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.

Contract No. DE-AC36-08GO28308

Evolution of Operating Reserve 

Determination in Wind Power 

Integration Studies 

Erik Ela and Michael Milligan

National Renewable Energy Laboratory

Brendan Kirby

Private Consultant

Eamonn Lannoye, Damian Flynn, and

Mark O’Malley

University College Dublin

Bob Zavadil

EnerNex

Presented at the 2010 IEEE Power & Energy Society General 

Meeting

Minneapolis, Minnesota

July 25-29, 2010

Conference Paper

NREL/CP-5500-49100

March 2011
NOTICE

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1

Abstract−The growth of wind power as an electrical power 

generation resource has produced great benefits with reductions 

in emissions and the supply of zero cost fuel. It also has created 

challenges for the operation of power systems arising from the 

increased variability and uncertainty it has introduced. A 

number of studies have been performed over the past decade to 

analyze the operational impacts that can occur at high 

penetrations of wind. One of the most crucial impacts is the 

amount of incremental operating reserves required due to the 

variability and uncertainty of wind generation. This paper 

describes different assumptions and methods utilized to calculate 

the amount of different types of reserves carried, and how these 

methods have evolved as more studies have been performed.

Index Terms−operating reserves, power system operation, 

power system reliability, power systems, wind power generation

I. INTRODUCTION

IND power has seen rapid growth in the past decade. Its 

zero-cost fuel and emissions-free output provide great 

benefits to consumers and society. Utility-scale wind is a new 

resource and is increasing at such a rapid rate that utilities and 

system operators are becoming concerned about the 

integration issues and costs that it introduces. Wind power 

integration studies have been performed by numerous entities 

to help understand and quantify these impacts [1], [2]. The 

studies typically simulate a future power system with high 

wind penetrations, and evaluate the impacts on the grid and 

the incremental operating costs that result [3]. These studies 

have been maturing continuously as the state of the art 

advances, with each study generally building on previous 

studies.

Some of these studies have compared the costs and 

operational differences between a system with high wind 

penetration and a system that does not bring the incremental 

variability and uncertainty that wind presents. The additional 

costs generally occur because the unit commitment is 

inefficient due to forecast errors and because it is adjusted to 

provide more flexibility, accommodating wind’s increased 

variability and uncertainty. Additional flexibility can be in the 

form of increased ramp rates, decreased minimum generation 

limits, and increased amounts of operating reserve. Noting that 

these are studies and that the results should be realized as 

such, much controversy often occurs over these costs due to 

the many assumptions that are required. For example, wind 

forecasts used in the study are usually based on a model of 

how a forecast may be produced some time in the future 

(looking at a past weather year). Since predicting the actual 

output of the wind resource from a model is a difficult task in 

itself, predicting what the forecast error may be can add more 

uncertainty to the results.

Secondly, the determination of operating reserves has been 

analyzed using many different methodologies and can differ 

significantly from study to study. Operating reserves are 

subject to many different naming conventions in different 

regions throughout the world. This paper defines operating 

reserve as the real power capacity that can be called on at any 

instance of imbalance between generation and load.1

This paper will focus on methods of determining operating 

reserves for power systems with high penetrations of wind 

power. Section II will describe current practices and 

definitions of operating reserves in North America, mainland 

Europe, and Ireland. Section III will cover some recent wind 

power integration studies that have been performed, and will 

focus on the methods used in each study when calculating the 

operating reserve requirements. In section IV, the authors will 

provide insight into the strengths of different methods, 

including analysis on how the operating reserve determination 

problem may change in wind power integration studies and in 

actual system operations. Section V concludes the discussion.

Most 

wind power integration studies run hourly simulations of bulk 

power system operations for a particular study area, and 

therefore the actual utilization of the designated operating 

reserve capacity is not in fact realized in detail. Therefore, 

operating reserve requirements are determined statistically, but 

usually not validated in simulations. Two important objectives 

that often form part of these studies are the costs or savings of 

integrating additional wind power, and the operational 

changes that are recommended at high penetrations of wind 

power. Many of the studies recommend the use of incremental 

operating reserves, which will also affect the total costs. This 

makes the assumptions used in the methodology to assess 

operating reserve a very important component of the overall 

study. Many areas will adopt these methodologies from the 

studies as wind penetrations increase and therefore, it is 

additionally important for actual system operations in the 

future.

II. OPERATING RESERVE DEFINITIONS AND STANDARDS

Variability and uncertainty are not unique to wind 

generation; similar characteristics in aggregate electric 

demand and even supply resources have always posed 

challenges for power system operators. Future loads cannot be 

perfectly predicted, loads and generator outputs can vary 

 1 Additionally, operating reserves or ancillary services can include voltage 

or reactive power support as well as black start service.

