[ECONOMICS OF ELECTRICITY MARKET] December 14, 2010
1 | P a g e School of Petroleum Management, Gandhinagar.
[ECONOMICS OF ELECTRICITY MARKET] December 14, 2010
2 | P a g e School of Petroleum Management, Gandhinagar.
PREFACE
This project is chosen as under the guidelines of our revered professor Mr. Rasananda
Panda. This is focused on the Economics involved in the Indian Electricity market
currently undergoing restructuring and adopting the deregulated industry structure for
better utilization of the resources and for providing choice and quality service to the
consumers at economical prices. Focus of the paper is to explore different economic
structural models in Indian electricity market, the negative externality in electricity, the
power trading models and the financial feasibility of investments made in power plants.
KEY WORDS: Electricity Economics, Power trading, Negative externality, Investment
feasibility.
SPM-Gandhinagar Authors
PDPU
14/12/2010
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EXECUTIVE SUMMARY
This paper explores the pre-reform and post reform economic models which results
into power market development in Indian electricity market. The study analyzed
several economic models and the feasibility of Competition in Maharashtra with
modeling the MH Electricity Market in the Cournot Framework. The concept of Optimal
Plant Mix which is utilization of mix of electricity generating techniques, which mainly
depends on the electricity demand curve is critically analyzed and economics of multi
plant firm taking economics of Load Division into account is discussed. The
environmental concerns related to power sector in India in terms of negative
externality models and social values are also discussed. The effort is to quantify
externalities, resulting from energy use, which often influence fiscal subsidy levels. The
paper also tries to address the present demand supply gap in Indian Electricity market.
Moreover the paper also explores the various econometric models in the power trading
operations in Indian particularly power exchange which is presently at the nascent
stage in India. With the enactment of Electricity Act 2003, Government of India has
outlined the counters of a suitable enabling framework for the force for generators to
innovate and operate in most efficient overall development of wholesale electricity
market and economic manner in order to remain in business and introducing
competition at various sectors. A restructured power recovers their cost. Other benefits
of competitive market trading model for Indian scenario within the boundary of legal
include customer benefits, generation economies of scale and framework is discussed in
our study. The finding is that longer term contracts and growing MPPs (Merchant power
plants) are the key growth drivers for the maturity of power trading in India. The paper
discussed the optimum bidding strategies for Generating companies in India with the
game theory perspective. The paper also analyzed the investment environment and the
feasibility of wholesale electricity competition environment in Indian power sector with
the financial feasibility calculations for putting up a new power plant.
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CONTENTS
Preface ................................................................................................................................................................................... 2
Executive Summary ......................................................................................................................................................... 3
Chapter 1 .............................................................................................................................................................................. 8
Introduction ........................................................................................................................................................................ 8
Industry Structure .................................................................................................................................................... 10
Industry Scenario ...................................................................................................................................................... 11
Generation ............................................................................................................................................................... 11
Transmission .......................................................................................................................................................... 12
Distribution ............................................................................................................................................................. 13
Chapter 2 ........................................................................................................................................................................... 15
Modelling Electricity Markets ................................................................................................................................... 15
Cost of Production .................................................................................................................................................... 15
Decreasing Average Costs ................................................................................................................................. 16
Increasing Average Costs .................................................................................................................................. 17
Power Market Development in India ................................................................................................................ 17
Monopoly in Indian Electricity Market........................................................................................................ 17
Economics of Monopoly ..................................................................................................................................... 19
Oligopoly Market ....................................................................................................................................................... 22
Independent Power Producers (IPPs) ......................................................................................................... 22
Unbundling, Privatisation and Independent Regulation ..................................................................... 23
Economics of Oligopoly ...................................................................................................................................... 24
Competitive Markets................................................................................................................................................ 26
Why Competition? ................................................................................................................................................ 26
Evolvement of Competition.............................................................................................................................. 27
Challenges of Making Competition in Electricity Market .................................................................... 28
Analysing feasibility of Competition in Maharashtra ................................................................................. 30
Modelling the MH Electricity Market in the Cournot Framework ................................................... 32
Economics of Load Division .................................................................................................................................. 37
The Screening Curve Method .......................................................................................................................... 39
Optimal Plant Mix ...................................................................................................................................................... 41
Economics of multi plant firm.............................................................................................................................. 42
Chapter 3 ........................................................................................................................................................................... 45
Negative externalities and Power Markets: ........................................................................................................ 45
Externalities in Electricity: .................................................................................................................................... 45
Fossil fuel environmental externality: ......................................................................................................... 46
Getting the price: .................................................................................................................................................. 48
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Full cost of Power plants: ....................................................................................................................................... 52
Life cycle Assessment/ Life Cycle Costing: ................................................................................................ 52
Environment cost model: ....................................................................................................................................... 55
Emission trading – economic model: ................................................................................................................ 56
Initial Emission Permits allocation: .............................................................................................................. 56
Allocation Model of initial Emission Permits: ............................................................................................... 57
Allocation model with fairness: ...................................................................................................................... 57
Allocation Model with economic efficiency: .............................................................................................. 57
Chapter 4 ........................................................................................................................................................................... 59
Addressing the demand-supply gap in India’s electricity market ............................................................. 59
Possible Solution ....................................................................................................................................................... 61
A. Options for the supply side ......................................................................................................................... 61
B. Options for solution on the demand side .............................................................................................. 62
Evaluation of Options .............................................................................................................................................. 64
A. Generic evaluation framework .................................................................................................................. 64
B. Supply side policy- choice 1: Investment in generation .................................................................. 65
C. Supply side policy- choice 2: Captive generation ............................................................................... 66
D. Demand side policy- choice 1: Reducing line losses ......................................................................... 66
E. Demand side policy- choice 2: Peak pricing ......................................................................................... 67
F. Demand side policy- choice 3: Seasonal pricing ................................................................................. 68
G. Demand side policy- choice 4: Energy rationing ................................................................................ 68
Chapter 5 ........................................................................................................................................................................... 69
Financial Feasibility study of a Greenfield power plant ................................................................................ 69
Major Assumptions................................................................................................................................................... 69
Project cost and Means of finance ................................................................................................................. 69
Power Project Cost Break-up .......................................................................................................................... 70
Mining Project Cost Break-up ......................................................................................................................... 71
Means of financing break-up ........................................................................................................................... 71
Profitibility Projection ............................................................................................................................................ 72
Chapter 6 ........................................................................................................................................................................... 74
Power Trading in India ................................................................................................................................................ 74
Power Exchange ........................................................................................................................................................ 74
Main functions of a Power Exchange ........................................................................................................... 75
Indian Energy Exchange ......................................................................................................................................... 75
congestion management ................................................................................................................................... 78
References ......................................................................................................................................................................... 80
Annexure I: Some Useful Internet Resources for Information on Indian Power Sector .................. 83
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CHAPTER 1
INTRODUCTION
In the first 100 years of its commercialization, electricity was supplied by vertically
integrated monopolies to consumers. It was generally thought that this was the only way
to do the business of electricity supply. The implication of monopoly characteristic was
that the prices had to be regulated to protect the interest of consumers. With passage of
time, electricity came to become a public good to be made available by the Governments
of the day in the developing world.
Economists have long debated the effects of economic regulation. Such debates remained
inconclusive until the deregulation of transportation and financial services in 1970s and
the wholesale market for natural gas in 1980s in Western economies. Each of the initial
experiments with deregulation produced enormous efficiency gains, accompanied by
significant price reduction. In the electricity sector too, by 1980s, economists started
questioning the conventional wisdom and argued that electricity can be subjected to
market discipline rather than being controlled through regulated monopoly or
Government policy. It was argued that the traditional cost of service regulation greatly
attenuated regulated firms' incentives to operate efficiently and often introduced
incentives to operate inefficiently. Simultaneously, with the invention of Combined Cycle
Gas Turbines (CCGT), economies of scale in generation came down from optimum size of
1000 MW for nuclear plants and 500 - 600 MW for coal fired stations to 200 MW - 300
MW and even smaller capacity in case of CCGTs.
As for co-ordination, economists argued that the coordination was possible through
market mechanisms. As a result of these developments, traditional industry structure and
regulatory approach started to break down in the West. The concept of non-
discriminatory open access in transmission under which transmission owning utilities
were required to provide third parties equal access to their transmission lines, made
competition possible. This called for various forms of structural unbundling of electricity
supply industry into generation, transmission, distribution and supply.
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In the Indian context, State Electricity Boards (SEBs) created as vertically integrated
monopolies as service providers with some powers of regulation had successfully
extended the network to cover the country. By the 1990s, however the losses of SEBs
had reached unsustainable levels on accounts of huge pilferage in the system as also the
reluctance to allow tariffs to cover reasonable costs. Initial attempts to get significant
amount of private investment in generation and transmission did not succeed. Driven
by a set of factors, many States brought about legislative changes to facilitate
unbundling of the Boards. Unbundling in India was aimed at enforcing accountability,
better management and promoting efficient operations, unlike in the west where
unbundling was considered necessary primarily for promoting competition.
The Union Parliament enacted the Electricity Act, 2003 laying down a road map for
evolving a competitive electricity supply industry in the country. Some of the
important features of the Electricity Act, 2003, which have bearing on competition
aspects, are as follows:
Ø Delicensed generation.
Ø Non-discriminatory open access m transmission mandated.
Ø Single buyer model dispensed with for the distribution utilities.
Ø Provision for open access in distribution is to be implemented in phases.
Ø Provision for multiple distribution licensees in the same area of supply has been
incorporated.
Ø Electricity trading is recognized as a distinct licensed activity.
Ø Development of market (including trading) in electricity made the responsibility
of the Regulatory Commission.
Ø Provision for reorganization of the State Electricity Boards, with the relaxation to
continue as SEBs' during a transition period is to be mutually decided between
the Centre and the States.
Further, the National Electricity Policy announced by the Central Government in
February 2005 inter-alia states that the development of power market would need to be
undertaken by the Appropriate Commission in consultation with all concerned.
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INDUSTRY STRUCTURE
Public sector institutions continue to play the dominant role in the electricity supply and
delivery chain in India. The Ministry of Power (MoP) is the Central government institution
responsible for overseeing India’s electricity industry. Several authorities and agencies
operate under the MoP, among them the Central Electricity Authority (CEA) assists the MoP
on technical and economic issues.
The Central Electricity Regulatory Commission (CERC) is an independent statutory body
with quasi-judicial powers. The CERC has a mandate to regulate interstate tariff related
matters, advise the central government on formulation of the national tariff policy and
promote competition and efficiency in the electricity sector. The CERC regulates Central
government owned utilities both in generation and transmission.
Industry structure
The State Electricity Regulatory Commissions (SERCs) have jurisdiction over state utilities
in generation, transmission and distribution. Independent Power Producers (IPPs) are
regulated by CERC / SERC depending on whether they sell power to one or more states.
Ministry of Power GOI Central Sector Companies
GenCos- NTPC, NHPC, NEEPCO & NPCIL
CTU- PGCIL
Finance-PFC
Rural Electrification- REC
Appellate tribunal for electricity
CEA
R&D, CPRI, NPTI,
CERC
SERC
Forum of regulators
NLDC
RLDC
SLDC State IPPs
Min. of Power State govt.
Electronic trading platform (multiple power exchange)
Trading companies
Generation
Transmission Pvt. Distribution
Distribution
Mega IPPs
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Regional Load Dispatch Centers (RLDCs) are responsible for managing the central
transmission system, whereas State Load Dispatch Center (SLDCs) manages the intra- state
and some inter-state systems. Central generating stations are contracted to state utilities and
are dispatched by RLDCs. State owned generating stations sell power to their own state
distribution licensee and are dispatched by SLDCs. Distribution licensees can also buy power
from mega power projects, IPP, traders and through the power exchange. The central
government, through public companies, owns and operates one-third of total generation
capacity and interstate transmission lines. At the state level, SEBs own and operate most of
the remaining two-thirds of the generation capacity, as well as the majority of intrastate
transmission and distribution systems.
INDUSTRY SCENARIO
GENERATION
The current installed capacity is approximately 160 GW with coal being the primary fuel
source. Of this the central and state sector accounted for approximately 86.5% [mop, 2010].
