 2018b, 4–24

d MISO 2017a e Xcel Energy 2016

f PGE 2016, 126

3.2 Operating Reserves

While wind was once considered a non-dispatchable “must-take” resource without the ability to 

provide reserves, it is now recognized that the output of a wind turbine can be accurately 

controlled (up to the amount allowed by instantaneous wind speed) (Milligan et al. 2015). This 

allows wind to provide multiple reserve services. Of course, wind has important differences that 

provide both relative advantages and disadvantages compared to more traditional resources. 

Table 14 summarizes the three characteristics of conventional thermal/hydro plants and wind

when providing operating reserves. 
27

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Table 14. Key Parameters for Provision of Operating Reserves for Thermal/Hydro Resources and 

Wind

Parameter Thermal/Hydro Wind

Dispatch Range 

(“how much”)

Min to max, min typically 25% to 50% 

of maxa

0 to max, where maximum output is 

variable (limited by current wind speed)

Ramp Rate (“how 

fast”)

Start time ranges from several minutes 

to hours. Ramp rate when online 

ranges from about 1%/min for 

combined-cycle/coal to 5%/min for 

combustion turbineb

Ramp rate greater than 5%/secondc

Availability of 

Output (“how 

long”)

Typically unconstrained with fuel 

availability

Contingent on wind resource, which has 

increased unpredictability with duration

a Lew et al. 2013

b Lew et al. 2013, Table 2, 34

c Chen et al. 2017

Because wind performance is different from that of conventional generators, the technical ability 

of wind to provide reserves varies by service. In general, the ramp rate capability of wind is 

much higher than that of conventional generators, so the ability of wind to provide reserves is 

largely related to two issues: the economics of pre-curtailment and the predictability of output 

over timescales needed for various reserve services. Note that for the most part, our discussions 

will focus on the provision of upward reserves, as there are few technical constraints on the 

ability of wind to provide downward reserves.22

A key element of providing reserves from wind is the need for pre-curtailment, which incurs the 

opportunity cost of reduced energy sales. Pre-curtailment requires reducing the output of the 

wind turbine, performed by changing the blade pitch angle and reducing the amount of energy 

extracted from the wind. The pre-curtailment requirement reduces the revenue from electricity 

sales for a wind generator providing this service, at least under current market conditions. The 

net revenue of a generation resource providing energy or reserves is the price of that service 

minus the variable cost of providing the service. For wind, the variable cost of providing either 

energy or reserves is about the same (zero). This means that a wind generator will always prefer 

to provide energy instead of reserves as long as the price of energy is greater than the price of 

reserves. Under historical grid conditions, the price of energy has almost always been higher than 

the price of reserves (as indicated by the results in Section 2).

However, as variable generation penetration increases, there may be times when the price of 

energy falls to zero and wind is curtailed. This may also correspond to times when the price of 

reserves is greater than zero, because thermal generators must be kept online to provide 

operating reserves. Under these conditions, it may be economically advantageous—for the wind 

plant and the system—for curtailed wind to provide reserves, and wind can potentially improve 

overall system dispatch by allowing decommitment (turning off) of more costly (on an operating 

basis) generators that are online primarily to provide reserves. Historically, most wind 

 22 An exception to this is policy-related issues. For example, CAISO has often asserted limited ability of wind or PV 

to provide downward reserves because of the need to meet renewable portfolio standards (RPS) obligations. 

