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

Alternative Approaches for 

Incentivizing the Frequency 

Responsive Reserve Ancillary 

Service

E. Ela, M. Milligan, and B. Kirby

National Renewable Energy Laboratory

A. Tuohy and D. Brooks

Electric Power Research Institute

Technical Report

NREL/TP-5500-54393

March 2012
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Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

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Contract No. DE-AC36-08GO28308

Alternative Approaches for 

Incentivizing the Frequency 

Responsive Reserve Ancillary 

Service

E. Ela, M. Milligan, and B. Kirby

National Renewable Energy Laboratory

A. Tuohy and D. Brooks

Electric Power Research Institute

Prepared under Task No. WE11.0905

Technical Report

NREL/TP-5500-54393

March 2012
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Alternative Approaches for Incentivizing the 

Frequency Responsive Reserve Ancillary Service 

Erik Ela1, Aidan Tuohy2, Michael Milligan1, Brendan Kirby1, and Daniel Brooks2 

1

National Renewable Energy Laboratory 

2

Electric Power Research Institute 

Abstract 

Frequency responsive reserve is the autonomous response of generators and demand response to 

deviations of system frequency, usually as a result of the instantaneous outage of a large 

supplier. Frequency responsive reserve arrests the frequency decline resulting in the 

stabilization of system frequency, and avoids the triggering of under-frequency load-shedding or 

the reaching of unstable frequencies that could ultimately lead to machinery damage or system 

blackouts. It is a crucial service required to maintain a reliable and secure power system. 

Regions with restructured electricity markets have historically had a lack of incentives for 

frequency responsive reserve because generators inherently provided the response and on large 

interconnected systems, more than sufficient response has been available. This may not be the 

case in future systems due to new technologies and declining response. This paper discusses the 

issues that can occur without proper incentives and even disincentives, and proposes alternatives 

to introduce incentives for resources to provide frequency responsive reserve to ensure an 

efficient and reliable power system. 
1 

I. Introduction 

The control of electrical frequency of a synchronous interconnection is one of the primary 

measures to maintaining a reliable and secure power system. Power system operators must hold 

frequency as close as possible to its nominal level (60 Hz in the United States, 50 Hz in most 

other areas of the world) by adjusting the generation and load balance. A constant frequency at 

its nominal level indicates if the aggregate generation and load are in balance. Most large 

interconnections will generally try to keep frequency to within 50 mHz of the scheduled 

frequency. The frequency of the interconnection will start to deviate from its nominal level when 

there is an imbalance between the supply and demand. Any supply or demand imbalance can 

cause this deviation. Demand and generation can vary over short time scales causing slight 

frequency deviations from nominal. However, the most common cause of significant deviations 

is from the sudden loss of a large supplier (e.g., generator). This loss must be made up by the 

other resources on the grid to ensure the demand is still met. Frequency responsive reserve is the 

automatic response to frequency excursions, usually through turbine speed governors and 

frequency responsive demand response, which adjusts output or consumption to counter 

frequency deviations. This immediate response is needed to arrest frequency deviations before 

triggering under-frequency load shedding relays, triggering under- or over-frequency generation 

protection relays, or reaching unstable frequencies that could ultimately lead to a blackout. 

Since the restructuring of the electricity sector, numerous markets have been designed to 

incentivize competition for providing different services. These complex markets integrate 

efficient economic principles with the engineering and physics of the power system [1]. In the 

United States, restructured markets have evolved toward a common set of market principles [2]. 

In this design, there usually exists a two-settlement system for forward and real-time markets, 

with co-optimized energy and ancillary services markets, locational marginal pricing for energy, 

and financial transmission rights markets in place for hedging. Current ancillary services markets 

include spinning reserve, nonspinning reserve, and regulation [3]-[4]. In the U.S., spinning 

reserve is reserve that must be online and available within ten minutes. Nonspinning reserve 

must also be available within ten minutes, but can be offline. Although the spinning reserve must 

come from resources that are synchronized to the grid, there are usually no enforceable 

requirements for the market participant to provide energy that is directly responsive to frequency, 

or for speed governors to be in an operational mode. Regulation is a type of ancillary service that 

is used to correct short-term imbalances in generation and load that happen during normal 

conditions. Regulation units usually must be equipped with automatic generation control. Since 

regulation is used to reduce the area control error at the direction of the system operator, it is not 

required to respond directly to frequency. The time scale for regulation is also longer than that 

relating to frequency responsive reserve. Few regions in the world have an explicit ancillary 

service market to procure frequency responsive reserve. One reason is likely because the 

conventional generating technologies historically had frequency responsive reserve as an 

inherent feature of the technology since installation. Another reason is likely because most 

systems, and especially those that are part of large synchronous, interconnected grids, had more 

response than was needed and, therefore, did not need to incentivize for more response. Both of 

these reasons may not hold true in future systems, based on current trends. 
2 

Recent studies have shown that the frequency response in the United States, and especially in the 

Eastern Interconnection, has been declining [5]. Reasons for this include high governor dead 

bands, generators operating in modes that do not offer frequency responsive reserve (e.g., sliding 

pressure mode), governors that are not enabled, a reduced percentage of direct drive motor load, 

and many other reasons (see [6]-[7]). Although at low levels today, significant penetrations of 

electronically-coupled renewable resources like wind and photovoltaic solar power can further 

reduce interconnection frequency response, if they are installed without additional enhancements 

that can provide frequency response [8]. However, the decline in frequency response may also be 

due to the electricity market design in some areas that may not incentivize frequency response, or 

in some cases offer disincentives. 

