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1
SUMMER INTERNSHIP REPORT
ON
Analysis & Implementation of Competitive bidding and ABT system
at Essar Power Salaya Plant
UNDER THE GUIDANCE OF
Ms. Sreelata Nilesh, Senior Fellow, CAMPS, NPTI
&
Mr. Bhavesh Kundalia Head (Commercial Dept.)
AT
ESSAR POWER GUJARAT LIMITED
SUBMITTED BY
ABHISHEK GUPTA
ROLL NO - 98
MBA (POWER MANAGEMENT)
MAHARSHI DAYANAND UNIVERSITY, ROHTAK
AUGUST 2013
2
DECLARATION
I, Abhishek Gupta, Roll No. 98, Class MBA (power Management) 20012-14, of the National
Power Training Institute, hereby declare that the Summer Training Report entitled “Analysis &
implementation of competitive bidding and ABT system at Essar power Salaya plant” is an
original work and the same has not been submitted to any other Institute for the award of any other
degree.
A Seminar presentation of the Training Report was made on 2nd September 2013 and the
suggestions as approved by the faculty were duly incorporated.
Presentation In-charge Signature of the Candidate Amit Mishra Abhishek Gupta
Asst. Director
CAMPS, NPTI
Countersigned
Director/Principal of the Institute
3
CERTIFICATE
4
ACKNOWLEDGEMENT
At the outset, I am grateful to Mr. Mayank Doshi (General Manager, EPGL), for giving me
the opportunity to do my summer internship in ESSAR POWER GUJARAT LIMITED.
I would like to thank my mentor Mr. Bhawesh Kundalia (Head of Commercial Dept. EPGL) for
his extensive help and guidance throughout the project. I would also like to thank Mr. Amit
Bhatnagar (Deputy Manager EPGL) and Mr. Mayur Chandrapal (Asst. Manager EPGL), who
imparted me with his valuable guidance and suggestions during the internship project work.
I also thank Mr. S.K. Choudhary (Principal Director), Mrs. Manju Mam (Director), Mrs. Indu
Maheshwari (Dy. Director), Mrs. Farida Khan (Sr. Fellow) for providing me such a nice
opportunity to work with an esteemed organization. My internal guide Mrs. Sreelata Nilesh (senior
fellow) helped me in structuring this project report and also on various other aspects of the study.
Last but not the least, I duly acknowledge with gratitude the help and support from my
family & loved ones which was always available to me during the hectic period of my summer
internship.
Abhishek Gupta
5
LIST OF ABBREVIATIONS
CBG - Competitive Bidding Guidelines
NTP - National Tariff Policy
EA - Electricity Act
UMPP - Ultra Mega Power Project
NEP - National Electricity Policy
TRANSCO - Transmission Company
DISCOM’s - Distribution Company
CEA - Central Electricity Authority
ABT - Availability Based Tariff
CERC - Central Electricity Regulatory Commission
CPP - Captive Power plant
EPOL - Essar Power limited
ESTL - Essar Steel Limited
GERC - Gujarat Electricity Regulatory Commission
GOI - Government of India
GUVNL - Gujarat Urja Vitaran nigam Limited
IEGC - Indian Electricity Grid Code
RLDC - Regional Load Dispatch Centre
SLDC - State Load Dispatch Centre
RFQ - Request for Qualification
RFP - Request for Proposal
6
NLDC - National Load Dispatch Center
Hz - Hertz
Mw - Megawatts
Kwh - Kilowatt hour
Var - Volt amperes
7
TABLE OF CONTENTS
Declaration ……..…………………………………………………….......................... ii
Certificate …………………………………………………………………………… iii
Acknowledgement ………………………………………………………………….... iv
List of Abbreviations ………………………………………………………………… v
1.0 Executive summary …………………………………………………………… 10
1.1 Objectives of the study ……………………………………………………... 12
1.2 Significance of the study .……….………………………………………….. 13
2.0 About the Organization ……………………………………………………… 14
2.1 Organizational profile ……………………………………………………... 14
2.2 Vision of Organization ……………………………………………………. 16
2.3. Mission ……………………….……………………………………. …... 16
2.4 Portfolio of Business …………………………………………………. 16
2.5 Size, Scale & Diversity ………………………………………………….. 17
3.0 Competitive Bidding ………………………………………………………… 18
3.1 Why Competitive bidding …………………………………………………. 20
3.2 CBG Framework …………………………………………………………. 21
3.2.1 Bidding Process ………………………………………………….. 22
3.3 Bidding Structure ………………………………………………………..... 30
3.3.1 Case 1 Bidding …………………………………………………… 31
3.3.2 Case 2 Bidding …………………………………………………… 34
3.4 Tariff Component ……………………………………………………….... 37
8
3.4.1 Capacity Charge ………………………………………………….. 38
3.4.2 Energy Charges ………………………………………………....... 40
3.4.3 Combine Capacity and Energy charges ……………………………. 40
3.5 Inductive Cost Comparison ………………………………………………. 41
4.0 Availability based tariff ……………………………………………………. 42
4.1 Components of ABT .……………………………………………………. 43
4.1.1 Capacity charges …………………………………………………… 45
4.1.2 Energy charges …………………………………………………….. 46
4.1.3 UI charges …………………………………………………………. 47
4.2 Need for ABT ……………………………………………………………. 48
4.3 IEGC Specifications ……………………………………………………… 50
4.3.1 Voltage Specification ………………………………………………. 51
4.4 How ABT works ………………………………………………………….. 52
4.5 Mechanism of ABT …………………………………………………………. 57
4.5.1 For Central Generating Units …………………………………………. 57
4.5.2 For State Generating Units …………………………………………… 58
4.6 The UI Mechanism …………………………………………………………... 58
4.6.1 Revised UI Rates ……………………………………………………… 62
4.7 Improvements in Grid Operation ………………………………………….. 64
4.8 Effect of Adopting ABT …………………………………………………… 68
5.0 Limitations of the study ..………………………………………………………. 70
6.0 Conclusions / Inferences ………………………………………………………… 71
7.0 Bibliography .……………………………………………………………………… 73
9
LIST OF TABLES
Table 1: Time Table for two stage bid process for Case – 2 ………………………………… 29
Table 2: Time Table for two stage bid process for Case -1 …………………………............. 30
Table 3: Historical case 1 Bids ……………………………………………………………… 32
Table 4: Historical case 2 Bids …………………………………………………………......... 35
Table 5: Tariff Component …………………………………………………………………... 37
Table 6: IEGC Voltage Specification …………...…………………………………………. .. 51
Table 7: Calculation of UI Charge …………………………………………………………… 61