(Providing downward reserves reduces energy production from wind when actually deployed.)
28

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curtailment has been due to transmission constraints, where wind would not be able to provide 

reserves, as the location where reserves are needed does not correspond to the location of the 

wind. This has limited the role of wind in providing reserves to date, although there have been 

locations in the United States where wind has been curtailed due to economic conditions 

(including minimum generation constraints on conventional plants) and has provided upward 

reserves (Milligan et al. 2015). Beyond opportunity costs, other costs for wind to provide these 

services, such as additional maintenance costs for equipment wear-and-tear associated with 

greater changes in output, are largely unknown.23

While the need for pre-curtailment is an economic factor, an important technical factor is 

ensuring that headroom will remain available for the response time needed. This issue is 

illustrated in Figure 9, which shows the potential output of a pre-curtailed wind resource. For a 

wind plant to provide reserve service at t=0 it must be pre-curtailed by the amount of service 

desired. But the wind availability must not drop below the maximum output at t=0 for the length 

of the reserve service. In this example, the wind is expected to stay at or above the amount of 

headroom for about 15 minutes. Beyond this point, the potential (maximum) wind output drops 

and there is a reduction in headroom, meaning the wind plant can no longer provide the full 

capacity of the reserve service (without increasing the amount of pre-curtailment). Furthermore,

this output must be predictable for the length of the service (meaning the operator must know

with high confidence the potential plant output if not curtailed). 

Figure 9. The impact of variable output on the ability of wind to provide upward reserve services. 

Following the sequence of reserve deployments in Figure 6 (moving from PFR to non-spinning) 

increases the length of response, along with decreasing the response speed. For conventional 

generators, the technical challenges decrease because only the speed matters for resources 

without fuel supply constraints. For wind, the opposite is true. Wind can increase output very

rapidly, but the duration of response becomes problematic. This means the “how long” 

 23 For additional discussion of this topic see Ela et al. (2014).
29

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component of reserve service from wind is limited by both the likelihood of wind remaining at or 

higher than current output and the predictability of this output. The uncertainty can become a 

particular challenge for scheduling the mix of power plants needed to meet energy and reserves. 

This scheduling often occurs 24 hours or more in advance of when the services are needed, 

making it more challenging to ensure wind output will be available to provide reserves. As a 

result, longer-duration (easier) operating reserve services for conventional generators are more 

difficult services for wind. Improved forecasting, shorter-term scheduling, and taking advantage 

of spatial diversity can all act to mitigate the impact of forecasting challenges for provision of 

reserves from wind. While the forecast accuracy of wind is increasing, the ultimate limit to wind 

headroom is the relatively low capacity credit. A system operator may not be able to plan on the 

availability of wind to provide upward reserves, and insufficient wind during certain periods may 

require other sources of capacity to be available to provide reserves. In this sense, similar to 

provision of energy, wind will act to reduce the variable costs associated with providing reserves, 

but have somewhat limited availability to reduce the fixed costs.

Each of the following subsections provides a more detailed discussion of the ability of wind to 

provide the various reserve services established in Section 2.2. 

3.2.1 Frequency-Responsive Reserves

As discussed in Section 2.2, frequency-responsive reserves are presently provided by 1) the 

inherent physical inertia in the rotating mass in synchronous generators and 2) primary frequency 

response.

Wind generators have demonstrated the ability to provide both an “inertia-like” product and 

PFR, and FERC requires new wind turbines to provide PFR (FERC 2018c). The growing 

deployment of wind (and PV) has also led to further examination of alternative frequency 

response products that are better suited towards a future with a greater presence of inverter-based

machines.

Modern wind turbines do not use synchronous generators and therefore do not provide inertia in 

the traditional sense (defined as automatically resisting changes in frequency). However, wind 

turbines do have kinetic energy in the rotating mass of the blades, shaft, and generator that can 

be extracted to rapidly inject real power into the grid. Provision of inertial service in this fashion 

requires active sensing of grid frequency, so that when a decrease in frequency is sensed, the 

generator can be programmed to increase output to beyond what can be supported by “steady 

state” wind speeds (Ela et al. 2014). This action will slow down the turbine and has limited 

duration.24 However, it can slow down frequency decay long enough for other mechanisms,

including PFR, to arrest and help restore frequency, as illustrated in the sequence shown 

previously in Figure 6.

The provision of inertia from wind turbines in this manner is unique compared to other reserve 

service provisions in that it does not require pre-curtailment of wind. (This also represents a 

substantial difference between wind and other inverter-based technologies such as PV.) 