Evolution of Operating Reserve Determination 

in Wind Power Integration Studies

Erik Ela, Member, IEEE, Brendan Kirby, Senior Member, IEEE, Eamonn Lannoye, Student Member, 

IEEE, Michael Milligan, Senior Member, IEEE, Damian Flynn, Member, IEEE, Bob Zavadil,

Member, IEEE Mark O’Malley, Fellow IEEE

W
2

substantially in different time frames, and large power system 

equipment can fail at any given time without notice. Power 

system operators secure different amounts and types of 

operating reserves to compensate for these characteristics in 

order to serve load reliably and maintain the system 

frequency. There are many different definitions and rules 

concerning what operating reserves entail. For example, the 

North American Electric Reliability Corporation (NERC) 

defines operating reserves as the following:

“That capability above firm system demand required to 

provide for regulation, load forecasting error, equipment 

forced and scheduled outages and local area protection. It 

consists of spinning and non-spinning reserve.” [4]

In most of North America, these reserves can be further 

placed in three categories:

• Spinning reserve – The portion of Operating Reserve 

consisting of: Generation synchronized to the system 

and fully available to serve load within the Disturbance 

Recovery Period following the contingency event; or 

Load fully removable from the system within the 

Disturbance Recovery Period following the 

contingency event.

• Supplemental reserve – The portion of Operating 

Reserve consisting of: Generation (synchronized or 

capable of being synchronized) that is fully available to 

serve load within the Disturbance Recovery Period 

following the contingency event; or Load fully 

removable from the system within the Disturbance 

Recovery Period following the contingency event.

• Regulating Reserve – An amount of reserve responsive 

to Automatic Generation Control which is sufficient to 

provide normal regulating margin.

Further definitions can separate the second category by 

response time and response sustainability. In North America, 

the spinning reserve and supplemental reserve described above 

are often combined and referred to as “contingency reserve,” 

only being used for instances of generator or network 

contingency events. Though contrary to the NERC definition 

of operating reserve described above, regulating reserve is 

generally procured in both the upward and downward 

directions (i.e., in cases of over-generation). Fast frequency 

response (governor response) is not yet explicitly addressed by 

NERC as a distinct operating reserve, but the Western 

Electricity Coordinating Council (WECC) has started to study 

the need for a 30-second response; frequency responsive 

reserve (FRR). Transmission also impacts the need for 

operating reserves, since it can provide access to additional 

reserve supplies and reduce the overall need for reserves by 

increasing the reserve sharing pool. Limited transmission may 

also mean more localized reserve requirements. Transmission 

lines may be operated at levels below their maximum 

capacities to account for other transmission contingencies, 

similar to generator operating reserve.

Other standards and policies detail how much a balancing 

area will require of each type of operating reserve [4]. For 

instance, the NERC BAL-002 standard requires that a 

balancing authority or reserve sharing group maintain at least 

enough contingency reserve to cover the most severe single 

contingency. For the western interconnection, this is extended 

by a proposal by WECC to state that the minimum amount of 

contingency reserve should be the greater of the most severe 

single contingency or the sum of 3% of the balancing area 

load and 3% of the balancing area generation. Detailed 

specifications of contingency reserve requirements, including 

the amount of spinning compared to supplemental reserve, are 

established by each Regional Reliability Organization. 

Regions typically require at least half of the contingency 

reserve to be spinning. An example of how reserves are 

deployed following a contingency is provided in Fig. 1.

Regulating reserve usually does not include explicit 

requirements. Instead, balancing areas will maintain sufficient 

regulating reserves so that they meet their CPS1 and CPS2

performance requirements. In some areas that currently have 

high penetrations of wind power, such as the Electric 

Reliability Council of Texas (ERCOT), the forecasted wind 

power output is considered when defining regulating and other 

types of operating reserve requirements [5].

Fig. 1. Reserve deployment as defined by NERC [6]

In Europe, broad guidelines are given by the former 

transmission system operator (TSO) groupings such as Nordel

and the Union for Coordination of Transmission of Electricity 

(UCTE), now part of the European Network for Transmission 

System Operators for Electricity (ENTSO-E). ENTSO-E 

defines reserve in three categories; primary, secondary, and 

tertiary control [7]. Primary control is activated when system 

frequency deviates by 20 mHz from the set point value 

(nominally 50 Hz) and must be fully operational within 30 

seconds. The purpose of primary control is to limit the 

deviation of system frequency following a system event.

Secondary control consists of units controlled by automatic 

generation control (AGC) and fast starting units. These are 

engaged 30 seconds after a contingency event and must be 

fully operational within 15 minutes. This category of control 

attempts to restore the frequency to its nominal value and 

reduce the area control error. Tertiary control has a slower 

response and is engaged to restore primary and secondary 

control units back to the reserve state.

-10 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150

Minutes

Contingency

Occurs

Spinning & Non-Spinning Reserve

Frequency

Response

Reserves "Should" 

be Restored

Reserves 

"Must" be 

Restored

Market Response

Supplemental Operating Reserve
3

Fig. 2. ENTSOE-UCTE control mechanisms [7]

The Irish system represents a much smaller, isolated power 

system, and has a more granular approach to its definition of 

reserve [8]. There are five main types including: regulating, 

operating, replacement, substitute, and contingency reserves. 

Regulating reserve acts within 30 seconds of a frequency 

deviation to restore the frequency to within 0.1 Hz of the set 

point value and controls inter-system transfers on the NorthSouth interconnector that joins the two systems on the island.

