An Introduction to Grid Services: 

Concepts, Technical Requirements, 

and Provision from Wind

Paul Denholm, Yinong Sun, and Trieu Mai
NREL | 2

Current Grid Services

Provision of Grid Services from Wind

Conclusions and Research Needs

Introduction
Introduction

• Geographical Scope 

• Regions Analyzed
NREL | 4

Geographical Scope and Regions Analyzed

Market Regions Estimated 

Electric 

Demand (TWh / 

% of U.S.)

Estimated 

Population 

(million / % of 

Total)

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%
Current Grid Services

• Energy and Capacity 

• Operating Reserves 

• Other Essential Reliability Services

• Relative Total System Costs
NREL | 6

Current Grid Services

• 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.

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
NREL | 7

Historical Capacity Requirements

Region Peak Demand (GW)

2016 2017

CAISO 46.2a 50.1a

PJM 152.2c 145.6c

ERCOT 71.1e 69.5e

ISO-NE 25.6g 24.0g

NYISO 32.1i 29.7i

MISO 121.0k 120.6k

SPP 50.6m 51.2m

Non-CAISO WECC 110.8o 106.0o

FRCC 47.7q 46.6q

SERC 129.0s 132.2s

Totalt 786 775

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

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

additional capacity to address outages or unanticipated increases in demand.
NREL | 8

2020 Estimated Regional Capacity Requirements

All U.S. regions are expected to have adequate generation capacity

to meet peak demand in the near future.

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

CAISO 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

U.S. Power System Peak Capacity Requirement Estimates
NREL | 9

Energy Capacity Costs and Prices

• Most costs associated with power system generation are the fixed and 

variable costs associated with providing capacity and energy.

• 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.

• Most U.S. regions have more capacity than is needed for resource 

adequacy/planning reserve targets, which tends to suppress capacity 

market prices.
NREL | 10

Energy Capacity Costs and Prices

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

U.S. Power System Energy Requirements
NREL | 11

Operating Reserves

Defined as the capability above firm system demand required to provide for 

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

area protection.

Distinctions can be

characterized by three factors: 

• How much

• How fast

• How long

There are no uniform definitions

for various operating reserve products.
NREL | 12

Timescales of Operating Reserve Requirements

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
NREL | 13

Operating Reserves

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).

Frequency-Responsive Reserves

• Inertial Response

• Primary Frequency Response

• Fast Frequency Response

Regulating Reserves

During normal operation, reserves are still required to meet random variations

in net load
NREL | 14

Operating Reserves

Contingency Reserves

• Spinning Reserves

• Non-Spinning/Supplemental Reserves

Ramping Reserves

• Least well defined of the reserve products

• Not yet a common market product

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.
NREL | 15

Frequency-Responsive Reserve Requirements

Frequency-responsive reserves traditionally consist of two services:

• Inertial response 

• PFR

• Neither inertial response nor PFR is a market product in any ISO/RTO market

Inertial Response

• Not much detailed estimation of inertial response requirements in U.S.

• Growing analysis of potential need to procure inertial response services

• Only ERCOT has studied the amount of inertia potentially “required”

• Requirement is measured in energy—how much energy can be injected 

rapidly into the system

• Often measured in GW-seconds

• No “headroom” component of inertial response

• The amount of inertia that can be provided by a generator is independent 

of instantaneous power output
NREL | 16

Frequency-Responsive Reserve Requirements

PFR

• NERC has 

established 

minimum 

recommended 

standards for PFR 

for each of the 

three U.S. grids

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%

• Each interconnection has a frequency response obligation

• Further divided by BA in proportion to demand so that each region 

“shares” its obligation

Primary Frequency Response Obligation
NREL | 17

Regulating Reserve Requirements and Costs

• Regulating reserves are a market product in each ISO/RTO

• 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

• Typically the most costly of the reserve services
NREL | 18

Regulating Reserve Requirements and Costs

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

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

Regulating Reserve Requirements
NREL | 19

Contingency Reserve Requirements and Costs

The actual quantity 

procured is typically 

greater than 

regulation 

requirements, but 

the price is typically 

lower due to the 

infrequent ramping 

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

Spinning Contingency Reserve Requirements
NREL | 20

Contingency Reserve Requirements and Costs

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.