 24 After the wind turbine has slowed, it must reduce output to increase speed. This means that the turbine must 

temporarily reduce energy output and its generation must be provided by another resource during this recovery 

period. 
30

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Provision of an inertia-like response in this fashion has sometimes been referred to as “synthetic” 

inertia, although this term does not appear to have a uniform definition. For example, it has been 

applied to the provision of rapid response from pre-curtailed PV or battery storage. Again, 

however, actually slowing down wind turbines and extracting kinetic energy is much closer to 

the definition of “real inertia” than increasing output from a pre-curtailed generator. The latter is 

more akin to PFR. Providing upward PFR from wind requires pre-curtailment and establishing 

headroom available for PFR. 

Overall, the combination of extracting energy from rotating wind turbines and using precurtailed wind energy to provide a rapid increase in output can mimic traditional frequencyresponsive reserves. However, it is important to note that because these services do not precisely 

match those from conventional generators, terminology is still in flux. One of the challenges in 

defining frequency-responsive reserves from wind (and other non-synchronous generators) is 

that we are trying to describe somewhat new services using terms established for legacy 

generators. 

Table 15 summarizes some of the terms that have been applied to wind providing frequencyresponsive services. In our review of the literature and after discussions with industry experts, it 

appears that “fast frequency response” (FFR) has emerged as a preferred term that captures the 

ability of non-synchronous generators to inject real power into a grid upon sensing a change in 

frequency (Voges 2017).

25 The difference between FFR and PFR is less clear, although generally 

PFR would reflect a somewhat slower response (but still measured in a few seconds or less). 

While terminology may not be well established, it is still important to distinguish frequency 

response that is derived from extraction of turbine kinetic energy as opposed to from precurtailment, given the potentially economic implication of these different sources.26

Table 15. Terms Applied to Frequency-Responsive Services

Conventional Synchronous Generator Wind (Previous Terms) Wind (Current Terms)

Inertia Synthetic inertia (derived 

from kinetic energy)

FFR (derived from kinetic 

energy)27

PFR PFR from pre-curtailment PFR or FFR (from precurtailment)

Regardless of the name, the ability of wind to provide frequency response from both extraction 

of kinetic energy and increased output from pre-curtailed wind is well established. Major wind 

turbine manufacturers offer this service, and ERCOT requires all new turbines to have FFR

capabilities. However, provision of frequency-responsive services from wind in the United States

is largely limited to ERCOT, as most other regions do not yet require wind to provide these 

reserves; additionally, these services are not a market product, so there is no financial incentive 

for wind to provide them.

 25 A variety of names have been offered for this service. 26 Extracting physical inertia from a wind turbine does not require pre-curtailment and thus does not incur lost 

energy production and lost sales. But pre-curtailment for provision of FFR requires a continual lost opportunity for 

energy production and sales as long as the wind plant is being held at part load to provide reserves.

27 Another proposed term is “inertia-based frequency response” (ERCOT 2018).
31

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Along with the evolving terminology is the evolving manner in which wind can provide 

frequency-responsive services. For example, wind can be “programmed” to provide a response 

similar to that of legacy synchronous generators. But response of those legacy generators is 

constrained by their physical characteristics and limits and is not necessarily perfectly aligned 

with the system’s needs. It is possible that wind response can be optimized to grid requirements 

and vary based on both the current frequency and the rate of change of frequency (ROCOF). 

Additional research is needed to understand how to best optimize provision of FFR from wind to 

maximize its benefits to the grid.

3.2.2 Regulating Reserves

Regulating reserves require a synchronized generator to have the ability to increase or decrease 

output in response to a signal from the system operator. Provision of regulating reserves is well 

within the technical capability of wind power plants in terms of speed and duration, but wind 

requires pre-curtailment to provide upward reserves. Because of this requirement there has been 

limited use of wind to provide regulating reserves, with one example being Xcel Energy in 

Colorado (Milligan et al. 2015). This location is fairly unique, as curtailment has been due to a 

relatively large instantaneous wind penetration as opposed to transmission constraints, which 

have been the major source of curtailment in other locations such as ERCOT.

