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

Effective Ancillary Services 

Market Designs on High Wind 

Power Penetration Systems

Preprint

Erik Ela

National Renewable Energy Laboratory

Brendan Kirby 

Independent Consultant

Nivad Navid 

Midwest Independent System Operator

J. Charles Smith 

Utility Wind Integration Group

To be presented at the IEEE Power and Energy Society General 

Meeting

San Diego, California

July 22-26, 2012 

Conference Paper

NREL/CP-5500-53514

December 2011
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1 

Abstract--Ancillary services markets have been developed in 

many of the restructured power system regions throughout the 

world. Ancillary services include the services that support the 

provision of energy to support power system reliability. The 

ancillary services markets are tied tightly to the design of the 

energy market and to the physics of the system and therefore 

careful consideration of power system economics and engineering 

must be considered in their design. This paper focuses on how the 

ancillary service market designs are implemented and how they 

may require changes on systems with greater penetrations of 

variable renewable energy suppliers, in particular wind power. 

Index Terms-- ancillary services, frequency response, market 

operations, operating reserves, power system operations, voltage 

support, wind integration, wind power. 

I. INTRODUCTION

ECENT trends in the power system industry have seen 

tremendous growth in renewable energy suppliers. Many 

of these renewable resources are variable generators who have 

an availability limit that changes through time (variability) and 

cannot be predicted with perfect accuracy (uncertainty). This 

variability and uncertainty add to the existing variability and 

uncertainty of the current systems. This additional variability 

and uncertainty have unique characteristics and may change 

the way that system operators maintain a reliable power 

system. Many entities have been studying these impacts in 

detail to understand how [1]-[2]. 

Many areas throughout the world, including the United 

States, have introduced restructured power systems with 

wholesale markets for electricity. In the U.S. these have 

evolved into the standard market design [3]. Energy is sold in 

forward (e.g., day-ahead markets) and real-time markets and is

usually settled at locational marginal prices. To support the 

scheduling of energy on power systems, operators require 

ancillary services. Ancillary services may include a number of 

different operations which include frequency support, voltage 

support, and system restoration [4]. To encourage the 

individual participants of the market to provide these services, 

ancillary services markets were created [5]. 

 E. Ela is with the National Renewable Energy Laboratory in Golden, CO, 

USA (erik.ela@nrel.gov) 

B. Kirby is an independent consultant in Knoxville, TN, USA 

(kirbybj@ieee.org) 

N. Navid is with the Midwest Independent System Operator in Carmel, 

IN, USA (nnavid@midwestiso.org) 

J.C. Smith is with the Utility Wind Integration Group in Kitty Hawk, NC 

(Charlie@uwig.org) 

Many of the ideas behind the complexity of the standard 

market design were implemented without the idea that variable 

renewable resources like wind would have such a market 

presence. The impact can be seen on the energy market, 

capacity market, ancillary service market, and other potentially 

new market designs [6]. The impact of wind power on the 

operating reserve requirements has been studied extensively 

[7]. Its impact on reactive power reserve and voltage control

has also been studied [8]. There has also been research onto 

possible ways that wind power can actually provide various 

ancillary services [9]-[11]. 

This paper will discuss some ideas that the authors have on 

potential changes, specifically, that the introduction of high 

penetrations of wind power will have on the ancillary services 

markets. Section II will discuss the current ancillary services 

market designs of the U.S. Section III will then discuss some 

ways that these market designs may change based on changing 

ancillary services requirements because of higher wind power 

penetrations. Section IV will discuss potential new market 

designs that may be needed. Section V will discuss a case 

study of a new ancillary services market being designed by the 

Midwest Independent Transmission System Operator. Section 

VI summarizes the paper.

II. CURRENT ANCILLARY SERVICE MARKETS

Ancillary services markets can either be dynamic with 

hourly or faster prices set based on system conditions, or they 

can be cost-based where set rates are made in advance to 

ensure that suppliers are made whole. Many of the ancillary 

services that assist in active power balance and frequency 

support will have dynamic markets since they are tied tightly 

to the energy markets. Other services, like for example black 

start, will have cost-based services. These services incur little 

change to system conditions nor are they part of a competitive 

paradigm. The following ancillary services were represented 

by FERC in its Order 888 [12] with our definition of how they 

are or are not represented in ancillary services markets:

1. Scheduling, system control and dispatch: This is the 

service that the Independent System Operator (ISO) or 

Regional Transmission Organization (RTO) provides 

and is not applicable to our discussion on ancillary 

services market design.

2. Reactive supply and voltage control from generation 

service: Reactive power supply and voltage control is 

generally supplied as a cost-based service.