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
NREL | 21

Ramping Reserve Requirements 

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

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
NREL | 22

0%

2%

4%

6%

8%

10%

12%

14%

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

Total Reserve Requirements
NREL | 23

Total Energy and Reserve Requirements

0

20

40

60

80

100

120

140

160

Capacity Needed (GW)

Ramping

Nonspinning

Spinning

Regulation

PFR

Energy
NREL | 24

Other Essential Reliability Services

• There are a number of other ERSs; two of the most important are:

• Black-start 

• Voltage support

• A significant difference from other services is that these are typically 

acquired on a cost-of-service basis
NREL | 25

Black-Start

• Represents capacity that can be started without external power and then 

subsequently provide power and energy to start other power plants

• Typically relatively small power plants including certain hydroelectric 

facilities, diesel generators, or small gas turbines

• Historically been procured on a cost-of-service basis, even in wholesale 

market regions

• Each region has specific technical requirements for the type and 

quantity procured
NREL | 26

Voltage Support

• Ensuring electric system reliability requires maintaining both frequency and voltage

• Frequency is constant throughout the grid.

• Voltage varies depending on location.

• 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.

• Key element of this is the ability to inject or absorb reactive power.

• Reactive power cannot be transmitted over long distances.

• 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. For additional discussion of reactive 

power.

• Reactive power is provided by “active” devices such as synchronous generators or 

power electronics devices or by “passive” devices such as capacitor banks. 
NREL | 27

Relative Total System Costs

• Vast majority of generation-related costs are associated with the provision of 

energy and capacity

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%

2017 ISO-NE Market Settlements Summarya 2017 PJM Market Settlements Summaryb

Billing 

($ Million) Percentage

Energy market 21,087 52.49%

Capacity 9,103 22.66%

Transmissionc 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%
Provision of Grid 

Services from Wind

• Energy and Capacity 

• Operating Reserves 

• Other Essential Reliability Services
NREL | 29

Provision of Services from Wind

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.

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

2017 Wind Energy Provision 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.
NREL | 30

Energy and Capacity

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

performed capacity credit analysis of wind.

• The following table demonstrates that for nearly all regions of the United 

States, a capacity credit of significantly less than 50% is applied to wind, 

with capacity credits well under 20% applied in many cases.
NREL | 31

Energy and Capacity

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.

Capacity Credit by Market Region
NREL | 32

Operating Reserves

• Wind was once considered a non-dispatchable “must-take” resource without the 

ability to provide reserves

• Now recognized that the output of a wind turbine can be accurately controlled (up 

to the amount allowed by instantaneous wind speed)

• Wind has important differences that provide both relative advantages and 

disadvantages compared to more traditional resources.

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 is 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 combinedcycle/coal to 5%/min for combustion 

turbine

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
NREL | 33

Operating Reserves

• Wind performance is different from that of conventional generators

• Technical ability of wind to provide reserves varies by service

• 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

• Pre-curtailment requirement reduces the revenue from electricity sales for a 

wind generator providing this service, at least under current market conditions

• Wind generators will always prefer to provide energy instead of reserves as long as 

the price of energy is greater than the price of reserves.
NREL | 34

Operating Reserves

• As variable generation penetration increases, there may be times when the price of 

energy falls to zero and wind is curtailed.

• Under certain 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.

• Most wind 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.
NREL | 35

Operating Reserves

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.

Impact of variable output on the ability of wind to provide upward reserve services
NREL | 36

Operating Reserves

• Wind can increase output very rapidly, but the duration of response becomes 

problematic.

• The “how long” 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.

• 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.

• Wind will act to reduce the variable costs associated with providing reserves, but 

have somewhat limited availability to reduce the fixed costs.
NREL | 37

Frequency-Responsive Reserves

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

product and PFR, and FERC requires new wind turbines to provide PFR.

• Modern wind turbines do not use synchronous generators

• Do not provide inertia in the traditional sense (defined as automatically 

resisting changes in frequency)

• 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.

• 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.
NREL | 38

Frequency-Responsive Reserves

• 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.

• Sometimes been referred to as “synthetic” inertia

• Combination of extracting energy from rotating wind turbines and using 

pre-curtailed wind energy to provide a rapid increase in output can mimic 

traditional frequency-responsive reserves

• These services do not precisely match those from conventional 

generators.

• Terminology is still in flux.
NREL | 39

Frequency-Responsive Reserves

• “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.