Because regulating reserves are typically the highest-cost reserve product, we would expect this 

to be the “first” market reserve product to be commonly provided by wind. In U.S. ISO/RTO 

markets, rules for wind providing regulating reserves are unclear, inconsistent, and evolving.

Only a few market ancillary service manuals explicitly call out wind in their discussions of 

service requirements. For example, MISO allows wind to act as a “dispatchable intermittent 

resource” that can bid into a variety of services based on specific requirements for each type of 

reserve. 

3.2.3 Ramping Reserves

As discussed in Section 2.2.5, flexibility/ramping reserves are an emerging market product 

without a uniform definition. However, they are similar to regulating reserves in that they require 

a generator to have the ability to increase or decrease output in response to a dispatch signal. The 

primary difference is that flexibility reserves are generally slower (i.e., lower ramp rate) and 

longer (i.e., requiring the generator to hold output for a longer period). The requirement for a 

plant to be synchronized is inconsistent. Overall, this makes this reserve product easier to meet 

for a conventional generator, and a lower-cost service from the system perspective. As with all 

other services, to provide upward flexibility reserves from wind requires pre-curtailment, which 

makes it more of an economic challenge than a technical one. Whether wind would provide 

flexibility reserves would depend on the opportunity costs. Given their less stringent 

requirements, a flexibility reserve product is likely to have lower costs than regulation. Only in 

likely rare instances when both energy and regulating prices are lower than the price of 

flexibility reserve would wind provide these services.

3.2.4 Contingency Reserves

Generally, spinning contingency reserves must have the ability to: 1) be synchronized to the grid 

and begin responding quickly (within a few seconds); 2) reach setpoint within about 10 minutes;

and 3) hold output for at least 30 minutes (60 in a few locations). For pre-curtailed wind, criteria 
32

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1 and 2 are well within the technical requirements, but the third requirement could be more 

challenging given the greater variability and lower predictability of wind over longer timescales. 

Contingency reserve prices are typically lower than those of regulation, so there is little incentive 

for wind to provide this service, and market rules have limited explicit discussion of wind 

providing it. For example, PJM considers wind as a resource type that “cannot reliably provide 

Synchronized Reserve;” however, resources may request an exception (PJM 2018). 

Non-spinning reserves are an upward-only reserve product that can be provided by online 

generators, or units that can start quickly. This results in non-spinning reserves typically being 

the lowest-cost operating reserve service. Because of this low price, wind has the least incentive 

to provide this service. Furthermore, the long-duration requirement (multiple hours) may limit 

the ability of wind to provide this service given the constraints of predictability and limited 

capacity credit.

3.3 Other Essential Reliability Services

3.3.1 Voltage Support 

The power electronics built into wind turbines are well suited to providing voltage control and 

reactive power. In 2016, FERC issued Order 827 requiring variable generation power plants

larger than 20 MW28 to provide reactive power (FERC 2016), and even before this utilities and 

system operators were increasingly requiring variable generation units to provide voltage control 

(Milligan et al. 2015). Modern wind turbines can also provide reactive power even when not 

generating. However, voltage support is a localized service, and grids often need it in areas 

where it is not possible to place wind turbines (e.g., large urban areas).

3.3.2 Black-Start Capacity

A black-start generator must be able to start on its own without grid power and create a reference 

grid frequency. This provides other generators with sufficient power to energize station power 

requirements, start, and synchronize.

Wind turbines typically start using external grid power. However, these parasitic/operating loads 

are relatively small and could be provided using a battery or small auxiliary generator. Some 

modern wind turbines also have “grid-forming” capacity, or the capability to create an AC 

reference (Göksu et al. 2017).

The primary challenge of black-start capability from wind turbines is their low capacity credit

and variability. To date, there has been very little analysis of the ability of wind to provide blackstart capability in the United States.