This is a subset of primary operating reserve. Operating 

reserve, as defined in the Irish system, is divided into three

parts: primary, secondary, and tertiary operating reserve. 

Primary reserve acts for the first 15 seconds to avoid transient 

nadirs below 49 Hz. Secondary reserve then acts to avoid 

continuous system operation below 49.5 Hz, and it is fully 

available from 15 seconds after an event for a further 75 

seconds. Tertiary operating reserve is used to replace the 

primary and secondary reserve. It is split into Tertiary1, which 

restores primary and secondary operating reserve for the first 5 

minutes and Tertiary2 reserve which is available after 5 

minutes for an additional 15 minutes.

Replacement reserve acts as a longer term resource to 

restore secondary and tertiary operating reserve from 

operation. This is fully available within 20 minutes for a four 

hour period. Substitute reserve is utilized to restore 

replacement reserve after 4 hours for a duration of 24 hours 

and is available for the replacement of emissions-restricted 

plants. Contingency reserve is available to restore all reserves 

24 hours after the event.

The names and definitions for operating reserve across

different parts of the world vary but the functionality is very 

similar. Systems of different sizes and with different 

generation or load characteristics may require different 

response requirements or different qualifications on how the 

operating reserve is provided. However, it is important to note 

that regardless of category, response time, and qualifications, 

operating reserves as discussed here are all secured and 

utilized for essentially the same reason; imbalance between 

generation and load. Thus, to offer clarity and reduce 

confusion between North American and European readers, 

Table I displays the terminology that will be used throughout 

the rest of this paper. Reference [9] also shows a detailed 

mapping and descriptions of a subset of these terms for active 

power control as well as for voltage control services.

TABLE I

NAMES AND DEFINITIONS OF RESERVES

Name Definition Common terms

Operating 

Reserve

Used for an imbalance between

generation and load at any time. All 

other reserve categories are a subset 

of this.

Operating reserve

(U.S.), reserve, 

balancing reserve

Spinning 

Reserve

Any of the categories where the 

resources are frequency responsive 

and begin responding immediately. 

Generators providing this service 

must have been committed. 

Spinning reserve, 

synchronous 

reserve, on-line 

reserve, responsive 

reserve

Non-Spinning 

Reserve

Similar to spinning reserve but the 

resources do not need to respond to 

frequency autonomously or begin 

responding immediately. 

Generators providing this service 

do not have to be committed. 

Upward only.

Non-spinning 

reserve, nonsynchronous 

reserve, off-line 

reserve, quick start 

reserve

Contingency 

reserve

Used during instantaneous failures 

(e.g., generator failures). 

Contingency reserves may include 

other types (e.g. frequency 

responsive, spinning, non-spinning, 

and supplemental). Upward only

Contingency 

reserve (U.S.), 

operating reserve 

(Ireland), primary 

and secondary

reserve (Europe)

Regulating 

Reserve

Used for frequency control and 

maintaining area control error 

during normal (non-event) 

conditions in a time frame that is 

faster than energy markets clear.

Due to random movements.

Requires automatic generation 

control. Upward and downward.

Regulating reserve, 

frequency control

Load 

following 

Reserve

Used for frequency control and 

maintaining area control error 

during normal (non-event) 

conditions. Due to non-random 

movements. Slower movements 

than regulation. Does not require 

automatic generation control.

Upward and downward.

Load following, 

dispatch

Frequency 

Responsive 

Reserve

Reserves that provide the initial 

autonomous response to a major 

disturbance. Upward and

downward.

Governor response, 

primary control

(Europe), FRR

Ramping 

Reserves

Used during failures and events that 

are not instantaneous, but occur 

over long time frames (e.g., wind 

ramps, forecast errors). Upward and 

downward.

Variable generation 

event reserve, 

forecast error 

reserve

Supplemental 

Reserve

Reserve that replaces faster reserve 

so that the system is secure and the 

level of pre-event reserve is 

restored. Upward only.

Replacement 

reserve, 

supplemental 

reserve, tertiary 

reserve (Europe), 

contingency reserve 

(Ireland), substitute 

reserve

The objective behind Table 1 is to define a consistent set of 

categories based on the purpose of their deployment and any 

differences in how they are provided. Note that any of these 

categories could have numerous response time definitions as 

the current standards generally do. Fig. 3 shows a hierarchical 

diagram of the defined operating reserves and how they may 

be interrelated. Note that the definitions of spinning and nonspinning reserve are characteristics of each of the other types, 

as seen in fig.3.
4 

Fig. 3. Operating Reserve Diagram

III. RESERVE DETERMINATION IN WIND INTEGRATION 

STUDIES

In the past several years, various organizations have 

participated and/or initiated wind power integration studies. 

The studies evaluate a power system in the future with high 

wind power penetrations and simulate the impacts that occur. 

A general process for wind power integration studies can be 

found in [10]. 

