Competitive Electricity Markets and Reactive Power...

___________________________________________________ *Some parts of this chapter has been published in the following paper:

• Amit Saraswat, Ashish Saini and Ajay Kumar Saxena, “Reactive Power Management and Pricing Policies in Deregulated Power System: A Global Perspective”, Proc. of National Conference on Emerging Trends in Electrical, Instrumentation and Communication Engineering (ETEIC-2012), pp. 558-563, Agra, India, 6th-7th April 2012.

Chapter 2

Competitive Electricity Markets and Reactive

Power Management*

“Good coordination cannot overcome bad market design. Markets in power,

more than most markets, are made, they don’t just happen”

– William H. Hogan,

Federal Energy Regulatory Commission,

Technical Conference on Interregional Coordination,

Washington, DC. June 19, 2001.

2.1. Introduction

Hogan rightly pointed out that “coordination for competition” is apparently an oxymoron.

However, without an effective forum in which to engage, with clear mechanisms, rules and

procedures, electricity is simply too fast, fluid and complex a commodity to harness in a

market that has no rules, governance or structure. Just as we require rules on which side of

the road to drive our cars, to stop at traffic lights, and to prevent us from speeding, we

require market rules to create uniform contract specification, coordinate our real time

schedules and prevent abuse of the system [132].

Having begun as liberalized free enterprise in the 1880’s, and fallen into municipal,

federal hands over the next few decades, the liberalization experiment began in 1970’s with

a partial opening of the generation sector to new entrants from whom the utilities were

required to buy, and continued in the 1980’s with the beginning of consumer choice [132].

The United Kingdom (actually England and Wales—Scotland and Northern Ireland work

Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013

Dept. of Electrical Engg., Faculty of Engineering, Dayalbagh Educational Institute, Agra-282110. 24

under different systems) was an early adopter of competition and has more than two decades

of experience with it [133]. In Chile, the UK and Norway, liberalization and privatization

have been a central theme in the electricity industry during the last two decades [134]. The

governments around the world have attempted to obtain more reliable and cheaper services

for the electricity customers by introducing competition and economic considerations. A

major step in Europe has been the directive of the European Commission in the end of

1996 (EU 1997), requiring the stepwise opening of electricity markets in the European

Union, ending with a fully competitive market at the latest in 2010. Also in the US, many

federal states have taken steps towards competitive and liberalized markets, with California

and several East coast states being among the first movers.

The challenge has been to open the market to create competition in a measured and

controlled manner such that each stage can be viewed in retrospect with regard to intended

and unintended impacts. In doing so, there is the recognition that transmission networks have

a strong tendency to being natural monopolies, and hence that liberalization and deregulation

might begin with power generation and supply. It is quite apparent that both are dependent

on use of the transmission networks. If there is common ownership of transmission networks

and generation, or transmission networks and supply, or both (as there is in a national

monopoly), there is conflict of interest, so that the incumbent is incentivized to raise the

entry barrier and excessively charge the new entrants. Hence, new entrants need to be

guaranteed free and fair access to power generation or consumption. This is by no means

simple, even with the best will of the incumbents because the operation of power generation

and of the transmission grid is optimized as a single entity. Hence to allow competition, it is

first necessary to restructure the national monopolies into vertically de-integrated

(unbundled) form, and for there to be some form of commercial arrangement between the

unbundled tiers so that this arrangement can be followed by the new entrants.

Liberalization and privatization in the electricity industry have lead to increased

competition among utilities [134]. At the same time, system operators are now exposed more

than ever to face difficulties associated with reliability and security of power system due to

its inherent complexity. The time/space characteristic of electricity causes particular

challenges, and a well designed market structure is essential to engender the motivation and

innovation on which the free market relies [132]. It is important to recognize that electricity

is not an easily marketable product or, in other words, it is far from being a true commodity

[133]. It is not possible to store it in large quantities, it must be produced at the same time it



is consumed, physical laws determine power system operation and there is a network that

often prevents the implementation of optimal economic generation strategies.

As the system complexity has increased after the restructuring, another unavoidable

concern is about the security and reliability of the power system operation in a deregulated

environment. Along the progress of restructuring in power industry, certain other class of

services (e.g. voltage and reactive power control, frequency regulation, energy imbalance

etc.) are identified as ancillary services, besides the basic energy and power delivery

services. In a deregulated environment, the reactive power ancillary service is essential for

secure and reliable operation of power system. Moreover, the effective reactive power

management is required to maintain the bus voltages within their permissible limits as well

as to enhance real power transfer capabilities of transmission system. A proper and effective

reactive power management also contributes to achieve an economically optimal power

system operation and sometimes, becomes necessary to avoid an extremely costly system

collapse. The competition in generation makes it further important to consider the

development of a reactive power market that complements the existing energy market.

In this context, the present chapter aims to present a theoretical background for

supporting the reactive management in the competitive electricity markets. Thereby key

constituents of a competitive electricity market and their roles, explanations of different

types of power markets and their operation are discussed. A particular focus is on the

concepts of reactive power ancillary service and existing reactive power management

worldwide, but also various critical issues (including technical as well as economic issues)

related with reactive power management are addressed.

2.2. Competitive Electricity Market

Efficiency is the goal; competition is the means; open access, restructuring and deregulation

are terms sometimes used to describe the reforms, but they are the tools to achieve it [133].

These terms are briefly discussed as follows:

Open Access: For creating fair competition in production, open access to the

transmission and distribution wires is required so that any competing producer can use them.

As transmission is an essential facility in power system, everyone (every participant) has to

use it. Therefore, open access means that everyone gets the same deal, without any

discrimination either in the opportunity to use the wires or in the cost to use them. The real-



time coordination of generation with transmission is a necessity to prevail the open access in

power industry.

Restructuring: It is a process of necessary decomposition of the three components of

electric power industry (i.e. generation, transmission, and distribution) with the purpose of

creating fair competition at different levels. In general, restructuring is about changing

existing companies by separating some functions and/or combining others and sometimes

creating new companies [133]. The basic aim of restructuring is to prevent discriminatory

behaviour, or to create more competitors, or to consolidate transmission over a wide region.

Different countries are implementing the restructuring in a variety of ways, depending on the

distinctiveness of each market area which include: demand/supply balances, the extent of

transmission capacity to facilitate energy imports to meet market demand, and the diversity

of generation by fuel types.

