ancillary services[1]

POWER SYSTEM OPERATION CORPORATION LIMITED

Ancillary Services in Indian

Context An Approach Paper

June 2010

The objective of this paper is to suggest certain mechanisms and processes which can be introduced

and implemented as ancillary services in the Indian Electricity market.

Table of Contents

CHAPTER 1 ......................................................................................................................................................... 1

ANCILLARY SERVICES .................................................................................................................................... 1

1.1. INTRODUCTION ...................................................................................................................................... 1

1.2. NATURE OF THE ELECTRICITY GRID ...................................................................................................... 1

1.3. ELECTRICITY MARKET ........................................................................................................................... 1

1.4. NEED FOR AN ELECTRICITY MARKET COMPLEMENTING RELIABILITY .................................................... 2

1.5. TYPES OF SERVICES IN ELECTRICITY INDUSTRY .................................................................................... 2

1.5.1. Basic/System Service .............................................................................................................. 2

1.5.2. Ancillary Service ....................................................................................................................... 3

1.6. RELEVANCE OF ANCILLARY SERVICES .................................................................................................. 4

CHAPTER 2 ......................................................................................................................................................... 6

CLASSIFICATION OF ANCILLARY SERVICES ............................................................................................. 6

2.1. CLASSIFICATION .................................................................................................................................... 6

2.2. FREQUENCY CONTROL SERVICES ......................................................................................................... 7

2.2.1. Levels of Frequency Control .................................................................................................. 8

2.2.2. Frequency Reserves .............................................................................................................. 11

2.3. VOLTAGE CONTROL ANCILLARY SERVICES ........................................................................................ 13

2.3.1. Need for Voltage Control ....................................................................................................... 13

2.3.2. Levels of Voltage Control ...................................................................................................... 14

2.3.3. Cost of Voltage Control ......................................................................................................... 15

2.4. BLACK START CAPABILITY ................................................................................................................. 15

CHAPTER 3 ....................................................................................................................................................... 16

PROPOSED ANCILLARY SERVICES IN INDIAN CONTEXT ...................................................................... 16

3.1. BACKGROUND ..................................................................................................................................... 16

3.2. PREVALENT SCENARIO IN INDIA .......................................................................................................... 16

3.3. ANCILLARY SERVICES MARKET: PRESENT POSITION .......................................................................... 17

3.4. PROPOSED ANCILLARY SERVICES IN INDIAN ELECTRICITY MARKETS ................................................. 20

3.5. LOAD GENERATION BALANCING SERVICE (LGBS) ............................................................................. 20

3.6. NETWORK CONTROL ANCILLARY SERVICES (NCAS) ......................................................................... 23

3.6.1. Power Flow Control Ancillary Services (PFCAS) .............................................................. 23

3.6.2. Voltage Control Ancillary Service (VCAS) ......................................................................... 24

3.7. SYSTEM RESTART ANCILLARY SERVICE (SRAS) ............................................................................... 25

3.8. ANCILLARY SERVICES FUND ............................................................................................................... 25

CHAPTER 4 ....................................................................................................................................................... 26

FUTURE SCOPE ............................................................................................................................................... 26

4.1. PRIMARY FREQUENCY CONTROL ........................................................................................................ 26

4.2. SPINNING RESERVES........................................................................................................................... 26

4.3. REACTIVE ANCILLARY MARKET .......................................................................................................... 27

4.4. METERING REQUIREMENTS ................................................................................................................. 29

CHAPTER 5 ....................................................................................................................................................... 30

CONCLUSION ................................................................................................................................................... 30

ANNEXURE I: INTERNATIONAL PRACTICES ............................................................................................. 31

ANNEXURE II: PRICING METHODOLOGIES ............................................................................................... 37

REFERENCES .................................................................................................................................................. 43

List of figures

FIGURE 1: DIFFERENCE BETWEEN SYSTEM SERVICES AND ANCILLARY SERVICES [2] .......................................... 2

FIGURE 2: FOUR PILLARS OF MARKET STRUCTURE [7] ..................................................................................... 4

FIGURE 3: FUNDAMENTAL BEHAVIOR OF A POWER SYSTEM [11] ...................................................................... 7

FIGURE 4: OPERATION AT DIFFERENT FREQUENCY LEVEL [6] ........................................................................... 8

FIGURE 5: UCTE’S CLASSIFICATION OF FREQUENCY RESERVES ........................................................................ 9

FIGURE 6: THREE FUNCTIONAL FREQUENCY CONTROL OF A GENERATOR [2] .................................................. 11

FIGURE 7: LEVELS OF CONTROL FOR A GENERATING UNIT ............................................................................... 12

FIGURE 8: THREE FUNCTIONAL VOLTAGE CONTROLS CONSIDERING A GENERATING UNIT[2] ........................... 14

FIGURE 9: PROPOSED CURVE FOR PRICING OF REACTIVE POWER V/S VOLTAGE............................................... 28

FIGURE 10: LOAD CURVE SHOWING REGULATION LOAD FOLLOWING ................................................................ 31

FIGURE 11: BREAK UP COST INCURRED IN PROVIDING ANCILLARY SERVICES IN US [20] .................................. 32

FIGURE 12: ANCILLARY SERVICE COST IN NEMMCO IN 1998-99 [20] ........................................................... 35

FIGURE 13: FREQUENCY RANGE AND OPERATOR ACTION IN NORDEL SYSTEM [20] .......................................... 35

FIGURE 14: RESERVE OPPORTUNITY COST FOR LOW COST GENERATING UNIT [6] ........................................... 41

FIGURE 15: RESERVE OPPORTUNITY COT FOR A HIGH COST GENERATING UNIT [6] ......................................... 41

Ancillary Services in Indian Context: An Approach paper Page 1

Chapter 1

Ancillary Services

1.1. Introduction

Ancillary Services have always been an integral part of the electricity industry. They were and

are always needed when electricity is to be transferred reliably and delivered with satisfactory

quality. In India also, ancillary services have grown along with the grid. They have traditionally

been a part of grid operation and are mostly mandatory.

Reforms in Indian electricity sector along with evolution of electricity markets have led to a

paradigm shift and electricity is now seen as a tradable commodity, rather than just an

infrastructural requirement. In a ‘market oriented electricity industry’, commercial mechanisms

need to be in place for procurement of various services and to have prompt response from the

entities. As a result ancillary services also should be separated from basic system services and

remunerated appropriately. This gains additional strength from the fact that a structured

ancillary service market would complement reliability of the power system.

1.2. Nature of the Electricity Grid

Electrical systems around the world are physically and operationally very similar. The

generation of power is done by utilizing different thermal, hydro, nuclear, wind and other non

conventional energy sources. Transmission of power takes place through high voltage AC and

DC lines and electricity reaches the end consumer through low voltage AC distribution network.

The system operator performs the task of operation of the power system in a secure, reliable

and efficient manner.

Electricity travels with the speed of light and the time period of various electrical phenomenon is

very less. Transients in electrical systems have a time period of micro-seconds and operation of

protection devices and circuit breakers take a few milliseconds. The response time of humans is

much sluggish when compared to that of different electrical phenomenon.

1.3. Electricity Market

Bulk of energy delivery in Indian market takes place through advance contracts between buyers

and sellers. The contracts are further divided into long-term, medium-term and short-term

energy contracts. Day-ahead scheduling of both beneficiaries and generators is done by the

system operator.

Indian power industry follows a decentralized system which means that the both the suppliers

and beneficiaries are free to declare their capacity/requirement and their deviation from

schedule is treated as per UI mechanism. This ‘Unscheduled Interchange(UI)’ is dealt

commercially on a post-facto basis using a ‘regional pool settlement’ system.


1.4. Need for an Electricity Market Complementing Reliability

One of the most fundamental requirements of the electricity market is that its design should be

such that it complements the reliability and security of the system. The balancing market keeps

supply and demand in balance until the system operator is forced to intervene.

Steven Stoft in his book on Power System Economics says “The structure of reliability

requirements determine not only short-term reliability, but the height and frequency spikes and

therefore long run investment in generation and long run reliability. These consequences of

market structure are often overlooked, so the design of the reliability structure is often

inappropriate, sometimes with serious consequences.”

1.5. Types of Services in Electricity Industry

Services in power systems are categorized into two subdivisions:

• Basic/ System Services

• Ancillary Services

Figure 1: Difference between system services and ancillary services [2]

The two services are interdependent on each other. This complicates things because the same

supplier can be simultaneously required to produce both system services and ancillary services.

1.5.1. Basic/System Service

Different definitions available in literature for basic/system service are:

“System services are all services provided by some system function (such as a system operator or a grid/network operator) to users connected to the system.”....Ancillary Services -Unbundling Electricity Products – an Emerging Market, Eurelectric[3]

“Basic –Services are generation, energy supply and power delivery.”….Para 30, judgment in appeal no.202 dated 13th December 2006, The Appellate Tribunal for Electricity[4]

“The frequency and voltage control services are called system services (SS) because they are delivered by the power system to all the users”….A Comprehensive Assessment of Markets for Frequency and Voltage Control, Yann Rebours[2]

Thus System or Basic services are the services such as generation, transmission and distribution of power which are delivered to all the users connected to the system.


1.5.2. Ancillary Service The word ‘ancillary’ in English language means subordinate, subsidiary or auxiliary. The Oxford

English dictionary says that it means ‘providing subsidiary support’. Collins describes it as

‘supporting the main work of an organization’. As per Longman it means ‘connected with or

supporting something else, but less important than it’. Etymologically the origin of the word can

be traced back to the year 1667 from the Latin word ‘ancillaris’, which means ‘ relating to

maidservants’.