The need for incentivizing frequency responsive reserve was one of the principal 

recommendations of an IEEE Task Force report on generation governing concerns [9]. Little 

attention has been given to frequency responsive reserve incentives since this initial report, and 

no U.S. region currently has a market for this service.1 As regions begin to understand the need 

for a reliable frequency responsive reserve and create the standards to guide this need, it will 

become more important to ensure incentives are in place to assist the individual resources. In this 

paper, we discuss the issues and possible solutions of ensuring incentives are available for 

resources to provide frequency responsive reserve. In our analysis, we focus on Independent 

System Operator (ISO) and Regional Transmission Organization (RTO) regions, which already 

have restructured energy and ancillary services markets. However, in non-restructured areas (i.e., 

regulated utility areas), it is equally important for the balancing area operator to offer incentives

for this response. Section II gives an overview of all of the mechanisms needed for reliable 

frequency control. In Section III, we give an overview of market design principles and discuss a 

possible flaw in the current market design where frequency response may be disincentivized. 

Next, Section IV describes potential changes to the existing market designs to eliminate 

disincentives and provide incentives for frequency responsive reserve. Section V provides a 

conclusion. 

II. Frequency Control Overview

Frequency control is utilized with a variety of mechanisms. When a disturbance occurs, there is a 

set of standards and procedures that guide how balancing areas should respond. In North 

America, part of the response guidance is based on the North American Electric Reliability 

Corporation (NERC) Disturbance Control Standard (DCS) [10]. In Europe, the way in which 

transmission system operators respond is based on the Union for Coordination of Transmission 

of Electricity (UCTE)2 Policy 1 [11]. Before discussing either of these policies, it is important to 

discuss the textbook example of the various mechanisms of response to a large disturbance 

event.

 

1 According to [9], the only restructured area in the world with a market for this service is in New Zealand. 2 The UCTE has been somewhat dissolved, with the European Network of Transmission System Operators for 

Electricity (ENTSO-E) now taking over as the entity with the responsibility of transmission level policies and 

standards. Policy 1 however, still refers to the UCTE Interconnection, which consists of the largest Interconnection 

in continental Europe.
3 

Generation must always meet demand. When a large loss of supply occurs, due to a generator 

tripping offline, or due to a loss of a large line carrying imports into an interconnection, the 

amount of generation from that supply will instantaneously be lost. At the instant of the loss, the 

deficiency is met by the release of kinetic energy from the synchronous generators and motors on 

the system. This response is often termed inertial response. Since these machines are 

synchronous with the system's electrical frequency, their release of kinetic energy will slow 

down the rotational speed, thereby causing a decrease in the electrical frequency. The rate at 

which the frequency declines will be determined by the amount of inertia on the system, as well 

as the amount of the imbalance. Larger machines, and more machines, provide greater inertial 

response and will result in a slower decline. A higher amount of generation lost will require more 

kinetic energy and will, thus, increase the speed of decline. The slower the decline, the better, as 

this gives more time for the reserve to respond before reaching undesirably low frequencies. 

The frequency responsive reserve (which is often also referred to as primary response) will then 

be triggered and is used to arrest the frequency decline and bring the frequency to a new steadystate level, below the nominal level. This response is autonomously triggered by turbine 

governors, inherent load response, and, in some cases, frequency responsive demand response 

[12], which sense the frequency deviation and, in response, increase generation (or decrease 

demand). After this quick response, a slower response can be supplied by resources on spinning 

and nonspinning reserve (often referred to as the secondary response), returning the frequency 

back to its nominal level. The NERC DCS and UCTE Policy 1 require that the frequency be 

returned to its nominal level in less than fifteen minutes.3 Figure 1 shows the frequency 

following a loss of a large supplier, with the associated responses that provide a service to ensure 

frequency is held as close as possible to its nominal level to avoid reliability issues and underfrequency load shedding.4

 Note that, though not as common, a loss of a large block of load or a 

pumped storage hydro plant in pumping mode, can cause a similar effect, but as an overfrequency event. The responses are somewhat similar, but generation must be decreased to avoid 

over-frequency issues. 

 

3

 The actual requirements are for the ACE, discussed later, to be returned to zero or its pre-contingency level, but 

since the secondary response is to be provided by the contingent balancing area, this can essentially result in a 

similar effect. 

4

 The highest setting for under-frequency load-shedding in the continental United States is in the range of 59.3 Hz 

(ERCOT) to 59.7 Hz (Eastern Interconnection). On island systems like in Hawaii, it can be much lower. 
4 

Figure 1: Frequency following a loss of a large supplier. 