Deregulation: It means ceasing to regulate. In contrast to the term “Regulation” is

about controlling prices of monopoly suppliers and restricting entry to the markets, the term

“Deregulation” is to remove controls on prices and entry of competing suppliers. In case of a

power industry, some of the existing suppliers are often having local monopolies (natural

monopoly) with 100 percent of a local area both at the production and at the retail level.

Hence, deregulation may results in simply disastrous situation for consumers in the electric

industry, if it was done without necessary safeguards or supportive market conditions [133].

Therefore, deregulation initiates stepwise opening of the monopoly sectors (with regulated

prices) to competition in a power industry.

2.2.1. Market Structure and Key Entities

After the deregulation in the power industries and subsequent restructuring of electricity

markets has changed the role of traditional entities in a vertically integrated utility and

created new entities that can function independently. A typical structure of a recent

deregulated power industry may be realized as shown in Fig.2.1. It may include various

market entities such as independent system operator (ISO), generating companies

(GENCOs), transmission companies (TRANSCOs), distribution companies (DISCOs),

retailers, and customers. All these market entities may be broadly classified into independent

market/system operator (ISO) and market participants (others). The ISO is the leading entity



in an electricity market and its function is to determine market rules. The major role of these

market entities are briefly described as follows:

Fig.2.1: Typical structure of a deregulated power industry [135]

Independent System Operators (ISO): The ISO is a central entity in a restructured

electricity market entrusted with the responsibility of ensuring the reliability and security of

the entire power system, fair and equitable transmission tariffs and other ancillary services

(e.g. reactive power support services). It is an independent authority and does not participate

in the electricity market trades and usually does not own any of the generating units,

transmission and distribution companies. It works independent of these market participants

with an aim to provide non-discriminatory open access to all transmission system users. In a

pool type competitive electricity market, the ISO may have the following responsibilities:

• The ISO administers transmission tariffs, maintains the system security, coordinates

maintenance scheduling, and has a role in coordinating long-term planning.

• The ISO has the authority for market settlement including scheduling and dispatch of

real and reactive power for all participating resources.

• The ISO has the authority to reschedule real and reactive power generations of some

or all participating generators and to curtail loads for maintaining the system security

(i.e., remove transmission violations, balance supply and demand, and maintain the

acceptable system frequency).



• The ISO ensures that proper economic signals are sent to all market participants,

which in turn, should encourage efficient use and motivate investment in resources

capable of alleviating constraints.

Generating Companies (GENCOs): The generators produce and have opportunity to

sell the electricity. This may refer either to individual generating units or more often to a

group of generating units within a single company ownership structure. Moreover, a

GENCO may own generating plants or interact on behalf of plant owners with the short-term

market (power exchange, power pool, or spot market). In addition to real power, GENCOs

may trade reactive power and operating reserves. GENCOs are not affiliated with the ISO or

TRANSCOs. A GENCO may offer electric power at several locations that will ultimately be

delivered through TRANSCOs and DISCOs to customers. In a competitive electricity

market, the objective of GENCOs is to maximize their profits. For this purpose, GENCOs

may choose to take part in whatever markets (energy and ancillary services markets) and

take whatever actions (arbitraging and gaming). It is a GENCO’s own responsibility to

consider possible risks.

Transmission Companies (TRANSCOs): The transmission companies are those

entities, which own and operate the transmission network. Their prime responsibility is to

transport the electricity from the generators to the customers. In a restructured electricity

market, TRANSCOs are regulated (i.e. worked under certain regulatory norms) to provide

non-discriminatory open access to all market participants. The regulatory norms are

formulated by state regulatory authorities. A TRANSCO has the role of building, owning,

maintaining, and operating the transmission system in a certain geographical region to

provide services for maintaining the overall reliability of the electrical system. TRANSCOs

provide the wholesale transmission of electricity, offer open access, and have no common

ownership or affiliation with other market participants (e.g., GENCOs and RETAILCOs).

Distribution Companies (DISCOs): The distribution companies are usually those

entities owning and operating local distribution network in a area. They buy wholesale

electricity either through the spot-market or through the direct contracts with suitable

GENCOs and supply to the customers. A DISCO is responsible for building and operating

its electric system to maintain a certain degree of reliability and availability. DISCOs have

the responsibility of responding to distribution network outages and power quality concerns.



They are also responsible for maintenance and ancillary services such as voltage/reactive

support services.

Retailer: Apart from the above mentioned entities, the retailer is an entity in a

competitive power industry which obtains legal approval to sell retail electricity. A retailer

buys electric power and other services necessary to provide electricity to its customers and

may combine electricity products and services in various packages for sale.

2.2.2. Types of Power Market

There may be two way to classify different electricity markets: (1) Based on trading,

different electricity markets may be categorized into the energy market and ancillary service

markets; (2) Based on the operational time-frame, different electricity markets may also be

classified as forward market (day-ahead or hour-ahead) and real-time market. It is important

to note that markets are not independent but interrelated. These market types along with their

organization and operations may be described as follows:

2.2.2.1. Real Power/Energy Market

In any competitive electricity market, real power is the main product and generally, it is

traded in bulk amount (MW) within a domain called energy market. Therefore, the energy

market is a place where the competitive trading (auction) of real power occurs. The energy

market is a centralized mechanism that facilitates energy trading between buyers and sellers.

The energy market has a neutral and independent clearing and settlement operation. In

general, the ISO operates the energy market. The ISO receives the offer bids (the price and

quantity pairs) from all the market participants. In a single-sided auction market, the bids are

called from GENCOs (only) for a given fixed demand. In contrast to that, the supply bids are

submitted by GENCOs as well as the demand bids are submitted by load serving entities in a

double-sided auction market. The ISO aggregates the supply bids into a supply curve and the

demand bids into a demand curve (in case of double-sided auction market). The market

clearing process for both single-sided and double-sided auctions are illustrated in Fig.2.2 and

Fig.2.3 respectively. The intersection of these supply and demand curves determines the

market-clearing price (MCP) at which energy (real power) is bought and sold.