Although the dictionary meaning of ancillary service is support or subsidiary service but the

exact sense differs from industry to industry. In hospital industry ancillary services are those

support services other than room, board, and medical and nursing services that are provided to

hospital patients in the course of care. They include such services as laboratory, radiology,

pharmacy, and physical therapy services. In tourism industry it includes services such as

marketing, reservations, and co-ordination among tour agencies.

In literature, following definitions of ancillary services are available pertinent to the electricity industry: “Ancillary services are services procured by a system functionality (system operator or grid/network operator) from system users in order to be able to provide system services.”… Ancillary Services -Unbundling Electricity Products – an Emerging Market, Eurelectric[3] “Ancillary services are those functions performed to support the basic services of generation, transmission, energy supply and power delivery. Ancillary services are required for the reliable operation of the power system.”… Para 30, judgment in appeal no.202 dated 13th December 2006, The Appellate Tribunal for Electricity[4]

“Ancillary services are those functions performed by the equipment and people that generate, control, transmit, and distribute electricity to support the basic services of generating capacity, energy supply, and power delivery.”….Electric Power Ancillary Service, Eric Hirst and Brendan Kirby[5] “necessary to support the transmission of electric power from seller to purchaser given the obligations of control areas and transmitting utilities within those control areas to maintain reliable operations of the interconnected transmission system”….FERC “Ancillary service is an interconnected operation service that is necessary to affect a transfer of

electricity between purchasing and selling entities, and which a transmission provider must

include in an open access transmission tariff.”….NERC

“Ancillary services are those services necessary to support the transmission of electric power from producer to purchaser.”.....Methods and Tools for Costing Ancillary Services, CIGRE[6] “Some users of the system, such as generators, contribute to these system services by acting on the frequency of the system or the voltage at the point where they are connected to the system. Because these services provided by users are ancillary to the production or


consumption of energy, they are called ancillary services (AS).”….. A Comprehensive Assessment of Markets for Frequency and Voltage Control, Yann Rebours[2] It is hence clear from the above quoted definitions that ancillary services are the value added services required to support the system services to facilitate reliable and efficient operation of the power system.

1.6. Relevance of Ancillary Services

Electricity is one of a kind market. The arrangements for delivery of power are at the fulcrum of

this market; as a result, the problems related to delivery of power have to be taken into account.

No other product or market has these problems which are both technical and institutional and

this is what makes this sector different from all other commodities and requires different

arrangements than those which apply to the rest of the economy. The features that make it

different are: electricity cannot be stored, flow of power takes place as per the laws of physics

and not as per any commercial agreement, production of energy and production of other

services are interdependent and it travels at the speed of light. The trading rules that deal with

these four unique features are the four pillars of good electricity market design. These are

imbalances, congestion management, ancillary services and scheduling and despatch [7].

Imbalances, congestion management and scheduling and despatch have already been

implemented in the India. Introduction of ancillary services should thus be certainly the next step

to ensure proper market design in place.

Figure 2: Four Pillars of Market Structure [7]

The Appellate Tribunal on Electricity in its judgment on appeal no.202 dated 13th December

2006 emphasizes on the importance of introduction of ancillary services in Indian Electricity

market. Para no. 37 of the judgment says “………because hitherto the entire system, be it

independent or interconnected were wholly owned and operated by State undertakings or

central undertakings and probably with reciprocal arrangement. Further they were not anxious

to provide quality service and outages remained till the very system rectified the outages and


outages were very common and usual. The scenario has now changed by unbundling and

private participation and the necessity to provide ancillary services of “stand-by” for assured and

uninterrupted supply and instantaneous management of outages have arisen. It is for the

legislature to undertake suitable legislative measures at the earliest in the interest of emerging

competitive market by introducing amendments…..”

In vertically integrated utilities the responsibility of generation, transmission and distribution is

with one organization and hence these services are an integral part of electrical supply and not

dealt with separately. However, since the liberalization of the electricity supply industry, the

resources required to achieve this control have been treated as an ancillary service that the

system operator has to obtain from other industry participants. This is essential because in a

deregulated power system, the system operator often has no direct control over individual

power stations and has to purchase these services from other service providers. In such a

scenario, issues pertinent to the pricing and procurement of these services become extremely

important for proper functioning of the system.


Chapter 2

Classification of Ancillary Services

The system operator is expected to ensure the required degree of quality and safety, undertake

preventive measures to ward off contingencies and perform several other functions to maintain

the integrity and reliability of the system. For realizing the same the operator must be able to

control the frequency and voltage of the system within certain bounds, maintain the stability of

the system, prevent overloads in the transmission system and restore the system or portions of

it when and if required. Implicit in this list is the need for the system operator to maintain system

integrity in the presence of events and contingencies. Ancillary services, as already mentioned

are essential to ensure that the above mentioned responsibilities are properly met.

2.1. Classification

Ancillary services are concerned with the despatch, trade and delivery of power. They are

usually defined by the benefits they provide to the market participants and not by their method

of provision. Different classifications of ancillary services as available in literature are listed

below:

Table 1: Definitions of Ancillary Services

S.no Source/ Author Services

1

Power System Economics, Steven Stoft

1) Real-power balancing (frequency stability)

2) Voltage Stability (for customers)

3) Transmission Security

4) Economic Despatch

5) Financial Trade Enforcement

6) Black Start

2

FERC

1) Reactive Power and Voltage Control

2) Loss Compensation

3) Scheduling and Despatch

4) Load Following

5) System Protection

6) Energy Imbalance

3

Eric Hirst and Brendan Kirby

1) Scheduling and Despatch

2) Load-Following Reserve

3) Operating Reserve

4) Energy Imbalance

5) Real-Power Loss Replacement

6) Voltage Control


4

Yann G Rebours, Daniel S Kirschen, Marc Trotingnon and Sebastien Rossignol

1) Frequency Control Service

2) Voltage Control Service

5

CIGRE

1) Reactive Power

2) Frequency Control

3) Black Start

4) Reserve

5) Losses

6

S.K. Parida, S.N. Singh and S.C. Srivastava

1) Frequency Control Service

2) Network Control Service

3) Black Start Service

The different lists of ancillary services tabulated above differ mainly in how they split and

combine the categories of services. Broadly all these services can be grouped under one of the

three following major categories:

• Frequency Control Services

• Network Control Services

• System Restart Services

2.2. Frequency Control Services

Frequency is a measure of the quantum of active power produced and the active power

consumed, both of which must remain in a balance for making possible the operation of an AC

system. An imbalance between these two results in deviation of frequency from the nominal

value. The frequency is thus a useful indicator to be used for regulation of active power

production to achieve balance.

Figure 3: Fundamental Behavior of a Power System [11]


Frequency regulation is of great importance for system security. The frequency deviation should

normally be within a specified acceptable range for secure power system operation and

ensuring safe and reliable operation of the equipments connected. As the power consumption

varies, the active power production must be regulated accordingly. Operation at different

frequency levels is shown in the figure below:

Figure 4: Operation at Different Frequency Level [6]

Technical Features of Frequency Control Services

Deployment times are the most important technical features for frequency related ancillary

services. ‘Deployment start’ is the maximum amount of time elapsed between the request from

the system operator and the beginning of response by the service provider. ‘Full availability’ is

the maximum time that can elapse between the moment when the provider receives the request

and the moment at which it delivers its full response. The maximum amount of time during

which the service must be provided starting from the time of the request is called ‘deployment

end’.

2.2.1. Levels of Frequency Control

Three levels of Frequency Control are generally used to maintain the balance between

generation and load i.e.

a) Primary Frequency Control

b) Secondary Frequency Control

c) Tertiary Frequency Control

Three levels differ as per their time of response to a fluctuation and the methodology adopted to

realize the fundamental operating philosophy of maintaining reliability and overall economy.

Figure 5 shows classification of frequency control services based on their deployment times.


Figure 5: UCTE’s classification of frequency reserves

a. Primary Frequency Control

Primary control is a local automatic control which adjusts the active power generation of

generating units and consumption of controllable loads to check the deviation in frequency. In

particular, it is designed to stabilize the frequency following large generation or load outages. It

is thus indispensable for the stability of the power system.

All the generators that are located in a synchronous zone and are fitted with a speed governor

(having droop1 settings) perform this control automatically. The demand side also participates in

this control through the self-regulating effect of frequency-sensitive loads such as induction

motors or the action of frequency-sensitive relays that disconnect or connect some loads at

given frequency thresholds.

Procurement/Source of Primary Control

Primary frequency reserves must be uniformly distributed across the network to reduce

unplanned transits following a large disturbance. Uniform distribution also helps to maintain

system stability in case of islanding.

Hydro turbines/stations are eminently suited for both primary control (FGMO) and load-

following. The unit load in these machines can be varied rapidly and units can be brought

in/taken out without causing any substantial stress or efficiency loss. Load-following may have

to be limited in some cases from other water release considerations (irrigation, minimum flow,

etc.). In case of canal-based hydro stations having no free-board, neither FGMO nor load-

following may be possible.

1 ‘Governor Droop’ is defined as the percentage change in frequency for which a generator changes its output from

full-load to no-load.


Gas turbines stations are suitable for load-following because they can be brought in/taken out in

a controlled manner but are not that suitable for primary control because they are to be

operated at a fixed firing temperature (balancing between efficiency and life). Increasing the fuel

injection to increase the MW would cause firing temperature to go above what can be

continuously sustained. Decreasing the fuel injection to decrease the MW lowers the firing

temperature, and rapid/frequent firing temperature changes cause thermal over-stressing.

The efficiency also falls with lowering of firing temperature.