Lastly, these reserves should be restored so that they are prepared for a subsequent disturbance. 

This is achieved using reserve referred to as replacement reserve, supplemental reserve, or 

tertiary reserve, and can be attained through market responses to the event. Figure 2 shows an 

example of the energy that each service deploys during the event, and when the reserves should 

be restored and prepared for a subsequent disturbance. The timing on the x-axis displays 

requirements to deploy the reserves (when they are increased) and when the reserves “should” 

and “must” be restored (reserves are restored when they are decreased back to zero) and are 

based on NERC criteria. Additional references on how these ancillary services differ throughout 

the world can be found in [13]-[14]. 

Figure 2: Reserve services deployment. 

-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
5 

During normal conditions, when there has not been a significant disturbance or large loss on the 

grid, regulation is used to correct the imbalance of generation and load for each balancing area5

in an interconnection. Regulation is generation (also sometimes demand response [15]) that is on 

automatic generation control (AGC). Units on AGC receive a control signal that is determined 

by a central operator, i.e., the ISO or balancing area authority. The signal, which the regulation 

providers receive, is based on correcting the area control error (ACE). ACE determines how 

much the balancing area is in imbalance with its generation and load. Positive ACE means the 

balancing area is over-generating and a negative ACE means it is under-generating. Most 

balancing areas that are part of large interconnected systems in North America, and elsewhere, 

will perform tie-line bias control [16]. With tie-line bias control, the ACE signal is determined 

based on Equation (1). 

ACE = NIA – NIS – 10B(FA – FS) (1) 

Where NIA is the actual net interchange with neighboring balancing areas, NIS is the scheduled 

net interchange, B is the frequency bias, FA is the actual frequency, and FS is the scheduled 

frequency. The net interchange is the sum of all interchanges of a balancing area out of (+) and 

into (-) the area. If the actual net interchange is greater than the scheduled net interchange, the 

balancing area is over-generating. The second part of the equation [– 10B(FA – FS)] is 

introduced to ensure that systems are providing frequency response, and that the AGC control 

does not counter its frequency response obligation. The frequency bias, B, is a constant, with the 

units of MW/0.1Hz, that represents the amount of frequency response that the balancing area 

has, or should have.6 The value as it is shown in Equation (1) is a negative value, showing that 

generation should increase when frequency is low and decrease when frequency is high. We now 

give some numerical examples. 

Scenario 1 

NIS = 500 MW NIA = 600 MW 

FS = 60 Hz FA = 60 Hz 

B = -200 MW/ 0.1 Hz ACE = 100 MW 

In Scenario 1, the balancing area is transmitting 100 MW more power out of its balancing area 

than it has scheduled to transmit. Therefore, the balancing area is over-generating by 100 MW, 

as seen in its 100 MW ACE. The AGC would send signals to the resources on regulation to 

reduce output and, thereby, reduce the 100 MW ACE back to zero. 

Scenario 2 

NIS = 500 MW NIA = 600 MW 

FS = 60 Hz FA = 59.95 Hz 

B = -200 MW/ 0.1 Hz ACE = 0 MW 

 

5

 A balancing area is an area within an interconnection that is responsible to balance its generation and load and 

keep its inter-tie line schedules with other areas to schedule. Interconnections in North America range from one 

balancing area (ERCOT and Hydro Quebec) to over 60 (Eastern Interconnection). 

6

 Some areas may have a variable frequency bias that changes based on conditions to better reflect the actual 

system frequency response. 
6 

In Scenario 2, the balancing area is again transmitting 100 MW more power out of its balancing 

area than it has scheduled to transmit. However, this time the actual frequency is below the 

scheduled frequency. According to the balancing area’s frequency bias, B, it is providing the 

correct amount of frequency response to assist the interconnection. By incorporating the 10 

coefficient, we have: (-2000MW/Hz)*(-0.05 Hz) = 100 MW of frequency response that is 

needed. Therefore, the 100 MW of over-generation from the balancing area is necessary, and so 

the AGC should not attempt to correct the imbalance between actual and scheduled interchange, 

hence the 0 MW of ACE. 

It is important to understand the contribution of individual resources providing frequency 

responsive reserve, to distinguish it from spinning reserve and regulation. For generating units, a 

turbine speed governor is usually in place for both thermal and hydro generating units. The 

governor will autonomously sense frequency changes, as it senses the speed of the turbine, and 

will change the position of steam valves, combustion turbine fuel flow, or water gates, to adjust 

the power output in response. For a stable response from the various resources contributing 

frequency response, a speed droop is used. The droop curve determines the pickup from each 

resource with respect to the frequency change. For example, Figure 3 shows a 5% droop curve. 

For a 5% change in frequency, which on a 60 Hz system reflects a 3 Hz change, the governor 

will adjust by 100% of its capacity. This determines the slope of the curve and how much the 

governor will adjust based on varying deviations of frequency. Typical droop curves range from 

3-5%. 