The statistics point to high perception of risk and lack of enthusiasm on part of the private
sector with regard to power generation in India. In the central sector, National Thermal Power
Corporation (NTPC) is a player of global scale. The state electricity boards also operate
generation facilities to serve their demand. Private sector comprises of many players like Tata
Power Company, Reliance Energy, GVK, GMR etc.
Exhibit 4: Sector-wise installed generation capacity
Sector MW %age
State sector 79,391.85 52.5
Central sector 50,992.63 34.0
Private sector 29,264.01 13.5
Total 1,59,648.49 100
Thermal power plants accounts for more than 64% of the installed generation capacity with
coal based thermal power plants contributing to more than 53% of the total capacity.
Renewable energy sources other than hydro contribute to around 7.7% of the capacity.
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Exhibit 5: Current Power Scenario (as on 30.04.10) region-wise and according to plant-type
REGION THERMAL
COAL GAS DSL TOTAL
Nuclear HYDRO
(Renewable)
R.E.S.@
(MNRE)
TOTAL
Northern 21275.00 3563.26 12.99 24851.25 1620.00 13310.75 2407.33 42189.33
Western 28395.50 8143.81 17.48 36556.79 1840.00 7447.50 4630.74 50475.03
Southern 17822.50 4392.78 939.32 23154.60 1100.00 11107.03 7938.87 43300.50
Eastern 16895.38 190.00 17.20 17102.58 0.00 3882.12 334.76 21319.46
N.Eastern 60.00 766.00 142.74 968.74 0.00 1116.00 204.16 2288.90
Islands 0.00 0.00 70.02 70.02 0.00 0.00 5.25 75.27
All India 84448.38 17055.85 1199 102703.98 4560.00 36863.40 15521.11 159648.49
Region-wise, Western region amounts for highest installed capacity in the country. Also, it
can be seen that among all the regions, North eastern region has been an altogether different
story and the conditions need to be improved there for all round development of the nation.
Despite significant recent additions, there is a significant stock of aging plants that have poor
performances. The sector also suffers from, fuel shortages, inadequate transmission
evacuation system, regulatory uncertainty and payment security concerns. Concerns about the
sector paved the path for reforms. The target for new capacity additions has created a
platform for billions of dollars of investments across different segment of the generation
sector. This calls for new policy framework and reforms to have a positive and optimistic
approach towards developing the generation facilities. The developers opting to set up a MPP
might pose a challenge in financing the project and have to do so at their own risk. Setting up
a merchant plant would necessarily mean balance sheet financing by the developer, as
financial institutions/lenders as a rule, may not be comfortable with projects that don’t have
long-term PPAs. Indigenous lenders are not yet comfortable carrying the risk of non-recourse
financing on merchant plants.
TRANSMISSION
Transmission of electricity is defined as a bulk transfer of power over a long distance at a
high voltage, generally at 132kV and above. The bulk transmission stands at around 265,000
ckm today. The entire country is divided into five regions viz. Northern, Western, Southern,
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Eastern and North Eastern. The interconnected transmission system within each region is
called regional grid.
Transmission plan in India has always been generation based. It is therefore not going to help
because there are bound to be imbalances. Even today, CTU and STU’s are very conservative
in agreeing to create more than the desired transmission capacity and freely allowing
interconnectivity. Investments in the Transmission sector have been therefore been
inadequate due to the heavy emphasis on generation capacity. In most states, the existing
distribution network has been formed by expanding and interconnecting smaller and
disjointed networks. Consequently, there are several deficiencies in the Transmission system,
such as high losses and low reliability. The major player in this sector is the government
owned Power Grid Corporation of India.
In order to accomplish the planning objective for 2012, it is imperative to create an
investment framework for timely and adequate evacuation infrastructure and transmission
facilities. As per the Working Group for Power constituted by Planning Commission, the
estimated investment of around USD 36 billion is required in XI Plan for completion of
National Grid, its associated transmission system and state level transmission infrastructure.
Out of this, an investment of about USD 14 billion would be required in central sector
transmission systems alone and the balance in state and private sector projects.
DISTRIBUTION
The total installed generating capacity of the country is over 135,000 MW and the total
number of consumers is over 144 million. Apart from an extensive transmission network at
500kV HVDC, 220kV, 132kV and 66kV which has developed to transmit the power from the
generating stations to the grid substations, a vast network of sub-transmission in distribution
system has also come up for the utilization of the power by ultimate consumers.
Out of the three sectors of electricity delivery chain, the distribution sector in India has been
the most daunting sector. More than 80 % of the total energy consumption is distributed by
the public sector while the balance is distributed by the private sector.
Most initiatives in the power sector (IPPs and mega power projects) are nothing but ways of
hiding the inefficiency of distribution sector under the umbrella of more generation. The
Distribution arm of the Power Sector had been the domain of the SEBs for a very long time
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which gave rise to financial problems due to lack of collection of dues. The SEB’s financial
difficulties led to problems in the upstream for power generation. To alleviate this situation
Distribution Companies are being privatized in some states. Reliance Energy and Tata Power
Company were the first private sector players to make a foray into power distribution in the
country.
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CHAPTER 2
MODELLING ELECTRICITY MARKETS
COST OF PRODUCTION
The cost of production of electricity is composed of two components, fixed costs and
variable costs. Fixed costs are not related to production, but to the initial investment,
and it has to be paid regardless of the production; whereas the variable cost is related to
the quantity of production of electricity. Fixed costs can include leases on office space,
insurance premiums, and equipments like electric generator, stack Gas scrubber to
remove sulphur dioxide. These are often referred to as sunk costs and very large in such
capital intensive industries.
The figure below shows the various types of costs, in which capital cost comes under the
fixed cost, whereas operation & maintenance cost and fuel cost do form part of the
variable cost.
FIGURE 1: ELECTRICITY GENERATION COSTS
Power plants have been large and requires infrastructure to acquire fuel and to deliver
to end-user customers. Although such costs are typically fixed in short run, as
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equipment has long life, but in the long run all costs are variable. Electric power plant
life can be considered to be 40 years. The total cost for electricity generation can be
represented by the following equation.
TC = FC + VC (Q)
Where,
TC= Total Cost
FC= Fixed Cost
Q=Quantity of production
VC= Variable Cost
VC (Q) = variable cost as a function of Q
Now, after having the total cost, it is important to look at the average cost and the
marginal cost. The average cost, cost to produce one unit on average, is determined by
dividing the total cost by output.
AC = TC/Q = FC/Q + VC (Q)/Q
DECREASING AVERAGE COSTS
As shown in the above equation, average total cost (TC/Q) equals average fixed cost
(FC/Q) plus average variable cost (VC (Q)/Q). Here, as Q increases, the FC/Q decreases
over the period of time. But as the variable costs are constant, average total cost falls as
Q increases.
FIGURE 2: DECREASING AVERAGE COST
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INCREASING AVERAGE COSTS
Now, if the variable cost takes the form of Q0.5, then the average variable cost also
changes Q0.5/Q = Q-0.5. Here, as the production is scaled up, the efficiency increases, and
average variable cost and average fixed cost fall.
FIGURE 3: INCREASING AVERAGE COST
Some of the reserves can be low-cost and others can be high-cost. To represent this
case, suppose the variable cost is Q1.5. Then
TC = FC + Q1.5
And hence average cost would be,
AC= TC/Q = FC/Q + Q1.5/Q = FC/Q + Q0.5
In this case, average fixed cost falls as Q increases, and average variable cost rises as Q
increase.
POWER MARKET DEVELOPMENT IN INDIA
MONOPOLY IN INDIAN ELECTRICITY MARKET
In the first 100 years of its commercialization, electricity was supplied by vertically
integrated monopolies to consumers. It was generally thought that this was the only way
to do the business of electricity supply for the reasons mentioned below.
1. Natural monopoly aspects of transmission and distribution: A natural monopoly
exists because of combination of market size and industry cost characteristics. It
exists when economies of scale available in the process are so large that the
market can be served at the least cost by a single firm. In case of transmission and
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distribution only one set of wires would run along the public right of way. The
capital cost associated with them is also high thereby exhibiting natural monopoly
characteristics.
2. Challenge of coordination: The technical challenges of coordinating the generation
with transmission and supply led to vertical integration. Transaction costs are
considered to be too high if these activities are separated.
3. Economies of scale: Economies of scale in generation, where bigger capacity plants
produced cheaper electricity, added to the conventional wisdom of running the
business in integrated manner.
4. Perspective planning: For the purpose of long term planning for investment in
generation and transmission vertical integration was thought to be beneficial.
The electricity consumers in India have long been served by vertically integrated State
Electricity Boards (SEBs). Figure below depicts the institutional structure of the power
sector in India before evolution of Independent Power Producers (IPPs) and
independent regulatory commissions.
The Indian Electricity (Supply) Act led to evolution of state owned State Electricity
Boards (SEBs), which were formed in 1960s and soon took over numerous small private
generation and distribution utilities in the respective states. SEBs are integrated utilities
with monopoly over generation, transmission and distribution of power within the
state. Except few urban based private distribution licensees in cities like Mumbai,
Kolkata and Ahmedabad, entire distribution is in the hands of SEBs.
FIGURE 4: INSTITUTIONAL STRUCTURE OF INDIAN POWER SECTOR BEFORE REFORMS
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In late 1970s the central government established National Thermal Power Corporation
(NTPC) for generation of power from large pit head coal thermal generating stations.
Currently, NTPC accounts for around 20% of India's total installed capacity and sells
power to various states utilities (i.e. SEBs). Apart from NTPC, the central government
also established companies such as Bharat Heavy Electricals Limited (BHEL) and Power
Grid Corporation of India (PGCIL) for manufacturing of electrical equipment (turbines,
transformers, boilers, etc.) and for erection and maintenance of interstate transmission
lines respectively. The central government also regulates investments in power sector
through its agencies such as the Central Electricity Authority (CEA), which was created
as per the Indian Electricity (Supply) Act 1948. All generation or distribution scheme
above a particular size requires approval of CEA.1
ECONOMICS OF MONOPOLY
In electricity industry is usually known as the decreasing cost industry, because average
cost decreases over a wide range of values. Figure below shows the demand and cost
curves for electricity.
FIGURE 5: MONOPOLY
The major advantage of monopoly is having the economies of scale. Thus, as production
increases, the average unit cost falls. Here, as the average cost falls, the marginal cost
also must be below average, pulling the average down. Such cost curves implies that the
largest producer of electricity will have the cheapest unit cost and will be able to
1 For example till 1991 any scheme involving capital expenditure above Rs. 250 Million (~ US $ 5 million at current exchange rate) required approval from CEA for technical as well as economical aspects.
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undercut producers with smaller generating units, which leads to evolvement of
monopoly. This is what exactly happened in India as stated above that with the Indian
Electricity (Supply) Act of 1960, SEBs took over numerous small private generation and
distribution utilities in the respective states and eventually SEBs evolved as the
monopoly over generation, transmission and distribution of power within the state.
The monopolist producer enjoys the market demand and picks up the point in the
demand curve, where he has maximum profits. The monopolist’s profits are total
revenues minus total costs:
� � ���� � � � ��� The profit is maximised at the point obtained through the first order derivative: ��� = P + ���� � � � ��
���� � �
Here the Marginal Revenue,
MR =P + ���� � � �
Whereas the Marginal Cost,
��� � ������
Hence, for the monopolist to continue his production, the required condition is
MR = MC
Slope of MR < Slope of MC
Since both the slopes are negative, the above result says that MC curve must be less
steep than MR curve.
Marginal Revenue is equal to,
���� � � � ���
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FIGURE 6: MONOPOLY PRODUCER SURPLUS
It shows that marginal revenue is downward sloping as well as twice as steep as the
demand curve. Suppose, monopolist’s output is Qm, Price is Pm, then profits would be
(Pm-A*Cm)*Qm. Hence this would lead to the producer surplus. Since the people are
willing to pay at that point greater than the marginal cost at Qm, there are social losses
associated with monopoly output.
Society’s welfare can be measured by sum of producer’s surplus and consumer’s
surplus. This sum can be represented by the area below demand and above price plus
the area above marginal cost and below price.