In case of steam turbines, efficiency falls only marginally at part-load, because steam

parameters can be maintained at rated levels. They can provide both primary control and load-

following. In the short time frame the active power from a steam turbine can be changed by the

actions of valves which provide primary response. In the longer range (for load following) it is

needed to change the primary input power, for example the flow of fuel. HVDC might also be

used as a source of primary control if it is interconnecting two systems, more so in developed

power systems where frequency is very tightly regulated and sufficient spinning reserves are

available.

b. Secondary Frequency Control

Secondary frequency control is a centralized automatic control that adjusts the active power

production of the generating units to restore the frequency and the interchanges with other

systems to their target values following an imbalance. This is achieved by either changing the

setpoint or reference point of generators, or by starting and stopping of power plants. Only the

generating units located in the control area2 where the imbalance has occurred should

participate in secondary control. [8]

The goal of secondary frequency control is to minimize the area control error (ACE)3. After an

unforeseen load power change, the primary frequency control will adjust generation to achieve

active power balance. This will result in a frequency deviation due to the permanent droop of the

primary frequency regulation in the power plants. However, this regulation will also result in a

deviation of power transfer between control areas from the intended power transfer in the

system. The automatic secondary frequency regulation will re-establish the intended power

transfer.

Secondary frequency control aims to bring the ACE to zero with the help of proportional integral

(PI) controller and filters. Within the UCTE, secondary frequency control is also known as load

frequency control (LFC) and in North America it is termed as automatic generation control

(AGC).

2 A control area is an electrical system bounded by interconnections (tie lines), metering and telemetry which

controls its generation and/or load to maintain its interchange schedule with other control areas whenever

required to do so and contributes to frequency regulation of the synchronously operating system. 3 ACE is the instantaneous difference between net actual and scheduled interchange, taking into account the

effects of frequency bias.


c. Tertiary Frequency Control

Tertiary frequency control refers to manual changes in the despatching and commitment of

generating units. This control is used to restore the primary and secondary frequency control

reserves, to manage congestions in the transmission network, and to bring the frequency and

the interchanges back to their target value when the secondary control is unable to perform this

last task. [8]

A figure showing realization of the three levels of frequency control for a generating unit with the

help of feedback control loops is show in Figure 6

Figure 6: Three Functional Frequency Control of a Generator [2]

2.2.2. Frequency Reserves

Frequency reserves are required to maintain the integrity of the system in case of an imbalance

between the active power consumption and generation. These situations may arise due to

generation outages or load variations. The amount of reserves required depends on the

probability of multiple generation outages and the volatility of load. For example if a system has

more arc furnace load then the reserve requirement of the system would go up as an arc

furnace load is highly volatile. However if a generator is prone to frequent outages the amount

of reserves required would not change but the use of reserves would go up.

Three types of frequency controls defined earlier in this chapter would need some reserves in

form of spare generation capacity/ load management to respond to deviations in frequency.


Reserve utilization for different types of frequency control in case of a typical generating unit is

shown in figure below

Frequency reserves can be split up into the following broad categories:

• Spinning Reserves/ Reliability Reserves

This includes generating units which are capable of being fully available of responding

nearly instantaneously. Some very fast acting units or controllable loads make up this

category. These reserves are not capable of continuing at increased power output for

long durations. They must therefore be eventually replaced by supplementary reserves.

This might be provided by synchronized hydro units or Internal Combustion Engines.

Figure 7: Levels of control for a generating unit


• Supplementary Reserves

Their response time need not be as quick as spinning reserves but they should be

capable of operating at increased power output for longer durations. They often require

manual intervention for activation. This reserve might be provided by generating units on

hot standby also.

• Backup reserves

These are reserves that can stay in service for a considerable period after they are

called upon (in the range of hours), but that are not expected to come on line for some

time (typically, 30 minutes or more).

2.3. Voltage Control Ancillary Services

System voltage is the other benchmark parameter for power quality. Voltage in power system is

controlled by controlling the reactive power injection and drawl. Flows in the network create

voltage increases and drops that are the result of interactions between flows and the inductance

and capacitance of each line or transformer.

2.3.1. Need for Voltage Control

System voltage control is used to maintain the voltages at different nodes in the system within

the specified limit and to compensate for the requirement of reactive power in the system.

Because of high inductance of lines and transformers, reactive power does not travel well

through the grid, so reactive power support must be provided much closer to reactive loads.

Voltage Control is required due to the following reasons:

i. Voltage supply to equipments must be within its design limits for safe operation and

good performance.

ii. Change in voltages changes the reactive power flow in the system which in turn has an

effect on the system losses.

iii. Voltages might also limit the transfer capability of the system.

iv. Injection and absorption of reactive power is also required to maintain system stability, in

particular to protect against contingencies that could lead to voltage collapse.

Enough reactive-power capacity must be available to meet expected demands plus a reserve

margin for contingencies. Thus, voltage control is analogous to reliability spinning reserve. Local

voltage regulation is a customer service intended to meet customer reactive-power needs and

to control each customer’s impact on system voltage and system losses so power-factor

problems at one customer site do not affect power quality elsewhere on the system.


2.3.2. Levels of Voltage Control

The overall task of regulating the voltage can be organized into a three level hierarchy.

1. Primary voltage control is a local automatic control that maintains the voltage at a

given bus (at the generating bus) at its set point. Automatic voltage regulator (AVR)

fulfills this task. Other controllable devices, such as static voltage compensators

(SVC), can also participate in this primary voltage control.

2. Secondary voltage control is a centralized automatic control that coordinates the

actions of local regulators in order to manage the injection of reactive power within a

regional power system.

3. Tertiary voltage control refers to the manual optimization of reactive power flows

across the power system.

Figure 8: Three Functional Voltage Controls Considering a Generating Unit[2]

Voltage is controlled throughout the transmission system through the application and operation

of ratio-changing devices (e.g., transformer taps and voltage regulators) and reactive power-

control devices (e.g., capacitors, reactors, static-VAR compensators, generators, and

occasionally synchronous condensers). The system operator must monitor and control these

voltages and supply the reactive-power requirements of the grid. At low-load times, VAR

absorption is required to keep voltages from getting too high; at high-load times, VAR

production is required to keep voltages from getting too low. At certain locations, it may be more

economical for the utility to purchase reactive support from a customer or generator than to

supply the reactive support directly. The equipment used to provide or absorb VARs can be

categorized as dynamic (referring primarily to generating units) or static (referring primarily to

transmission-system equipment) depending on its ability to change VAR output or absorption

quickly. Per VAR, dynamic equipment is much more expensive than static equipment.


2.3.3. Cost of Voltage Control

The cost of supplying reactive power is primarily the capital cost of the equipment (e.g.,

generators and capacitors) needed to meet expected requirements plus a reserve. In addition,

the operating cost of over or under excitation of generating units should be assigned to reactive

support. The primary cost of voltage support provided by generators is for the losses in the

rotor, stator, exciter, and step-up transformer. In some cases, there may also be an opportunity

cost associated with the reduction in real-power production capability caused by production or

absorption of VARs.

In case of reactive power the actual cost of providing the service is likely to consist of mostly

fixed cost and it is also generally lumped or discrete. The variable cost components are

generally quite low.

2.4. Black Start Capability

Black start is the ability in respect of a black start station, for at least one of its generating units

to start-up from shutdown and to energize a part of the system and to be synchronized to the

system under instructions without an external power supply .It can also be termed as a process

to recover or reenergize a system from total or partial failure. For black start of an electrical

power system we need to have generating units with black start capability.

A black start unit is defined as a generating unit that is able to start without an outside electrical

supply or the demonstrated ability of a base load unit to remain operating, at reduced levels,

when automatically disconnected from the grid. A black start station has one or more black start

units. Such generating units or stations form the black start reserve of a system which would be

used to energize the power system in case of a blackout and to generate power for local needs

if the power system is out of operation.

All generating stations except a few small hydro stations need electrical supply to start up. Such

stations must have some form of supply which could be used to operate the unit auxiliaries so

that the turbo-generator set is prepared for operation. Generally for small diesel generators this

supply is provided by batteries, for large diesel generators or gas engines it is done using

pressurized air and diesel engines supply the start up supply for gas turbines[12]( startup supply

requirement is typically 2% of the installed capacity for gas turbines and 1% for hydro stations).

Such a generating unit may then be used to energize a sub-system or other generating stations

in its proximity.

For a unit to qualify as a black start unit it must satisfy the following performance criteria [13]

i. A black start unit must have the capability of closing its circuit breaker to a dead bus

upon request.

ii. It must have the capability to maintain frequency under varying loads.

iii. It must have the capability to maintain voltage under varying loads

iv. It must be able to maintain its rated output for a given time (as decided by the system

operator)


Chapter 3

Proposed Ancillary Services in Indian Context

3.1. Background

Ancillary services are activities done for a common good, which benefit all the users and

specific identification of beneficiary of these services is not possible. As a result, activities like

enhancement of transfer capability should not be termed as ancillary services because the

beneficiaries of these are already identified and charges on account of capital expenditure for

installation of transmission elements must be paid by those who are benefited. Hence the scope

of ancillary services is limited to operational expenditure only.

Ancillary Services discussed in international literature are in the context of mature electricity

systems of advanced countries which operate with adequate reserves, tight frequency control

and effective primary, secondary and tertiary response. Therefore while applying these

concepts in Indian context, the features of Indian power system that distinguishes it from other

power systems have to be considered.

3.2. Prevalent Scenario in India

3.2.1. Frequency Profile

The permissible frequency band as per the Indian Electricity Grid Code (IEGC) is 49.5- 50.2 Hz.