Figure 3: Governor Droop Curve in per unit values. 1 p.u. frequency would equate to 60 Hz in the United 

States, and 1.01 p.u. would equate to 60.6 Hz. A 100 p.u. power output would equate to the capacity of the 

plant. 
7 

Usually, generators will also carry a governor dead band (depicted in Figure 3). The governor 

dead band ensures that the governor is not operating during relatively minor frequency changes, 

as its autonomous operation is only desired for large disturbances. Typical governor dead bands 

are in the range of 0.02 – 0.06% of nominal frequency (e.g., 12-36 mHz on a 60 Hz system). 

When frequency deviations are below these levels, the generator does not provide frequency 

response through its governor. 

The amount of frequency responsive reserve is also dependent on the set point of the generating 

unit and its minimum and maximum capacity levels, as well as if it is operating in a mode that 

allows for frequency response or an enabled governor. If a generator is generating at its 

maximum capacity, it cannot provide any frequency response during under-frequency events, 

regardless of its droop curve, dead band, and its governor being enabled. Therefore, the “head 

room” is very important when determining how much frequency responsive reserve is available. 

Units also may be operating in modes that do not provide frequency response or block the 

governor response. These include turbine follow, integrated boiler turbine controls, and sliding 

pressure modes [6]. Extremely high dead bands and limiters can also block governor response. 

The last important component of frequency responsive reserve is the timing when the frequency 

response is achieved. Different technologies have different inherent time constants for the 

frequency response to be fully activated. For example, when steam valves are opened on a steam 

turbine generator, the change in electrical output that results is not instantaneous. This delay is 

important as the faster the frequency response is delivered, the sooner the frequency change can 

be arrested, and a higher minimum frequency, or nadir, can be achieved, resulting in less 

potential for under-frequency load-shedding. In addition, the response should be sustained long 

enough for the secondary response to return the frequency to its nominal setting. If there is a 

withdrawal of the frequency responsive reserve before the secondary reserve response, the 

frequency will start to decline from the steady-state level, placing it again at risk of underfrequency load-shedding. Resources operating in outer-loop megawatt control will have this 

affect; shortly after they provide frequency response, they are driven back to their original MW 

set point. 

Although not discussed in detail, frequency responsive demand response can assist in frequency 

response, both inherently and intentionally. Some loads are frequency dependent, like for 

example fans and pumps that are directly driven by synchronous or induction motors, and will, 

therefore, inherently reduce demand during frequency declines (and increase when frequency 

increases). The amount that the load inherently changes with frequency is referred to as the load 

damping constant, given in the percent change in the load per the percent of frequency change. 

For most systems, this value ranges from a 1-2% load change per 1% frequency change. In 

ERCOT, Loads Acting as a Resource (LAaR) is the demand response that provides an 

intentional load response, either manually as directed by the ERCOT operator, or through 

intentional under-frequency relays, set at frequencies significantly higher than under-frequency 

load-shedding relays for fixed load, but still at frequencies that are low enough so that they are 

only reached during very large disturbances. These demand resources are paid for their service 

and can help avoid significant frequency declines. 
8 

The payment for ERCOT LAaR might be one of the few instances when a resource is paid for 

providing frequency responsive reserve, since there are instances in which the resources 

explicitly respond to frequency deviations. However, the resources are paid under the 

“Responsive Reserve Service” market (similar to spinning reserve), and at slower timescales. 

Otherwise, technologies that provide any of these services are not incentivized to provide the 

frequency response service. There is often no requirement for generators to be operated such that 

their governors are enabled or provide effective response. If the requirement does exist in areas, 

it is difficult to monitor and enforce the rule as many technologies may be operating in modes 

that do not provide adequate response. This is likely one of the major reasons for the decline of 

frequency response in the United States, especially in the Eastern Interconnection. If resources 

have no incentive (or requirement) to provide the service, and it costs them to provide it, either 

directly or indirectly through increased wear and tear, there would be little motivation for them 

to provide the service. 

III. Markets and Incentives 

A well-designed electricity market can be difficult to design and must carefully consider the 

alignment of the market incentives with the needs of the power system [1], [17]. Unintended 

consequences can occur, reducing the effectiveness of the market or causing undesired impacts 

in separate related markets. The objective of a market is to elicit an incentive for providers to 

supply the desired product in an economically efficient manner. The market will create 

competition, which will initiate market participants to minimize their costs of providing the 

particular service. This means that a well-designed market will induce the least-cost solution, 

subject to the various physical constraints and objectives of the market. 

When a new market is introduced, there will typically be short-run and long-run adjustments. 

Initially, market suppliers may have limited ability to respond because operational changes or 

equipment needs or modifications may be required. After the suppliers make these changes, the 

market is likely to function smoothly (in the absence of market power). 