A major component of each study is to evaluate the 

incremental need for additional operating reserves for the 

future system that result from high wind penetration. The 

study teams usually consider traditional definitions and 

requirement determinations, and propose needed changes to 

maintain reliability while accommodating the variability and 

uncertainty present in the wind power. This value is generally 

calculated via statistical methods analyzing wind power time 

series data that are modeled for the study. The methodologies 

used to compute these values have evolved as each study 

learns from past studies. The most recent studies evaluating 

very high penetrations are using sophisticated methodologies 

that are diverging further from the traditional methods used 

today in actual system operations. 

In the U.S., the first two major wind power integration 

studies were performed in the states of New York and 

Minnesota [1], [2]. In New York, the study evaluated 3,300 

MW of wind power on the 33,000 MW peak load NYISO 

system. The study concluded that no incremental contingency 

reserves would be needed since the largest single severe 

contingency would not change. The study concluded that an 

additional 36 MW of regulating reserve was required on top of 

the current 175 - 250 MW procured today. This is a result of 

analyzing the standard deviation of 6-second changes in load 

net of wind compared with that of load alone. The standard 

deviation with wind increased from 71 MW to 83 MW, 

presenting a 12 MW increase. As was the current guideline in 

New York, the total standard deviation is multiplied by three 

to ensure that the total regulation requirement is sufficient to 

cover 99.7% of all instances, thus giving the 36 MW increase. 

In Minnesota, the study evaluated 15, 20, and 25% wind 

energy as a percentage of total annual demand (3441 MW, 

4582 MW, and 5688 MW of wind on a system with a peak 

demand of roughly 20,000 MW). Similar to New York, it was 

concluded that there would be no impact on the contingency 

reserve requirement with the added wind penetrations. The 

regulating reserve requirement similarly evaluated the added 

variability of wind, but calculated it to be a 2 MW standard 

deviation for every 100 MW wind plant installed. This 

calculation was based on operational data from existing wind 

plants. The ratio was used to calculate the regulating reserve 

requirement as seen in equation (1). 

where k is a factor relating regulation capacity requirements to 

the standard deviation of the regulation variations (assumed to 

be 5 in this study, reflecting current practices); σload is the 

standard deviation of regulation variations from load; σW100 is 

the standard deviation of regulation variations from a 100 MW 

wind plant; and N is the wind generation capacity in the 

scenario divided by 100. The results showed increases of 12, 

16, and 20 MW for the 15, 20, and 25% cases, respectively. 

The Minnesota study quantified two other defined 

categories that the New York study did not. In the study, these 

are defined as load following and operating reserve margin 

(load following reserve and ramping reserve in Table I). Load 

following was calculated as twice the standard deviation of the 

five minute changes in the net load, and increases ranged from 

10 to 24 MW for the three cases. The operating reserve margin 

was allocated specifically for hourly forecast errors in the net 

load. This analysis assumed a dynamic requirement, one that 

was not constant for all hours, but in fact was a function of the 

amount of expected wind capacity. The consideration was that 

the variability of wind is highest when the wind capacity is in 

the middle range (i.e., 40-60% of total capacity) due to the 

wind turbines being on the steepest parts of their wind speed 

to wind power conversion curves. Therefore, more reserve 

was needed for the middle range compared to times of very 

low wind generation or times of very high wind generation. 

These studies paved the way for future thinking of how 

operating reserves should be handled with high penetrations of 

wind. More recent studies have evolved and taken the ideas 

from those preceding studies with increasing sizes, 

penetrations, and scopes. The traditional definitions and 

methods used in current operations were simply not feasible 

with penetrations of 20% wind energy and more. Next, we 

will focus on two recently completed studies and describe the 

operating reserve determination methods explored in each. 

A. All Island Grid Study (Ireland) 

The All Island Grid Study in Ireland was published in 2007 

and examined, among other things, the Irish system’s ability to 

integrate various penetrations of wind generation [11]. Six 

plant portfolios were examined to meet the load forecasted for 

2020. Portfolio 1 contained 2 GW of wind; 2, 3, and 4 

contained 4 GW; portfolio 5 contained 6 GW; and portfolio 6 

contained 8 GW of wind generation. This is in the context of 

a projected peak load of 9,618 MW and a load factor of 

63.9%. The study involved hourly scheduling of the system 

with the WILMAR system planning tool [12]. 

The study incorporated a refined implementation for reserve 

provision with only two categories specified in the model; 

spinning and replacement reserve. The definition of a unit 

capable of meeting the replacement reserve standard was an offline unit with a start up time of less than 60 minutes and online 

units whose capacity was not allocated to the spinning reserve 
5

requirement. This is a highly simplified model given the 

existing structure of reserve provision in the Irish system. The 

requirements for spinning and replacement reserve were based 

on a mixture of existing and proven requirements and newer 

techniques for the provision of reserve for wind generators.

The spinning reserve requirement is calculated as being the 

size of the largest on-line unit plus an additional contribution 

for wind generation, calculated based on the work in [13]. 

Ireland is an island system with one 500 MW interconnector 

in operation and a 500 MW interconnector under construction. 

System modeling for the year 2020 assumed that 100 MW of 

spinning reserve can be obtained through interconnection. 

Another 50 MW of reserve is assumed to be provided from 

interruptible contract loads. Of the remainder, a maximum 

constraint of 50% of reserve demand can be provided by 

pumped storage. Wind generators are allowed to provide 

spinning reserve through curtailment.