Market Clearing Point

Market Clearing Quantity

Market Clearing Price (MCP)

Fig.2.2: Energy Market Clearing for a single-sided auction market [135]

Bid Prices ($/MWh)

Market Clearing Point

Market Clearing Quantity

Market Clearing Price (MCP)

Fig.2.3: Energy Market Clearing for a double-sided auction market [135]

2.2.2.2. Ancillary Service Markets

As the electric power industry approaches toward the full competition, various services

previously provided (before restructuring) by electric utilities are being unbundled. Much of

the attention given to the ISO development has focused on the structure of markets for

energy and power transmission, and the market for ancillary services which is getting to be

more critical [136]. Ancillary services are generally referred to as those services other than

energy that are essential to ensure the reliable operation of the electrical grid. As

restructuring evolves, determining the cost of supplying ancillary services and finding out

how these costs would change with respect to operating decisions is becoming a major issue

[137]. According to the Federal Energy Regulatory Commission (FERC), ancillary services

are necessary to support the transmission of power from sellers to buyers given the

obligation of control areas and transmission utilities to maintain a reliable operation of the



interconnected transmission system. FERC defines ancillary services in Order 888 (Open

Access Rule, issued in April 1996) [3] as “Those services that are necessary to support the

transmission of energy from resources to loads while maintaining reliable operation of the

Transmission Provider's Transmission System in accordance with good utility practices”. In

FERC Order 888, the following six ancillary services are determined and must be included

in an open access transmission tariff:

(a) Scheduling, System Control and Dispatch: Under this class of ancillary services, the

transmitting utilities would schedule and coordinate transactions (i.e. movement of

power) with other entities and confirm the power exchange in and out of their control

areas so as to maintain supply-demand balance.

(b) Reactive supply and voltage control from Generation Sources: The system operator

(like ISO) requires generators to provide (or absorb) reactive power in order to

maintain the system bus voltages within some desired limits. This ancillary service

would facilitate sufficient reactive power and voltage control, which is unbundled

from basic transmission rates.

(c) Regulation and Frequency Response: The use of generation equipped with

governors and automatic generation control (AGC) to follow the instantaneous

variations in customer (load) demand or scheduled generation delivery, in order to

maintain the frequency.

(d) Energy Imbalance: The use of generation to correct for hourly mismatches between

actual and scheduled delivery of energy between suppliers and their customers.

(e) Operating Reserves Service: This ancillary service is required where spinning

reserve and non-spinning reserve are defined as extra energy for supplying the load

in the case of unplanned events such as the outage of a major generation facility.

(i) Spinning Reserves: This service is provided by on-line generating units which

are either unloaded or operate at less than maximum output, and be ready to

immediately serve load for correcting the generation-load imbalance in the event

of a system contingency.

(ii) Non-Spinning Reserves: This service is also known as the supplemental reserve

service which is provided by unloaded generating units, by quick-start generation,

or by interruptible load to generate capacity for emergency conditions but not be

available immediately. Non-spinning reserve capacity should be started up very

quickly (usually within 10 minutes).



Although a transmission provider must be equipped to offer all of the above six

ancillary services to transmission customers, FERC [3] clarified that only the first two

ancillary services must be offered to all transmission customers. In addition, FERC

suggested that transmission customers must buy the first two ancillary services because these

services are local by nature and the transmission provider is best suited to provide these

services. For the other four ancillary services, FERC allows transmission customers to obtain

the service in any of the following three ways: from the transmission provider, from another

source (third party), or by self-provision.

2.2.2.3. Forward and Real-time Markets

The competitive electricity markets may also be classified based on operational timeframes

into the following two categories:

Forward Markets: In most electricity markets, a day-ahead forward market is used

for scheduling resources at each hour of the following day. An hour-ahead forward market is

a market for deviations from the day-ahead schedule. Both energy and ancillary services can

be traded in forward markets. In general, the forward energy market is cleared first. Then,

bids for ancillary services are submitted, which could be cleared sequentially or

simultaneously.

Real-Time Markets: To ensure the reliability of power systems, the production and

consumption of electric power must be balanced in real-time. However, real-time values of

load, generation, and transmission system can differ from forward market schedules. The

real-time market is established to meet the balancing requirement known as balancing

market, usually operated by the ISO. Available resources for accommodating real-time

energy imbalances can be further classified according to their response time, including that

of AGC, spinning, non-spinning and supplemental reserves which could be available within

a required time (probably vary minimum time) of the ISO’s dispatch instruction based on

ramping considerations.



Fig.2.4: Illustration of a competitive electricity market operation



2.2.3. Competitive Electricity Market Operation

For the recent deregulated electric power industries, a typical competitive electricity market

operation may be realized as shown in Fig.2.4. In this realization, the different functions of

two key market entities such as independent system operator (ISO) and generating

companies (GENCOs) are illustrated. Therefore, the market operation for a competitive

electricity market may be explained based on different functions within the domain of ISO

and GENCOs as follows:

The ISO is a central unit which has the responsibilities to establish the energy and

ancillary market, to operate these markets securely and efficiently, and to monitor that the

market is free from the market power problems. First of all, the ISO needs to forecast the

system load accurately to guarantee that there is enough energy to satisfy the load and

enough ancillary services to ensure the reliability of the physical power system. Moreover,

the price forecast for different markets (energy market and ancillary service market like

reactive power service market) are required for the procurement and settlement of these

markets in a fair, transparent and economical manner. Moreover, the operational

responsibilities of the ISO include the energy market and the ancillary services market (e.g.

reactive power and voltage control services). The ISO must be equipped with powerful tools

(i.e. methodologies or strategies) to discharge these responsibilities, such as through day-

ahead market settlement, the ancillary services auction, congestion management and

transmission pricing. Further, the ISO must also be equipped to monitor the market to

suppress the market power problem. According to FERC Order 2000, the market monitoring

is an essential tool for ensuring non-discriminatory market operation and avoiding any

opportunity for exercise of market power [138]. In order to measure/quantify the market

power in real power auctions, several indices such as Herfindahl-Hirshman Index (HHI)

[139] and Residual Supply Index (RSI) [140] are defined. These indices may also be

considered for measuring market power in case of reactive power ancillary service auction.

ISO in the electricity industry must identify and correct situations in which some companies

possess market power.

In the present competitive power market, the sole objective of a GENCO is to

maximize its profit. In order to achieve this objective, the GENCO must make an accurate

forecast about the system, including its load and its price. In most situations, load forecasting

is the basis for price forecasting since the load is the most important price driver. Price



forecasting is important for the GENCO in the Competitive power industry, since the price

reflects the market situation. In other words, the market price is a signal, according to which

a GENCO decides its action in the market. Moreover, the GENCO usually apply good

bidding strategy based on the forecasted system information to achieve the maximum profit.