� ����� � � ! � ��� �������� � �� ����� ��� �������
"
"
"
"
This intends to maximize the area between D and MC. This would yield to the ouput,
P(Q) = MC(Q)
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FIGURE 7: SOCIAL OPTIMUM IN A NATURAL MONOPOLY ELECTRICITY MARKET
Hence, it concludes that monopolist should operate where the price equals the marginal
cost or where the demand curve crosses the marginal cost curve. At output less than Qs,
price is above MC so social welfare can be increased by increasing the output. While
producing the output more than Qs, price is below marginal cost and people value the
extra output by less than the cost of the extra output and welfare is diminished.
OLIGOPOLY MARKET
The traditional electricity supply or value chain is altered by restructuring with the
same activities as when it was vertically integrated: transmission, generation,
distribution, and commercialization. However, the new structure has revolved the way
of making business.
INDEPENDENT POWER PRODUCERS (IPPS)
In 1991, in response to severe foreign exchange crisis and lack of capital for expanding
power generation capacity the Central Government opened up power generation for
foreign and Indian private investment. Government offered concessions such as 100%
foreign ownership, long-term purchase agreement, and assured profits (as high as 32%
post tax return on equity every year in the currency of investment). In the initial period
state governments and SEBs were allowed to enter into negotiated contracts with IPPs
without competitive bidding. Initial response to this was enormous. During the three
year period when such non-competitive contracts were allowed, SEBs signed 243
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contracts (MOUs) for the capacity addition of over 90,000 MW (more than the national
installed capacity at that time), amounting to contracts of nearly 90 MW per working
day2.
In their zeal to sign as many IPP contracts as possible states and SEBs virtually gave a go
by to even elementary norms of power planning including proper demand forecasts and
evolution of least cost plans based on comparative costing of different options for sites
and fuels. After 1995 the Central Government enforced competitive bidding route for
acquiring new capacity (i.e. IPPs).
Major reasons for this failure to add capacity was weak financial situation of SEBs and
lack of demand. IPPs found it difficult to achieve financial closure due to lack of
creditworthiness of the sole buyer i.e. SEBs. SEBs were making huge financial losses
mainly due to huge transmission and distribution losses (including theft) and highly
subsidised tariff to agricultural and domestic consumers. Some IPPs could progress
beyond the initial stage due to credit enhancement through guarantees from state and
central governments as well as allocation of escrow facility.
UNBUNDLING, PRIVATISATION AND INDEPENDENT REGULATION
In mid 1990s, many states in India began a process of fundamental restructuring of the
state power sector. This consisted of a three pronged strategy of:
1. Un-bundling the integrated utility in three separate sectors of generation,
transmission and distribution
2. Privatisation of generation and distribution companies
3. Establishment of independent regulatory commissions to regulate these utilities
The reform model adopted by a number of states
resulted in restructuring of some of the SEBs,
leading to separation of generation, transmission
and distribution segments and their corporatisation.
Regulatory reform included setting up of Central
Electricity Regulatory Commissions (CERCs) and
State Electricity Regulatory Commissions (SERCs).
The monopolistic nature of bulk supply as well as
FIGURE 8: MARKET STRUCTURE BEFORE ELECTRICITY ACT 2003
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24 | P a g e School of Petroleum Management, Gandhinagar.
retail supply has been abolished with the enactment of the Electricity Act 2003 (the
Act). This led to deepening of the reform process by dismantling the monopoly in the
power sector. The new Act provides for non-discriminatory open access of the
transmission network, de-licensing of generation including captive power generation.
The Act also recognizes trading as a distinct activity. Such provisions of the Act provide
an enabling environment for development of bulk power market in the country. Phased
open access of the distribution network by respective state utilities provides consumer
choice subject to open access regulations including the cross-subsidy surcharge.
Electricity is in the concurrent list of the constitution i.e. both the central as well as the
state regulators have undertaken regulatory initiatives that followed the Act. The
Central Electricity Regulatory Commission (CERC) has introduced regulations for short-
term and long-term open access, and has defined rules for transmission capacity
allocation and congestion management. It continues to use regional postage stamp
method for transmission pricing. In a well developed bulk power markets such rules
would need to be redesigned.
ECONOMICS OF OLIGOPOLY
Consider the linear market-demand function given by:
P(Q(k)) = a − bQ(k)
where p(Q(k)) is inverse market demand, Q(k) is the total market output, a and b are
constants. Total market output is
Q(k) = PG1 (k) + PG2 (k)
Where PGi (k) is the Generating Companies i’s contribution.
At period k, the profit of the GENCO i is:
πi(k) = (a − b(PG1(k) + PG2(k)) − ci ) PGi (k)
Where ci is the production cost of GENCO i.
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FIGURE 9: OLIGOPOLY MARKET STRUCTURE
The first order condition to maximize profits is:
#$#% � a − ci − 2bPGi (k) – b PG j (k) = 0
GENCO i should set output to maximize profit considering the output decision of
competitor. Under naive expectation, GENCO i believes that GENCO j will not change its
output such as:
PG j (k) = PG j (k − 1)
Therefore at period k GENCO i setups its output as:
PG j (k) = &�'�()*+ - �,�-��.'/�+
The market system can be represented by the following 2nd order system:
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Where pE(k + 1) is the electricity price at period k+1. Under naive expectation, market
system is always stable, even though A has one eigenvalue with real part.
Generation upper limits
In traditional Cournot analysis players choose quantities simultaneously. In addition,
each firm presumes no reaction on the part of the other firms to a change in its output.
Now, considering that GENCO j has a capacity constraint ,-0&%
,1�.� �2 � 3)�45 � ,-0&%
5
Thus, the Genco1’s quantity would be depending on the quantity produced by the
Genco2. In India, we can say there is a regulated oligopoly, as generating companies
have control over the quantity they produce but not on the price, as price is determined
by the government or by the market clearing price of the power exchange where the
electricity trading is done.
COMPETITIVE MARKETS
WHY COMPETITION?
The major difference between regulation and competition emanates from the debate as
to who takes responsibility for various risks. In respect of electricity supply industry the
risks could be any of the following:
§ Cost and time overruns during construction.
§ Fuel supply: availability and price.
§ Technological changes: Obsolescence
§ Management decisions about manpower, investments and maintenance.
§ Market demand and pr-ices.
§ Credit risk.
§ Risk of payment default by off takers.
Under regulated regimes, customers take most of the risks, as also most of rewards with
the regulators doing their prudence checks to verify reasonableness of expenditures
incurred. In the regulated regimes many of the old, inefficient or obsolete plants may
continue to function and recover investments while in the competitive regimes they
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may be out of the market. During regulated regimes, overcapacity causes prices to
increase as consumers do pay for the stranded capacity, whereas, in a competitive
environment, excess capacity causes prices to fall. In nutshell, in a typical cost plus
reasonable profit regulation regime, the incentives to cut cost are non-existent. In a
publicly owned monopoly, the incentives are very different as the investments, their
types, location etc. are often governed by political consideration rather than or sound
economic principles.
Under competition, most of these risks are borne at least initially by owners - they
would be responsible for bad decisions as also for profits from sound decision and
managements practices. Investors also have strong urge to devise methods to hedge
these risks taking advantage of various instruments available in financial markets.
Competition also improves transparency adding significant value to the customers.
EVOLVEMENT OF COMPETITION
The existing market structure for the bulk power market is primarily characterised by
bilateral and multilateral contracts between generation plants owned by central and
state governments, IPPs, surplus captive generation capacity and the distribution
utilities/SEBs. Less than 5 % of the gross energy generated in the country is being
traded either through negotiated trading arrangements or brokered by power traders.
In a sellers market, the trading activity is far from competitive and this led to complaints
of higher margins being charged by some traders. Setting up of an organised platform
for trading electricity contract is under consideration for some time. Figure below
shows the competition evolving in the Indian bulk power market.
In January 2006, Forward Markets
Commission (FMC) has notified electricity to
be included in the list of commodities
permitted for futures trading. A commodity
exchange in the country is envisaging
introduction of exchange tradable contracts.
The process seems to lack a roadmap towards
FIGURE 10: EVOLVING COMPETITION IN THE BULK POWER MARKET
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development of a competitive bulk power market, which is entrusted to appropriate
commission and is guided by the National Electricity Policy. CERC has recently rolled
out a staff paper on the subject and the process of discussion would continue for some
time due to a large number of stakeholders involved and intricacies in designing
competitive markets. Figure below shows how the market reform would take place
with the respective competitiveness of the market.
FIGURE 11: EVOLVING COMPETITION IN THE BULK POWER MARKET
The transition from a single-buyer model to a multi-buyer multi-seller model should
result in a competitive power market so to provide incentives for new investment while
providing affordable and quality power to consumers. A number of steps need to be
undertaken in that respect. These include adoption of a direction sensitive and efficient
transmission pricing regime, adoption of intra-state ABT regime, liberalisation of fuel
markets, unbundling and rationalisation of retail tariffs and competitive procurement of
renewable energy.
CHALLENGES OF MAKING COMPETITION IN ELECTRICITY MARKET
Introducing competition in electricity is based on the premise that the electricity can be
treated as any other commodity. There are, however, important differences between
electric energy and other commodities, which pose serious challenges in making it
amenable to competition. These challenges arise from the following:
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1. Electricity cannot be stored
Electrical energy is linked with a physical system where demand and supply must
be balanced in real time. This is because electricity cannot be economically stored. If
this balance is not maintained, the system collapses with catastrophic
consequences.
2. Demand of electricity varies intra-day and between seasons
Demand for electricity fluctuates widely within the hours of the day as also from
season to season. Since the electricity can not be stored, it has to be generated when
it is needed. Not all generating units will be producing throughout the day. When
demand is low only most efficient plants will get dispatched. Since the marginal
producers change as the load increases or decreases, the prices also vary over the
course of the day. Such rapid cyclical variation in cost and price of a commodity are
unusual.
3. Electricity travels in accordance with laws of Physics
Electricity, not being a commodity in the conventional sense, there is no defined
path for delivery. Energy generated from a generator cannot be directed to a
specific customer. A customer simply gets whatever electricity was flowing in the
wires he is connected to. Power produced by all generators is pooled on its way to
the load. Pooling has beneficial effects of economics of scale. However, the
downside is that any breakdown in a system affects everybody, not just the parties
to a specific transaction.
4. Electricity travels at the speed of light
The consequence of this property is that it requires advance planning and split
second decision-making and control by the load dispatcher to co-ordinate the
generation and consumption. Speed of decision making by market is often much
slower than the speed of electricity. Balancing of supply and demand of electricity is
therefore difficult to be left to the market.
5. Electricity has demand side flaws
Important demand side flaws in electricity are,
a. Lack of elasticity of demand - Electricity being essential for modern life, its
demand responds only minimally to price. Even in a country like India, the
demand is becoming less elastic to price.
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b. Ability of a load to draw power- from the grid without a prior agreement with
supplier. Because of this, it is often impossible to enforce bilateral contracts, as
customers who exceed their contracted demand cannot be disconnected. In such
an event, some other supplier becomes the default supplier. In an organized
power market, the system operator often discharges this responsibility.
ANALYSING FEASIBILITY OF COMPETITION IN MAHARASHTRA
Conventional wisdom suggests that competitive wholesale electricity markets are not
feasible in most developing countries. A case study is done by Mr Amol Phadke, to
model a potential wholesale electricity market in Maharashtra state, India in a Cournot
framework to analyze the circumstances under which it could be competitive.
The effect of certain characteristics of the MH state electricity sector that create unique
opportunities for demand response has been modelled. The certain characteristics of
electricity sectors in some developing countries could in fact increase the feasibility of
wholesale electricity competition. The effect of these characteristics on the
competitiveness of potential wholesale electricity markets is rarely considered by
policymakers and researchers. The following are some of these characteristics in the
context of the Indian power sector:
1. The Availability of Large Quantities of Industrial Back-Up Generation
The Indian power sector has been facing increasing power shortages since 1998
and many industrial consumers have installed back-up generation to cope with
them. The total back-up generation capacity in India is estimated to be at least
21,000 to 21,500 MW which is about 13% to 15% of the total installed
generation capacity in India (Ministry of Power). When the current power
shortages are reduced, this back-up generation capacity will be an additional
capacity available in the system.