• Difference between FFR and PFR is less clear; generally PFR would reflect a 

somewhat slower response (but still measured in a few seconds or less)

• Still important to distinguish frequency response that is derived from 

extraction of turbine kinetic energy as opposed to from pre-curtailment, 

given the potentially economic implication of these different sources

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

Inertia Synthetic inertia (derived 

from kinetic energy)

FFR (derived from kinetic 

energy)

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

Terms Applied to Frequency-Responsive Services
NREL | 40

Frequency-Responsive Reserves

• 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.

• ERCOT requires all new turbines to have FFR capabilities.

• Manner in which wind can provide frequency-responsive services is also 

evolving

• Can be “programmed” to provide a response similar to that of legacy 

synchronous generators

• It is possible wind response can be optimized to grid requirements and 

vary based on both the current frequency and the rate of change of 

frequency (ROCOF).
NREL | 41

Regulating Reserves

• Require synchronized generator to have the ability to increase or decrease 

output in response to a signal from the system operator

• Wind requires pre-curtailment to provide upward reserves

• There has been limited use of wind to provide regulating reserves, 

with one example being Xcel Energy in Colorado.

• Regulating reserves are typically the highest-cost reserve product

• Rules for wind providing regulating reserves are unclear, inconsistent, and 

evolving in U.S. ISO/RTO markets
NREL | 42

Ramping Reserves

• 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.

• 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)

• Makes this reserve product easier to meet for a conventional 

generator, and a lower-cost service from the system perspective

• A flexibility reserve product is likely to have lower costs than regulation.
NREL | 43

Contingency Reserves

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

3. Hold output for at least 30 minutes (60 in a few locations)

• For pre-curtailed wind, criteria 1 and 2 are well within the technical requirements.

• 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.

• Little incentive for wind to provide this service, and market rules have limited 

explicit discussion of wind providing it
NREL | 44

Contingency Reserves

Non-spinning Contingency Reserves

• Upward-only reserve product that can be provided by online generators, or units 

that can start quickly

• Non-spinning reserves typically the lowest-cost operating reserve service

• Long-duration requirement (multiple hours) may limit the ability of wind to provide 

this service given the constraints of predictability and limited capacity credit
NREL | 45

Other Essential Reliability Services

Voltage Support

• Power electronics built into wind turbines are well suited to providing voltage 

control and reactive power. 

• Variable generation power plants larger than 20 MW must provide reactive power

• Aggregated capacity of the plant, which typically consists of multiple turbines 

or solar arrays

• Modern wind turbines can also provide reactive power even when not generating.

• Voltage support is a localized service, and grids often need it in areas where it is not 

possible to place wind turbines.
NREL | 46

Other Essential Reliability Services

Black-Start Capacity

• Must be able to start on its own without grid power and create a reference grid 

frequency

• Provides other generators with sufficient power to energize station power 

requirements, start, and synchronize

• Wind turbines typically start using external grid power.

• Parasitic/operating loads are relatively small and could be provided using a battery 

or small auxiliary generator.

• Some have “grid-forming” capacity, or the capability to create an AC reference.

• Primary challenge of black-start capability from wind turbines is their low capacity 

credit and variability.

• There has been very little analysis of the ability of wind to provide black-start 

capability in the United States.
NREL | 47

Summary – Grid Services from Wind

• 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.

• Wind does not provide all services in U.S. regions currently due to market 

rules, the aforementioned constraints, and economic considerations.

• Until there is significant curtailment of wind energy, wind will likely 

continue to act primarily as an energy resource.
NREL | 48

Summary – Grid Services 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 – Nonspinning 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
Conclusions and 

Research Needs
NREL | 50

Conclusions

• There is potential for growth in and changes to essential reliability service requirements—and 

potential for wind energy to provide them.

• Wind has already demonstrated the capability to provide multiple reserve services, with 

response rates that meet or exceed those from conventional synchronous generators.

• Major limitation in providing operating reserves is the need to pre-curtail and provide upward 

headroom

• Reduces the amount of energy that can be sold

• 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.

• Wind is far more suited for shorter-term (but more valuable) services that can take advantage 

of wind’s rapid response rate, including FFR, PFR, and regulating reserves.
NREL | 51

Research Needs

• Further analysis is needed to determine both the types and quantities of reserves 

needed to address greater variability and uncertainty of net load under future grid 

conditions.

• 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.
www.nrel.gov

Read the full report: 

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

NREL/PR-6A20-73590

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 Technologies Office. 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 

and the publisher, by accepting the article for publication, acknowledges that 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.