Rules can be used in cases where markets are too difficult to design, or if the market would be 

fundamentally flawed as a result of market power or other concerns. For example, the ancillary 

service of voltage support is typically a cost-based service [18]. Voltage support does not have a 

market with dynamic pricing and competitive suppliers. Voltage support is serviced with 

injecting and absorbing reactive power, and reactive power does not travel far on the 

transmission system. Since reactive power does not travel far, there are few suppliers of voltage 

support when it is needed in a particular location, limiting the competition for that service. This 

type of limitation is the main reason behind creating rules and standards for supplying voltage 

and reactive power support rather than introducing a dynamic market. Complexity, cost of 

administration, and low diversity in costs from competitors (i.e., if all suppliers would inherently 

cost the same to supply the service and innovations to reduce costs are not possible) are all 

reasons why rules may be more practical than introducing markets for certain services. 
9 

Disincentives in the current market design to provide frequency response 

Sometimes, in the absence of markets for particular services, there may be flaws when that 

service is coupled with other incentives. We will highlight an example of how current energy 

market designs may be giving disincentives to potential suppliers of frequency responsive 

reserve. In most ISO regions, energy is settled at prices and schedules that are produced from a 

security-constrained economic dispatch model. The energy markets are based on two settlement 

systems, so that a forward market will create initial schedules, and a real-time market will 

accommodate the differences in demand from what was expected in the forward market. The 

day-ahead market is the common forward market. Day-ahead schedules and day-ahead locational 

marginal prices, or LMP, are produced. The LMP is the price settled for each location on the 

transmission grid, and is based on the marginal cost of supplying energy at the location. In the 

real-time market, differences from the day-ahead market are settled at the real-time LMP, which 

can be quite different than the day-ahead LMP at the same location, based on the new 

characteristics of the demand, and generation and transmission available. Therefore, the full 

settlement of a generator is based on Equation (2) where DA is day-ahead, RT is real-time, Pg is 

the generation schedule, i is the index for the generator, and h is the index for the hour. 

௛,௜ܲ݃ ൌ௛ ,௜ݐ݉݁݊ݕܲܽ௛,௜ܲܯܮ כ ஺஽

஽஺ ൅ ሺܲ݃௜,௛ோ் െ ܲ݃௜,௛

௛,௜ܲܯܮ כ ሻ஽஺

ோ் (2) 

The only time that payment may differ from this situation is when generators do not produce the 

same amount of energy as they are scheduled in the real-time market. Even though it is a realtime market, the schedules are produced for some time in the future (usually 5-10 minutes 

ahead). Therefore, it cannot predict the energy that the generators will produce nor can it predict 

the exact demand. Since generators have particular control over the output that they produce, 

most ISOs provide disincentives for the generators to produce energy differently from what they 

were told to produce. In some cases, this may be a change of LMP to reflect the actual conditions 

(i.e., the prices are given ex post, where prices are based on actual outcomes, rather than ex ante, 

where prices are based on expected outcomes). In other cases, financial penalties may be 

assessed to those market participants who stray from the schedule they were given. Both 

methods should work in incentivizing generators to follow their schedule as closely as possible. 

As discussed in the last section, a properly functioning governor will respond autonomously to 

frequency deviations, without the intervention of a control room operator. This is what they are 

designed to do and this response is vital for power system reliability. In conversations with ISO 

employees, and in various manuals, tariffs, and user guides of the U.S. ISOs, the authors have 

found that few, if any, ISOs incorporate frequency as input into the energy settlements system. A 

frequency deviation will cause a generator with a turbine governor to adjust its output to assist 

the interconnection in arresting the frequency decline (or frequency increase in the case of a loss 

of load or a loss of a pumped storage hydro facility), and its energy output will deviate from its 

real-time energy schedule. This can cause either a change in the LMP that reflects the ex post 

pricing, which may harm the generator, or it can be financially penalized for deviating from its 

energy schedule. 
10 

As an example, one U.S. ISO has a 3% tolerance band around its financial penalties. This means 

that if a generator deviates from its schedule by more than 3% of its operating capacity above or 

below its energy schedule, it will receive a financial penalty for not following schedule. 

Assuming, that a generator with a properly functioning governor has a 5% droop curve, we have 

the following: 

ݎ݁ݓ݋݌ .ݑ .݌ 1

ݎ݁ݓ݋݌ .ݑ .݌ 0.03 ൌ ݕ݁݊ܿݑݍ݁ݎ݂ .ݑ .݌ 0.05

ݕ݁݊ܿݑݍ݁ݎ݂ .ݑ .݌ ܺ

݁݉ݐݏݕݏ ݖܪ60 ܽ ݎ݋݂ ݖܪ݉ 90 ൌ ݕ݁݊ܿݑݍ݁ݎ݂ .ݑ .݌ 0.0015 ൌ ܺ

This means that any time the frequency deviates more than 90 mHz (i.e., if frequency dips below 

59.91 Hz or above 60.09 Hz), any generator with a properly functioning governor and a 5% 

droop curve will automatically be penalized under this rule, if frequency is not incorporated 

within the energy settlements system. This is a significant disincentive. If the generator has no 

other incentive to provide frequency response, which occurs when there is no frequency 

responsive reserve ancillary service market, it will have no motivation to enable its governor or 

operate in modes to provide frequency response. Since frequency response is a crucial service to 

the power system, this can have drastic affects if this turns into a trend, which some researchers 

believe it has [9]. 