While the demand for electricity in India is growing by leaps and bounds, the absence of

matching addition in the generation capacity coupled with the ever-increasing pressure to meet

demand has resulted in operation beyond the permissible system frequency band. As a

consequence of this, the frequency profile of the grid fluctuates widely.

Frequency does invariably go out of the permissible band in spite of specifying upper and lower

limits in the IEGC and facilitating a balancing market in the form of frequency linked UI

mechanism. This clearly brings out the fact that the idea of having a tight frequency profile

cannot be realized only with UI mechanism and by specifying a frequency band through

regulations. Availability Based tariff (ABT) and regulatory initiatives alone are not sufficient as

they involve manual intervention and the response time is much more when compared to the

dynamically changing power system. A flat and tight frequency profile (as existent in developed

countries) can thus only be there if these manually triggered controls are adequately

complemented by automatic controls.

However, from past experiences it is evident that giving a commercial signal in form of ABT

helped in tightening of the frequency band and utilization of generation resources available with

‘fence sitters’ which were earlier left untapped (under the previous settlement mechanism).

Hence apart from regulatory interventions some commercial mechanisms also need to be in

place to tap all the possible generating resources in the country and to have a better frequency

profile.


3.2.2. Voltage Profile

Extreme environmental condition varying from foggy cold winter to extremely hot summer and

wide fluctuation in hydro-thermal generation mix reflects in the form of wide fluctuation in system

voltage profile. Seasonal variation and agricultural loads causes extremes of voltage profiles in

the network. Similarly voltage variations are also there in the system depending on the location

of the node.

During winter season, generations at most of the hydro stations are at their minimum level. This

result into low voltage profile during early peak hours and high voltage during off peak hours

because of lightly loaded long hydro stations connecting lines. On the other hand, during

summer season large weather beating loads and agricultural loads for paddy crop results into

extreme low voltage throughout the regional grid.

Maintaining voltage profile within acceptable permissible limits requires meticulous reactive

power management in the form of shunt reactor switching, shunt capacitor switching,

transformer tap co-ordination, switching of transmission lines and running the generators in the

synchronous condenser mode.

3.3. Ancillary Services Market: Present Position

3.3.1. Primary Frequency Response: Governor Action

The primary response activates generator governors to react to frequency deviation by opening

or closing the turbine steam valve and alter the MW output as per the frequency deviation. As

per the clause 5.2 (f) of the IEGC:

“All thermal generating units of 200 MW and above and all hydro units of 10 MW and above,

which are synchronized with the grid, irrespective of their ownership, shall have their governors

in operation at all the times ………..”

The above clause mandates all the generators (except nuclear generators) to have their

governors functional w.e.f 1st August 2010. However in the present scenario the governing

function has been bypassed/ restricted in generators across the country. Absence of this feature

results in sharp notches in the frequency of the grid. Trials of Free Governor Mode of Operation

(FGMO) have been carried out in different regions but successful implementation of FGMO in all

the generators throughout the country is still not there.

Cost of equipments required for FGMO/RGMO is included in the total capital cost and is being

recovered by the stations in their annual fixed charges. IEGC also emphasizes on the

importance of FGMO/RGMO in maintaining grid reliability and reiterates that governors in

generating units should become functional. Hence it is expected that in the time to come all

generators will operate in FGMO/RGMO.


3.3.2. Secondary Frequency Response: AGC

Secondary frequency response refers to a centralized, automatic control which acts to bring

back the frequency and interchanges across tie lines to their nominal value. In US and

European countries this control is known as Automatic Generation Control (AGC) and Load

Frequency Control (LFC) respectively.

In India the philosophy of loose power pools is followed, in which there is a special treatment of

deviations from the schedule. Secondary Frequency Control is thus absent in India by design.

Similar philosophy is followed in Nordic countries and UK where automatic generation control is

not exercised.

3.3.3. Tertiary Frequency Response

Tertiary Frequency Response refers to manual changes in load and generation on deviation of

the grid frequency from its nominal value. Apart from manual load shedding, the Availability

based tariff (ABT) mechanism in vogue today provides frequency linked incentives/penalties to

beneficiaries/suppliers. All Inter – State supply arrangements are implemented through day-

ahead despatch and drawl schedules as per IEGC. Real time deviations from the schedules

(over-drawl, under-drawl, over-generation and under-generation) are financially settled through

UI mechanism. The settlement rate is a function of the grid frequency in a given time block.

Thus, at inter-state level, tertiary frequency control ancillary service has been provided to some

extent through the balancing market (UI mechanism).

3.3.4. Voltage Control Service

As per the Indian Electricity Grid Code (IEGC) section 6.6.1:

“Reactive power compensation should ideally be provided locally, by generating reactive power

as close to the reactive power consumption as possible. The Regional Entities except

Generating Stations are therefore expected to provide local VAr compensation/generation such

that they do not draw VArs from the EHV grid, particularly under low-voltage condition. To

discourage VAr drawals by Regional Entities except Generating Stations, VAr exchanges with

ISTS shall be priced as follows:

The Regional Entity except Generating Stations pays for VAr drawal when voltage at the

metering point is below 97%

The Regional Entity except Generating Stations gets paid for VAr return when voltage is

below 97%

The Regional Entity except Generating Stations gets paid for VAr drawal when voltage is

above103%

The Regional Entity except Generating Stations pays for VAr return when voltage is

above 103%”


The present rate of reactive power exchange in our country is 10 paise/kVArh and it escalates

at a rate of 0.5 paise/kVArh/year.

The reactive power requirement must be met locally, however it is clear from the above clause

that it is not mandatory and the utilities are allowed to draw reactive power from the grid too. In

addition, the reactive power exchange prices mentioned above are not applicable to ISGS and

they are mandated to produce/absorb reactive power within their capability curve.

3.3.5. System Restart Ancillary Service

In the current Indian scenario there is no scheme for compensation to the suppliers of black

start service. Certain identified units are often asked to provide the black start service in case of

islanding of a sub- system and for mock exercises (e.g Bhakra and Tehri Hydro stations in

Northern Region). But these units are not reimbursed for the cost they incur while providing this

service. A proper compensation mechanism should be in place so that the black start service

can be voluntarily procured from generating units.

Table 2: Summary of Present Position w.r.t other international ancillary services market [20#]

Service NGC#

Svenska

Kraftnat# NEMMCO# NYISO# India

Scheduling

and

Despatch

Recognized

and

provided

Not

Recognized

Not

Recognized

Recognized

and provided

System Operator is

mandated as per

IEGC

Frequency

Response

Primary

Response

Provided

through

balance

service

Bilateral

Contracts

Recognized

and

compensated

Recognized

and price

based on

market

Mandated as per

IEGC

Secondary

Response

Balance

Service Absent by Design

Tertiary

Response

Only manual load

shedding is done

Voltage

Control

Recognized

and

provided

through

Grid Code

No payment

scheme

Recognized

and paid to

generators and

synchronous

compensators

Recognized

and paid to

generators

only

Mandatory for

ISGS. Commercial

mechanism for

states

Operating

Reserve

Within

purview of

balance

service

Recognized

and

compensated

Recognized

and

compensated

Limited reserves

available. Not

treated as a

service

Black Start

Capability

Service Provided

Provided

through

bilateral

contract

Recognized

and

compensated

Recognized

and

compensated

Mandatory as per

IEGC


3.4. Proposed Ancillary Services in Indian Electricity Markets

The earlier section clearly brought out the fact that presently in India almost all the activities

which can be classified as an ancillary service are mandated by regulatory initiatives. Making a

service obligatory without any commercial consequences might not always be able to yield

tangible deliverables. The providers and users of these services would not be prompted for the

same unless a proper commercial mechanism is in place for it. This paper in the coming

sections proposes a set of ancillary services as well the costing methodologies which could be

used for procurement of these services.

Ancillary services can be classified in numerous ways and many methods can be suggested for

procurement and remuneration of these services. However considering the present condition

and maturity of the Indian Electricity Market, it is prudent to avoid complex definition of these

services and refrain from mechanisms which are complicated and difficult to implement. Under

the present scenario, ancillary services can be broadly classified into three major categories:

(i) Load Generation Balancing Service (LGBS)

(ii) Network Control Ancillary Services (NCAS)

a) Power Flow Control Ancillary Services (PFCAS)

b) Voltage Control Ancillary Services (VCAS)

(iii) System Restart Ancillary Services (SRAS)

3.5. Load Generation Balancing Service (LGBS)

The requirement for this service arises from mis-matches between supply and demand. In India

although a commercial signal in form of Unscheduled Interchange (UI) is present, the frequency

does deviate beyond its permissible band. This is because of the fact that UI also requires

manual intervention which makes its response time slower and it also does not settle the

adequacy issue. The power system in India will be even more reliable by attracting more

generation, both by getting existing idle generation to operate at opportune times and by

increasing the investment in the new generation capacity. As ancillary services, the attention is

focused on getting idle generation to operate at opportune times.

The various options that might be harnessed under LGBS are:

3.5.1. Un-despatched Surplus

There are a number of gas based combined cycle Inter-state generating stations, which are

facing almost perennial fuel (gas) shortage. These power stations can be operated with

alternate fuel like HSD, RLNG, Naphtha etc., however cost of operation with these fuels is much

higher than that with gas. As per provisions of IEGC, these power stations declare capacity for

units and modules on APM gas, RLNG and liquid fuel separately and these are scheduled

separately based on different fuels. Due to the high cost of liquid fuel in prevalent market

condition, and absence of proper commercial signal, available liquid fuel capacity is not being

fully requisitioned by beneficiaries. In spite of scarcity of electricity the distribution utilities of

States are not fully harnessing intra-state and inter-state sources of costly generation based on


liquid fuels (diesel, naphtha, HFO etc.). Part of this un-despatched surplus power is sold by the

concerned generating stations to other utilities through STOA. However available un-

despatched capacity and need of load serving entities / buyers is fragmented and, it is at times

difficult to utilize through STOA. As a result, part of high cost generating capacity remains un-

utilized.