In the Competitive power market, the price-based unit commitment (PBUC), replacing the

traditional unit commitment, would be the basis for a good bidding strategy. In addition,

identifying arbitrage opportunities in the market and exploiting those opportunities to

achieve maximum profit should be one of the capabilities of the GENCO. In most cases, the

identification of arbitrage opportunities depends on PBUC. Because of the uncertainty and

the competitiveness of the market, a game strategy would be an indispensable tool for the

GENCO. Another significant issue is the risk management on which, enough attention must

be paid by a GENCO by considering various risk factors. Asset valuation is an important

function in risk management, and this would utilize PBUC, arbitrage, and gaming.

Table 2.1: Characteristics of different types of voltage control equipment [40]

Equipment Type

Speed of Response

Ability to Support Voltage Costs

Ability Availability Disruption Capital Cost (per KVAr)

Operating Cost

Opportunity Cost

Generator Fast Excellent,

additional short-term capacity

Low Low Difficult to

separate High Yes

Synchronous Condenser

Fast Excellent,

additional short-term capacity

Low Low $30-35 High No

Capacitor Slow Poor, drops with

V2 High High $8-10 Very low No

Static VAR Compensator

Fast Poor, drops with

V2 High Low $45-50 Moderate No

STATCOM Fast Fair, drops with

V2 High Low $50-55 Moderate No

Distributed Generation

Fast Fair, drops with

V2 Low Low

Difficult to separate

High Yes

2.3. Reactive Power as an Identifiable Ancillary Service

In a recent structure of deregulated power industry as shown Fig.2.2, the reactive power and

voltage control service is identified as an important ancillary service. According to FERC

Report 2005 [40], the reactive power and voltage control, where generation sources (i.e.

reactive power providers) help maintain a proper transmission line voltage, is a necessary

ancillary service to retain the power system reliability and security. This ancillary service



would supply reactive power and voltage control, which is unbundled from basic

transmission service (i.e. energy or real power service). Therefore, a separate competitive

market for these reactive power support services should be established and recognized as a

reactive power ancillary market. The ISO is the entity entrusted to provide reactive power

ancillary service through commercial transactions with reactive power service providers. In a

competitive environment, the reactive power ancillary service must be carefully managed by

the ISO so that the power system requirements and market objectives are adequately

achieved.

Many devices can contribute to the reactive power support and voltage profile, these

devices are synchronous generators, synchronous condensers, capacitors etc. The basic

characteristics of these reactive power support and voltage control devices are summarised

as given in Table 2.1. The ability to support voltage means the ability to produce reactive

power when voltage is falling. The availability of voltage support indicates how quickly a

device can change its reactive power supply or consumption. Disruption is low for devices

that can smoothly change reactive power output and high for devices that cannot change

reactive power output smoothly. Generally, reactive power support is divided into two

categories: static and dynamic [40]. An exhaustive discussion about these reactive power

support devices may be found in FERC Report 2005 [40]. The static reactive power support

devices like capacitors have no actual control of the reactive power output in response to the

system voltage. On the other hand, the dynamic reactive power support devices are capable

of adjusting their output according to pre-set limits in response to the changing system

voltages. The dynamic reactive power devices are the fast responding devices such as

synchronous generators, synchronous condensers, Flexible AC Transmission Systems

(FACTS) including static VAR compensators (SVC), static compensators (STATCOM). At

this end, a critical question arises: which type of reactive power supports should be

considered as the authentic reactive power ancillary services?

According to FERC Order 888 [3] and NERC White Paper on Proposed Standards

for Interconnection Services [141], it is clearly recommended that, only reactive power

support from synchronous generators is recognized as an ancillary service and is eligible to

receive financial compensation. For example, presently in North America, only synchronous

generators are compensated for reactive power provision as per NERC's Operating Policy 10

[142] and also according to the recommendation made in FERC Order 888 [3]. However,

these restrictive market policies are currently under review, since it can be readily argued



that with the more liberal market policies for a reactive power ancillary service market, there

would be more competition due to an increased number of service providers. These liberal

market policies for the reactive power ancillary market will lead to a reduction in reactive

power prices, and improved system reliability and security.

In the past, the above market policy issues are also raised at many platforms and

forums worldwide, several discussions and recommendation have come. A significant and

detailed discussion about the use of different reactive power providers may be found in the

latest FERC Report 2005 [40]. In this report, it is concluded that the ISO may also consider

other sources of reactive power supply in competitive electricity markets [40]. In view of

these discussions, it is important to examine how other reactive power providers, such as

capacitor banks and particularly FACTS controllers, could participate in the reactive power

ancillary service markets to help develop a fully competitive reactive power market. It is

worth mentioning that this particular issue is not studied in this thesis, since the

characteristics of these reactive power resources make them essentially different from

generators; hence, appropriate policies will be required to determine how these resources can

be properly compensated for providing reactive power as an ancillary service. Therefore, in

the work presented in this thesis, only reactive power from synchronous generators is

considered as an ancillary service, as per the existing FERC and NERC regulations.

Moreover according to FERC Report 2005 [40], the market design for the reactive

power ancillary services should align financial compensation and incentives with desired

outcomes to ensure that adequate reactive power is available and produced in the right

locations in order to maintain reliability and meet load at the lowest reasonable cost. Some

have a different view – that independent generators should be obligated to provide a

specified minimum capability to produce reactive power without compensation as a

condition of interconnecting to the grid, but we think that this view will not encourage

optimal investment and production of reactive power. If independent generators aren’t paid

for providing reactive power capability, some may elect not to enter the market, and some

existing generators may elect to retire sooner than if payments were made. Therefore, the

FERC Report 2005 [40] made the following recommendations:

• Suppliers of reactive power should be financially compensated for providing reactive

power and reactive power capability. Similarly, once capability payments are



received, capability tests for reactive power should be a routine part of reliability

procedures and penalties should be assessed for test failures.

• The market rules should allow greater compensation for reactive power capability

having greater quality and value, just as they do for real power operating reserves.

For example, reactive power capability from dynamic sources is more valuable than

from static sources, because dynamic sources can adjust their production or

consumption of reactive power much more quickly when needed to maintain voltage

and, thus, prevent a voltage collapse. Thus, reactive capability from dynamic sources

should be paid more than capability from static sources at the same location. This is

consistent with the policy of paying higher prices for faster-response (and thus,

higher quality) operating reserves for real power.

• However, reactive power that is actually produced or consumed at a given location

and time has the same value whether it is provided by a static or dynamic source.