The demand for spinning reserve is illustrated in Fig. 4 on a 

weekly averaged basis. Spinning reserve is required more 

frequently as the amount of wind increases in the portfolio, 

significantly so in portfolio 6. The scheduled outage of the 

largest unit on the system (480MW CCGT unit) is seen to 

reduce the spinning reserve requirement significantly during 

weeks 31 to 34. While the variable generation requires 

additional spinning reserve, the largest contributing factor 

remains the loss of the largest conventional unit.

Fig. 4. Weekly demand for spinning reserve for each generation portfolio

Replacement reserve is calculated as a function of the 

possible forced outages of units and an additional margin 

which is a function of the 90th percentile of the net load (loadwind) forecast for each particular scenario. The 90th percentile 

was chosen as it most closely matches experience with proven 

reserve standards. WILMAR implements rolling unit 

commitment and has stochastic optimization functionality,

which requires the forecast data to be an input to the scenario 

tree tool and thus, replacement reserve is activated accordingly 

by the scheduling tool. Demand for replacement reserve is a 

function of the installed wind power and the forecast error 

over longer timelines, as shown in Fig. 5 and Fig.6. Fig. 5 

shows how the replacement reserve requirement is a function 

of how far ahead the optimization is evaluating. In other 

words, generally, errors will be larger further out and therefore 

more replacement reserve is required than more immediate 

horizons. In Fig. 6, where portfolio 5 contains 6 GW of wind 

generation, the requirement for replacement reserve is seen to 

exceed 3 GW in one instance. This is due to a 1 GW load rise 

at the same time as a 1 GW decrease in wind, combined with a 

forecast error.

Fig. 5. Average requirement for replacement reserve by time horizon

Fig. 6. Hourly requirement for replacement reserve

B. Eastern Wind Integration and Transmission Study (U.S.)

The Eastern Wind Integration and Transmission Study 

(EWITS) evaluated the operational impacts of various wind 

penetrations, locations, and transmission build-out options for

most of the U.S. eastern interconnection. The study included 

three scenarios of 20% wind energy with each representing 

different primary locations of the wind, and one 30% wind 

energy scenario [14]. The majority of this region is currently 

operated by Independent System Operators (ISO) and 

Regional Transmission Organizations (RTO) who administer 

the wholesale electricity markets. These markets have evolved 

since their inception in the late 1990s. The further evolution of 

the rules and procedures that the markets will follow is a key 

assumption on how operating reserve requirements are 

determined in the study, with the boundary between operating 

reserves and what is extracted from sub-hourly energy markets 

also having an impact on the method used.

The first procedure of the study was to determine the 

contingency reserves required. As many previous U.S. studies 

have done, these assumed the current rule and determined that 

the largest contingency was not affected by the large amounts 

of wind generation. One and a half times the single largest 

hazard in each operating region determined the amount of 

contingency reserves for that region.

Many prior studies in the United States concluded a slight, 

but not insignificant, increase in the amount of required 

regulating reserve due to the increased variability of wind 

power added to that of the load. In EWITS, a similar 

methodology to the prior studies was performed. The minuteto-minute variability separated from a 20 minute rolling 

0

2000

4000

1

481961

14411921240128813361384143214801528157616241672172017681

81618641

Replacement Reserve 

Demand (MW)

Hour

P5 P3 P1
6 

average of a 100 MW wind plant was used for the analysis and 

the standard deviation was determined to be 1 MW. It was 

assumed that there is no correlation between wind plants for 

power output deltas in this time frame, and therefore, the total 

standard deviation for a balancing area was calculated by 

geometrically adding the 1-MW standard deviation for all 

100-MW wind plants on the system. For load only, the 

regulating reserve requirement was assumed to be 1% of the 

total load, and assumed to be equal to three times the standard 

deviation of the load variability. Since load and all wind 

variability on this timeframe were also considered to be 

independent of one another, the standard deviations of all 

wind and all load were then geometrically added together by 

calculating the square root of the sum of their squares. The 

total standard deviation was increased by less than 1 MW 

when wind power was added to load, and therefore, the wind 

power variability was not considered as part of the regulating 

reserve for the study.2

Different from most studies, however, it was determined 

that the uncertainty in the wind forecasts used for economic 

dispatch would impact the regulating reserve much more than 

what was shown for the variability. Economic dispatch 

programs that run every five minutes would use information 

from at least ten minutes before the operating interval. Since it 

is too late to adjust the economic dispatch for any deviations, 

these deviations would all be met by units providing 

regulating reserve. Assuming a 10-minute ahead persistence 

forecast, the additional regulating reserve was determined by 

looking at the standard deviation of ten-minute changes in 

wind output (load forecast for 10-minute ahead was assumed 

to be quite good and load forecast error was ignored). Fig. 7 

shows the standard deviation of the 10-minute ahead wind 

forecast errors as a function of the average hourly production 

of total wind. The highest variability is near 50% production, 

where the anticipated 10-minute change can be up or down 

and also relates to wind turbines being at the steepest part of 

the power conversion curve. The function was used for the 

hourly wind-related standard deviation of the regulating 

reserve requirement and was geometrically added to the load 

regulating reserve requirement discussed above. Equation (2) 

is shown below, where σst is the standard deviation of wind 

forecast errors described in Fig. 7. 