One of the options available to the generating stations is to sell power through UI to utilize the

idle capacity and generate power. This may be feasible if UI rate normally remains higher than

variable cost of generation of liquid fuel based capacity. The generating stations avoid taking

the risk of UI rate variation (due to frequency variation). Moreover the generating stations would

like to avoid frequent start-stop with change in system frequency hence some other

methodology of compensating and incentivizing such generators must be devised to harness

this un-despatched surplus.

As per Regulation 11(1)b of UI Regulations, the surplus funds available in UI pool may be

utilized for providing ancillary services including but not limited to ‘load generation balancing’

during low grid frequency as identified by the Regional Load Despatch Centre, in accordance

with the procedure prepared by it, to ensure grid security and safety.

3.5.2. Peaking Gas Stations

In future this mechanism would also facilitate peaking power stations to come up. These

stations would be despatched by the system operator to meet the peaking shortage. The

monetary recovery and incentive of these stations would be taken care of by this mechanism.

Commercial Settlement

A scheme can be evolved in which the system operator (SLDC/RLDC) would ask all the sellers

who want their surplus power to be scheduled to pool to submit their respective bids. This can

be facilitated in Power Exchange platform. At 6 pm after clearance of all the bids and

preparation of day ahead schedules at RLDCs, the generators who are interested in providing

LGBS can participate. Such generators can bid in any of the Power Exchanges and would have

to declare their bid area and bid price. These bids shall then be stacked together as per the

respective bid price and would get despatched depending on the system conditions, merit order

and deficit in real time as anticipated by the system operator. Prior to despatching a consent

from seller would be taken and the generator would be scheduled accordingly within 6 blocks

only if he has not already been scheduled in the short term market.

A ‘uniform pricing’ settlement mechanism might be followed in which the price of highest

activated bid price becomes the uniform price for all the activated bids. This will mean that all

the activated bids will be dispatched at a single ‘uniform price’. This method has a distinct

advantage over ‘pay-as-bid price’ system as the probability of participants gaining through price

manipulation and gaming would be lesser. Subsequently a detailed procedure for deciding

quantum of dispatch and maximum rate of procurement can be developed.


Modifications in the schedule on account of dispatch of generators under LGBS can directly be

communicated by the power exchange to concerned SLDC as well as RLDC/NLDC. Payment to

all the dispatched sellers can be made directly through the power exchanges. Power exchanges

which act as the facilitating agency under this provision can also be paid as per the rates

existing for energy trading in collective transactions (1 paisa/unit at present).

3.5.3. Pumped Storage Plants

Hydro power stations with pumping facility can be used to meet the peaking shortage and utilize

surplus availability during off peak periods. During off peak periods the system operator might

ask such hydro stations to pump some water upstream which would be later used to generate

peaking power. A number of pumped storage stations are expected to come in the near future

to meet the peaking shortage. This mechanism might be used for the commercial settlement of

such plants.

Suppose a station is asked to pump water by the system operator during off-peak period and

consumes 1 MU of energy from the grid during the operation. Assuming a UI rate of Rs 4/kWh,

the plant would have to pay a UI charge of Rs 40 lacs. Considering an overall efficiency of 70%

the excess energy on account of pumping that the station can generate would be limited to 0.7

MU. Assuming a rate of Rs 5/kWh during peak, the plant would receive Rs 35 lacs from UI. As

can be seen in this case the station incurs a net loss of Rs 5 lacs. The station would be

reimbursed the same amount, along with some nominal incentive as decided by the

Commission.

Benefits of the Proposed Mechanisms

The mechanisms proposed are meant to utilize large amount of stranded capacity to

schedule/inject power into the grid. It will ensure maximization of generation at optimal cost for

grid participants. National Electricity Policy talks about creation of spinning reserves of at least

5% by 2012, which can also be compensated using this mechanism.

The advantages are:

- Resources optimization

- Reducing peaking shortage

- Providing a very powerful signal for investment in generation and harnessing of diverse

sources of power such as co-generation, captive, wind power etc.

It should however not be expected that the frequency profile would become flat and would

remain within the permissible band on tapping the idle generation through LGBS. This is

because it does not address the adequacy issue prevalent in the system. Adding to that it is

also not an automatic control which can arrest sharp notches in the frequency profile.


3.6. Network Control Ancillary Services (NCAS)

NCAS are primarily used to control voltages at different points of the network and control the

power flow on network elements within the prescribed limits. It is further subdivided into-

3.6.1. Power Flow Control Ancillary Services (PFCAS)

Power Flow Control ancillary services are used to control the flow on inter-connectors within

their limits. Overloading of lines connecting one control area to another can be reduced by –

• Shedding load or increasing generation in the exporting area

• Generation backing down in the exporting area

In the present context, manual load shedding is usually done to relieve congestion in the

interconnecting tie lines. In addition to manual load shedding, the option of backing down

generators in the exporting area and compensating them in case they incur any financial loss as

a result of this backing down operation to relieve congestion can also be introduced under the

head of ancillary service.

Inadequacy of generating resources in the country limits the alternative of increasing generation

in the drawee area to relieve congestion. The option of utilizing untapped generation available is

already being explored under Load Generation Balancing Service (LGBS). If there is congestion

in the system then the generators in the drawee area would be asked to increase their

generation under the head of Power Flow Control Ancillary Service (PFCAS). However if

congestion in the network cannot be relieved despite utilizing PFCAS, congestion charge can be

applied as per CERC’s (Measures to Relieve Congestion in Real-time Operation) Regulation,

2009.


The commercial settlement for PFCAS would be similar to LGBS with the exception that in

LGBS merit order of the generators would be the only criteria for invocation of the service;

whereas for PFCAS along with the merit order, location of injecting point would decide whether

the service of a generator is availed or not. A situation might occur in which the generators with

lesser variable costs would be skipped and the services of higher variable cost generators

would be availed, if the condition is such that the lower cost generators are congesting and the

higher cost generators are decongesting the network path.

As per Chapter 6, clause 6.4.12 of the IEGC

“However, notwithstanding the above, the RLDC may direct the SLDCs/ISGS/other regional

entities to increase/decrease their drawal/generation in case of contingencies e.g. overloading

of lines/transformers, abnormal voltages, threat to system security. Such directions shall

immediately be acted upon. In case the situation does not call for very urgent action, and RLDC

has some time for analysis, it shall be checked whether the situation has arisen due to

deviations from schedules, or due to any power flows pursuant to short-term open access.

These shall be got terminated first, before an action, which would affect the scheduled supplies

from ISGS to the long term customers is initiated.”


The mechanism proposed under PFCAS talks about commercial mechanisms to control

overloading when the system security is under threat. This does not however dilute above

stated clause 6.4.12 of the IEGC which clearly gives system operator the power to reschedule in

interest of the power system. Attaching a commercial consequence to the mechanism would

only ensure promptness in response by the constituents and would enhance security of the

system.

3.6.2. Voltage Control Ancillary Service (VCAS)

The alternative which can be currently exercised for obtaining VCAS is operation of a

synchronous machine as synchronous condenser. Many of the hydro units have the capability

to operate as synchronous condensers. During condenser mode of operation the real power

production of the unit is ‘nil’ and the unit is required to provide reactive power support (mostly

absorb reactive power). Such situations are usually encountered in winter off-peak periods

when the water level in the dams is low and active power generation by the unit is not possible.

Generating units with this capability are mostly reluctant to operate in synchronous condenser

mode because the tariff received by them is only dependant on their real power output. In

addition to this they also have to bear the cost of running their generators by drawing the energy

from the grid to meet the friction and windage losses. Based on discussions with hydro power

stations typical values of these friction and windage losses are known to be of the order of 1.7

MW/machine for a 120 MW machine. In addition to this, some auxiliary consumption in the form

of power drawn by the air compressors etc has also to be borne by the generator. In Northern

Region, the cost of energy drawn is compensated by making the post facto schedule of the

plant as equal to the zero, but there is no real incentive available to generators for performing

such an operation. It is therefore proposed there should be provision for sufficient compensation

amount and incentives so that generating units voluntarily make themselves available for

synchronous condenser operation.


IEGC specifies a rate of 10 paisa/kVArh for reactive power exchange. However a source like

synchronous condenser has many distinct advantages over a static VAr compensator. The

reactive power supplied by a synchronous condenser is dynamic, voltage independent,

increases the fault level and also enhances the stability. Thus it is proposed that a generator

who is operating as synchronous condenser will be reimbursed at a rate approved by the

Commission say 25 paisa/kVArh.The compensation rate might further be refined and made

variable by making it dependant on the voltage profile of the area.

System operator would advise a generating station to run one or more units in synchronous

condenser mode. Remuneration to the generator would be based on number of hours of

operation and reactive power generated / absorbed. In addition to this, the losses incurred by

generator on account of friction and windage losses and copper losses in generating

transformer during synchronous mode operation will be made zero by socializing the same as

pooled losses.


In future old gas and thermal power stations might also provide voltage control ancillary services

by operating in synchronous mode. Moreover as the market for ancillary services grows, entities

might also be interested in providing VAR support using mobile reactive installations. Enabling

mechanisms to harness this potential might also be proposed in times to come.