Thus, the price faced by all reactive power providers in a day-ahead market at a given

location and time should be the same, regardless of the source. This policy is

consistent with the approach followed in spot auction markets for real power in ISO

markets, where all suppliers at a given location and time are paid the same price for

their real power production.

2.4. Existing Reactive Power Market Policies: International Experiences

This section presents an overview of existing reactive power management along with market

policies in some of electricity markets world-wide, including those in England and Wales,

United States, Nordic Countries, Australia, India.

2.4.1. England and Wales (UK)

The National Grid Company (NGC), like the ISO, arranges the tenders of reactive support

services. The generator bid reactive power support includes capacity (price per MVAr and

quantity on offer) and utilization (MVAr-h price curve) components. The bidder that is

selected is paid for both the capacity and utilization components through annual bilateral

contracts with NGC.

The Grid Code places a minimum obligation on all generating units, with a power

generating capacity more than 50 MW, to provide a basic (mandatory) reactive power

service. In order to receive payment for this service, the generators must enter into a Default



Payment Mechanism (DPM) or a tendering system. The tendering system consists of either

an Obligatory Reactive Power Service (ORPS) or an Enhanced Reactive Power Service

(ERPS). As an incentive for generators to enter into the tendering system, the DPM ratio of

capability to utilization was introduced as 80:20 in 1997/98 when the scheme was started and

was then modified incrementally to 0:100 up to the April 2000. Alternatively, the generators

can tender specific prices for capability and utilization with regards to ORPS or ERPS. The

rounds for tenders have been held every six months since 1997 and the ninth tender round

was for contracts effective from 1st April, 2002. The tenders are for supplying a reactive

power service for a period of twelve months or more.

The cost of providing reactive power services is currently recovered by National Grid

via use of system charge in the balancing mechanism. The cost of reactive power contracts

are recovered by National Grid via the daily IBC (Incentive Balancing Cost). These are the

cost that National Grid is incentivized to manage and are the basis upon which incentive

payment to (or from) National Grid is calculated. The reactive power contracts costs are

included in the daily BSCCA (Balancing Service Contract Costs Allocation) that is a

component of IBC.

2.4.2. United States (US)

The NYISO (New York Independent System Operator) [143] is responsible for operating the

transmission system in the New York State. In operating the transmission system NYISO is

required to procure reactive power services from generators. Reactive power services are

specified as ancillary services and therefore qualify for payments for the provision of such

services. In order to qualify for payment, suppliers of voltage support services must provide

a resource that has an Automatic Voltage Regulator (AVR) and has passed reactive power

capability testing in accordance with the NYISO procedures and standards. The NYISO

directs the suppliers to operate within their tested reactive capability limits. The schedule of

voltage support services is the responsibility of NYISO and the transmission owners. The

transmission owners are responsible for the local control of reactive power support. The

NYISO provides reactive power support service at embedded cost based price. The reactive

power support cost includes:

• The total annual embedded cost for payment.

• Any applicable lost opportunity cost to provide reactive power service.



• Total of prior year payments to suppliers of reactive power service less the total of

payments received by the NYISO from transmission customers in the prior year for

reactive power service.

2.4.3. Nordic Electricity Market (Norway, Sweden, Finland and Denmark)

In Norway, the generators are paid for reactive power service if only the generators operate

at a power factor beyond the mandatory operating range of 0.92 lagging to 0.98 leading.

In Sweden, there is not any organized reactive power market but reactive power

service is provided on a mandatory basis and there is no scheme for financial compensation

to the providers of this service. The reactive power exchange on the national grid is

controlled by instructions from the Svenska Kraftnät, the Swedish ISO. It is recommended

that reactive power flow between different parts of the grid be kept near zero. The ISO has

the right to supply reactive power from spinning generators connected directly to the

national grid.

In Finland, Fingrid is responsible for the maintenance of adequate reactive power

reserves. This is done through the use of its own resources and also by acquiring reactive

power reserves from Independent parties. Now this provision becomes mandatory. As per

the guidelines, generators of more than 10 MVA rating are required to maintain reactive

power reserves during the normal state of the power system.

2.4.4. Australia

In Australia, the NEMMCO (National Electricity Market Management Company Limited)

[144] an ISO is responsible for reactive power provision same as NYISO. With regard to the

reactive power provision, the scheduled generators are required to provide obligatory

reactive power provision and the generator receives no payment.

The provision of a network transmission service requires reactive power support;

therefore the Transmission Network Service Providers (TNSP) must provide a significant

amount of reactive power support in order to ensure such a provision. The reactive power

support provided by TNSP is available to NEMMCO to utilize it free of charge. NEMMCO

will utilize all obligatory generator reactive power support and all TNSP reactive power

support in order to maintain the security of Power System. Where NEMMCO requires



additional reactive power support it is procured via a contract tender process. Suppliers of

such power services are paid by NEMMCO as follows:

• Generators: Availability + Compensation fee.

• Synchronous Compensators: Availability + Enabling fee.

Availability fee is related to the supplier’s readiness in providing the service.

Compensation fee is related to opportunity cost to a supplier. Enabling fee is related to the

start-up of the service by a supplier. The NEMMCO mandates that generators provide

reactive power in the power factor range of 0.9 lagging to 0.93 leading. If a generator

operates in a power factor beyond this range then it will be compensated financially based on

the lost opportunity cost.

2.4.5. India

According to the CERC (Central Electricity Regulatory Commission) Notification

No.L/68(84)/2006-CERC (14th March, 2006), the beneficiaries are expected to provide local

VAr compensation/generation such that they do not draw VArs from the EHV grid,

particularly under low-voltage condition. However, considering the present limitations, this

is not being insisted upon. Instead, to discourage VAr drawl by beneficiaries, VAr exchange

with Inter State Transmission System (ISTS) shall be priced as follows:

• The Beneficiary pays for VAr drawl when voltage at the metering point is below

97%

• The Beneficiary gets paid for VAr return when voltage is below 97%

• The Beneficiary gets paid for VAr drawl when voltage is above 103% Indian

Electricity Grid Code (IEGC) 51.

• The Beneficiary pays for VAr return when voltage is above 103%

The charges of reactive power support are user-specific. According to CERC

Approach Paper on Formulating Pricing Methodology for Inter-State Transmission in India,

(May 15, 2009), CERC imposes a 5 paisa/kVArh (~$1/MVArh) price on reactive power in

over-voltage and under-voltage conditions (1.03 < voltage < 0.97). Table 2.2 presents a

snapshot of reactive pricing schemes and proposals for Indian states.