Industrial consumers can use this capacity for demand response. If the wholesale
price goes above a certain level, industrial consumers can generate from their
back-up generators rather than buying power from the grid and in effect reduce
their demand. This demand response ability will increase the competitiveness of
a potential wholesale electricity market.
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2. The Ability to Shift Large Quantities of Electricity Demand for Agricultural
Pumping From Peak to Off-peak Periods
In order to deal with the current power shortages, many state utilities in India
are implementing schemes such as feeder separation, which enable them to shift
large quantities of agricultural pumping load from a peak period to off-peak
period. Such load shifting may not be necessary in the long-run when power
shortages are removed or reduced significantly. However, the distribution sector
will continue to have the ability to shift the agricultural pumping load.
This ability creates unique opportunities for demand response. The agricultural
pumping load need not shifted permanently to the off-peak periods to prevent
the exercise of market power. A credible threat of shifting the agricultural
pumping load if market power is exercised will reduce the exercise of market
power.
3. The Feasibility of Interruptible Tariffs
Everyday living in developed countries is far more dependent on electricity than
developing countries. In developed countries, the distribution utilities almost
always have to buy power even if severe market power is exercised because load
curtailment has enormous economic and political costs. The distribution utilities
in developing countries can, however, curtail load under special circumstances
without enormous economic and political costs. Hence they can credibly refuse
to buy power if the price goes above a certain level. This credible threat will
reduce the generators’ ability to exercise market power.
4. Relatively Large Size of the Market
Unlike many developing countries, the Indian power sector is relatively large
with an installed capacity of about 160,000 MW. Individual electricity markets in
India will be smaller due to transmission constraints between various states.
However, even a single state can be large enough to have effective competition.
For example, MH has an installed capacity of about 21,000 MW and can be
considered large enough to have effective competition
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5. The Likely Presence of Public Generation Firms Along With Private Generation
Firms
Certain public generation utilities in India are not likely to be privatized in the
near future and are likely to act as price-taking firms in a potential wholesale
electricity market. Price-taking firms limit the ability of strategic firms to
exercise market power.
6. The Ability to Trade on Commercial Terms
Unlike the state utilities in many other developing countries, state utilities in
India are already trading power with each other in real time on commercial
terms. Hence they can participate in a wholesale market.
7. Learning from the Past Experiences of Power Markets
We now understand power markets better than when some of the developed
countries designed their markets. The importance of demand response, long-
term contracts, and the divestiture of dominant firms in fostering effective
competition is now relatively well understood and appreciated. The improved
understanding of power markets will enable us to design policies that foster
competition.
MODELLING THE MH ELECTRICITY MARKET IN THE COURNOT FRAMEWORK
India has four regional grids connected to the neighbouring regional grids by High
Voltage Direct Transmission (HVDC) lines. However, the inter-regional transmission
capacity is quite limited. Each regional grid connects a few states. The electricity grid in
MH state is a part of the Western Grid, which includes three other large states and one
small union territory. The MH state grid is also connected to the neighbouring state of
Karnataka, which is part of the Southern Grid. Table 2 shows the transmission capacity
between MH and its neighbouring states.
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Figure 12: Transmission Capacity between MH and its Neighbouring States
Each major state in India has been allocated a share of capacity in the central sector
utilities (CSUs). The CSUs include the National Thermal Power Corporation (NTPC), the
Nuclear Power Corporation (NPC), and the National Hydro Power Corporation (NHPC).
These CSUs have power plants spread all across the country with NTPC having the
largest capacity, which is almost 20% of the total installed capacity in the country. The
majority of the MH state’s share in the CSUs is in the plants outside of MH state.
Currently, the power imports by MH state from the neighbouring states are limited to
the MH state’s share in the generation by the CSUs’ plants in the neighbouring states.
It is possible that if the price is high enough in MH state, the utilities in the neighbouring
states will export power to MH State. Currently all the states in the Western Grid are
facing power shortages and it is unlikely that any state in the Western Grid will have
substantially more spare capacity than MH state in the near future. The diurnal and the
seasonal patterns of the electricity demand in all of the states in the Western Grid are
quite similar. Hence possibilities of imports when a peak period in MH state coincides
with an off-peak period in the neighbouring states are rare. If the price is high enough, it
is possible that utilities in neighbouring states could curtail load of their own consumers
and export power to MH state. However, the feasibility of this option depends upon load
curtailment policies of utilities in neighbouring states and the regulations guiding load
curtailment in addition to political considerations.
Generators in the MH Electricity Market
Table below gives the generation capacity installed in MH state and MH state’s share in
the power plants of the CSUs outside of MH state for the financial year 2005-06.
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Figure 13: Generation Capacity for MH State
Source: MSEB Generation Statistics (MSEB, 2005-06)
MH State Electricity Board (MSEB), NTPC, and NPC are public utilities while TATA and
Reliance are private utilities. Enron’s Dabhol power plant is now owned by a joint
venture of NTPC and the Gas Authority of India Ltd. (GAIL). Table also shows that most
(64%) of the generation capacity is coal based.
Estimating Marginal Costs
MERC examines heat rate and fuel cost estimates provided by the utilities in MH state in
a tariff case and approves certain fuel costs and heat rates based on their own estimates.
The heat rate of a power plant is its design parameter and should not change
significantly within a short period of time. Figure 1 shows the marginal cost estimates
for various suppliers in MH state calculated from the forecasted fuel prices and MERC’s
estimates of the heat rates. Transmission and distribution losses (T&D losses) in MH
state are estimated to be 33%. To account for the transmission losses, the marginal cost
of the delivered electricity, MC = marginal cost at the bus-bar15/(1-TL) where TL is the
transmission loss as a fraction of total generation.
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Figure 14: Marginal Cost of the Suppliers in MH State
The Cournot framework is used to simulate competition in a potential wholesale
electricity market in MH state. The Cournot equilibrium is found interactively using a
grid search method. First, the supply curve of price-taking firms is determined as
follows: price-taking firms generate every unit of output possible as long as their
marginal cost of generation is less than or equal to the market price. Hence the data on
marginal costs of price-taking firms allows obtaining relationships between the supply
from price-taking firms and the market price which are supply curves of price-taking
firms.
A residual demand curve is obtained by subtracting the supply curves of price-taking
firms from the market demand curve. Each Cournot firm is facing a demand curve that is
equal to the residual demand curve minus the supply from all the other Cournot firms,
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Where Di(P) is the demand curve faced by a Cournot firm i, Dr (P) is the residual
demand curve obtained in equation (1), and Σ j q is the sum of the supply of all the other
Cournot firms.
Profit maximizing output for a Cournot firm is determined by considering the residual
demand curve and the marginal cost curve of the Cournot firm, taking the output of the
other Cournot firms as given. The process of finding the Cournot equilibrium starts by
assuming that all the Cournot players have no output and the first Cournot player sets
its output given that the other Cournot players have no output. The second Cournot
player sets its output given the supply of the first Cournot player determined in the
previous iteration. This process is repeated for all the Cournot firms until no firm can
profit from changing its output given the output of the other firms. This state is the
Cournot equilibrium where each firm is producing its profit-maximizing output.
Because the supply curves of price-taking firms have flat regions (since I assume that
power plants have a constant marginal costs up to their capacity), the residual demand
curve also has some flat regions which occasionally cause multiple equilibria. In such
cases, one of the equilibria results in more total profits for firms compared to all the
other equilibria. All the other equilibria and represents a worst case scenario of market
power.
Figure 15: Policies and Market Competitiveness
Table above summarizes the effect of these policies when they are implemented at
levels that are easily attainable. The MH electricity market is competitive when all the
three policies are implemented simultaneously at levels easily attainable.
Thus, the MH electricity market is competitive in a situation of small supply shortages;
however, it is not competitive when the supply shortages are severe. An increase in
private (Cournot) ownership of the generation capacity in the MH electricity market
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compared to the base case reduces its competitiveness and the market exhibits a high
degree of market power when all the capacity is owned by private (Cournot) players.
ECONOMICS OF LOAD DIVISION
Peak load describes a period in which electrical power is expected to be provided for a
sustained period at a significantly higher than average supply level. Peak demand
fluctuations may occur on daily, monthly, seasonal and yearly cycles. For an electric
utility company, the actual point of peak demand is a single half hour or hourly period
which represents the highest point of customer consumption of electricity. Peak
demand is considered to be the opposite of off-peak hours when power demand is
usually low.
FIGURE 16: ECONOMICS OF LOAD DIVISION
There are three kinds of equipment that can produce electricity.
• Gas-based, with a low capital cost (F1), but a high variable cost (v1)
• Coal, with a capital cost (F2) that is higher than gas, but a variable cost (v2) that
is lower
• Nuclear with the highest capital cost (F3), but the lowest variable cost (v3)
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This arrangement can be seen in the top diagram of Figure (a). Once again the cost
relationships are linear and of the type C = F + V * t, with the applicable part of these
curves being the solid lines that form the aggregate cost curve. Forecast for the peak
load are traditionally deduced from forecasts of electricity demand, using the peak load
factor approach. The peal load factor of an electrical system is defined as the ratios of
the average electrical load in a year to the peak load anticipated in the same period.
�6789�:;8<�=8>?;@ � AB7@8C7�ADDE8F�:;8<6789�:;8< � � ADDE8F�GF7>?@H>H?I�J7K8D<
6789�:;8< � LMN��O;E@P�HD�8�I78@
Thus, peak load is estimated by solving above equation, using the forecasts for the
annual electricity demand as the input. Peak load pricing means charging different
prices for electricity depending on the load factor. Since it is expensive to store
electricity, capacity is usually made large enough to satisfy the peak demand. This
means, however, that during much of the time some capital is sitting idle. If a utility can
move some of the peak demand to off-peak, it can decrease the amount of total capital
needed and use existing capital more intensely, reducing the costs. A typical load
duration curve is as shown in the figure.
While the peak load dictated the magnitude of the installed capacity, it does not provide
any information on the use of electricity, i.e. how many hours of a given period loads
will have a certain value. This information is essential for identifying the power
generation technology mix and the operation of the installed capacity. The load duration
curve is a graphic representation of the distribution of loads in the electrical system,
which is the rearrangement of loads within a time period from the highest to the lowest
load. The figure below shows the annual load duration and daily load duration curve.
FIGURE 17: DAILY LOAD DURATION CURVE
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FIGURE 18: ANNUAL LOAD DURATION CURVE
THE SCREENING CURVE METHOD
An accurate estimate of the composition of the power plant fleet that is needed to meet
an anticipated peak load and a load profile is made using sophisticated but complex
probabilistic simulation methods that aim to minimise the expected electricity
production costs. This method estimates the capacity factors, where capacity factor is
defined as the ratio of electricity generated by a power plant in a year to the maximum
amount of electricity that the plant would generate if it operated at full capacity during
the same period.
FIGURE 19: ANNUAL COSTS PER KW OF INSTALLED CAPACITY FOR THREE TYPES OF POWER
PANT
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FIGURE 20: IMPLEMENTATION OF SCREENING CURVE METHOD
The screening curve method is used to estimate the technology mix. It combines the cost
curves and projections of load duration curves to provide rough estimates for the
electricity generation technology mix. Here, first of all, the cost curves of all candidate
power plant technologies are constructed as shown in the figure. Three types of power
plant are considered as discussed earlier.
Although, screening curve method has the following limitations when compared to
other sophisticated production cost analysis.
Ø It assumes an ideal, monopolistic electricity market, implying a structure with a
single entity with exclusive control of electricity supply and hence planning and
price.
Ø It does not consider any transmission or distribution constraints.
Ø It cannot account for scheduled or forced outages.
Ø It doesn’t consider the size of power plant units. It is unlikely that the capacity
estimated for a specific type of power plant will be an integer multiple of
available unit sizes.
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Ø Screening curve method indicates the capacity mix needed to meet demand but
does not directly indentify the technology mix required to fill a capacity gap
existing at any given time.
Ø It is not designed to include non-conventional electricity generation options with
distinctive patterns of availability, like pumped storage or wind power.
Ø It has difficulties in treating dynamic factors such as load changes, short term
solutions for the technology mix etc. These issues can only be addresses by
advanced simulation techniques.