3.7. System Restart Ancillary Service (SRAS)

System restart ancillary services (SRAS) are reserved for contingency situations like partial /

total grid disturbances wherein the electrical system must be restarted in line with the regional

black start procedure. Black start is a vital but inexpensive service. Its costs are primarily the

capital cost of the equipment used to start the unit, the cost of the operators, the routine

maintenance and testing of equipment and the cost of fuel when the service is required.

The fixed costs associated with these units should not be included in this list because this is

recovered from the beneficiaries in the generation tariff. However for all the other costs

mentioned above, the service provider should be adequately compensated and reimbursed.


As per clause 5.8(b) of the IEGC, mock exercises for black start must be conducted twice a year

by the identified units on demand by the system operator. The generators should be

incentivized for performing each successful mock exercise. Appropriate nominal incentive

amount might be decided by the Commission which would be paid to the generator for

successfully displaying black start capability in the mock exercise.

If black start is treated as an Ancillary service it would help in utilizing the capacity of even the

‘fence-sitters’ – mainly gas turbines, diesel generators who can provide the service with

incremental investment.

3.8. Ancillary Services Fund

Billing and settlement of ancillary services should be done through a separate account and it

must not be clubbed into the fees and charges of the system operator. In some countries the

system operator gets in advance the amount likely to be spent for procurement of these

services and the actual expense incurred is added to the expenditure of system. However in the

present scenario accounting and settlement of these services should be done under a separate

head and not included in the fees and charges of the system operator.

An ‘Ancillary Services Fund’ account might be opened and all the payment liabilities for

procurement of ancillary services would be funded from the Power System development Fund

(PSDF) via the Ancillary Services Fund. Based on estimate and subsequent experience gained,

some amount would be transferred from PSDF to Ancillary Services Fund on a yearly basis

after approval of the Commission. This amount would then be used for procuring ancillary

services and this fund account would be maintained by the system operator.


Chapter 4

Future Scope

Apart from the already proposed ancillary service which could be easily implemented within the

present market framework, it is possible to implement gradually other ancillary services which

are already being availed worldwide, after examining the response of the market towards

provision of ancillary service. System Operator is expected to ensure availability of enough

ancillary service for safe and reliable operation of the vast network in India.

4.1. Primary Frequency Control

Indian Power market is a deficit market and implementation of spinning reserve as an ancillary

service which in turn may reduce the availability of generation may not always be very feasible.

Commission has recently released a regulation on Medium Term Open Access and Long Term

Access where large consumers having more than 100 MW capacity is eligible to get connected

to the ISTS.

It is possible that an aggregator can design and group its load accordingly to provide emergency

reserve through disconnection of total or partial demand as per requirement in case enough

commercial signal is given through provision of such ancillary service. All such bulk load

providers may be attracted to self declare such service with properly implemented metering.

The willing customer should arrange proper telemetry and metering so that the same could be

measured to ensure compliance and paid accordingly.

The payment may be made to such provider in two parts one fixed part which shall be

applicable for the period when such service is made available and may be reimbursed in Rs. /

MW / month. Such service should be available at least for a full month to enable payment

against fixed part. The price may be determined by the Commission based on the fixed cost of

the contemporary generator. The operational philosophy such as testing of availability of such

demand may be decided by system operator. The variable part may be paid as and when the

service is called for and may be reimbursed in Rs. / kWh.

4.2. Spinning Reserves

These reserves are available nearly instantaneously, and are able to stabilize system frequency

upon the outage of a large generating unit in the system. Their time of response is from a few

seconds to about 5 minutes or less and requires no notification. Some very fast starting units

(hydro in some cases) and some types of demand management programs (no-notice

interruptible load programs) can also serve the function of spinning reserve. It is not necessary

for spinning reserves to be able to deliver power for long periods. That is, the energy

requirements for spinning reserves are not necessarily large, since spinning reserves are

eventually displaced by supplemental reserves. System Operator can contract spinning reserve


(hydro units kept spinning) from private hydro units and despatch the same when frequency falls

(actuated by UF or df/dt signal) at UI prices.

4.3. Reactive Ancillary Market

i. Long term Reactive Procurement

The long term Ancillary market is proposed to promote participation by generators (other than

ISGS). The market would be bid based and has to be finalized in advance. No zonal method is

proposed for this market. The challenge is to allocate the fixed costs of the plant specifically

used to procure reactive power. Order 888 of FERC (opinion 440) AEP method is suggested for

separating the capital costs sunk for producing reactive power.

ARR (Reactive) = ARR total x Mvar2/Mva2

There would be no compensation for the generator between 0.95 lead and lag. Bid zones would

be identified in advance and sealed bids could be invited with tentative reactive demand

(zonewise) being estimated by the system operator. A Power Exchange like ‘one run’ algorithm

for each zone could be used for deciding the prices. Stiff penalties for non generation of

contracted reactive power/gaming (participating generators gaining under advantage due to

non-participating generators subdued reactive output) would need to be factored in to make the

market meaningful.

Nonparticipating generators are also to generate reactive power as mandated by IEGC to

prevent perverse incentives. The Regulator could as an alternative decide the ARR (Reactive)

and its recovery through tariff as a separate component. The generator would have to be closely

monitored by the system operator. All participating generators may have to demonstrate their

capability for reactive generation. Optimizing of GT taps would be done by generator & system

operator and all generators with capacity more than 50MW can participate in this service.

ii. Real time Reactive market

This market would be operated by the system operator in real time. The Region could be

demarcated into zones keeping in mind that the voltage profile in a zone is coherent. The

voltage at a designated EHV bus in the zone would determine the price of reactive power in the

zone as per the graph shown below:


Figure 9: Proposed curve for pricing of Reactive Power v/s Voltage

Different slopes for both quadrants for consumers and generators of Reactive power could be

adopted to have a non-zero sum approach and would help in ensuring a non –ve pool.

The ‘UI price curve’ like methodology would:

• Discourage VAr drawls at low voltage & VAr supply at high voltage and help to keep

voltages at narrow band.

• Incentivize optimal reactive power purchase.

• Encourage new sources.

iii. Dynamic VArs

Dynamic VArs are valuable for the grid as they provide support independent of the voltage level.

D-VArs cannot be priced the same as VArs from static sources due to the above reason. D-

VArs are to be procured by the system operator on case to case basis depending on the

requirement for such a service in a location.

D-VArs could be requisitioned for

• Voltage stability problems especially in metros & stability challenged areas. The

payment could be made at a % over the zonal market price prevailing in real time.

• Enhance transfer capability especially in areas where further ROW is unavailable and

transmission lines are fully loaded. Remuneration could be linked to the transmission

charges for the capacity that is enhanced due to the D-Vars. If the transmission capacity


of a line from Bus A to Bus B is constrained due to voltage stability limits (TTC/ATC

would have be declared accordingly) and D-VArs are provided to enhance the stability

thus causing say a 10% increase in the capacity, then the D-VArs are to be paid for on

the basis of transmission charges for the line pro-rata for the enhanced capacity. This

would provide an incentive for providers of D-VArs to enter the market. D-VArs supplied

could be in the form of mobile installations (as in NGC, UK). The transmission charge

linkage is for pricing only and will not affect the transmission capital cost recovery of the

line in any way.

4.4. Metering Requirements

Successful implementation of all the ancillary services would be dependent on whether the

service provided can be judiciously measured by the existing metering infrastructure. The

existing meters in our country have a least count of 0.02 Hz for frequency measurement.

However with the tightening of frequency band in the country as per the orders of the

Commission, the step change in the UI linked prices would be of larger magnitude. Hence the

sensitivity or the least count of these meters should be reduced from 0.02 to 0.01 Hz.

Similar problem exists with reactive power measurement. As per the current structure the net

reactive power drawl or injection of a node below 97% and above 103 % is available for an

entire day. But for introduction of voltage control market structure the meters should be able to

read all the values of reactive power drawl and injection and voltage for each time block so that

the prices could be paid accordingly.


Chapter 5

Conclusion

This paper tries to suggest certain ancillary services which can be implemented considering

present condition of Indian electricity market. The scope of the suggested services has been

kept to operational expenditure only and does not take into account capital expenditure. In a

nutshell, the recommendations made in the paper talk about:

• Use of idle generation in the form of un-despatched surplus and utilization of peaking

gas stations and pumped hydro stations for providing load generation balancing service

as well as Power Flow Control Ancillary Service (PFCAS), tapping in the generation

potential available with ‘fence sitters’ and improvement in frequency profile.

• Use of hydro stations as synchronous condenser for providing reactive power support

• Introduction of black start as an ancillary service for hydro, gas and combined cycle

stations which have black start capability

The commercial mechanism proposed for these services only talks about reimbursement to the

service provider and recovery from users of the service has not been suggested. Although for a

sustainable market design we must have both ‘payable’ and ‘receivable’ components, but the

structure of commercial mechanisms in the paper has been proposed keeping in mind the

present state of Indian electricity sector. More refined commercial mechanisms where a ‘user’

will have to pay for the ancillary services it uses, might be proposed at a later stage as the

market for ancillary services develops further in our country.

One of the foremost requirements for successful implementation of these services is to ensure

that adequate monitoring mechanisms are in place. The monitoring and feedback system would

also additionally help in preparing future roadmap for introduction of newer ancillary services as

maturity in the market increases. Further a similar arrangement for ancillary services should be

replicated by states also so that maximum benefits could be availed in the interest of Indian

power system as well as Indian electricity market.

The awareness and understanding of the concepts associated with ancillary services is still in a

nascent stage in India. Learning from worldwide experience in respect of developing the

ancillary service market and designing it such that it complements reliability of the power system

is a continuous process. An attempt has been made through this document to initiate a focused

discussion in this area.