Effective Ancillary Services Market Designs on 

High Wind Power Penetration Systems

Erik Ela, Member, IEEE, Brendan Kirby, Senior Member, IEEE, Nivad Navid, Senior Member, IEEE,

and J. Charles Smith, Senior Member, IEEE

R
2 

3. Regulation and frequency response service: Today, 

regulation is typically supplied and priced by dynamic 

markets in ISO/RTO regions. It is used to assist in 

controlling frequency. However, frequency response, as 

defined by the droop response of governors immediately 

in response to frequency is generally not included in any 

dynamic markets nor is it given cost-based rates.

4. Energy imbalance service: Energy imbalance is usually

the service of the real-time markets balancing out the 

imbalance from the forward markets and therefore is 

priced by the real-time energy markets.

5. Operating reserve – synchronized reserve service: This 

service is typically supplied and priced by dynamic 

markets in ISO/RTO regions.

6. Operating reserve – supplemental reserve service: This 

service is typically supplied and priced by dynamic 

markets in ISO/RTO regions.

We will focus our attention of the current market designs in 

this section to the services of regulation (part of service 3), 

spinning reserve (service 5), and non-spinning reserve (service 

6). We will reintroduce some of the other services later in the 

paper when discussing the potential for new ancillary services 

markets. Fig. 1 shows the ISO and RTO regions of North 

America. Of these regions and at the time of this writing, only 

the Southwest Power Pool does not currently have ancillary 

services markets. The remaining regions all have dynamic dayahead and real-time ancillary services markets for regulation, 

spinning reserve, and non-spinning reserve [13]. 

Fig. 1. ISO and RTO regions in North America. 

A. Ancillary Services Requirements

Many of the ancillary services requirements that the ISO 

(we will use ISO to refer to both ISO and RTO throughout the 

rest of this paper) will procure in its markets are directed by 

the reliability requirements. In North America, the reliability 

requirements are directed by the North American Electric 

Reliability Corporation (NERC) [14]. These may be further 

defined by regional reliability organizations, state reliability

councils, or the ISO itself. These requirements are usually 

consistent between day-ahead and real-time markets.

The NERC Disturbance Control Standard (DCS) requires 

that each balancing area have enough reserve to cover its 

largest credible contingency. This can include both spinning 

and non-spinning reserve. Often, spinning reserve and nonspinning reserve are combined to refer to contingency reserve. 

Although not a NERC requirement, most regions will also 

require that at least 50% of this reserve be spinning reserve, 

meaning it must come from generators online and 

synchronized to the grid [15]. Also according to the DCS, 

these reserves must be able to respond within 10 minutes after 

a contingency. Still other regions have requirements for second 

contingencies. For example, in the Northeast Power 

Coordinating Council, a requirement is to procure 50% of the 

second largest contingency to be available within 30 minutes

[16]. This shows how both quantity and speed requirements 

must be part of the market clearing engine when each ISO 

procures its service. Both will affect what resources are 

selected and what prices are calculated. These particular 

reserves and reserve requirements are currently not impacted 

in these systems by the recent growth of wind power.

NERC also requires all balancing area authorities be in 

compliance with the control performance standards (CPS1 and 

CPS2). These standards direct the balancing requirements 

during normal conditions (i.e., not during contingencies). 

These requirements will give the ISO direction on how much 

and what type of regulation to procure in the regulation 

markets. Usually the ISO will base its requirements on time of 

day, weekday vs. weekend, and season among other things. 

ERCOT will actually consider the additional wind impact 

when determining its current requirement [17]. Usually, the 

regulation requirement must be fully available within the 

economic dispatch interval, which is typically 5 minutes in 

U.S. ISOs. Lastly, unlike spinning and non-spinning reserve, 

the regulation requirement is bi-directional, meaning that both 

upward and downward capacity must be made available. 

Interestingly, some regions will combine both services in the 

market, while others keep them as two separate markets. Table 

I shows some examples of these requirements [7]. 

TABLE I 

REGULATION MARKETS AND REQUIREMENTS IN VARIOUS ISOS

Region

Separate/ 

Combined Rule

PJM Combined

Based on 1% of the peak load during peak 

hours and 1% of the valley peak during offpeak hours.

NYISO Combined Set requirement based on weekday or weekend, 

hour of day, and season.

ERCOT Separate

Based on 98.8th percentile of regulation utilized 

in previous 30 days of same month of previous 

year and adjusted by installed wind capacity. 

CAISO Separate

Use a requirement floor of 350-MW up and 

down regulating reserves which can be adjusted 

based on load forecast, must-run instructions, 

previous CPS performance, and interchange and 

generation schedule changes.

MISO Combined

Requirement made once a day based on 

conditions and before the day-ahead market 

closes.