 ݍܴ݁ ܴ݁݃

ൌ 3 כ ඨ൬

ܽ݀݋ܮ ݕ݈ݎݑ݋ܪ1%

3 ൰

ଶ

൅ ߪௌ்ሺݎݑ݋ܪ݈ݕܹ݅݊݀ሻଶ ሺ2ሻ

A similar approach was used for the hour-ahead wind 

forecast error. However, in this case it was assumed that the 

errors that were not occurring often could be compensated for 

with off-line non-spinning reserve. Therefore, one standard 

deviation of the hour-ahead forecast error was required to be 

spinning, and two standard deviations could be non-spinning. 

Also, since the reserves were used in the production cost 

simulations for the study, it was ensured that if the reserves 

had to be used for the hour-ahead forecast error of the hour in 

 2

 Calculations based on a balancing area with 100 GW load and 60 GW 

wind, which was about the average for the largest ISO balancing areas that 

were a part of the study. 

question, those reserves did not have to be kept in real time. In 

other words, if reserves were needed because less wind was 

available than forecast, the model would release that amount 

of reserves in real time since the reserves were used for the 

forecast error and not needed further. The total amounts of all 

reserves used in the study are shown in Fig. 8. The reserve 

requirement was an hourly value that was a function of both 

wind and load levels. 

Fig. 7. 10-minute ahead wind generation forecast errors as function of 

production 

Fig. 8 Summary of reserve methodologies for EWITS

IV. EVOLVING METHODS FOR DETERMINING RESERVE 

REQUIREMENTS WITH HIGH PENETRATIONS OF WIND 

GENERATION

The treatment of the reserve determination problem has 

evolved substantially for both wind power integration studies 

and in actual system operations. The authors believe that this 

is a continuing trend and that there are still a number of 

inconsistencies with the data and methodologies used, where 

improvements can be made. The key issue to recognize is that 

it is generally not difficult to be overly conservative and hold 

much more reserves than is needed. The real issue is knowing 

what is causing the need for different types of reserves today, 

how high penetrations of wind power will change the needs of 

reserves, and how to use as much information as is available at 

any given time to determine an optimal and efficient amount 

of operating reserves. 

The data quality used in wind power integration studies is 

very crucial in the reserve determination problem. Studies are 

evaluating high penetrations of wind power that do not 

currently exist, so the estimated power output of the wind 
7

generation must be modeled. Different modeling techniques 

are usually employed where issues can often occur that differ

the modeled output from what would be realistic. Data 

quantity is also important because longer datasets and higher 

resolution data can give much more information on the 

anticipated behavior of wind power and how it affects reserve 

requirements. Lastly, the wind power forecasts used in studies 

are yet another model that may not be totally representative of 

wind power forecasts used in actual operations. The 

requirements for ramping reserves, load following reserves, 

and regulating reserves may be highly dependent on how good 

a wind forecast is, so it is important that the error 

characteristics of the synthetic forecasts closely match those in 

operations today and in the future.

Dynamic reserve requirements have been proposed in many 

of the recent studies [2], [5], [11], and [14]. In operations 

today, most reserves are static and even those that vary hour 

by hour are usually based on hourly rules, not on forecasted 

conditions. It is important that if more reserves are needed 

because of certain operating conditions, those conditions must 

be taken into account when the control area operator decides 

the operating reserve requirement. In the future, we see it 

possible that each balancing area operator will have a reserve 

requirement that is a function of load forecast, variable 

generation forecast, net load variability forecast, uncertainty 

predictions (i.e., confidence of forecasts), and possibly even 

information on the predicted behavior of conventional 

generation.

In addition to reserve requirements that vary by time, they 

may also vary by time horizon. Today, the majority of 

operating reserves are dominated by contingency and 

regulating reserves (considering the first tier of Fig. 3). These 

reserves are mostly used today due to generation and 

transmission failures, and load and generation variability. 

These phenomena generally are as likely to happen in the next 

five minutes as they are tomorrow (i.e., their likelihood does 

not change with look-ahead horizon). On the other hand, 

events that are caused by wind may be much better predicted 

as the operating time gets closer. This was introduced in the 

All Island Grid Study [11] for the use of replacement reserves. 

When operators are more confident in the outcome of 

operating conditions, the need to hold reserves is reduced. 

This applies mostly to ramping and load following reserves,

but may apply to other categories as well.

The last point that the authors would like to make concerns

the traditional requirements that balancing areas throughout 

the world have set for operating reserves. The requirements 

should always be set towards the needs of the power system, 

not towards the resources that are currently available to 

provide those needs. This issue has arisen recently due to 

requirements that originally precluded many demand response 

resources and storage resources from providing operating 

reserves, when in fact, in some cases, they could provide the 

service with as good or better performance than the generating 

resources that had currently provided them. The amount of 

spinning reserve compared to non-spinning reserve for all of 

the different categories should be evaluated both economically 

and operationally. The response times for different categories 

should be evaluated regarding what is optimal, and may also 

change depending on predicted system conditions. The sharing 

between reserves should also be evaluated. For instance, if all 

ramping reserves are used up but a net load event continues to 

ramp, what are the consequences of taking contingency 

reserves for that purpose? Also, how should reserves be 

accounted for with a stochastic scheduling system that 

inherently schedules reserves without explicitly calling for 

them? This team has built a high-resolution power system 

model similar to those used in wind power integration studies. 