Despite these deficiencies, the screening curve method is a very useful tool and is
widely used as the first step in every capacity planning study. It is quick, uncomplicated
and allows users to determine the composition of an electricity generation technology
portfolio with decent accuracy.
OPTIMAL PLANT MIX
There is always the utilization of mix of electricity generating techniques, which mainly
depends on the electricity demand curve. This is concept is very crucial particularly to
electricity market, as demand typically varies during a day as shown in the figure below.
Not only the demand curve is responsible for the “optimal plant mix” concept to be very
crucial, but also the different cost characteristics of various types of generating
equipments. The fixed cost and variable cost of these electricity generating plants
depending on their fuel type is as shown in the table below.
FIGURE 21: OPTIMAL PLANT MIX
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Hence according to load type, capital cost (fixed cost) and operating cost (variable cost),
the power plant group can be classified following.
Power Plant Group Capital cost (fixed cost) Operating cost
(variable cost)
Base Load High Low
Intermediate Load Medium Medium
Peak Load Low High
The various types of plants have approximate following capital cost and operating cost.
Power Plant Type Capital Cost Operating Cost
Nuclear Plant Very High Very Low
Hydro Plant High Low
Coal Moderate Moderate
Natural Gas Low High
Oil Low Very High
ECONOMICS OF MULTI PLANT FIRM
Suppose a generator can produce output at more than one plant. If there are h plants at
which the firm can produce with cj being the constant unit cost of production in plant j
and Kj its plant capacity, then the firm would wish to adopt the least cost method of
producing any level of output in order to maximize profits.
Suppose, c represents the cost, then,
c1 < c2 <…< ch
Let Q > 0 be the total output that the firm wants to produce. Let,
Q (1) = min {Q, K1}.
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Having obtained Q(1),..,Q(j), if Q – [Q(1) + …+Q(j)] > 0, then let
Q (j+1) = min {Q – [Q(1) + …+Q(j)], Kj+1}; otherwise let Q(j+1) = 0.
FIGURE 22: ECONOMICS OF MULTI PLANT FIRM
The least cost method of producing Q is to produce Q(j) in plant j.
Why?
Towards a contradiction suppose Q(j) < Kj and Q(j+1) >0. Let,
q = min {Kj – Q(j), Q(j+1)}.
By Removing ‘q’ units of production from plant j+1 to plant j,cost of production reduces
by q(cj+1 – cj) > 0. Thus, if the firm were to produce efficiently, it would not leave
capacity idle in a plant with a lower unit cost of production than in another plant where
it was also producing.
Suppose the profit maximizing output Q = Q1 +…+ Qh were such that 0 < Qh < Kh, with the
output being produced efficiently.
Then,
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Revenue = aQ – bQ2
= a(Q1 +…+Qh) – b(Q1 +…+Qh)2
Cost = c1Q1+…+chQh
Since 0 < Qh < Kh, profit maximization entails the following after differentiating with
respect to Qh,
MR = a – 2bQ = ch
Thus, here Qh can be varied (increase or decrease) to have the optimum quantity and
maximum profit.
Hence, depending upon the load, the generating plant is chosen as shown in the figure
below.
Chapter 3
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CHAPTER 3
NEGATIVE EXTERNALITIES AND POWER MARKETS:
EXTERNALITIES IN ELECTRICITY:
An externality arises when the utility of an economic agent is affected by the action of
another agent, and there is no control over such actions because the variables involved have
no market value. External effects are not appropriately priced and allocated by the market.
Efforts to quantify externalities, resulting from energy use, are not only widely debated, but
when performed, they often significantly exceed fiscal subsidy levels.
The energy systems affect various ecosystems such as
• Climate regulation
• Nutrient cycling
• Water distribution
• Soil Dynamics
• Natural population dynamics etc
These pressures that are put on the natural systems may lead to their complete destruction,
and because these life-support systems are fundamental for the operation of the economy, it is
fair to claim that they have an infinite monetary value. A partial monetary valuation of the
world’s ecosystem services estimated the value of the aggregated world’s ecosystem services
to be in the range of $18 to $59 trillion (2001 figures). The recent figures can be estimated by
adding an average of $36 trillion per year.
For most time since historical ages the electricity utility sectors has focused on making
electricity abundant and cheap with the assistance of regulators and politicians, who subsidize
all forms of energy to shield consumers from the true costs of extraction, generation,
distribution, and use. The immense environmental and social costs inherent with the existing
system, therefore, have also become less and less noticeable. Many electricity generation
companies use centralized fossil fuel, nuclear plants and the reason behind this rationale is
that they can pass on the costs from these polluting power systems directly onto consumers
and society at large. There exists a non alignment between the electricity prices and the cost
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incurred to produce the electricity. The prices are well below the cost incurred by the
electricity generation which is the reason why public reject renewable and continue to rely on
less efficient and more damaging generators that guarantee them future profits. At issue is
whether we want an electricity market that allows the industry to continue to place billions of
burdens on society without having to pay for it, or a more just and equitable system that seeks
to adequately price electricity and properly value all generators, for better or for worse.
FOSSIL FUEL ENVIRONMENTAL EXTERNALITY:
The shortcoming in measuring the externalities associated with the use of energy has been a
driver of efforts to develop a new set of analytic tools. The applications of both
epidemiological tools and methods from risk assessment have been applied to the analysis of
the costs of energy services. To quantify the impact of pollutants associated with fossil-fuel
combustion, it is necessary to model the dispersion of pollutants, their transformation in the
atmosphere, and the production of different compounds that affect human health and the
environment. Finally, population exposure to air pollution causes morbidity and mortality,
which are converted to economic values. The regional context is fundamental in this part of
the analysis, which draws on air pollution modelling, atmospheric chemistry, demographics,
epidemiology, and statistics in a complex analytical chain.
An analysis was made at the Illinois plant which reveals that it averages to 50 annual deaths
per year due to the operation in the power plant. If a “value of a statistical life,” which
represents the value of reducing a collection of individual risks is put upon the annual cost
due to the operation of those power plants would amount a huge sum of money. Efforts to
place the human and ecological impacts of electricity generation in economic terms are
clearly still evolving, but an important emerging finding is that the externalities are frequently
significantly larger than the prices we associate with electricity supply options today. the
following figure shows the market prices of electricity from a range of supply options capture
as little as one fifth of what an ecological or epidemiological evaluation of the costs of energy
supply would dictate.
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Source: Energy and Resources Group and the Goldman School of Public Policy, University
of California,
The commingling of pollutants has been a challenge to providing improved calculations of
the full costs of electricity generation. In urban areas, in particular, it is difficult to
differentiate between pollution coming from power plants and pollution coming from
nonpoint sources, such as vehicles.
The other costs that are involved and confused to be joint with the list of electricity
externality would be from various disorders such as
• Auto Emissions
• Total suspended particles
• Impaired visibility
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GETTING THE PRICE:
Imagine a situation where the regulators started to include all quantifiable externalities in the
price. This appears imperfect. But the accurate picture of real costs of electricity can be
figured out with the help of three concepts together
• Marginal costs
• Levelized costs
• Complete pricing
Marginal costs: this concept separates the past and present which we cannot influence, from
the future, whose shape we can determine. The marginal cost in this case would be the cost of
the generator which is the cost of the next power plant to be planned and built in the future.
Marginal costs tend to be much higher than historic or current costs because the cheap and
easy things have already been done. Confusion is often caused, sometimes deliberately, by
comparing the historic or current cost of one alternative with the marginal cost of another. To
be fair and consistent, marginal costs must be compared equally among all technologies.
Full life cycle or Levelized cost: the costs involved in these are
• Initial capital cost
• Future fuel cost
• Future operation cost
• Future maintenance cost
• Decommissioning cost
To get the full life cycle cost the above mentioned costs are averaged over the lifetime of
the equipment and the expected electricity it will generate. In short, the levelized cost of
electricity (LCOE) refers to the cost over the life of a generator divided by the numbers of
kWh it will produce. Using data from the International Energy Agency, Cornell University,
California Energy Commission, National Renewable Energy Laboratory, and the Virginia
Center for Coal and Energy Research (and looking at marginal costs), the LCOE for
conventional and renewable generators is presented below.
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Source: International conference on Energy and Environment- 2009
The above table identifies the most competitive technologies in today’s prices and rates are
the renewable power sources such as
• Off shore wind Power
• Hydroelectric Power
• Land Fill Gas
Estimation of this levelized cost acts as a starting point for calculating the costs of electricity
generation, it still fails to price a host externalities associated with electricity generation. But
two economists Thomas Sundqvist and Patrik Soderholm analyzed 132 estimates for
individual generators to determine the extent that positive and negative externalities were not
reflected in electricity prices. They found that these costs, when averaged across studies,
represented an additional 0.29 to 14.87 ¢/kWh. Their values which are arrived at when
extrapolated to 2007 gives the following table which shows full social cost of Power.
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Source: International conference on Energy and Environment- 2009
This table shows that the seven technologies with the lowest full social costs are energy
efficiency,
Ø Off shore wind
Ø On shore wind
Ø Geo thermal
Ø Hydroelectric
Ø Biomass
Ø Solar
Ø Thermal
When all of its costs are included, scrubbed coal is ten times more expensive than energy
efficiency; advanced nuclear five times more expensive than offshore wind; and hydroelectric
and geothermal half as much as the most advanced natural gas turbine.
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For example: In US,
Extra cost associated with scrubbed coal= 19.14 ¢/kWh
Generation for one year = 1,191 billion kWh
On multiplying the above both we get a boggling amount of $228 billion. In other words, coal
generation created $228 billion of additional costs that neither coal producers nor consumers
had to pay for, costs that were instead shifted to society at large.
For the cheapest oil and gas generators, the number is $105 billion (12 ¢/kWh and about 877
billion kWh). For nuclear, it is $87 billion (11.1 ¢/kWh and about 787 billion kWh). Adding
the three together, one gets $420 billion—$143 billion more than the $277 billion in revenues
the electricity industry.
If looked at globally, these numbers amount to roughly 13.46 ¢/kWh for every unit of
electricity generated worldwide, or $2.55 trillion in external damages every year.
The three key learning out of the above information are as follows:
Ø By combining LCOE and full cost pricing and looking at marginal costs of
generation, the estimates above are a much more accurate assessment offuel costs
than estimates relying on each in isolation.
Ø The LCOE above already factor in the intermittent nature of some renewable
resources such as wind and solar, assigning wind a capacity factor of 35 percent and
solar PV a capacity factor of 17 percent.
Ø The tables given above are conservative for certain reasons, because they did not
include any values for CO2 and climate change. They explained that for many studies
the range of damages was so large (from 1.4 ¢/kWh to 700 ¢/kWh) that it was
excluded.
In some cases the studies analyzed relied on a “willingness-to-pay” metric to assess damages,
but many things (such as clear skies and absolute silence) are impossible to quantify in
dollars. Most of the studies surveyed modeled damages associated with a single power plant,
not the combined or cumulative damages from a fleet of power plants or an entire utility
system. Many studies assumed reference, rather than representative, technologies. That is,
they assumed benchmark and state-of the art technologies instead of those used by utilities in
the real world where many power plants are more than 50 years old.
In one recent study, traditional coal boiler generation technology appeared to produce
relatively cheap power—under 5 ¢/kWh over the life of the equipment, which included
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capital, operating and maintenance, and fuel costs—while wind-turbine generators and
biomass plants produced power that cost 7.4 cents per kWh and 8.9 ¢/kWh respectively (and
tended to require larger amounts of land). But when analysts factored in a host of external
costs, coal boiler technology costs rose to almost 17 ¢/kWh, while wind turbines and biomass
plants yielded power costing about 10 ¢/kWh.
Researchers from the Alliance to Save Energy found that if damages in the form of noxious
emissions and impacts on human health resulting from combustion of coal, oil, and natural
gas were included in electricity prices, then it will lead to following
Ø Coal would cost 261.8 percent more
Ø Oil – 13.4%
Ø Natural Gas – 0.5%
Further if the price would include risks from green house gas from emission and climate
change then the rise would be
Ø Coal 30-70% more
Ø Oil – 9-8%
Ø Natural Gas – 6-12%
The researchers also found that if electricity was priced this way, fossil fuel use would
decrease 37.7 percent compared to projections; CO2 emissions would decrease 44.1 percent,
and GDP would improve 7.7 percent and household wealth jump 5.5 percent as a result of
improved health. Further if the cost of mortality and asthma are internalised and assumed the
value of a life was $5 million which is cheap in conservative manner, then the average
operational costs would increase around 8 times.