ISO NE Combined Based on month, hour of day, weekday/sat/sun.
3 

B. Ancillary Services Pricing

Generally, the pricing of ancillary services is given by the 

shadow price of the ancillary services inequality constraint. 

Therefore, the price would be calculated as the cost of the 

marginal resource providing the ancillary service. The costs 

may include the bid-in cost of the resource as well as the lost 

opportunity cost it has from forgoing the energy market or 

other ancillary services markets. Opportunity costs usually 

dominate the pricing of the active-power balancing ancillary 

services in organized markets (regulation and the contingency 

reserves). Under most conditions a generator that is supplying 

spinning reserve, for example, must reduce output and forgo a 

profitable energy sale in order to stand ready to respond to a 

contingency. If that generator’s variable fuel and maintenance 

cost was $40/MWh and the energy market was clearing at 

$50/MWh, the market would have to pay at least $10/MWh 

for spinning reserve to make provision of spinning reserve 

more attractive than the provision of energy. Providing 

regulation typically includes an additional cost component to 

cover the reduction in plant efficiency that thermal generators 

experience when they position their throttling valves to enable 

fast and controlled regulation response. It may also include 

additional maintenance costs from the increased wear and tear 

of operating in this mode.

Spinning and non-spinning reserves are typically very low 

cost when the power system is at minimum load since there are 

typically numerous generators operating below full load that 

have the ability to rapidly increase output. There is no 

opportunity cost for these generators. Regulation prices do 

reflect opportunity costs at system minimum load however. 

Regulation capable generators would typically be operating at 

minimum capacities themselves, if they were still on line. They 

must increase output above the minimum capacity in order to 

be able to regulate down. Fig. 2 shows the regulation price an 

example generator would have to receive to prefer providing 

regulation as opposed to providing energy. This example 

generator has an $18/MWh fuel and variable operating and 

maintenance cost when operating at minimum load. If the 

system energy cost is below $18/MWh the generator would 

prefer to shut down. The black line shows the regulation price 

as a function of the energy price if the unit is forced on just to 

provide regulation. The dotted blue line shows the regulation 

price if the unit is being held on at minimum load because it is 

unable to cycle off.

Calculating ancillary services prices based on generator 

opportunity costs is straightforward. Including generator 

efficiency penalties is also reasonably straightforward. 

Operators of organized markets are able to perform the 

calculation for the generators, allowing the generators to 

simply provide their costs and letting the market clearing 

process generate the appropriate energy and ancillary service 

prices. Further, the market operator can co-optimize all of the 

generator bids such that it simultaneously guarantees each 

generator the maximum profit and minimizes the overall cost 

of procuring energy and ancillary services. Each generator 

submits its energy cost and operating limitations and the 

market clearing process schedules each generator for the 

optimal mix of energy and ancillary service production each 

hour.

Fig. 2. The opportunity cost of providing regulation depends on the price of 

energy and the generators variable O&M cost.

Co-optimization works well for generators but it often does 

not work for responsive loads. It is difficult to calculate the 

responsive load’s opportunity cost because it depends on more 

than the energy price. Further, unlike most generators many 

loads have a rising response cost. There may be little cost for 

providing 30 minutes of spinning reserve response but there 

may be a very large cost if the duration is extended to six 

hours of energy. Co-optimizing reserves into energy does not 

work for these resources. Energy-limited storage, which can 

provide excellent regulation but is unable to provide energy, is 

similarly restricted.

C. Other requirements

It is important to briefly mention some other requirements 

that are in existence in today’s ancillary services market 

designs. Many regions have some constraints on what 

resources can currently provide ancillary services. For 

example, in ERCOT, a maximum of 50% of the responsive 

reserve service (contingency reserve) can be supplied by 

demand response resources [17]. Also, in most if not all of the 

ISOs, variable renewable resources (wind and solar) are 

precluded from providing ancillary services.

A second important consideration of many of the ancillary 

services market designs is a location-based requirement. Many 

ISOs, especially large transmission constrained systems, will 

require certain portions of their contingency reserve to come 

from certain parts of the grid. For example, import constrained 

pockets will require that a certain portion of the contingency 

reserves that they procure come from within the pocket to 

ensure that the area can receive the reserves when transmission 

is limited. Some examples of regions that have these locational 

requirements are MISO, PJM, CAISO, NYISO, and ISO-New 

England. Regulation markets, however, are usually not 

constrained by location. Since regulation deployments are of a 

shorter timeframe, their impact on transmission constraints is 

of less consequence. 

D. Ancillary Services Cost Allocation

Ancillary services costs are not typically allocated based on 

cost causation. Instead, they are socialized based either on 
4 

energy consumption or demand. This is in spite of the fact that 

some customers differ dramatically in their ancillary service 

consumption [18]. One customer is responsible for half of the 

regulation burden in a 30-GW BA yet pays for only 3% of the 

ancillary service cost through the bundled rate. There have 

been recent efforts to assess specific ancillary service charges 

on variable renewable suppliers even though the impact of 

nonconforming loads is typically significantly higher.