Table 2.2: Reactive pricing schemes and proposals for different states of India

State Reactive Power Pricing Scheme

Gujarat1

Tariff for reactive energy drawl by Bagasse based cogeneration shall be the same as that

for solar or wind generators, which is as under:

• 10 paisa/ kVArh: For the drawl of reactive energy at 10% or less of the net energy

exported.

• 25 paisa/kVArh: For the drawl of reactive energy at more than 10% of the net active

energy exported.

Haryana2

Reactive Energy charge @5paise/unit on utilities for drawl at voltage lower than 97% of

the normal voltage and for reactive energy injection at voltage higher than 103% of the

normal levels.

Maharashtra3

The Bombay Electric Supply and Transport Undertaking (BEST) has implemented a

system, in which there is an additional charge on kVArh recorded instead of penalty

charge on low p.f. During 1996-97, BEST introduced a double-metered tariff based on

kWh and kVArh meter reading for voltage class LT consumers. The charges on kVArh

reading were roughly 40-50% of the charges on the kWh bill.

Orissa4

Reactive Energy Charges @6.00paisa/kVArh for FY 2010-11 in line with the

Commission’s order dated 06.04.2009 in Case No. 22/2009 on Reactive Energy Charges

for FY 2009-10 and as per Clause 1.7 of Orissa Grid Code 2006 which states that the rate

for charge/payment of Reactive Energy Charges shall be 5 paisa/kVArh with effect from

14.06.2006 and shall be escalated at 0.25 paisa/kVArh per year thereafter, unless

otherwise revised by Orissa Electricity Regulatory Commission (OERC).

Tamil Nadu5

Reactive energy charges of 5 paisa/kVArh with effect from 1-4-2006 with an escalation of

0.25 paisa/kVArh every year thereafter. The present order stipulates reactive power

charges @6 paisa/kVArh. The Commission wishes to adopt the IEGC and therefore

prescribes 5.75 paisa/kVArh as on 1-4-2009 and escalated by 0.25 paisa/kVArh every year

thereafter.

Uttar

Pradesh6

If the power factor of a consumer is leading and is within the range of 0.95-1.00 then for

tariff application purposes the same shall be treated as unity. However, if the leading

power factor was below 0.95 (lead) then the consumer was to be billed as per the kVAh

reading indicated by the meter. The cutoff of 0.95 (lead) was consciously adopted by the

Commission because below 0.95(lead) the reactive compensation of the consumer may

relax the grid slightly but at the same time it may cause localized over-voltages that may

endanger the surrounding system. 1 Order No. 4 of 2010, Gujarat Electricity Regulatory Commission

2 Concept paper of MERCADOS Energy Market International (4th November, 2009) for Haryana Electricity Regulatory Commission

3 Reactive Power Management, D M Tagare, Tata McGraw-Hill Publishing Company Limited, Reprint-2008, pp-111

4 Case No. 145 of 2009 of Orissa Electricity Regulatory Commission (Date of Order 30.03.2010) 5 http://tnerc.tn.nic.in/

6 Order on ARR and Tariff Petition for TRANSCOs and DISCOs for FY 2009-10,Uttar Pradesh Electricity Regulatory Commission



2.5. Key Issues Related with Reactive Power Management

From the brief overview of utility practices in different countries as presented in previous

section, it is clear that there is no fully developed competitive structure or pricing approach

for reactive power services in any of the power systems world-wide. Moreover there is

universally acceptable framework for reactive power management practices that have

evolved post-deregulation. Further, it is possible (for an ISO), but not easy, to establish

competitive markets for the provision, acquisition, and pricing of reactive power ancillary

service. The difficulty stems from the complexity due to several technical and economic

issues involved in handling the reactive power service and in creating an efficient market for

reactive power.

2.5.1. Technical Issues with Reactive Power

The technical issues such as localized nature of reactive power and capability curve of

synchronous generator are very critical while designing an efficient reactive power

management scheme. These technical issues are discussed in the following subsections.

2.5.1.1. Localized Nature of Reactive Power

The reactive power support in a power system is a highly localized service because of the

fact that the reactive power is difficult to transport. In a heavy loading condition, the relative

reactive power losses on transmission lines are often significantly greater than the relative

real power losses [40]. The reactive power does not travel well for a long distance because

the reactive power consumption or losses can increase significantly with the distance

transported. Moreover, if the sufficient reactive power support is not available locally, it

must be supplied remotely, resulting larger currents and voltage drops along the path. The

very local nature of the reactive power and its interaction with real power may raise several

challenges during the reactive power management in a competitive electricity market as

addressed below:

• Fewer reactive power providers may be available locally to supply the reactive power

demand at any individual location of the power system. In such situations, the local

suppliers are likely to take advantage by increasing their reactive power price offers.



• As the reactive power demands vary widely by location and system conditions, and

since reactive power must be supplied locally, there could be numerous reactive

power zones, each with different requirements for reactive power support services.

According to Ref. [31], the reactive power needs to be provided locally, and hence, the

“worth” of one mega-volt-ampere (MVAr) of reactive power is not the same everywhere in

the system. Thus, if a reactive power market is settled like a real power market, the ISO can

end up with a stack of low-priced offers from locations that are undesirable from system

considerations. Therefore, reactive power markets need a new approach that takes into

account both offer prices and location of the resource.

According to Ref. [40], the locational supply of reactive power can at times increase

the available flow, or transfer capability, for real power between two points. Since reactive

power and real power in combination congest the transmission system, increased reactive

supply in the right locations can increase the transfer capability for real power. Existing

pricing systems give no incentive to supply additional reactive power that may allow low

priced real power to displace more expensive real power sources. This is particularly true if

any increased supply of reactive power requires a reduction in real power output. Because

the generator is generally compensated for real power sales only and there is little incentive

to provide additional reactive power even if it increases efficiency and lowers the total

system costs.

The local nature of reactive power and its interaction with active power present

challenges to market designers. At present, the methodologies and models used for reactive

power procurement and it pricing supplied from generation sources vary significantly with

different transmission operators [33]. Under a competitive market environment, a formal

process of managing reactive power provider is highly desirable to achieve economically

efficient solution and market transparency.