FULL COST OF POWER PLANTS:
LIFE CYCLE ASSESSMENT/ LIFE CYCLE COSTING:
An environmental cost accounting approach that adds environmental cost information into
existing energy cost accounting method would calculate the externality cost of electricity.
However, the comparison of externalities associated with different power sources demands
the assessment of emissions over the whole life cycle of the facilities. Full-cost accounting
would then involve the addition of direct and indirect environmental costs into energy
costing. Life-cycle assessment (LCA) has become increasingly popular as a standardized
platform to compare the costs of a given technology over its lifetime. In fact, LCA of energy
technologies grew out of earlier ideas of net energy analysis, a term coined after the first oil
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crisis to designate the assessment of the energy input-output ratio of energy supply and
conservation technologies.
A modern LCA captures energy input and emissions during the entire production and supply
chain associated with power systems, including
• Resource extraction
• Manufacturing for construction
• Operation
• Manufacturing
• Transportation
• Installation of Power Plant equipment
• Retrofits and upgrades of equipments
• Waste management
• Decommissioning
An LCA captures emissions beyond those generated during electricity production, such as those associated with
the construction of the power plant. this is shown from the figure following.
Life Cycle Phases of a Power Plant:
Source: Energy and Resources Group and the Goldman School of Public Policy, University
of California
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There are two types of LCAs. They are
• Process based LCA
• Economic Input Output analysis based LCA
These both may be used to estimate emissions from the supply chain. They both differ in
boundary setting approaches. The boundary of the process-based method is flexible and is
typically selected at the discretion of the analyst, whereas the boundary of input-output based
LCAs is determined by
the economic system that yields the data.
The framework divides each product or service into individual process flows and strives to
quantify their upstream environmental effects. The assessment has the following four major
components
Ø Goal and scope phase, definition of the objective of the analysis and the criteria that
best represent the performance of the assessed alternatives to accomplish the objective
defined.
Ø Inventory phase, identification of the major material and energy inputs associated
with the production of each component in the supply chain, and quantification of the
stressors of interest (e.g., energy, pollution, toxic releases, water consumption, and
waste generation)
Ø Impact assessment phase, quantification and aggregation of effects arising from the
use of each component to yield life-cycle impacts of the object assessed.
Ø Final phase, interpretation of results by means of comparisons, rankings, sensitivity
analyses, and simulations.
The EIO LCA utilizes economic transactions to identify the interdependencies between all
sectors in economy. The method is more inclusive, and the boundary of the assessment is the
national economy. Various commodities, such as steel, coal, and sugar, are represented by
characteristic sectors. The association of the total economic output of each sector with a set of
environmental indicators, such as energy consumption, water use, and pollution, produced by
the respective sectors, yields environmental intensity factors that may be used in
environmental analyses. In most classical economic analyses, the ratio of subsidies per
energy output of different energy technologies is based on the energy output during the
operation of the systems. In contrast, an LCA tracks all energy inputs over the life cycle of a
power plant and includes its decommissioning and waste management. For example, in an
LCA analysis of the cost of electricity from a photovoltaic system, the true cost reflects not
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only the bus bar cost, but also the cost of the materials and the manufacture of the panel, as
well as any costs associated with the disposal of the panel at end of its operational life. In the
same vein, subsidies of nuclear energy are higher if energy consumed to manage and store
used fuel is taken into account. On the environmental side, LCA can be useful because
different electricity generation technologies may produce a variety of impacts during
different phases of their life cycle. Indeed, different life-cycle stages are dominant in the
impacts of different electricity generation technologies. The challenge is how to translate
emissions that vary over spatial and temporal dimensions into meaningful monetary figures.
Full-cost accounting attempts to translate impacts that arise from the entire life cycle of a
process or product into economic values. In the case of electricity production, the cost
accounting consists of an LCA and evaluation of the resulting damage caused by pollutants
and toxic releases. Next, the damages are are further aggregated, and the ratio between the
total damage, which is expressed in monetary units, and the total electricity produced by the
power plant renders the full environmental cost of the electricity.
ENVIRONMENT COST MODEL:
The internalized environmental cost of power plant has included abatement cost which
invested on environmental protection facilities and damage cost which is turned in as
pollutant charge.
Cs = Ce +Cp = Ce + Ct + Cr
=∑[ti.(ui-ri)/αi+fi(ri)]
Cs- environmental cost of Power plant pollution
Ce- external environment cost of Power plant pollutant emission
Cp- Internal environment cost of Power plant pollutant emission
Ct- Pollutant charge that power plant turns in
Cr- Cost of power plant that invested on emission Reduction
ti- The pollutant charge standard of the ith pollutant of the power plant local area
ui- Pollutant emission amount of the ith pollutant corresponding to the unit generated
electricity before the protection control launched
ri- Pollutant reduction corresponding to the unit generated electricity of the ith pollutant
fi(ri ) --The cost control function of the ith pollutant
αi--The compensation factor corresponds to the local pollutant charge standard of the ith
pollutant.
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EMISSION TRADING – ECONOMIC MODEL:
Emission trading is a kind of environment control system. The essential aspect of emission
trading is to improve the optimization of environmental capacity resources that means using
marketing method to control emission and protect environment.
In 1968, emission trading was firstly elaborated by American economist J. H. Dales and also
firstly used to reduce the air and river pollution by U.S. Environmental Protection Agency. In
the following years, German, Australia, and Britain held such practice in succession.
Allocation of initial emission permits is the key element of emission trading. Scientific and
reasonable allocation will decide the marketing capacity of emission trading and also will
make an active market.
The essence of initial allocation of emission permits is to optimize environment as a special
goods. There are two kinds of allocation for initial allocation. One is paid allocation, the other
is free allocation. For paid allocation, the practical method is auction or public sale with
quoting prices. For free allocation, government is entitled to allocate the emission permits. In
the initial development of emission trading, free allocation is the dominating method to
allocate emission permits. This is suitable for countries where emission trading is in young
stage.
INITIAL EMISSION PERMITS ALLOCATION:
Fairness and optimum economy efficiency is the two primary principles in initial emission
permits allocation. Fairness of allocation: During the initial allocation of emission permits,
regulator must take fairness into consideration. Every pollutant power plant has the equal
right of emission permit. This equal allocation can stir power plant's enthusiasm to invest on
clean production and environmental protection. Under this equal allocation situation,
regulator should also take the different levels of development, production technology,
pollution control and the level of future development plans and other factors into
consideration. The goal is neither to protect the backward power plant nor limit the
development of backward power plant.
Economy efficiency of allocation: During the initial allocation of emission permits, regulator
should also consider optimum economy efficiency which is also called optimum profits. To
produce the best possible profits with certain pollutants is the purpose of optimum efficiency.
Thus, in a limited environmental capacity and the equal pollutant amount situation, cost-
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effective power plant that can make full use of environmental resources should be given more
emission permits.
ALLOCATION MODEL OF INITIAL EMISSION PERMITS:
ALLOCATION MODEL WITH FAIRNESS:
In order to control atmospheric pollution and maintain a sustained development power
industry, US government adopted GPS (Generation Performance Standard) to reinforce the
control of pollutants. GPS is a relatively fair and scientific allocation method for controlling
the emission quota.
The meaning of generation performance is the emission amount that power plant emits with
the production of unit kWh electrical energy. And GPS is the allowed pollutant amount
standard based on the regional total pollutant control objective and electricity demand.
Generation performance is a comprehensive reflection of production to the process of energy
efficiency and emissions of pollutants as an important indicator. This indicator considers
power plant's production technology, efficiency, fuel quality, pollution control condition and
total emission. Simple in form and easy to operate is the merits of generation performance.
When using this indicator, all the power plant could share the fair management environment.
Mathematical model of EPS allocation is such:
ei = Sf X gi
ei- The emission permits that allocated to the ith power plant
Sf- Generation performance standard of end-of-term control objective
gi- Electricity generation of the ith power plant every time when a regulator calculates the
GPS they must take into account the current GPS and then the future desired value for
calculation.
ALLOCATION MODEL WITH ECONOMIC EFFICIENCY:
The target that regulator wants to realize the initial allocation of emission permits with
economy efficiency is to maximize the overall social wealth in the controlled area Allocation
model with optimum economy efficiency is such
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Wi(ei)- The social wealth of the ith power plant using emission permits ei which reflects the
contribution of the ith power plant to the wealth accumulation in the controlled area.
Combining the fairness model and economic efficiency model a new optimization model is
evolved which is
ei- The emission permits that allocated to the ith power plant
eavei- The contrast level of the fairness allocation of emission permits of the ith power plant
based on model.
Thus by using the above three methods there held a research on three power plants in China,
where the environment external cost is measured by all the three formulae. The results
arrived are
Source: research of environmental externalities control of Power plants – IEEE-2008
From the above data it is concluded that the synthesized allocation model is an equalising
outcome of fairness allocation model and economy efficiency allocation model.
Deal with electricity externality properly has become an important strategy for environment
protection and sustainable economy development all over the world. With the development of
market economy, processing method of internalization of environmental cost should also be
market oriented. Emission trading is a market-oriented system to control pollutant emission.
Now days, people pay great attention to emission trading system.
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CHAPTER 4
ADDRESSING THE DEMAND-SUPPLY GAP IN INDIA’S
ELECTRICITY MARKET
Despite these power sector reforms, India is still experiencing a severe gap between
demand and supply. Recent supply additions have not kept pace with the strong
economic development of India. Table 1 and Table 2 show the supply-demand gap for
electricity in different regions in India. It can be seen that the energy shortage and
peaking shortage in whole India is about 11.1% and 11.9% respectively.
TABLE 1: POWER SUPPLY POSITION (ENERGY) 2007-08 TABLE 2: POWER SUPPLY POSITION (PEAK) 2007-08
There are two main causes of this problem, namely slow addition in generation capacity
and inability to control distribution losses. These two causes are interrelated with one
another. India has a five year planning process in which policymakers set targets to be
achieved in these five years. The power sector is also the subject of a five year planning
process on capacity addition. However, the sector has always under-achieved its target.
The total goal for the 10th planning period was to add about 41.1GW of generation.
However, only 14GW was achieved, which is a significant mismatch between target and
achievement Table 3 refers to the 10th planning period (2002/2003 – 2006/2007). The
underachievement of targets continues in the 11th planning period (which runs from
2007 to 2012). The 11th plan contains a target of target of 78.7 GW to be achieved in
these five years. Recent data on generation addition in the first year of the 11th plan
(2007/2008) shows a similar trend as Table 4. The increases in generation capacity are
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missing the target by about 50% in the first year. This trend is likely to continue in the
Eleventh planning period. TABLE 3: UNDERACHIEVEMENT IN POWER SUPPLY TABLE 4: POWER SUPPLY POSITION IN 2007-08
Another important cause of the supply-demand gap is the mismatch between the
average cost of supply and the realization of this cost. Cross subsidization between
different groups of consumers is common in India. The industrial consumers pay
significantly higher than the residential consumers while the farmers pay very small
amount and in some cases it is even free to agriculture based consumers.
Table 5 shows the trend of average cost of power supply and realization. This has
reduced the revenues of state electricity boards making them financially insolvent.
TABLE 5: GAP BETWEEN COST OF SUPPLY AND COST RECOVERY
Investment in an industry depends on the long-run financial prospects. In the case of
electricity, the value chain has a cash flow leak, as a result of which, investors find it
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risky to invest in the sector. With significant losses in the distribution sector and
subsidized tariffs to domestic and agriculture consumers, the long-run financial viability
of the industry continues to be strained. Hence, as long as there is leakage of energy in
transmission and distribution, the recoverable cost would be always less than the cost
of supplying electricity, resulting in a disincentive to invest in generation. Thus the
growth of the supply side and the management of the demand side are linked.
POSSIBLE SOLUTION
Solutions to address supply-demand gap need to address both the supply and the
demand sides. India is a growing economy; hence there is no alternative to adding new
capacity, however adding generation capacity alone in the current system would be like
adding water to a bucket with a hole in the bottom. We categorized some possible
solutions for the supply as well as the demand side, based on their short and long-term
feasibility as shown in Table 6.