III. POTENTIAL CHANGES TO THE EXISTING DESIGNS

Most of these existing ancillary services markets have 

changed only slightly if at all since their inception. However, 

as new changes to the requirements are made to ancillary 

services as variable renewable generation enters the grid, these 

changes must be incorporated in the ancillary services markets. 

The changes that may seem like simple adjustments to the 

requirements can have unintended consequences when 

ensuring they are represented in the market design.

In some recent wind integration studies, the changes to the 

reserve requirements have been analyzed to see how the 

introduction of up to 30% wind and solar on large portions of 

the Eastern and Western Interconnections would impact the 

ancillary services requirements [19]-[20]. Each of these studies 

concluded that the reserve requirements should not be static, 

but should in fact change based on the predicted conditions of 

the system. For example, the predicted wind power would 

impact the amount of variability on the system (see Fig. 3) and 

therefore, this would change the reserve need on the system. In 

current systems, this is rarely done. By having a requirement 

that changes each hour based on predicted conditions, market 

participants would have to plan ahead to understand what the 

ancillary services demand might be, similar to how they 

anticipate the load demand.

Fig. 3. Variability of wind as a function of its hourly production level.

In today’s systems, the operating reserve demand must 

usually be kept constant between the day-ahead and real-time 

markets. This is because the rules that guide operating reserves 

are such that the requirements would not change as one gets 

closer to real-time. For example, the probability of a large 

generator contingency occurring generally does not change 

since it cannot be better predicted closer to real-time. 

However, operating reserves that are held to account for the 

uncertainty of wind power may not be the same [21]. The 

operator has more information as the system gets closer in 

real-time and more confidence in scheduling generation, which 

means less operating reserves would be required. The reserve 

demand would therefore change between day-ahead and realtime markets, similar to how load demand does today. Some 

care should be taken to limit market power and ensure 

inefficiency does not result. For example, if the reserve 

demand is always higher in the day-ahead, there may be large 

price premiums for the reserve market in the day-ahead which 

could lead to diverging prices between the day-ahead and realtime markets. To account for this in the energy market, virtual 

trading is introduced. Some careful research should be 

undertaken to determine the practicality of virtual trading in

the ancillary services market.

Lastly, the technologies that participate in the ancillary 

services markets are ever changing. Today, more and more 

demand response resources are beginning to offer in to 

contingency reserve markets and regulation markets. More 

recently, some new limited energy storage resources are 

participating in the regulation markets [22]. Certain rules that 

focused on generating technologies had to be changed to allow 

for these new technologies to participate given their unique 

characteristics. In the future it is quite possible that more 

variable renewable technology like wind power may also be 

participating in certain ancillary services markets. Some 

analysis has shown this to be economic, especially in 

regulation markets [23]-[24]. Ideally, the ancillary service 

requirement is based on the need of that service and not 

tailored to the conventional market participants that are 

currently providing the service. 

IV. POTENTIAL FOR NEW ANCILLARY SERVICES MARKET 

DESIGNS

The set of ancillary services originally defined in FERC 

Order 888 that have developed into ancillary services markets 

has stood the test of time quite well. Regulation, spinning 

reserve, and non-spinning reserve cover most of the activepower balancing requirements for both normal and 

contingency conditions. Changing conditions, driven largely 

but not exclusively by the increase in variable renewable 

generation, may be creating the need for new ancillary 

services: following, frequency responsive reserve, inertial 

response, and reactive power support. All four appear to be 

amenable to market provision as ancillary services but the 

reliability requirements could also be partially or wholly 

addressed through interconnection requirements instead.

A. Following

Regulation provides the minute-to-minute balancing during 

normal conditions. Regulation operates in a time frame that is 

faster than the fastest energy market or than the economic 

dispatch scheduling interval. As such, regulation is a 

somewhat different service in regions with 5-minute energy 

markets than it is in regions that have hourly scheduled energy 

transactions.

FERC did not establish a following or load following 

service but instead, presumably, expected that the energy 
5 

market would inherently provide load following, and this is 

what normally does occur today. Following is normally 

provided by the economic movement of the conventional 

generators as part of providing energy. This can be from the 

economic dispatch of the vertically integrated utilities’ 

generation or from the hourly and sub-hourly energy markets 

of ISOs. In both cases, the conventional generation fleet was 

typically designed and built with sufficient flexibility to follow 

the net load (load minus variable renewable) daily load cycle. 