There are some important discussion points that are worth mentioning. First, a 90 mHz deviation, 

especially in the Eastern Interconnection, is extremely rare. A very large loss of supply or loss of 

two or more large generating units would have to occur for a frequency deviation of this 

magnitude to occur in large interconnections. Second, frequency usually begins to return to its 

nominal level a few minutes after the disturbance event. Penalties may be based on an hourly 

average production, meaning that a deviation based on the frequency response would likely have 

little impact on deviations from the hourly schedule. The point is, regardless of these caveats that 

may lessen the impact of these disincentives from providing frequency response, there still is a 

disincentive, and without any incentive for providing frequency response or any standard or grid 

code enforcing the response, generators will have every reason to disable their governors or 

operate in a way that provides little or no frequency responsive reserve. When the governors are 

disabled, the frequency response would then have to come from the secondary (AGC) response, 

a much slower response, which may cause degradation in the overall system frequency response, 

and put the system at higher risk for under-frequency load-shedding and other issues. 

IV. Market Designs Modifications to Incentivize the Frequency Responsive 

Reserve Ancillary Service 

We now discuss some potential resolutions and new or modified market designs to provide 

alternative levels of incentives, with varying levels of market design effort. There are two, 

usually conflicting goals, in market design. The more complexities that are included to 

characterize the responses of the market participants and system will better reflect what is needed 

as the desired response. It should also limit market participant gaming. However, the more 

complex the market design, the more difficult and expensive it will be to implement and obtain 
11 

regulatory approval, and the benefits may be diminished in smaller markets. With this in mind, 

we have proposed four market design proposals for consideration. If any of the ISOs were to 

choose any of these proposals, or a combination of them, they would likely work out specific 

details through the regular ISO stakeholder process to determine which design best fits the 

particular region. 

Proposal 1: Elimination of penalties during frequency events. 

The simplest proposal would eliminate penalties during frequency events, as discussed in the 

previous section. For example, in the New York Independent System Operator (NYISO) Market 

Services Tariff [19], there is a current rule that over-generation penalties do not apply during 

reserve pick up periods. Reserve pick up periods occur when reserves are needed for a 

disturbance that occurred in the NYISO balancing area. This rule could be extended so that overgeneration penalties do not apply when frequency is below some threshold, and under-generation 

penalties do not apply when frequency is above some threshold during any instant within the 

settlements interval. This would assure market participants that enabling the governor and 

providing frequency responsive reserve cannot harm them financially. 

The benefit of this change is that it is relatively simple to implement. No new markets or changes 

to scheduling software are required, and there are no changes to the resulting prices or schedules. 

However, it would mean that frequency would have to be recorded in the settlement system, and 

that some basic logic would have to be added to the settlements system. The logic would simply 

check every penalty assessed to see if there were any frequency excursions that would have 

caused governors to cause the penalty, and void the penalty if so. A simple threshold could be 

based on a typical governor dead band. If the frequency deviation is within the governor dead 

band, the governors do not react and, therefore, there is no reason to void the penalty. If the 

frequency deviation is outside the dead band, then the governors react and, therefore, there is a 

reason to ensure that no resources with functioning governors are penalized during these times. 

While this proposal may eliminate disincentives, there is still no incentive for resources to enable 

governors and provide frequency response. 

Proposal 2: Specific accountability of frequency response to avoid penalties. 

The second option applies additional parameters to the settlements system, so that only those 

resources that offer the frequency responsive reserve avoid penalties. In this proposal, in addition 

to the frequency being used in the settlements system, governor droop and governor dead band 

are added. The settlements system now includes the logic to determine what the resource’s 

output should be during frequency excursions and during normal conditions. Instead of avoiding 

penalties during frequency excursions, the settlements system knows what the frequency 

responsive units should have provided based on the frequency and its response characteristics. 

Resources without a governor or operating in a mode that does not provide frequency response 

should not avoid these penalties. 

The benefit of this change is that it ensures proper frequency response, and still retains the 

original goals of penalties and settlements for those resources that are not following schedules, 

whereas Proposal 1 may eliminate the penalties for resources regardless of whether they are 
12 

actually helping the system during the frequency excursions. This can better incentivize 

resources to provide the desired frequency response. However, there is added complexity in that 

additional parameters and logic must be added to the settlements software. The complexity of the 

software logic will depend on the time resolution of the retained frequency measurements. Also, 

if this proposal is implemented without any rule that certain resources are required to enable 

governors, there is still no incentive for those resources to enable governors and provide the 

frequency response. 

Proposal 3: Incorporate Frequency Responsive Reserve Requirement within Spinning Reserve 

Requirement. 