TABLE 6: SHORT AND LONG TERM POLICY OPTIONS ON DEMAND AND SUPPLY SIDE
A. OPTIONS FOR THE SUPPLY SIDE
Supply augmentation in the national grid is the primary solution for the supply-demand
gap. The current economic growth of India is around 8% per annum. The electricity
consumption growth and economic growth are positively correlated. With this rate of
economic growth, meeting the demand by addressing the problems on the demand side
alone will not be sufficient. Hence, incentives to bring new generation capacity to grid
are necessary. In the case of India, it is not just new generation that needs to be
connected to the grid but there is also an opportunity to bring a significant portion of
existing captive generation to the grid. Currently, captive generation connected to the
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grid is about 20GW. Improving generation efficiency is another supply-side solution to
address the supply-demand gap. A recent CEA report of 2007-2008 shows about 25% of
shortfall of energy generation is contributed to lack of performance of thermal
generation. The plant load factor (Plus) of these generators were well below their
expected value. In early 1990s the PLF of thermal plants in India was at around 53%;
this has been improving since then and the average PLF has risen up to 78% in 2007.
The private generation plants and Central generation plants have high PLFs around
90% and 86%.respectively; however, the average of State generation plants is only
about 70%.
B. OPTIONS FOR SOLUTION ON THE DEMAND SIDE
As the Government of India states: energy saved is energy generated. Reducing AT&C
losses should be a primary focus because reducing line losses consequently results in
improving the financial viability of distribution companies and the industry in general.
More investment is needed in the distribution sector to improve its technical
performance. At the same time, there is a need for administrative measures to control
the theft of electricity. These are long-term solutions which will take number of years to
bring the performance to acceptable level. Besides these long term solutions, specific
tariff mechanisms may contribute to reducing the supply-demand gap. Seasonal pricing
is one such possible tariff mechanism that could be implemented in India. Electricity
production and consumption in India vary with the seasons. Consumption increases
during summer seasons and production of hydro plant increases during monsoon rains.
Figure 1 and Figure 2 are examples of such seasonal variation taken from the
consumption data of Karnataka for the year 2009-10. Seasonal pricing could help States
that depend on hydropower to use the water in the reservoirs more efficiently and thus
avoid long hours of load shedding. As this mechanism does not require addition of new
infrastructure, it is relatively easy to implement. Similar to seasonal pricing, peak
pricing is another tariff mechanism to efficiently reduce the supply-demand gap during
peak hours. However, unlike seasonal pricing, peak pricing requires special energy
meters, which, considering the number of consumers, would require significant capital
investment.
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FIGURE 23: ANTICIPATED PEAK DEMAND VS. AVAILABLE CAPACITY IN KARNATAKA 2009-2010
Another interesting mechanism on the demand side is a quota system with penalization
and bonus incentives to encourage energy saving during critical supply scarcity. This
method has been successful in Brazil in avoiding blackouts, thus decreasing the impact
on the national economic. After introduction of wholesale competition, no entity took
the responsibility of long term planning and policy guidance. Earlier, this was taken care
of by Eletrobras, the state owned utility; in a restructured system Electrobras was being
broken up which led to weakening of its long term strategic functions. Brazil
experienced a major power crisis in 2001/2002, when the water level in the
hydropower dams was extremely low due to a series of dry years. Brazil’s power
authorities introduced a rationing scheme to reduce consumption during these months.
Although electricity demand is considered to be inelastic in nature, with this mechanism
in place, at the end of the year the aggregate consumption declined by almost 20% and
blackouts and brownouts could be avoided. Electricity savings in Brazil's southeast,
central-west and northeast regions were higher than anticipated. In December, 2001
they were 9.9% more than the federal government's target in the southeast and central-
west, 8.1% in the northeast and 8.2% in the north.
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FIGURE 24: ANTICIPATED ENERGY REQUIREMENT VS. AVAILABLE ENERGY IN KARNATAKA 2009-2010
This measure could be used in India when there is a power crisis, whether due to
unavailability of fuel or due to a lack of rainfall. Introducing a quota system does not
require investment in new infrastructure and does not require significant capital
investment as in case of introducing peak pricing. However, it does require participation
of all the actors. With different actors having vested interests, designing a quota system
with appropriate bonuses and penalties could be time consuming and politically
difficult, as was the case in Brazil where about two months were spent in debates on
ways to cope with the crisis. The Brazilian experience showed that rationing can be
implemented in large scale and that it may lead to a reduction of consumption by 20-
25%. It has many flexible features to convey price signals to the consumers. Consumers
tend to be more motivated when they are allowed to make their own energy saving
decisions and even more so when they can make profit by overachieving their quotas.
EVALUATION OF OPTIONS
A. GENERIC EVALUATION FRAMEWORK
In our paper we analyse the policy options based on the goals of the power sector in
India. We have selected two main goals for our analysis namely, reliability of power and
affordability of energy for consumers. The Planning Commission of India projects power
for all by 2012 which requires addition of about 78GW. Despite the economic growth of
India, a significant portion of the population is still under poverty level. This means
implementing market based instruments alone is not feasible as the prices are bound to
rise in a supply constrained environment. The policy choice needs to address both
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reliability of supply and affordability of energy to the consumers. A generic evaluation
framework used in our analysis is shown in the Figure 3.
FIGURE 25: POLICY EVALUATION FRAMEWORK
B. SUPPLY SIDE POLICY- CHOICE 1: INVESTMENT IN GENERATION
On the supply side, new generation continues to need to be added to meet growing
demand. Demand-side measures alone will not be sufficient for meeting the increasing
energy gap when the economy of the country is growing. However, there are limitations
to adding large generation plants in India. Electricity generation in India depends
largely on coal, as it is the most available fuel source in India. About 65% of installed
capacity is based on thermal power plants with coal as a major fuel share. With
increasing dependence on coal, there are concerns of depletion of coal stock in India. In
November 2007, the government had to revise the planned coal import from 12MT to
14MT in view of the large number of coal plants with critical coal stocks and the
depletion of national coal stock to an alarmingly low level. There are cases where
energy generation has suffered due to unavailability of coal. Given the limited
availability of natural gas, there are limitations to adding gas-based power plants as
well. With these limitations to adding thermal power plants, the sector needs to look at
other solution options as well to meet the demand. This policy choice does assist in
addressing the reliability of the supply however, to attract investment of this need the
current retail prices need to be revised to make the industry financially viable which
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could mean increase in price of electricity thus making it less affordable to consumers
or additional burden of subsidy to the State. From the feasibility point of view, this
policy is facing a number of challenges as past data shows an underachievement in
generation addition. Main barriers are lack of cost recovery of electricity, significant
losses, and at times fuel shortages.
C. SUPPLY SIDE POLICY- CHOICE 2: CAPTIVE GENERATION
In the short term, there is an opportunity to reduce the electricity supply-demand gap
by bringing all existing generation capacity to the national grid. In India, there is a
significant amount of captive generation held by industrial consumers. These
consumers installed generation units of their own because of the poor reliability of the
national grid and the high prices that were caused by cross subsidies. About 20% of
total installed capacity is captive generation. Before 2003, these captive generators did
not sell excess power to the grid, not even during power shortages, due to a number of
bureaucratic hurdles. The Electricity Act of 2003 introduced the concept of open access
which relieved generation of all licences and allowed captive generation to sell energy
to anyone in the grid. Although this has been successful to some extent in bringing
captive generation to the grid, there are some limitations. In India, system stability uses
a market based approach where frequency is a price indicator.
However, this price is capped keeping some captive generation out of the grid. This
policy choice also addresses the reliability problem in the sector however for all captive
generation to be connected to the grid the capped price must be high enough to meet
the cost of these captive generators. From the feasibility point of view, this policy has
been fairly successful with introduction of open access; however, open access has not
been fully effective in all States as there are cases which show that the State
transmission utility sometimes ignores open access provisions.
D. DEMAND SIDE POLICY- CHOICE 1: REDUCING LINE LOSSES
Although supply-side solutions are necessary, the demand side should not be forgotten.
Economic viability of an industry can be improved only if AT&C losses in the
distribution sector are brought under control. As long as there is such a large gap
between cost realization and the cost of supply, the prospects for investment will
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continue to suffer, making it difficult to realize the supply-side solution of adding new
generation. The average AT&C loss of all India was about 32% in 2006-2007. This is
only 2% less than in 2003, indicating that the control of these losses is only improving
slowly. It requires significant investment in the distribution sector, from training the
manpower to improving the transformers and distribution lines as well as increasing
public awareness of theft of electricity. From our evaluation framework, this
implementing this policy choice addresses reliability of supply if technical losses are
reduced while reducing theft and unmetered consumption means the consumers have
to pay for their energy making it costly for consumers who are not used to paying.
Achieving this is not feasible in the short term as the trend shows. Main barriers in the
implementation of this policy are lack of fund with distribution companies to invest in
upgradation as they are already in difficult financial situation plus implementation of
legal measures in controlling theft has not been adequate. In addition to that, there are
consumers with no meters or faulty meters which require additional capital investment
to install energy meters.
E. DEMAND SIDE POLICY- CHOICE 2: PEAK PRICING
In India, the retail price of electricity is flat. It is fixed until the next price revision. This
means that consumers do not experience peak prices. Hence, even if the entire country
is facing a power crisis, consumers do not have an incentive to change their
consumption and will keep using electricity during peak hours. This aggravates the
problem and results in long hours of load shedding. Peak pricing could change this
behaviour of consumers and save some energy which might lead to less load shedding
hours. However, implementing this takes time and investment in energy meters which
considering the number of households can be a significant amount. This policy choice
does address the problem of reliability during peak hours however this requires
increase in peak prices making it less affordable to poor consumers. Hence, peak pricing
should be waived for low income groups to protect them from high prices. This policy is
feasible in theory but in practice it has number of barriers like need of capital
investments to install meters to measure peak demand and with price increase being
politically sensitive there will be very little political commitment to this policy.
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F. DEMAND SIDE POLICY- CHOICE 3: SEASONAL PRICING
Seasonal pricing is another market mechanism on the demand side which could be used
in India because of the seasonal variation of generation and consumption, especially in
states that are hydro-dependent. It is much easier to apply than other demand-side
solutions. The state simply needs to apply two different prices, one during the season
with excess supply and another during the season with tight supply. This is mostly
suitable to states that depend on hydropower, because there is sufficient capacity
during the monsoon season due to availability of water. These states often need to shed
load during the dry season. Therefore a high price in the dry season compared to the
wet season could reduce consumption keeping the states away from blackouts. This
policy choice does address the reliability of the system during shortage seasons
however increasing prices means costly energy during summer for consumers. This is a
more feasible option than peak pricing as implementing this policy does not require
investing in new meters and is also flexible in implementing with seasonal changes in
power availability.
G. DEMAND SIDE POLICY- CHOICE 4: ENERGY RATIONING
Another demand-side solution is the use of quota. In Brazil, the power sector was able
to avoid blackouts by using a rationing method. This could also be used in India to limit
the hours of blackouts. However, success in Brazil does not necessarily mean it will
work in India as well. In India, the quota mechanism would not be helpful in reducing
the AT&C losses. Instead it could lead to more consumers stealing electricity thereby
increasing the commercial losses. Besides, the economic growth rate of India is high,
compared to Brazil, and there is still a significant number of households who are not
connected to the electricity grid, as opposed to Brazil where the electricity coverage is
above 90%. This policy choice addresses the problem of reliability by incentivising
consumers to conserve energy during energy shortage however it will be costly for
consumers if penalties are high for consuming above the quota limit. In Brazil, this has
been a successful and feasible mechanism to conserve energy during crisis however in
India the feasibility of this policy is uncertain as this is a new approach and there is little
base for learning from the past unlike Brazil which had implemented energy rationing
in the past.