As net load rises or falls, the system operator simply commits 

and dispatches the marginal units (the most expensive 

generators currently operating) up or down to follow the net 

load. There is no explicit cost for this following service and, as 

mentioned, it was not identified as an ancillary service by 

FERC in Order 888, though discussions from some ISOs have 

occurred about establishing separate markets for its service. 

With increasing penetrations of variable renewables, the 

required ramp rate can exceed the ramping capability of the 

conventional generation fleet under some conditions [25]. Fig. 

4 shows an overly simplified hypothetical example to illustrate 

this concept. In this example there is plenty of low-cost 

$10/MWh generation available to meet the load. This low-cost 

generation has a slow ramp rate capability of 1 MW/minute, 

however. When the load ramps up by 300 MW in 30 minutes 

(10 MW/minute) the economically preferred generation cannot 

keep up. A faster ramping, but more expensive generator must 

be started and run for 3 hours simply to follow the fast load 

ramp. Eventually the low cost generation catches up and the 

ramping generator can be turned off.

Fig. 4. A Following ancillary service is required when net load ramping 

requirements exceed the ramping capabilities of the energy producing 

generators.

In organized energy markets the lack of a separate 

following service can result in a distortion of the energy 

market clearing price: the entire 2600 MW energy market may 

clear at $90/MWh from 8:00 to 13:00 even though only 300 

MW of ramping capacity is needed in the above example. In 

vertically integrated utility areas this results in the deployment 

of generation out of merit order. Regulation should not be used 

to respond to this event because the event is slow relative to 

the energy scheduling interval. Using contingency reserves is 

similarly inappropriate. Establishing an explicit following 

ancillary service may be appropriate if this type of event 

happens more than vary rarely.

Historically a separate following reserve has not been 

required in North America. Increased penetration levels of 

variable renewable generation can increase the net load 

ramping requirements, however, and both MISO and CAISO 

have recognized the need to assure that sufficient ramping 

capability is available when needed (the former described 

later). It may be appropriate to more generally define a 

following service that is similar to regulation, but slower. The 

requirement, or the compensation, may be zero during the 

many hours when the energy producing fleet inherently has 

sufficient ramping capacity to follow the net load. There is 

little need to create either an additional service or, ultimately, 

an additional payment for times when something is already in 

sufficient supply.

Like regulation, following requirements would be measured 

in MW of ramping capacity within a specific time frame. 

Accuracy of responding to system operator commands would 

be measured. Also like regulation, power system following 

requirements will likely vary hourly depending on system load 

and variable resource output. The cost to provide following 

will likely be more volatile than regulation and often zero.

B. Frequency Responsive Reserve

Spinning reserve and non-spinning reserve are usually 

defined as services which respond to contingency events. Both 

reserves must be fully deployed within 10 minutes but the 

required response during the first few cycles or first few 

seconds is not well defined. Historically this was acceptable 

because the conventional generation fleet tended to naturally 

provide the required inertia and governor response. Changes in 

the generation mix, with electronically coupled generation that 

has no inherent inertia, and changes in the operating practices 

of some large conventional generators that effectively 

eliminate governor response create a reliability concern that 

may require the addition of two new ancillary services: 

frequency responsive reserve and inertial response. 

Frequency responsive reserve was historically provided by 

conventional generators with governors. It is an autonomous 

response triggered by the frequency drop associated with a 

contingency event itself. While frequency responsive reserve is 

not yet an ancillary service, WECC has been studying 

frequency responsive reserve for many years [26]. There is 

also an established requirement in the continental European 

Interconnection [27]. It may soon be required in the Eastern 

Interconnection where governor response has declined 

significantly due to the economic operating mode of many 

large conventional generators [28]. 

Changes in technology make it possible for some 

responsive load and storage to provide frequency responsive 

reserve along with generation. Electronically coupled 

generators often have faster ramp rates and greater flexibility 

to tailor their frequency response to the requirements of the 

power system. These changes in both the power system 

requirements for frequency responsive reserve and the 

increased number of resources that are potentially capable of 
6 

providing the response may make establishing a new ancillary 

service market appropriate. Ancillary service requirements 

would be specified in terms of response need rather than in 

terms of interconnection requirements for generators. WECC 

outlined a method for determining the required amount of 

frequency responsive reserve based on the governor droop and 

the settings of the under frequency load shedding relays that it 

is desirable to avoid tripping. The droop and response speed 

must also be defined for the ancillary service providers.

C. Inertial Response

Even though there appears to be no reason that ancillary 

services markets cannot provide frequency responsive reserve

service, there is still some thought that this service ought to be 

an inherent generation feature that is specified through the 

interconnection requirements. This line of thinking is driven 

in part by the recognition that frequency response is critical for 

the stable and reliable operation of a power system, and ought 

not to be left to the vagaries of the market. This also carries 

over to the provision of an even faster responding 

characteristic of conventional generation, inertial response.