The third proposal can likely be implemented in conjunction with either Proposal 1 or Proposal 

2. This proposal would require that any resource providing spinning reserve and participating in 

the existing spinning reserve market enable its governors and provide frequency responsive 

reserve with enforcement. There is a connection with spinning reserve and frequency responsive 

reserve since both are responsive to disturbances on the system. The spinning reserve would then 

be required to respond both to system operator commands and autonomously to frequency 

deviations. This offers an additional incentive for resources to provide frequency responsive 

reserve in contrast with Proposal 1 or Proposal 2 by themselves. The resources would have to 

enable the governors to earn revenue in the new spinning reserve market. 

This is also a relatively easy market design change to implement. However, it is not clear that 

this change by itself will obtain the correct amount of frequency response. Resources differ in the 

amount of frequency response they are capable of providing. Scheduling sufficient spinning 

reserve might not result in sufficient frequency responsive reserve being available. Further, the 

amount of available frequency responsive reserve could change as the mix of resources 

providing the spinning reserve changed. Imposing specific frequency response capability 

requirements on spinning reserve resources would likely limit the spinning reserve supply and 

increase the price [20]. Energy prices could also be impacted since spinning reserve resources 

also supply energy. Locational constraints for spinning reserve and frequency response often 

differ, further complicating a simple joint supply requirement. Spinning reserves in many areas 

have locational requirements to avoid overloading the transmission system during contingency 

events. Frequency responsive reserves may have completely different location-based 

requirements, or may have none at all, which would add a further complexity, if the two were 

paired together in one market. Other than these issues, the proposal would be relatively easy to 

implement, making an incentive available for resources to provide frequency responsive reserve. 

Proposal 4: Separate Frequency Responsive Reserve Ancillary Service Market. 

The fourth proposal is the implementation of a new frequency responsive reserve ancillary 

service market within the ISO. This proposal is also recommended in [20] and, less explicitly, in 

[9]. The market would incorporate the reliability requirement of a minimum amount of frequency 

responsive reserve, similar to spinning reserve. This requirement, in both MW and MW/0.1 Hz, 

would ensure enough head room and enough sensitivity to avoid under-frequency load-shedding 

following some large, credible interconnection-wide event. The resources would offer their 

droop curves, response range, time delays, and governor dead bands, and the market would select 
13 

the least cost optimization that meets the specified reliability requirements. Since frequency 

responsive reserve is tightly coupled with energy and other reserves, it would be beneficial to cooptimize this service with energy, as is done with the other ancillary services. 

This proposal provides the incentives in Proposal 3 to provide frequency responsive reserve. 

However, it avoids the issues of pairing two services at the same price when they are in fact 

different services, as well as the other issues (e.g., measurement of compliance, and locational 

requirements). The major issue is the complexity of implementing this new market, with regard 

to both software and regulatory complexity. The market software would have to be enhanced to 

incorporate these new parameters and requirements, as is done for example in [21]-[23]. It would 

also have to go through large regulatory hurdles to introduce a new market to consumers, which 

would require the approval of stakeholders and federal regulators. 

Comparison 

Table I gives an overview of the four market design proposals discussed in the previous sections. 

Each has different ways of eliminating disincentives, providing incentives, and increasing market 

design complexity. Each of these proposals has different advantages, and can also be paired with 

another to achieve the best efficiency. The authors believe that the most efficient results can be 

achieved with Proposal 4 paired with some version of Proposals 1 or 2. However, the benefits 

will likely be system-specific. The costs and regulatory hurdles of Proposal 4 can make it less 

attractive and perhaps not appropriate in certain markets. However, this option will establish 

clear incentives for resources to enable governors and provide frequency responsive reserve, 

while eliminating any disincentives that penalize resources in the energy market for providing 

the response. Importantly, if there is no cost for providing the service during certain instances, 

which should occur during times when enough resources are available to provide the service and 

compete in the market, then it should result in a price of zero. This often occurs with the other 

ancillary services like spinning reserve, especially at night when the supply-side competition is 

high, and costs are low. If this market was created, it would be important to monitor the activities 

and outcomes, through normal market monitoring procedures, to ensure proper competition 

exists and resources are not gaming the market through loopholes or other means. 
14 

Table I: Overview of Frequency Responsive Reserve Market Design Proposals 

Market Design 

Proposal 

Eliminate 

Disincentives? 

Provide Incentives? Complexity 

L:Low 

M:Medium 

H:High 

Limitations 

Proposal 1: 

Elimination of 

penalties during 

frequency events

Yes, penalties 

would no longer be 

assessed during 

frequency 

disturbances 

No, but could be 

paired with Proposal 

3 or 4 

L: Very minor 

changes to 

settlements rules 

Penalties will be 

avoided regardless of 

whether the resource is 

providing frequency 

response 

Proposal 2: 

Specific 

accountability of 

frequency response to 

avoid penalties

Yes, for resources 

that can properly 

provide frequency 

responsive reserve 

No, but could be 

paired with Proposal 

3 or 4 

L-M: Somewhat 

complicated 

logic, but only to 

the settlements 

system 

No requirement to 

enable governors 

Proposal 3: 