2.5.1.2. Reactive Power from Synchronous Generator: Capability Curve

In view of the existing FERC and NERC guidelines [3], [40], [141]-[142], only reactive

power support from synchronous generators is considered as an ancillary service throughout

this thesis. Thus, it is useful to present a brief discussion on the main characteristics of a

synchronous generator as a reactive power service provider and attempt to examine its

reactive power generation capability in following paragraphs.



=f t aR V I

= t afa

S

V ER

X

2

0

−

, t

S

VX

Fig.2.5: Capability curve of synchronous generator [145]

The synchronous generator settings can be adjusted (smoothly and almost

instantaneously) to produce combinations of real power and reactive power smoothly and

almost instantaneously within its designed capabilities. Further, synchronous generators are

rated in terms of the maximum MVA output at a specified voltage and power factor (usually

0.85 or 0.9 lagging) [145] which they can carry continuously without overheating. Moreover,

both real and reactive power outputs of a synchronous generator are tightly coupled and their



mutual relationship is generally represented by capability curve. The determination of the

capability curve for a synchronous generator may be illustrated as shown in Fig.2.5. The real

power output ( GP ) of a synchronous generator is limited by its prime mover capability to a

value within the MVA rating. When real power and terminal voltage is fixed, the reactive

power output ( GQ ) capability of machine is usually determined by three limits: armature

heating limit, field heating limit and under excitation limit. These three reactive power

output limits for a synchronous generator may be described as follows:

Armature Heating Limit: In the P-Q plane, the armature heating limit appears as a

circle with centre at the origin (0, 0) and the radius equal to the MVA rating i.e. 1 t aR V I=

as shown in Fig.2.5. Let tV is the voltage at the generator terminal bus and aI is the steady-

state armature current. GP and GQ are real and reactive power generation from the machine

respectively. Therefore, the armature heating limit of a synchronous generator may be

expressed as follows:

( )22 2G G t aP Q V I+ ≤ (2.1)

Field Heating Limit: The relationship between the real and reactive powers for a

given field current is a circle centred at ( )20, t SV X− and with 2 t af SR V E X= as the radius.

Therefore, the effect of the maximum field current rating on the capability (i.e. field heating

limit) of the machine may also be illustrated on the P-Q plane as shown in Fig.2.5. If, afE is

the excitation voltage and SX is the synchronous reactance then, the field heating limit of a

synchronous generator may be mathematically expressed as follows:

222 t aft

G GS S

V EVP Q

X X

+ + ≤

(2.2)

Under Excitation Limit: The localized heating in the end region of the armature

imposes a third limit on the operation of a synchronous machine which affects the capability

of the machine in the under-excited condition. Hence, the lower limit on the reactive power

output ( GQ ) of a synchronous generator (called as under excitation limit) is also illustrated

as shown in Fig.2.5.



Moreover, the machine rating of a synchronous generator is the point of intersection

of the two circles corresponding to armature and field heating limits and marked as 'R' in

Fig.2.5. Let GRP is the real power corresponding to machine rating power. WhenG GRP P< ,

the limit on reactive power output (GQ ) is imposed by the generator's field heating limit.

While, when G GRP P> the armature heating limit imposes restrictions onGQ .

In order to examine further into the generator’s reactive power supply, suppose baseQ

is the reactive power required by the generator for its auxiliary equipment. If the operating

point (say point 'A') lies inside the limiting curves, say at( ),GA GbaseP Q , then the machine may

increase its reactive power output from GbaseQ up to GAQ without modifying it real power

output ( GAP ). This will however, result in increased losses in the windings and hence

increase the cost of loss.

Furthermore, let the generator is operating on the limiting curve, any increase in GQ

will require a decrease in GP so as to adhere to the winding heating limits. With reference

the operating point 'A' on the limiting curve defined by( ),GA GAP Q . If the reactive power

output of the synchronous generator is required to be increased up to BQ then, the operating

point requires shifting back along the curve to point ‘B’ i.e. ( ),GB GBP Q , where GB GAP P> .

This signifies that the unit has to reduce its real power output to adhere to field heating limits

when higher reactive power is demanded and hence there will be the loss of revenue for the

generating unit. In such as situation, the generating unit should be paid an additional amount

(known as opportunity cost) by the ISO in a competitive reactive power market.

From the above discussion, it is very clear that the reactive power outputs of a

synchronous generator limited limited by its filed and armature limits, and may also affect its

real power output. Therefore, the synchronous generator capability curve is considered to be

an important issue while settling the competitive reactive power market and hence included

in the reactive power management models as proposed in this thesis.

2.5.2. Economic Issues with Reactive Power Management

Besides the technical issues as discussed in previous subsection, there are also some issues

such as market power and generators gaming, reactive power payment mechanism and



pricing methods. These issues govern the economy in a competitive market, while managing

the reactive power ancillary services and therefore, are discussed in the subsequent

subsections.

2.5.2.1. Market Power and Gaming

In general, the term “market power” may be defined as owning the ability by a seller, or a

group of sellers, to drive the spot price over a competitive level, control the total output, or

exclude competitors from a relevant market for a significant period of time [136]. In other

words, Market power is the ability of a firm to raise its price significantly above the

competitive price level to maintain this high profitable price for a considerable period [146].

Moreover, when an owner of a generation facility is able to exert a significant influence

(monopoly) on pricing or on the availability of electricity, a market power is manifested. A

market power could hamper the competition in power production, service quality, and

technological innovation in a restructured power system. The net result of the existence of

market power is a transfer of wealth from buyers to sellers through a misallocation of

resources.

As mentioned earlier, the reactive power is a very local service, i.e. it must be

produced and provided as close to the demand buses as possible because of the technical

issues associated with transporting reactive power over long distances. Such a localized

characteristic may result in market situation when fewer suppliers are ordinarily available to

provide the reactive power needed at any individual location. Such critical locations in a

market, where very fewer reactive power suppliers are present to meet up the service

demand, may be recognised as the strategic locations. In a reactive power market, it is

certainly plausible that some suppliers at these strategic locations may try to exercise market

power by submitting excessively high price offers or by withholding reactive power supply

in an attempt to increase the reactive power market price to their own advantage. In this

way, these providers could hold market power and if they indulged in gaming (a non-

competitive practise), could alter the market prices to their advantage. Such a situation is

undesirable for an efficient market operation, and therefore market power is one of the

primary barriers to the implementation of a competitive reactive power market. Furthermore,

in contrast to energy market (real power market), the market power is more serious problem

in a reactive power market because of the localized characteristics of reactive power.