As an increasing share of energy is provided from variable 

generation with no inherent inertial response, there is a 

concern that when fossil generation is pushed out of the market 

to make room for the renewable generation, the system will be 

less stable due to the lower inertia, thereby allowing the 

frequency to decline faster during the first swing, bringing the 

system closer to the first step of under-frequency load 

shedding or instability. Detailed system simulations of WECC 

[29] have shown that during the most stressed system 

conditions – those being very light load periods during spring 

or fall nights with high wind plant output resulting in some 

fossil units being decommitted – there is a noticeable 

degradation in the system frequency response following a 

disturbance. There may be insufficient fossil-fueled

generation remaining on the system to provide adequate 

inertial response in the event of a fault. The severity of the 

disturbance is a function of the amount of wind capacity on the 

system and the amount of fossil-fueled generation 

decommitted. The simulations show that it is economically 

and technically possible to provide an emulated inertial 

response from the wind plants as good as or better than the 

response in a no-wind case.

Wind turbines connected to the system through a power 

electronic converter are capable of providing an inertial 

response. The converter controls can be programmed to apply

a retarding torque to the rotating shaft during a frequency 

disturbance to extract energy and emulate the behavior of 

inertia. This topic was brought to the fore with the 

requirement in a Hydro Quebec procurement request for 2,000 

MW of wind turbines in 2005, requesting wind turbine 

behavior representative of a machine with an inertia constant 

of 3.5 seconds [30]. 

Unlike a wind turbine, a PV cell has no inertia, and cannot 

provide an inertial response on its own. However, a fastacting storage device like a flywheel or a battery could 

certainly be programmed to provide this service. There 

appears to be a good possibility that certain fast-acting load 

could also provide a similar service.

There is an ongoing discussion over whether to trust the 

provision of inertial response to the market, or to mandate it 

through the process of interconnection requirements or grid 

codes. Until more experience has been gained with these 

alternative approaches to providing inertial response to the 

system, it is likely that a preference will be shown for this 

service, which is so important to system reliability, to be 

required through grid codes rather than left to a new ancillary 

service market design. 

D. Reactive Power Support/ Voltage Control

Reactive power is required to maintain voltages within 

acceptable limits throughout the power system [31]. Dynamic 

reactive power (reactive power that can be controlled rapidly 

and accurately) is required to respond to contingencies and to 

shifts in load and generation. FERC defined “Reactive Supply 

and Voltage Control from Generation or Other Sources” as an 

ancillary service and required transmission providers to 

provide it to transmission customers.

While the supply of dynamic reactive power is a very real 

physical function, the payments for the service are more of an 

accounting mechanism that helps to recover costs. This is 

because reactive power does not travel far through the 

transmission system and it must be supplied near where it is 

needed. This largely prevents markets from being used to 

select alternative dynamic reactive reserve providers since the 

location constraint highly limits the competition to provide the 

service. Instead, utilities typically require generators to 

provide an amount of dynamic reactive power capability which 

is then controlled by the system operator as a condition of 

interconnection. That said, other devices are also capable of 

providing dynamic reactive power and it may be appropriate to 

incentivize them to do so. Any device with a solid-state 

interface with the power system (PV, storage, variable 

frequency drives, etc.) can be designed to provide excellent 

dynamic reactive power and voltage control.

V. NEW ANCILLARY SERVICE MARKET CASE STUDY

Occasionally, the current market designs lead to short 

duration price volatility that indicate desired market actions 

but challenge the reaction times of the market participants. 

Among the variety of reasons for such price spikes are 

temporary scarcity conditions created by resource ramp 

shortages. The main causes of ramp shortages in real time 

include the forecasted variability of load, interchange 

transactions and non-controllable variable energy resources at 

or beyond the dispatch horizon and the uncertainty associated 

with the forecasts and generating unit deviations from their set 

points. Higher penetration levels of renewable resources 

including some of the SMART Grid initiatives or technologies 

intensify this problem.

What is required is a comprehensive approach in market 

clearing processes to address the required resource ramp 
7 

capability to cover the multiple sources of variability and 

uncertainty. This approach has recently been taken at the 

Midwest ISO [32]. The market clearing process should 

manage the required level of flexibility among the generation 

resources by ensuring adequate flexible capacity is available 

and sending appropriate price signals to provide incentive for 

resources to continue offering their flexibility.

The proposed approach manages the ramp capability from 

controllable resources responding to dispatch instructions in a 

way that better positions (pre-position / pre-ramp) them to be 

able to respond to variations and uncertainty in net load. The 

response available with the defined ramp capability is depicted 

in Fig. 5. 

Fig. 5. Up and Down Ramp Capability in SCED.