Incorporate 

Frequency 

Responsive Reserve 

Requirement within 

Spinning Reserve 

Requirement

No, but could be 

paired with 

Proposal 1 or 2 

Yes, resources that 

provide frequency 

response can bid in 

spinning reserve 

market 

M: Settlements 

system, 

monitoring 

requirements, 

and regulatory 

complexities 

would result 

Price signals may not 

be clear due to joining 

of two services in one 

market 

Proposal 4: 

Separate Frequency 

Responsive Reserve 

Ancillary Service 

Market

No, but could be 

paired with 

Proposal 1 or 2 

Yes, correct 

implementation 

would give clear 

incentives for 

resources to provide 

frequency responsive 

reserves 

H: Many 

different 

software 

programs would 

be impacted 

significantly; 

Large regulatory 

process 

Complexity of market 

will be expensive and 

will take time for 

market participants to 

learn 

Standards and Requirements vs. Markets 

Any new market designs should be compatible with the physics and reliability needs of the 

power system. Well-functioning markets do not have significant market power issues and 

provide the product in an economically efficient manner. A frequency responsive reserve 

ancillary service market is nonsensical, without a justifiable standard or requirement for 

frequency response. Currently, outside ERCOT, no interconnection in North America has a 

frequency response standard, though it is currently being developed [24]. The standard will 

likely be consistent with the current European frequency response policy [11]. The European 

policy sets an interconnection-wide amount of frequency responsive reserve7 of 3000 MW. This 

amount is to be fully deployed when a frequency deviation reaches 200 mHz, which also gives a 

requirement in MW/Hz (or MW/0.1Hz). The contribution of each balancing area is then based on 

total energy generated in a year by the balancing area divided by the total energy generated in a 

year by the entire interconnection. Other requirements discuss the governor dead bands and 

speed of deployment. Each of these requirements could be utilized as minimum requirements, or 

achieved through market designs that incentivize the desired response characteristics. For 

 

7

 In Europe this is called primary control reserve. 
15

example, to achieve the frequency response characteristic requirement in MW/Hz, the market 

may increase the pay for a generator of more MW/Hz than another, e.g., a generator with 4% 

droop would get paid more than a generator with a 5% droop, even if the same MW capacity is 

offered, because it is offering more frequency response. The design must be careful to 

incentivize the right responses. Finally, any of these requirements should be coordinated in 

regions throughout the interconnection. Unlike spinning reserve and regulation, frequency 

response is an interconnection-wide issue, and coordination of the new market rules should be 

consistent throughout the interconnection. This becomes difficult on an interconnection like the 

U.S. Eastern Interconnection, where there are many balancing areas of different sizes and not all 

areas have restructured market designs. Also, other ancillary service markets and requirements 

are constantly evolving and these changing requirements should be considered in any new 

market designs. For example, the proposed reliability-based control requirement may change 

regulation requirements [25], and the new pay-for-performance requirements for the regulation 

requirement in a recent FERC order [26] are two ways the regulation market may change and 

impact the rules and market design of a frequency responsive reserve market. 

While a system standard is absolutely required for a market to exist, unit-specific standards can 

exist as an alternative to a market. For example, if every generating unit on the system was 

required to have its governor enabled with specific characteristics, the need for a frequency 

responsive reserve market would be eliminated. The original movement toward deregulating the 

electricity sector initiated from the fact that new supply-side technologies could offer energy at 

various ranges of costs, and deregulation helps to reduce costs borne by consumers. This trend is

seen in the technologies that provide frequency responsive reserve. Many technologies have 

different ways of providing frequency response. For example, nuclear generators rarely have 

governors as they are generally operated with load limiting. Combined cycle gas turbine 

technology has a very different frequency response than conventional steam turbine 

technologies. Wind generators, which historically did not provide any frequency response, can 

be equipped with power electronics that can control the blade pitching to provide frequency

response [27]. However, adding this control will likely come at a cost. By introducing frequency 

responsive reserve incentives, it would be up to the wind plant market participant to decide 

whether or not to include this control, based on how much revenue it believes it can earn.

Photovoltaic solar or electronically interfaced storage would face the same question. This new 

trend of different market participants being able to supply different forms of frequency 

responsive reserve at different costs, may reveal a frequency responsive reserve market that is a 

more efficient alternative to unit-specific requirements.

V. Conclusions 

This paper discusses the needs for introducing incentives and eliminating disincentives for 

resources on the electricity grid to provide frequency responsive reserves. In some areas, 

especially in the Eastern Interconnection of the United States, the frequency response has been in 

a constant decline for the past 20 years. Given that load and generation have been increasing 

during this time, this trend should not occur. If the trend continues, the system may be at risk of 

under-frequency load shedding, especially during instances of system islanding. The authors 
16 

believe one of the most important ways to end this trend is to eliminate any disincentives that 

may convince market participants to provide little or zero frequency response, and potentially to 

introduce new incentives that may entice current resources to provide the response, or new 

resources to ensure that the capability is installed. Four potential designs are detailed. While we 

believe any of the four designs should eventually lead to a better frequency response on a 

system, the design for any particular system will depend on the characteristics of that system. 

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