The model will focus on the utilization of reserves, however, 

at a very fine timescale (4-6 seconds for one day) and attempt 

to capture all of the different contributing factors that would 

cause the utilization of different types of operating reserves. 

This research should help highlight how different operating 

reserves could be determined based on a function of the 

predicted operating condition inputs. Table II shows further 

additional research ideas for each of the operating reserve 

categories defined in Table I.

TABLE II 

OPERATING RESERVE DETERMINATION TRENDS 

Name Trends and future research questions

Spinning Reserve For each operating reserve category, the percentage of 

reserve that is spinning should be based on reliability 

and economics. Quicker responses need to be spinning. 

For event reserves, events that occur frequently should 

have more spinning reserve, based on a tradeoff between 

spinning reserves having a higher standby cost, but nonspinning reserves having a higher utilization cost. Should 

demand response or generation that can be started in 

extremely quick times (e.g., < 1 minute) be considered 

spinning?

Non-Spinning 

Reserve

See above. How quickly must these resources start up for 

the different categories?

Contingency 

Reserve

Should this only be used for major failures? Can we 

share this with other categories? Can we use a fully

probabilistic approach with forced outage rates of all 

generators and facilities, rather than simply using the 

largest hazard (for instance if many smaller units 

dominate a region rather than larger ones)?

Regulating 

Reserve

Is this based on variability or forecast errors? Can 

uncertainty or variability predictions (rather than energy 

forecasts) be used for determination of the requirement? 

How good does regulating reserve have to be?

Load following 

Reserve

Unit commitments are performed on an hourly resolution 

and normally load trends monotonically in one direction 

within an hour. High wind penetrations may change this 

assumption so that load following reserves are set aside 

for the hour to meet changes within the hour. Conditions 

where the short-term economic generation and load 

response stack has insufficient response capability need 

to be identified and addressed with a dedicated response 

service.

Frequency 

Responsive 

Reserve

What type of response is needed (appropriate droop)?

Ramping 

Reserves

Should the response time requirement be a function of 

the net load ramp prediction? Should the spinning and 

non-spinning contribution be a function of the 

confidence of the anticipated ramp event?

Supplemental 

Reserve

How quickly should each of the categories be replaced?

Is there any reason that downward reserves should be 

considered so that if too much are used that they can be 

replaced?
8

V. SUMMARY

This paper describes new methods of determining the 

optimal amount of operating reserves for systems with high 

wind penetrations. Wind power integration studies are 

analyzing innovative methods on this issue, but different

methods can produce substantially different results. The All 

Island Grid Study and the Eastern Wind Integration and 

Transmission Study are two of the most recent studies of their 

kind and both have made key contributions to the optimal 

operating reserve requirement determination problem.

Most of the wind power integration studies that have been 

performed to date run hourly simulations of a security 

constrained unit commitment and dispatch of the system. Few 

are truly capturing the details at a level that can replicate 

system operations, whereby operating reserves are being 

utilized in detail. Therefore, the statistical methods used in the 

studies have not been validated extensively. The authors finish 

by discussing different assumptions and evolving methods on 

determining the optimal amount of operating reserves with 

high penetrations of wind power, both in future studies and 

ultimately in actual system operations.

VI. REFERENCES

[1] Richard Piwko, Xinggang Bai, Kara Clark, Gary Jordan, Nicholas 

Miller, and Joy Zimberlin. “The Effects of Integrating Wind Power on 

Transmission System Planning, Reliability, and Operations: Report on 

Phase 2,” Prepared for The New York State Energy Research and 

Development Authority, Mar. 2005. Available: 

http://www.nyiso.com/public/webdocs/services/planning/special_studies

/wind_integration_report.pdf.

[2] Enernex Corporation, “2006 Minnesota Wind Integration Study Volume 

I,” Nov. 2006. Available: http://www.uwig.org/windrpt_vol%201.pdf.

[3] J. C. Smith, M. Milligan, E. Demeo, and B. Parsons, “Utility Wind 

Integration and Operating Impact State of the Art,” IEEE Trans. Power 

Syst., vol. 22, pp. 900-908, Aug. 2007.

[4] North American Electric Reliability Corporation, “Reliability Standards 

for the Bulk Electric Systems of North America,” November 2009.

[5] “ERCOT Methodologies for Determining Ancillary Service 

Requirements,” 2009.

[6] B. Kirby, 2006, Demand Response For Power System Reliability: FAQ, 

ORNL/TM 2006/565, Oak Ridge National 

Laboratory, December 2006.

[7] Report: Entsoe, UCTE Operational Handbook Policy 1, [Online] 

http://www.entsoe.eu/index.php?id=57

[8] Report: Eirgrid, All Island Reserve Review, Dublin, Ireland, 2003.