A. Pricing

Two options are introduced for pricing these products in 

Day Ahead and Real Time. The first option is based on the 

opportunity cost for not using participating resource capacity 

for providing other products. The next option is to allow 

qualified resources to provide a separate availability offer for 

each ramp product. The optimization process in DA and RT 

will clear these products with a system level or zonal level 

cleared prices. The selected resources will be paid the cleared 

price and the opportunity cost. Similar to conventional 

ancillary services, the interactions between the two market 

layers (DA and RT) are considered for ramp products. 

Furthermore, a demand curve for each product is considered 

restricting the cleared prices.

B. Payments

Awarded resources will be paid the cleared price both in 

DA and RT. If the cleared amount is different in DA and RT, 

the resource will sell or buy the ramp capability to/from 

market. These resources are subject to real time monitoring of 

their obligations and will be penalized if they do not perform 

within the pre-specified limits. The make whole payment 

procedure is extended to cover the ramp products.

C. Charges

Similar to other ancillary services, load will be responsible 

for charges. The amount paid in DA and RT markets to 

resources for ramp products will be distributed among loads in 

the system (or zonal) level based on their load level. As an 

alternative a different approach based on causation of 

variability and uncertainty is considered to charge not only 

load, but other variable generation resources and interchanges.

This approach will not be in place initially, however.

D. Deployment

The main difference between conventional ancillary services 

and the ramp products are in the deployment process. There is 

no separate deployment mechanism for ramp products. The 

dispatch process in the RT market acts as the deployment 

process. It withholds the rampable capacity for the future 

intervals and in the meantime deploys what is necessary for the 

next interval.

E. Resource participation

All qualified dispatchable generation resources can 

participate in Up Ramp and Down Ramp products. However, 

renewable resources can participate in Down Ramp markets, 

the demand response can participate in Up ramp markets and 

the storage resources can participate in both markets.

VI. SUMMARY

This paper describes the ancillary services markets and how 

they are impacted by variable renewable resources such as 

wind power. Many of the initial designs of electricity markets 

did not incorporate the unique characteristics of variable 

generation. The ancillary services markets are no exception. 

Potential changes to the existing ancillary services markets are 

likely to occur due to the changing requirements of those 

ancillary services. The requirements that change should be 

carefully considered to eliminate any unintended 

consequences. The market design rules guiding the ancillary 

services markets should not preclude technologies that can 

provide the desired need. This may soon include ancillary 

services being provided by variable renewable resources. 

Lastly, careful consideration should evaluate system needs that 

may currently be supplied without market incentives to 

understand if new ancillary services markets are needed to 

provide the needed services at lowest cost.

VII. REFERENCES

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

integration and operating impact state of the art,” IEEE Transactions on 

Power Systems, vol. 22, pp. 900-908, Aug. 2007.

[2] 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. 

[3] W. Hogan, Competitive Electricity Market Design: A Wholesale 

Primer, Cambridge, MA: John F. Kennedy School of Government, 

Harvard Univ., Dec. 1998. 

[4] S. Stoft, Power System Economics. New York: Wiley, 2002.
8 

[5] H. Singh, A. Papalexopoulos, “Competitive Procurement of Ancillary 

Services by an Independent System Operator,” IEEE Transactions on 

Power Systems, vol. 14, no. 2, pp 498-504,May 1999.

[6] J.C. Smith et al, “Impact of variable renewable energy on US electricity 

markets,” Proceedings of IEEE PES General Meeting, Minneapolis, 

MN, July 2010.

[7] E. Ela, M. Milligan, and B. Kirby, “Operating Reserves and Variable 

Generation,” NREL/TP-5500-51928, August 2011.

[8] V. Vittal, J. McCalley, V. Ajjarapu, and U. Shanbhag, “Impact of 

Increased DFIG Wind Penetration on Power Systems and Markets,” 

PSERC Publication 09-10, October 2009.

[9] N.W. Miller K. Clark, and M. Shao, “Impact of frequency responsive 

wind plant controls on grid performance,” Proceedings of the 9th 

Annual Large-Scale Integration of Wind Power into Power Systems and 

Transmission Networks for Offshore Wind Power Plant, Quebec, 

Canada, October 2010.

[10] I. Erlich, & M. Wilch, “Primary frequency control by wind turbines,”

Proceedings of the IEEE Power and Energy Society General Meeting, 

Minneapolis, MN, July 2010.

[11] N. R. Ullah, T. Thiringer, D. Karlsson, “Voltage and transient stability 

support by wind farms complying with the E. ON Netz grid code,” IEEE 

Transactions on Power Systems, vol. 22, no. 4, pp 1647-1656, 

November 2007.