In the restructured marketplaces, it becomes a challenging task in front of the power

market authorities or independent system operator (ISO) to identify and correct non-

competitive situations where some companies possess market power. Moreover, the market

power problem related with reactive power, in general, cannot be solved with pure technical

solutions as mentioned in Ref. [33]. For example, when a generator knows that the ISO must

call on its reactive power support, no technical solutions suffice. Furthermore, FERC report

2005 [40] addressed many issues related with the existence of market power in reactive

power market and suggested that several options must be considered while developing a

competitive reactive power market. Nevertheless, proper regulation or market power

mitigation policies may be needed to prevent reactive power prices from reflecting an

exercise of market power. Therefore, the appropriateness of a reactive power management

model considerably depends upon its ability to combat the market power due to generator

gaming in a competitive electricity market. While, effective market regulations or a well-

designed market structure can mitigate or eliminate the market power in the system, hence

prevent market power holder from exercising market power; a not well-designed market may

worsen the situation [50].

2.5.2.2. Reactive Power Payment Mechanism

In a competitive market environment, the ISO aims to utilize the available reactive power

resources efficiently and economically through an appropriate choice of payment

mechanism. The reactive power providers must be properly compensated for their reactive

power support services so as to ensure their participations in the reactive power ancillary

service market, otherwise the power system reliability and security may be affected. The ISO

selects an appropriate payment mechanism such that all the providers shall have enough

incentive for their reactive power support services. The international electricity market

experience suggests three types of reactive power payment mechanisms: (a) Contractual

basis, (b) Tender basis and (c) Market-based auction.

Contractual Basis: In this payment mechanism, the ISO enters into bilateral

agreements with the service providers by signing long-term contracts for the required

reactive power services. Such type of reactive power payment mechanism is frequently

adopted by Independent Electric System Operator (IESO) in Ontario, Canada [147] and the

ISO-New England [148]. IESO in Ontario makes yearly contracts with the generators,

recognizing additional energy losses and opportunity costs associated with reactive power



generation, and the cost of running the generating units as synchronous condensers if

requested by the IESO. In contrast to that, the ISO-New England pays a capacity component

for qualified generators for their capability to provide reactive power services along with

their lost opportunity components.

Tender Basis: The payment mechanism for reactive power support services may also

be set to form a tender market structure as in the UK [149]. National Grid Electricity

Transmission (NGET) in UK calls the tenders from the reactive power providers.

Subsequently, the selected generators are contracted for six months and are paid based on

their initial tender price offers, similar to a pay-as-bid (first price) auction market.

Market-based Auction: The payment mechanism based on market auction may be

the most suitable option to establish a competitive reactive power market. The ISO could

hold an auction for reactive power capability and the winners of the auction would receive

the applicable Market Clearing Price (MCP) as suggested in Ref. [40]. In a market-based

auction, the prices for the reactive power support services are determined through auction.

All the service providers are required to submit their reactive power price offers (bids) to the

ISO, which in turn determines the best MCP by optimizing an appropriate objective function

(e.g. total reactive power payment burden on ISO).

2.5.2.3. Pricing Methods for Reactive Power

The reactive power market prices may be determined based on either locational marginal

pricing method or uniform pricing method. In locational marginal pricing method, the

marginal cost depends on the location where the reactive power is produced or consumed. In

general, if a different price is defined at each bus or node in the system, locational marginal

pricing is called nodal pricing [150]. The locational marginal price (LMP) varies across each

bus (node) in a given power system, it is higher in areas that normally import power and

lower in areas that export power [150]. In contrast to LMP based method, only a single

market clearing price is obtained and applied to all market participants in a uniform price

auction as there exist only one uniform market price for whole system.

Gil et al. [28] proposed a theoretical approach of marginal pricing (nodal or LMP

based) to assess and charge for reactive services. According to Ref. [31], it can be argued

that nodal reactive power pricing (LMP based) methods would motivate new reactive power

investments in high-demand areas and thereby reduce market power concerns. However, as



discussed in [22], these pricing instruments would only represent a portion of the true cost of

the reactive power service—that associated with fuel costs of real power. The capital and

opportunity cost components of reactive power will not be accounted for. Moreover, with the

enormous volatility of nodal prices, this type of pricing could lead to highly unstable

markets. Furthermore, if a uniform price auction is adopted to determine the reactive power

market prices, the reactive power providers will have incentives to offer their true operating

and opportunity costs. Since each provider would receive a price greater than its offered

price, submitting an offer priced above its costs will expose the provider to the risk that the

offer is not selected, with a resulting loss of revenue. Thus, providers will have a clear

incentive to offer prices equal to their costs and quantities equal to their capacity [151].

As mentioned in previous subsection, a market-based auction may be the most

appropriate payment mechanism for realizing a competitive reactive power market. A

market-based auction usually adopted either pay-as-bid approach or uniform price approach.

A pay-as-bid approach is based on first price auction, where selected participants (service

providers) are paid as per their respective bid. A uniform price approach is based on second

price auction, where all selected participants are paid a uniform price, which is the highest

accepted offer. Applying the uniform price to reactive power markets would be a natural

extension to the already existing real power auction mechanisms. However, given the

localized nature of reactive power and the existence of market power due to the limited

number of providers at a given location, the preferable approach may be to disaggregate the

uniform price of reactive power into localized/zonal components. Furthermore, the Ref. [35]

suggests that the reactive power market may also be settled on a localized/zonal basis by

splitting the whole power system into different reactive power zones according to electrical

distance concept. Such a localized/zonal reactive power markets based on uniform price

auction would overcome the impact of market power exercised by certain gaming

generators, and should hence restrict them only to their given zones.

2.6. Concluding Remarks

This chapter provides an overview of various ingredients of a competitive electricity market

including market structure and key entities, different power markets (classification) and its

market operation. The critical terms such as open access, restructuring and deregulation are

defined in the perspective of power industry and electricity market. Thereafter, a background

discussion on various ancillary services is presented, highlighting their significance. Special



attention is given to explain the importance of reactive power as an identifiable ancillary

service in a competitive electricity market. Moreover, the existing reactive power pricing and

management policies are discussed in an international context. Finally, a detailed discussion

on various technical issues (i.e. localized nature and synchronous generator capability curve)

along with some of economic issues (market power and gaming, payment mechanisms and

pricing methods), involved in reactive power management is presented.

***

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