It is important that this subject is taken up further and the next practices identified and

implemented to have the fourth pillar of market design ready in our country.


Annexure I: International Practices

The existence, definition, and pricing of ancillary services is a function of the underlying industry

structure. The technical definition of ancillary services and the rules governing their trading vary

considerably throughout the world. This is because of the fact that the liberalization process in

electricity industry has proceeded independently in different parts and the structure of the

underlying power systems is different throughout the world.

The classification and definition of various ancillary services differ across systems and markets.

There are many lists of ancillary services which differ mainly in how they split and combine the

categories of service. The subsequent section describes ancillary services management

practices in various countries across the world.

1. The United States

According to NERC Operating Policy 10 the ancillary services required for safe and secure

delivery of power to the customer are:

� Maintaining Generation and Load Balance

• Regulation Service

It is the minute to minute adaptation of a generator output to arrest the deviation in frequency.

This is realized by the use of governor droop characteristic or automatic control signal from the

control area to correct the Area Control Error.

• Load Following

It is associated with ramping up or down of the generating units to meet the imbalance between

load and generation. This may be automatic or manual and track a long term variation of the

load. These units are chosen because they respond to controls and will fit into optimal despatch

when loaded.

Figure 10: Load curve showing regulation load following


• Contingency Reserve

These are required at the time of contingency and are further classified into spinning reserve

and supplemental reserve services. These are further classified into spinning reserve service

and supplemental reserve service.

� Transmission System security

• Reactive Power Supply

Voltage control is done by load power factor correction, reactive power compensation through

static sources and reactive power support from generators NERC’s proposed standards on

interconnected operation services have defined that reactive power from generating sources

only qualify as ancillary services and get financial compensation from ISO.

• Frequency Response

It is the immediate governor response resulting from a change in interconnection frequency due

to any disturbance.

� Emergency Preparedness

• System Black Start Capability

NERC makes it a responsibility of the system operator to arrange, provide for and deploy

system black start capability as and when required to energize the transmission system

following a blackout by defining it as an ancillary service.

Figure 11: Break up cost incurred in providing Ancillary Services in US [20]


2. Great Britain

National Grid Company (NGC) being the ISO in UK is responsible for making arrangements with

regards to ancillary services. NGC contracts for ancillary services to enable voltage and

frequency control standards to be maintained and also for black start capability. These services

can be supplied by Generators, Regional Electricity Companies (RECs), large customers or

External Pool Members. The payment of these services is made through the pool as enabled by

the Pool and Settlement Agreement (P&SA) between the pool members and parties that govern

the operation of the pool.

The Grid Code details the technical operational requirements of NGC and defines two major

ancillary services as follows:

� System Ancillary Services

All centrally despatched generating plant must be able to provide these services as they are

fundamental to the operation of grid. They are listed in the grid code in two parts:

• Part 1: Those services which all generators are obliged to provide. These are

a) Reactive Energy : other than those supplied by synchronous or static voltage

compensators

b) Operating Margin : capability of a generating unit to provide additional output at

short notice

• Part 2: Those services that need not be provided at every site and are purchased by

NGC from specific sites through agreements. It includes

a) Operating Margin : capability of GTs or PSPPs to fast start

b) Black Start

� Commercial Ancillary services

An entity is not obliged to provide them and hence they are subjected to commercial

agreement. These services include

• Reactive Energy : Supplied by synchronous or static voltage compensators

• Operating Margin : Provided by PSPPs, Load reduction, Hot Standby etc

Ancillary Service Agreements made between NGC and supplier of ancillary services covers the

provisions of all services. It specifies the services to be provided from each site and the price to

be paid for each service. The details of generator prices remain strictly confidential under the

terms of the agreement.


3. Australia

National Electricity Market Management Company (NEMMCO) is the system operator in

Australia and is responsible procurement of various ancillary services in the country under the

National Electricity Code (the Code). The Code provides for NEMMCO to purchase these

services from market participants, by means of either:

• Market Ancillary Services Arrangements

• Ancillary Service Agreements

All NEM Ancillary Services can be grouped under one of the following three major categories

[11]:

� Frequency Control Ancillary Services (FCAS)

It comprises of Automatic Generation Control, Governor Control, Rapid generator unit

loading and load shedding

� Network Control Ancillary Services(NCAS)

NCAS are primarily used to control the voltage at different points of the electrical network

and control the power flow on network elements.

� System Restart Ancillary Services (SRAC)

These are required to enable the system to be restarted following a complete or partial

system blackout.

The payment mechanism in Australian market depends on the type of service provided and a

service might call for one or more of the following payment components [16]:

� Availability Payment

It is made to those services that require the provider’s preparedness for providing the service

when called for. It is made to system restart services and reactive power services

� Enabling Payment

It is made if the service has been enabled by the system operator for use. This applies to all the

ancillary services except system restart and reactive power from generators.

� Usage Payment

It is based on the actual usage charges and applies to rapid loading and unloading services

provided by generators.

� Compensation Payment

It is paid in lieu of provider’s opportunity cost4. It is applicable to all categories of service except

the reactive power support service from synchronous compensators and system restart

services.

4 Opportunity cost is the loss in profit if the output is reduced


Figure 12: Ancillary Service Cost in NEMMCO in 1998-99 [20]

4. Nordel5 System

The nominal frequency in the Nordic system is 50 Hz and it is stipulated that fluctuations during

normal system operation should not exceed 0.1 Hz. Unlike other systems each country in the

Nordel system is responsible for a part of the reserve margin and gain in relation to the annual

energy consumption of the system.

The capacity margin required for primary frequency control is provided principally by hydro

units. The various operator actions that are initiated when frequency in the Nordel system

deviates from its nominal values are shown in the figure below.

Figure 13: Frequency range and operator action in Nordel System [20]

5 organization of the electricity transmission companies that operate the wide area synchronous grid of the Nordic

countries of Finland , Sweden , Norway and Eastern Denmark.


5. Summary

Worldwide ancillary services are being recognized and compensated under different names.

Although the basic purpose of these services is more or less the same but the difference in

nomenclature and compensation methodology is there because of the inherent difference in

their market structures. Following is a comparative table showing various ancillary services

under implementation in European markets:

Table 3: Services Considered as Ancillary Service (Y=Yes) [3]

Austria Belgium Denmark Finland France Germany Hungary Ireland Norway Spain Sweden UK

Frequency

Control Y Y Y Y Y Y Y Y Y Y Y

Voltage

Control Y Y Y Y Y Y Y Y Y Y Y Y

Spinning

Reserve Y Y Y Y Y Y Y Y Y Y Y

Standing

reserve Y Y Y Y Y Y Y Y Y

Black Start

Capability Y Y Y Y Y Y Y Y Y Y

AGC Y Y Y Y Y Y Y

Grid Loss

Compensation Y Y Y Emergency

Control

Actions Y Y Y


Annexure II: Pricing Methodologies

In its Notice of Proposed Rulemaking, the Federal Energy Regulatory Commission (FERC

1999) wrote “The Commission believes that, whenever it is economically feasible, it is important

for the RTO [Regional Transmission Organization] to provide accurate price signals that reflect

the costs of supplying ancillary services to particular customers.” Earlier, FERC (1996) wrote in

its Order 888 “Because customers that take similar amounts of transmission service may

require different amounts of some ancillary services, bundling these services with basic

transmission service would result in some customers having to take and pay for more or less of

an ancillary service than they use. For these reasons, the Commission concludes that the six

required ancillary services should not be bundled with transmission service.” [14]

The manners in which ancillary services can be procured by the operator are [6]:

a. By ownership of the equipment necessary to provide the service. This is the practical

means of providing the services in many cases, such as for example the ownership of

shunt capacitors and other reactive power equipment.

b. By contracting with ancillary service providers for long-term provision of these services

under specific terms and conditions.

c. By creating a market for the supply of services, where parties interested in providing the

services bid for the right to provide the service. The bidders often (but not always) will be

the same parties that are engaged in the provision of the primary energy services.

In competitive electricity markets, the costs for each ancillary service should be charged to

those that cause the costs to be incurred and collected in a way that reflects the factors that

contribute to these costs. As an example of the first point, operating reserves are required to

protect bulk-power systems from potential adverse effects associated with major generator or

transmission forced outages. Therefore, in the first instance, the costs of operating reserves

should be assigned to generators, and should reflect the frequency and severity of forced

outages. Although these costs are ultimately paid by retail electricity consumers, charging them

to generators encourages generation owners to maintain equipment to reduce the frequency of

forced outages. As an example of the second point, the amount of generating capacity assigned

to the regulation service is a function of the short-term volatility of system load. Therefore, the

charges for regulation should be related to the volatility of each load, not to its average demand.

[14]

i. Procurement Methods for Ancillary Services

Generally a system operator is responsible for the procurement of all ancillary services. These

services can be procured through four procurement methods: compulsory provision, bilateral

contracts, tendering and spot market. Table shows a comparison between these methods:


Compulsory

Provision

Bilateral Tendering Spot Market

Operating

Principle

A certain class of

network users are

required as part of their

connecting conditions

to provide a certain

amount of given

ancillary service on

request by system

operator.

System Operator

procures the ancillary

services using

bilateral contracts

A tendering

process is

developed which

involves less

standardized

products or

products with

longer duration

A spot market is

developed where

standardized

products with short

duration are

exchanged.

Merits Fairness, because all

users belonging to a

certain class provide

the same absolute or

relative amount of

service.

Simplification

Only the amount of

ancillary services

required are

procured

Cost minimization by

procurement from

cheaper providers

Enhance

Transparency

Promotes

Competition

Enhance

Transparency

Promotes

Competition

Demerits Volume of services

provided might exceed

the requirement.