[12] Promotion of wholesale competition through open access nondiscriminatory transmission services by public utilities and recovery of 

stranded costs by public utilities and transmitting utilities, Order No. 

888, FERC Stats. & Regs. Issued April 1996.

[13] S. Fink, J. Rodgers, and K. Porter, “Wind Power and Electricity 

Markets,” August 2009. Available: 

http://www.uwig.org/WindinMarketsTableSept09.pdf. 

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

for the Bulk Electric Systems of North America,” October 2011. 

[15] WECC, “Western Electricity Coordinating Council minimum operating 

reliability criteria,” April 2005.

[16] Northeast Power Coordinating Council, A-06 Operating Reserve 

Criteria, December 2008, section 3.2.

[17] Electric Reliability Council of Texas, “ERCOT Methodologies for 

Determining Ancillary Service Requirements,” 2009.

[18] B. Kirby and E. Hirst, “Customer-Specific Metrics for the Regulation 

and Load-Following Ancillary Services,” ORNL/CON-474, Oak Ridge 

National Laboratory, Oak Ridge TN, January 2000. 

[19] Enernex Corporation, “Eastern Wind Integration and Transmission 

Study,” Prepared for the National Renewable Energy Laboratory, 

January 2010.

[20] GE Energy, “Western Wind and Solar Integration Study,” Prepared for 

the National Renewable Energy Laboratory, May 2010.

[21] R. Doherty and M. O’Malley, “A new approach to quantify reserve 

demand in systems with significant installed wind capacity,” IEEE 

Transactions on Power Systems, vol. 20, no. 2, pp. 587-595, May 2005.

[22] M. Lazarewicz, A. Rojas, “Grid frequency regulation by recycling 

electrical energy in flywheels,” Proceedings of Power Engineering 

Society General Meeting, Denver, CO, June 2004.

[23] B. Kirby, M. Milligan, and E. Ela, “Providing minute-to-minute 

regulation from wind plants,” Proceedings of the 9th Annual LargeScale Integration of Wind Power into Power Systems and Transmission 

Networks for Offshore Wind Power Plant, Quebec, Canada, October 

2010.

[24] J. Liang, S. Grijalva, and R. Harley, “Increased wind revenue and 

system security by trading wind power in energy and regulation reserve 

markets,” IEEE Transactions on Sustainable Energy, vol. 2, no. 3, pp. 

340-347, July 2011.

[25] B. Kirby, M. Milligan, “Examination of Capacity and Ramping Impacts 

of Wind Energy on Power Systems,” NREL/TP-500-42872, July 2008.

[26] Western Electricity Coordinating Council, “White Paper on Frequency 

Responsive Reserve Standard,” April 2005.

[27] Report: ENTSO-E, UCTE Operational Handbook Policy 1, LoadFrequency Control and Performance, March 2009.

[28] R. Schulz, “Modeling of governing response in the Eastern 

Interconnection,” Proceedings of the IEEE Power Engineering Society 

Winter Meeting, New York, NY, February 1999.

[29] N. Miller, K. Clark, M. Shao, Frequency Responsive Wind Plant 

Controls: Impacts on Grid Performance. IEEE PES General Meeting, 

Detroit, July, 2011.

[30] J. Brisebois, N. Aubut, Wind Farm Inertia Emulation to Fulfill HydroQuebec’s Specific Need. IEEE PES General Meeting, Detroit, July, 

2011.

[31] B. Kirby and E. Hirst, “Ancillary-Service Details: Voltage Control,” 

ORNL/CON-453, Oak Ridge National Laboratory, Oak Ridge TN, 

December 1997.

[32] N. Navid, G. Rosenwald, and D. Chatterjee, “Ramp Capability for Load 

Following in the MISO Markets,” Version 1.0, July 2011.

VIII. BIOGRAPHIES

Erik Ela (M’06) 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. 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.

Nivad Navid is consulting engineer in Market Development and Analysis 

department at MISO. Nivad held various positions in MISO working on 

reliability, market and seams projects. Before joining MISO, he held positions 

in Siemens, CAE Electronics and Power engineering consultants. He has 

broad experience ranging a wide variety from the utility operation to the 

system planning, operation, reliability, security and design. His current 

interests are: electricity markets, renewable generation, storage resources and 

SMART grid. He received his PhD from McGill University, Montreal, 

Canada in 1995. He is a senior member of IEEE.

J. Charles Smith (SM ’85) is the Executive Director of the Utility Wind 

Integration Group. He is a Senior Member of the IEEE PES and a member of 

CIGRE. He received his BSME and MS degrees from MIT in 1970. He 

currently serves as the Executive Director of the Utility Wind Integration 

Group (UWIG). Previously, he served as President of Electrotek Concepts, a 

power engineering consulting firm. He has 35 years of experience in the 

electric power industry.