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CHAPTER 5
FINANCIAL FEASIBILITY STUDY OF A GREENFIELD POWER PLANT
MAJOR ASSUMPTIONS
Ø Plant capacity = 500 MW
Ø Plant life = 25 years
Ø Fuel used- coal
Ø D/E ratio = 70:30
Ø Plant Load Factor (PLF) = 80%
Ø Estimated cost of project per MW = Rs.6 crores
Ø Depreciation (% of total cost of the project) = 5.9%
Ø Return on Equity (ROE) = 15.5%
PROJECT COST AND MEANS OF FINANCE
The total cost of the power project has been estimated at Rs.3000 crore out of which 15% i.e.
Rs. 450 crore is assumed to be the cost of mining project and Rs. 2550 crore would contribute
towards the 2 X 250 MW project.
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POWER PROJECT COST BREAK-UP
Exhibit 17: Power project cost break-up (in Rs. Crores)
Sl.
No
Particulars AMOUNT
1 Land and site development 13.21
2 Civil / Structural works 281.3
3 Plant and machinery 1847.04
4 Technical services fee 16.14
5 Miscellaneous fixed assets 10.54
6 Preliminary expenses 30.86
7 Pre-operative expenses (incl. IDC) 241.83
8 Provision for contingencies 64.57
9 Margin money for working capital 43.47
T O T A L 2548.96
(say, 2550)
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MINING PROJECT COST BREAK-UP
The cost estimates of the mining project have been worked out based on the previous
projects.
Exhibit 18: Mining project cost break-up (in Rs. Crores)
Sl Particulars AMOUNT
1 Land and Site Development 106.3
2 Buildings 4.05
3 Plant and Machinery 113.3
4 Mine Development Cost 146.07
5 Pre-operative expenses 79.36
T O T A L 449.08
(say 450)
MEANS OF FINANCING BREAK-UP
The total cost of the 2 X 250 MW power project (including mining), estimated at Rs.3000
crore, is proposed to be financed as given in the Exhibit 19.
Exhibit 19: Means of financing break-up (in Rs. crores)
Particulars Proposed 2X250 MW
Power Mining Total
EQUITY
- Internal accruals
- Public issue
(out of which promoters)
- Total Equity
500
336
(90)
836
0.00
64
(0.00)
64
500
400
(90)
900
DEBT
- Rupee Term Loans
- Total Debt
1714
1714
386
386
2100
2100
Total 2550 450 3000
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It may be seen from the above that the project cost for the 2X250 MW power plant at Rs.3000
crore would be financed at a D-E ratio of 70:30, which is permissible under CERC
regulations, and will reduce the tariff, making the power generated from the project more
competitive. The drawl from the debt portion is expected to begin from the first quarter of the
FY 2011-12.
PROFITIBILITY PROJECTION
Summary of profitability estimates and financial indicators in the first full year of operations
(FY 2015-2016) are as given in the Exhibit 20.
Exhibit 20: Profitability outlook in the first year of operations
Particulars Unit Value
Profitability Outlook (FY 2015-16)
Installed capacity (MW) 500
PLF (%) 80 %
Energy Generated (MU) 3504
Energy Sold (MU) 3153.6
Sales (Rs. Crore) 938.2
Gross Profit (PBDIT) (Rs. Crore) 564.17
GP Margin (%) 60.13%
Profit Before Tax (Rs. Crore) 169.5
PBT Margin (%) 18.1%
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The financial indicators of the 2X250 MW expansion project are given in the Exhibit 21.
Exhibit 21: Financial indicators for the project
Particulars Value
Financial Indicators
Debt Equity Ratio 70:30
Internal Rate of Return (%) 12%
Levelised Tariff (Rs/kWh) 1.78
DSCR
- Maximum
- Minimum
- Average
2.65
1.33
1.45
Payback period 13 years
Net Present value (NPV) Rs.830.2Crores
The tariff for the project has been calculated as per the CERC tariff regulations. The levelised
tariff comes to Rs.1.78 per unit considering project life of 25 years and discounting factor of
8%. The projected profitability parameters and financial indicators are satisfactory.
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CHAPTER 6
POWER TRADING IN INDIA
In India, while there is a huge section of consumers, who are power deprived, there are a lot
of Captive Power Plants (CPPs) that are underutilized and a lot of merchant capacity also
expected to be added in the near future, there is a need to encourage the peaking power plants
and bring the surplus captive generation in the grid.
The Electricity Act, 2003, mandated development of power markets by appropriate
commissions through enabling regulations. This paved the way for the new trends to emerge
like Open Access and the one in February, 2007, when the Central Electricity Regulatory
Commission (CERC) issued guidelines for grant of permission for setting up operation of
power exchanges within an overall regulatory framework. The emerging trends will help in
proper flow of power from surplus regions to deficit regions and thus try to bring about a
balance in the power sector. The National Electricity Policy, pronounced in February 2005,
stipulated that enabling regulations for inter-and-intra-state trading, and also regulations on
power exchange, shall be notified by the appropriate Commissions within six months. On 6th
February 2007, the Central electricity Regulatory Commission (CERC) issued guidelines for
grant of permission for setting up and operation of power exchanges within an overall
regulatory framework. Private entrepreneurship is allowed to play its role. Promoters are
required to develop their model power exchange and seek permission from CERC before start
of operation.
POWER EXCHANGE
The Power Exchange is a competitive wholesale spot trading arrangement that facilitates the
selling and buying of electricity. It is an organized market that facilitates trade in
standardized hourly and multi-hourly contracts. An exchange is absolutely neutral towards
the market because its rule apply to both sides of the transaction. Bids on an exchange only
contain quantity and prices for a particular period.
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MAIN FUNCTIONS OF A POWER EXCHANGE
Ø Price discovery.
Ø A contract for Purchase and/or sale of electricity as prescribed by the Exchange and
permitted by CERC.
Ø All transactions in Contracts shall be cleared, registered and settled by the Exchange.
Ø Exchange to prescribe trading days & trading session.
Ø Exchange to act as a legal central counter party.
INDIAN ENERGY EXCHANGE
On a daily basis the Exchange will offer a double side closed auction for delivery on the
following day, which is termed as day-ahead market. Price discovery would be through
double side bidding and buyers and suppliers shall pay/receive uniform price.
Day Ahead Market operations will be carried out in accordance with the ‘Procedure for
scheduling of collective transactions’ issued by the Central Transmission Utility (PGCIL),
‘CERC (Open Access in inter-State Transmission) Regulations, 2008’ ,its modifications
issued from time to time and the Bye-Laws, Rules and Business Rules of the Exchange.
Process of Closed-Bidding Auction
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Ø Bid accumulation period (Bidding phase)
During the auction sessions on each Trading Day, bids entered by Members on
the IEX Trading Platform are automatically stored in the Central Order Book
without giving rise to Contracts. During this phase, bids entered can be revised
or cancelled. Bid accumulation period shall start at 10.00 AM and will end at
12.00 Noon.
Ø Auction period
At the end of the bidding session, the IEX Trading Platform will seek to match
bids for each hourly contract. After the price determination phase is concluded,
the Members, whose bids have been partially or fully executed, will be provided
all relevant trade information regarding each contract traded on the IEX Trading
Platform.
Ø Price Determination Process (Provisional)
All purchase bids and sale offers will be aggregated in the unconstrained
scenario. The aggregate supply and demand curves will be drawn on Price-
Quantity axes. The intersection point of the two curves will give Market Clearing
Price (MCP) and Market Clearing Volume (MCV) corresponding to price and
quantity of the intersection point. Results from the process will be preliminary
results. Based on these results the Exchange will work out provisional obligation
and provisional power flow. Funds available in the settlement account of the
Members shall be checked with the Clearing Banks and also requisition for
capacity allocation shall be sent to the NLDC. In case sufficient funds are not
available in the settlement account of the Member then his bid (s) will be deleted
from further evaluation procedure.
[ECONOMICS OF ELECTRICITY MARKET
School of Petroleum Management, Gandhinagar.
Ø Price Determination Process (Final)
Based on the transmission capacity reserved for the Exchange by the NLDC on
day ahead basis by 2.00 PM, fresh iteration shall be run at 2.30 PM and final
Market Clearing Price and Volume as well as Area
shall be determined. These Area Clearing Prices shall be used for settlement of
the contracts.
CITY MARKET]
School of Petroleum Management, Gandhinagar.
Price Determination Process (Final)
Based on the transmission capacity reserved for the Exchange by the NLDC on
day ahead basis by 2.00 PM, fresh iteration shall be run at 2.30 PM and final
Market Clearing Price and Volume as well as Area Clearing Price and Volume
shall be determined. These Area Clearing Prices shall be used for settlement of
December 14, 2010
77 | P a g e
Based on the transmission capacity reserved for the Exchange by the NLDC on
day ahead basis by 2.00 PM, fresh iteration shall be run at 2.30 PM and final
Clearing Price and Volume
shall be determined. These Area Clearing Prices shall be used for settlement of
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CONGESTION MANAGEMENT
Market-splitting methodology shall be adopted for congestion management.
Grid bottlenecks are relieved by comparison of the calculated contractual flow with
the transmission capacity available for spot trading, and if the flow exceeds the
capacity, the prices are adjusted on both sides of the bottleneck so that the flow
equals the capacity. If the flow does not exceed the capacity, a common price is
established for the whole area.
If the flow exceeds the capacity at the common price for the whole market area, it is
split in a surplus part and a deficit part. The price is reduced in the surplus area
(sale > purchase) and increased in the deficit area (purchase > sale). This will
reduce the sale and increase the purchase in the surplus area. In the same way, it
will reduce the purchase and increase the sale in the deficit area. Thus, the needed
flow is reduced to match the available transfer capability. This method of managing
congestion is also known as market-splitting. Initially, the electrical regions are
defined as bid areas since inter-regional links are most likely to be congested,
however, each electrical region of the country has been divided in two bid-areas so
as to accommodate any exigencies of congestion in intra-regional transmission
system.
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CONCLUSION
The power sector remains a major infrastructure concern and India’s continued
economic growth will depend heavily on the ability to meet the growing demand for
electricity. Better grid connectivity, price affordability and increased certainty of
electricity supply; all play an equally important role in shaping the intricacies of the
sector. The introduction of EA2003 has transformed the electricity sector and paved the
way for competition in the sector. Power trading in India is made possible as a result of
this.
The steady increase in electricity demand is attributed to the country’s rapid economic
growth. Over and above India’s visible electricity demand growth, there is significant
latent demand that remains under-represented. India’s pattern of energy demand,
consumption and growth can be understood in the context of its dual objectives – as a
basis for sustaining economic growth and as an instrument for poverty reduction. Over
the last few years, the story on India’s economic growth has been underlined by the
story of India’s power sector.
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KEY LEARNINGS
Ø Evolvement of Market Structure in India over the years.
Ø Economics of Load Division and Optimal Plant Mix.
Ø Effect of internalization of negative externalities cost on the electricity market
structure.
Ø Role of various regulatory authorities in the sector.
Ø Role of National and Regional load dispatch centres in avoiding congestion.
Ø Functioning of power exchange in India.
Ø Optimal bidding strategies for buyers and sellers in the electricity market.
Ø Tariff calculation with respect to new power generation unit.
Ø Approach of power generation companies in checking the financial feasibility of a
Greenfield power plant.
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ANNEXURE I: SOME USEFUL INTERNET RESOURCES FOR
INFORMATION ON INDIAN POWER SECTOR
Prayas, Pune www.prayaspune.org
Ministry of Power http://powermin.nic.in
Central Electricity Regulatory Commission http://www.cercind.org
Central Electricity Authority http://www.cea.nic.in
Orissa Electricity Regulatory Commission http://www.orierc.org/
Andhra Pradesh Electricity Regulatory Commission www.ercap.org
Uttar Pradesh Electricity Regulatory Commission www.uperc.org
Orissa Government www.orissagov.com
Andhra Pradesh Transmission Corporation www.aptranscorp.com
Andhra Pradesh Generation Corporation www.apgenco.com
National Thermal Power Corporation www.ntpc.co.in
Powergrid Corporation of India www.powergridindia.com
BSES Ltd. www.bses.com
World Bank - India Power Projects www.worldbank.org/projects
Asian Development Bank - India Power Projects www.adb.org/India
Tata Energy Research Institute (TERI) www.teriin.org
Power Line www.indiapoweronline.com
Financial Express Newspaper www.financialexpress.com
The Hindu Newspaper www.hindugrouponnet.com
Times of India Newspaper www.timesofindia.com