[9] Y. Rebours, D. Kirschen, M. Trotignon, and S. Rossignol, “A Survey of 

Frequency and Voltage Control Ancillary Services – Part I: Technical 

Features,” IEEE Trans. Power Syst., vol. 22, no. 1, pp. 350-, Feb 2007.

[10] E. Ela, M. Milligan, B. Parsons, D. Lew, and D. Corbus, “The evolution 

of wind power integration studies: past, present, and future,” 

Proceedings of IEEE PES General Meeting, Calgary, CA, July 2009.

[11] P. Meibom, R. Barth, H. Brand, B. Hasche, D. Swider, H. Ravn, and C. 

Weber, “All Island Grid Study Workstream 2B: Wind Variability 

Management Studies,” July 2007. Available: 

http://www.uwig.org/Irish_All_Island_Grid_Study/Workstream_2B.pdf

[12] “Wind Power Integration in Liberalised Electricity Markets 

(WILMAR),” www.wilmar.risoe.dk

[13] R. Doherty and M. O’Malley, “New approach to quantify reserve 

demand in systems with significant installed wind capacity,” IEEE 

Trans. Power Syst., vol. 20, no. 2, pp. 587–595, May 2005.

Enernex Corporation, “Eastern Wind Integration and Transmission 

Study,” Prepared for the National Renewable Energy Laboratory, 

January 2010. Available: 

http://www.nrel.gov/wind/systemsintegration/pdfs/2010/ewits_final_rep

ort.pdf.

VII. BIOGRAPHIES

Erik Ela (M ’05) received the B.S.E.E degree from Binghamton University and 

the M.S. degree in Power Systems at the Illinois Institute of Technology. He 

joined the NREL grid integration team to work on different wind integration 

issues. His experience lies mostly in different topics relating to grid operations 

and market operations. Erik previously worked for the New York ISO 

developing and improving products in the energy markets and operations areas.

Erik is a member of IEEE and the Power and Energy Society.

Brendan Kirby (SM ‘76) is a private consultant with numerous clients 

including AWEA, National Renewable Energy Laboratory, Oak Ridge 

National Laboratory, EPRI and others. He recently retired as a senior 

researcher with the Oak Ridge National Laboratory’s Power Systems 

Research Program. He has 34 years of electric utility experience and has 

published over 120 papers, articles, and reports on ancillary services, wind 

integration, restructuring, the use of responsive load as a bulk system 

reliability resource, and power system reliability. He has a patent for 

responsive loads providing real-power regulation and is the author of a NERC 

certified course on Introduction to Bulk Power Systems: Physics / Economics 

/ Regulatory Policy.

Eamonn Lannoye (S’08) received the B.E (Hons.) degree in mechanical 

engineering from University College Dublin, Dublin, Ireland in 2009. He 

joined the Electricity Research Centre in UCD as an Irish Research Council 

for Science, Engineering and Technology Embark Initiative doctoral student. 

His research is concerned with flexibility in power systems with high 

penetrations of variable generation.

Michael Milligan (M ’98) is part of the Transmission and Grid Integration 

Team at the National Renewable Energy Laboratory. He has authored or 

coauthored more than 100 papers and book chapters and has served on 

numerous technical review committees for wind integration studies around the 

U.S. Michael is a member of the leadership team of the NERC Variable 

Generation Task Force, member of WECC’s Variable Generation 

Subcommittee, member of the IEEE Wind Power Coordinating Committee,, 

and served on the Western Governors’ Association Clean and Diverse Energy 

Wind Task Force. Michael has M.A. and Ph.D. degrees from the University of

Colorado, and a B.A. from Albion College.

Damian Flynn (M’96) is a senior lecturer in power engineering at University 

College Dublin. His research interests involve an investigation of the effects 

of embedded generation sources, especially renewables, on the operation of 

power systems. He is also interested in advanced modeling and control 

techniques applied to power plant. He is a member of the IEEE.

Bob Zavadil (M) is co-founder of EnerNex and is responsible for developing 

and overseeing the company’s power system engineering consulting business. 

He has worked on electric power system issues for wind generation for over 

15 years. From 1989 to the summer of 2003, Mr. Zavadil served in various

consulting and product development capacities for Electrotek Concepts and its 

parent company, WPT. Mr. Zavadil began his career in the electric power 

industry in 1982 as a special studies engineer in the Transmission and 

Distribution Engineering Division of the Nebraska Public Power District. He 

is a member of the IEEE Power Engineering, Power Electronics, and 

Industrial Applications Societies, and serves as Secretary of the IEEE PES 

Wind Power Coordinating Committee.

Mark O’Malley (F’07) received B.E. and Ph. D. degrees from University 

College Dublin in 1983 and 1987, respectively. He is the professor of 

Electrical Engineering in University College Dublin and is director of the 

Electricity Research Centre with research interests in power systems, grid

integration of renewable energy, control theory and biomedical engineering. 

He is a fellow of the IEEE.
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This paper describes different assumptions and methods utilized to calculate the amount of different types of 

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