Cost minimization

might not be there

because low cost

providers are treated

on the same basis as

more expensive ones.

Bilateral contracts

lack transparency.

They are long,

complex and costly

Price and Volume

are often fixed for a

long time

High data

management cost

Might facilitate the

exercise of market

power by some

participants

High data

management cost

Might facilitate the

exercise of market

power by some

participants

ii. Remuneration Methods

The remuneration of ancillary services can be done as per its regulated price (RP), a pay as bid

price (PBP) or a common clearing price (CCP).

If the remuneration is done as per regulated price, the price is set by the regulator and is usually

the same for all providers. This form of remuneration is particularly justified when market power

is an issue. In general, however, a regulated price is not desirable as it reflects very imperfectly

the actual cost of providing an ancillary service, particularly when this cost changes with time or

circumstances.

In a pay as bid system, the supplier receives the price of its accepted offer. This type of

remuneration method is suitable when the quality of the ancillary services offered is highly


differentiated and those offers are thus not easily comparable. However, a pay as bid price does

not give providers an incentive to bid their marginal cost, except when market concentration is

low [9].

In a common clearing price system, all the successful providers are paid the price of the most

expensive accepted or the least expensive rejected offer. This form of pricing gives real

incentives to suppliers to offer their marginal cost. But in this system all the offers have to be

comparable as it is not adapted to differential products.

Primary control is usually provided by compulsory provision as it would lead to a uniform

distribution of primary control throughout the system. Zonal prices might be preferred for these

services as frequency of a network is not geographically dependant. Basic voltage control

service is usually compulsory and no spot markets are in place for voltage control because

these services are very local and susceptible to the exercise of market power. Being a localized

phenomenon, nodal prices might be favored for voltage control services. [9]

iii. Cost Allocation among service users[6]

Ancillary Services have usually low marginal costs; hence it might happen that if the market

prices these services at marginal cost it might not result in sufficient compensation to the

service providers. The reliability of the system is compromised in such a case and it becomes

necessary to split the payments for the service into market component and a cost allocation

component .Cost allocation based on marginal cost is most desirable in order to promote

economic efficiency in resource utilization because it is compatible with a competitive economic

environment [6].

Any cost allocation method must ensure fairness and revenue adequacy. The allocation

methodologies which might be used are:

• Marginal cost allocation

Charging the users in proportion to their marginal cost induces economic efficiency. The cost

allocated to each user is proportional to the marginal use of the service by the user. This

method is simple to implement but in some cases this method might lead to over-recovery if the

nature of the service cost function6 is convex. Application of a reduction factor in this method to

avoid over-recovery may lead to a situation where a user is made to cross-subsidize some other

user of the service.

• Shapley Pricing

Shapley allocation is an improvement over the incremental cost allocation principle which is very

sensitive to the entrance order of users to determine their marginal cost. The Shapley scheme

tries to eliminate this limitation by calculating all permutations of entrance order. The major

drawbacks of this are the computational effort required which increases exponentially as the

6 The service cost function gives the relation between the amount of transaction and the cost of service.


number of agents increase. Also users with higher transaction amounts in this are less sensitive

to the entrance order rather than those with lower values.

• Aumann- Shapley Pricing

This method corrects the limitation in Shapley allocation scheme by splitting agents with larger

transactions into smaller sub-agents with smaller sizes. The Aumann-Shapley allocation is a

limiting process of agent “splitting” and permutations of entrance orders as the size of each sub-

agent goes to zero. As this method is based on marginal costs, it induces economic efficiency.

Also it is considered fairer as it eliminates order of entry as a consideration and has the property

of recovering cost.

Some other important features of the Ancillary services market are:

o Duration of the Contract: A long term contract reduces the competition until it comes up

again for renewal. A short term contract increases both the competition and risk

involved.

o Frequency of Review of amount of service required: A system operator can make a more

near to real estimation if the amount of ancillary services required is reviewed on a

frequent basis.

o Price Cap: A price cap on the purchase of ancillary services might be put to mitigate the

effect of market power. However the consequences of putting a price cap should be

considered on other electricity market as they are all dependant on each other.

o Market Concentration: Market Concentration is usually measured by Herfindalh-

Hirschman Index (HHI)7. Markets for voltage control suffer from high market

concentration and markets for primary and secondary frequency control are less

concentrated as participants located anywhere can participate as long as transfer

capabilities are sufficient.

iv. Reserve Costs

a) Reserve Availability Cost

Reserve availability cost is the cost of making reserves available even if they are not actually

used. This includes investment cost, operational cost to keep the reserve standby, operational

cost when the reserve is activated, cost of non optimal generation despatch and investment cost

for power capability which is not getting used for energy production.

For those generators which do not usually operate and are used to provide only reserve service,

the cost is generally of starting up and shutting down the units. For a cheap unit (whose

marginal cost is lesser than the market energy price) that generates below its rated capacity for

providing the reserve service, the opportunity cost of providing the reserve is the loss in profit

due to reduced level of generation. This case is illustrated in the example figure below

7 It is a measure of the size of firms in relation to the industry and an indicator of the amount of competition

among them


Figure 14: Reserve opportunity cost for Low Cost Generating Unit [6]

For an expensive unit that operates near minimum output levels, the cost of providing reserves

equals the amount by which the price of energy fails to compensate the generator for its start-

up, shut-down, and operating costs. This case is shown in the figure below

Figure 15: Reserve Opportunity Cot for a High Cost generating Unit [6]

b) Reserve Use Cost

Reserve use cost is the cost incurred at the time of providing the service. The costs of reserves

supplied by generators include the usual fuel and variable operating and maintenance costs,

and the cost related to the stresses that accompany changing output levels for the generating

units. These stresses are worst for those generators that change output levels most frequently.

The marginal costs of energy service for a particular period are the change in production cost

per unit change in energy consumption.


The benefits available from reserves are available to all market participants irrespective of who

has paid for them. As a result there might be a tendency among the participants to avoid paying

for reserves which might in turn lower the reliability of the power system. This problem can be

solved by having a mechanism which makes the participants pay for the benefits that they

receive. This is done by using one of the following approaches [6]:

• Quantity Mandate Approach : each participant is required to either provide the system

operator with a certain amount of reserve service identified or buy that amount from the

system operator

• Performance Requirement Approach: the participants are free to provide whatever level

of service they want to provide but their power s promptly cutoff if they fail to meet their

own needs.

As the system reliability is of prime concern, the quantity mandate approach is more effective

and is followed by authorities such as NERC. However the performance requirement approach

is more consistent with the ideology of competition and free energy market.


References

[1] Steven Stoft- ‘Power System Economics – Designing Markets for Electricity’.

[2] Yann Rebours- ‘A Comprehensive Assessment of Markets for Frequency and Voltage Control Ancillary Services’ – 2008.

[3] Eurelectric – ‘Ancillary Services, Unbundling Electricity Products: an Emerging Market’ –

February 2004.

[4] Appellate Tribunal for Electricity, Appellate Jurisdiction, New Delhi – ‘Judgment on Appeal

No. 202 of 2005’ – 13th December 2006.

[5] Eric Hirst and Brendon Kirby– ‘Electric Power Ancillary Services’ – February 1996.

[6] CIGRE Task Force – ‘Methods and Tools for Costing Ancillary Services’ – June 2001

[7] Sally Hunt –‘ Making Competition Work in Electricity’.

[8] Yann G. Rebours, Student Member, IEEE, Daniel S. Kirschen, Fellow, IEEE, Marc

Trotignon, and Sébastien Rossignol - ‘A Survey of Frequency and Voltage Control Ancillary

Services—Part I: Technical Features’ – February 2007.

[9] Yann G. Rebours, Student Member, IEEE, Daniel S. Kirschen, Fellow, IEEE, Marc

Trotignon, and Sébastien Rossignol - ‘A Survey of Frequency and Voltage Control Ancillary

Services—Part I: Economic Features’ – February 2007.

[10] S.K. Parida, S.N. Singh and S.C. Srivastava – ‘ Ancillary Services Management Policies in

India : An Overview and Key Issues’

[11] National Electricity Market Management Company Limited- ‘Guide to Ancillary Services in

the National Electricity Market’ – Version No. 1.0

[12] Asko Vuorinen – ‘Planning of Optimal Power Systems’ – 2007

[13] PJM Interconnection – ‘Blackstart Service Business Rules’ – Revision 2

[14] Eric Hirst and Brendon Kirby – ‘Ancillary Services : A Call For Fair Prices’ – December 1998

[15] CIGRE 39-203 – ‘ Ancillary Service in Deregulated Electric Power Industry

[16] Central Electricity Regulatory Commission – ‘Indian Electricity Grid Code Regulation, 2010’

– April 2010

[17] Central Electricity Regulatory Commission – ‘ Unscheduled Interchange Charges and

Related matters (Amendment) Regulations, 2010’ – April 2010

[18] Government of India – ‘Electricity act, 2003’ – June 2003

[19] National Grid Corporation – ‘ Ancillary Services – An Introduction’

[20] Kankar Bhattacharya, Math H. J Bollen and Jaap E. Daalder – ‘Operation of Restructured

Power Systems’

[21] Thomas J. Overbye -‘Re-engineering the Electric Grid’, American Scientist, May-June 2000.

[22] RLDC’s system restoration manuals

[23] Nathan Cohn – ‘Control of Generation and Powerflow in interconnected Systems’ – Second

Edition

[24] Federal Electricty regulatory Commission –‘ Order No. 888’ – April 1996

[25] North America Electricity Reliability Council – ‘ Reference Document: Interconnected

operations Service’ – March 2001


Notes

ancillary services[1]

Documents