Modelling Electricity Markets

83
[ECONOMICS OF ELECTRICITY MARKET] December 14, 2010 1 | Page School of Petroleum Management, Gandhinagar.

Transcript of Modelling Electricity Markets

Page 1: Modelling Electricity Markets

[ECONOMICS OF ELECTRICITY MARKET] December 14, 2010

1 | P a g e School of Petroleum Management, Gandhinagar.

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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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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.

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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