___________________________________________________ *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
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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
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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-
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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
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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).
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• 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.
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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.
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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
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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).
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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.
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Fig.2.4: Illustration of a competitive electricity market operation
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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
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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
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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
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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
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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
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
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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.
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
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• 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
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
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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.
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
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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
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
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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.
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
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• 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.
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
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=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
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
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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.
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
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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
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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.
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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
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
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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
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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
Chapter 2: Competitive Electricity Markets and Reactive Power Management 2013
Dept. of Electrical Engg., Faculty of Engineering, Dayalbagh Educational Institute, Agra-282110. 52
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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