29

3.4 Summary

Table 16 summarizes the grid services discussed in this report. In general, both existing practices 

and ongoing research indicate that wind can technically provide nearly all services procured and 

utilized in the grid, but this ability is constrained by the geographical and temporal availability of 

the wind resource. Despite its technical capabilities, wind does not provide all services in U.S. 

 28 Aggregated capacity of the plant, which typically consist of multiple turbines or solar arrays. 29 A discussion of the potential role of wind to provide black-start capability is provided in Miller (2018).
33

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regions currently due to market rules, the aforementioned constraints, and economic 

considerations. Economic considerations include the relative prices or value of the various 

services, competition from other sources, and opportunity costs caused by the fact that most 

reserves require pre-curtailment. Until there is significant curtailment of wind energy, wind will

likely continue to act primarily as an energy resource.

Table 16. Grid Services and Provision from Wind

Service Market Procured 

and 

Compensated 

Service?

Wind Can 

Technically 

Provide?a

Wind Currently 

Provides in 

U.S.?

Requires PreCurtailment for 

Wind to Provide?

Capacity Y Y Y N

Energy Y Y Y N

Inertial 

Response N Y N/A Nob

Primary 

Frequency 

Response

Required but not 

compensated –

proposals only Y Limited Y 

Fast Frequency 

Response

N – proposals 

only Y Limited Y 

Regulating 

Reserves Y Y Limited Y

Contingency –

Spinning Y Y Limited Y 

Contingency –

Non-spinning Y Y No Y 

Contingency –

Replacement Y Maybe No Y 

Ramping 

Reserves

Y (some 

locations) Y Limited Y 

Voltage Support

Y – cost of 

Service

Yc – location

dependent Limited N

Black-Start

Y – cost of 

Service

Unclear, location

dependent No N

a Note that all services require actual wind generation potential (the wind must be blowing). The ability of wind to 

provide all services except where noted is inherently limited by wind’s capacity credit.

b When providing an inertia-like response using extracted kinetic energy. As noted previously, the terminology 

around this service is still evolving.

c This service does not require the wind to be blowing, so it is the only service not limited by the capacity credit of 

wind.
34

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4 Conclusions and Research Needs

Historically, the costs of generator-related services have been dominated by energy and capacity, 

with those comprising more than 95% of total costs. Essential reliability services, while a critical 

part of system operation, are relatively small in terms of both physical capacity and costs. With 

increased deployment of variable generation resources including wind, there is potential for

growth in and changes to essential reliability service requirements—and potential for wind 

energy to provide them. In general, wind has already demonstrated the capability to provide 

multiple reserve services, with response rates that meet or exceed those from conventional 

synchronous generators. The major limitation of wind in providing operating reserves is the need 

to pre-curtail and provide upward headroom. This reduces the amount of energy that can be sold, 

so there is little economic incentive to provide these services in today’s grid. As curtailment 

increases due to greater wind deployment, or as reserve requirements increase, it may become 

more economic for wind to provide reserves. Some reserve services may be less appropriate for 

wind, including services (e.g., replacement or supplemental reserves) that require very long (i.e., 

multiple hour) response time. Wind is far more suited for shorter-term (but more valuable) 

services that can take advantage of wind’s rapid response rate, including fast frequency response, 

primary frequency response, and regulating reserves. 

This work points to several areas of additional analysis needed to better understand the role of 

wind in providing grid services. Data presented in this work considers historical conditions and 

does not reflect changes that may occur under increased penetration of variable generation. 

Further analysis is needed to determine both the types and quantities of reserves needed to 

address greater variablity and uncertainty of net load under future grid conditions. An important 

consideration is the evolution of energy markets under these future conditions. A variety of 

technologies including wind can provide services needed by the grid, but market products may 

need to be altered to align the technical needs with appropriate economic incentives. This will 

ensure services are provided by the technologies that can do so in the most cost-effective manner 

while enabling continued or increased grid reliability.
35

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