Table 8: Revised UI rates …………………………………………………………………….. 63
LIST OF FIGURE
Figure 1: Bidding Structure ………………………………………………………………… 30
Figure 2: Trends - Historical Case I Bids ……………………………………………………. 33
Figure 3: Trends - Historical Case II Bids …………………………………………………... 36
Figure 4: Indicative Cost Comparison b/w MOU Case-I, and Case-II …………………….. 41
Figure 5: Components of Availability Based Tariff …………………………………….... 44
Figure 6: Components of Fixed Cost of a Power Plant ……………………………….......... 45
Figure 7: Pictorial representation of Day Ahead Scheduling for ABT …………………….. 55
Figure 8: ABT operating mechanism …………………………………………………........ 56
Figure 9: UI rates on 15.04.2012 …………………………………………………………... 59
Figure 10: UI Rate Graph ……………………………………………………………………. 64
Figure 11: Daily frequency profile before implementation of ABT ……………………….. 66
Figure 12: Daily frequency profile post implementation of ABT ………………………….. 67
Figure 13: Smoothened grid frequency curve recorded at Dadri TPS
post implementation of ABT ………………………………………………….. 67
10
1. Executive Summary
“We will make electricity so cheap that only the rich will
burn candles”
- Thomas Alva Edison (1847 - 1931)
Which cannot be seen, counted in numbers, or measured in Kilos, liters or meters? Which cannot
be put into container with forwarding address, on a particular truck taking a particular route, but
flows as per laws of Physics? Which cannot be stored and whose availability and cost keep
changing widely. Electricity is the single most important input in the developmental process and
the progress of any country or State is heavily dependent on the availability of reliable and cost
effective power supply. With more and more investments pouring into the State, the restructuring
of the power sector has become the need of the hour.
Power generation and distribution in India started towards the end of the nineteenth century.
However, it was only after our independence in 1947 that the power sector got the required
momentum and power generation was identified as a key area for our development. With sustained
efforts over the decades, the power generation scenario in India presents a rich and composite
mixture of hydro, nuclear, thermal, wind and solar generation. Our installed capacity across the
nation well exceeds 2,11,766 MW, a major share of which is derived from thermal sources
(coal/lignite, gas, diesel).
Competition among power companies could become fiercer soon, with the Centre all set to
introduce tariff-based competitive bidding for the allocation of projects from January 6.
Consumers can rejoice as the new regime would bring down electricity tariffs across the country.
Electricity Act 2003 emphasizes the promotion of competition in the sector through various
provisions, such as delicensed generation, open access for T&D systems. All these provisions
leading to the development of an open and competitive market in electricity
11
Electricity Act 2003 (EA 2003) and National Tariff Policy (NTP) provide for tariff regulation and
determination under following guidelines
Promote competitive procurement by distribution licensees
Facilitate transparency and fairness in procurement
Facilitate reduction of information asymmetries for bidders
Protect consumer interests by facilitating competition in procurement
Availability Based Tariff (ABT) is concerned with the tariff structure for bulk power and is aimed
at bringing about more responsibility and accountability in power generation and consumption
through a scheme of incentives and disincentives. ABT tries to improve the quality of power and
curtail the following disruptive trends:
(a) Unacceptable rapid and high frequency deviations causing damage and disruptions.
(b) Frequent grid disturbances resulting in generators tripping, power outages and grid instability.
ABT has been implemented in the Western Region since June 1st 2002. One of the main reasons
for implementing these tariffs was to encourage grid discipline by making the pricing of power
frequency dependent, thereby forcing state participants to improve procedures for forecasting,
scheduling and load dispatch.
12
1.1 Objectives of the study
While working on this project, the main issue for our focus would be around the effect of
competitive bidding in the power market. Thus we studies about impact of introduction of
competition in the power market. The project contain the detailed analysis of the competitive
bidding guideline (CBG) provided by the Ministry of power government of India.
This project studies the process and conditions for the implementation of the ABT system at Essar
Power, salaya . For proper and safe functioning of the electrical equipment and to supply the power
more efficiently according to need, there was a need of a tariff system which can appreciate these
situations. So that the concept of Availability Based Tariff was proposed. It lays down upon the
idea of generate according to requirement.
The scope of this project report is
Study and analysis of the need and concept of the Availability based Tariff System
Study and analysis of the regulations and guidelines provided by the CERC and SERC for
the implementation of ABT system.
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1.2 Significance of the study
This study mainly shows the process and effect of the adoption of competition in the power
market. As we know Competitive bidding is one of the primary mechanism for procurement and
the premise for electricity sector reforms in India. The Electricity Act, 2003 ushered in a transition
from a vertically integrated public monopoly to the introduction of competition in different
segments of the industry. This project report puts light upon all the process and sub processes
associated to the proper implementation of the ABT system. This report also describes the
regulatory aspects to be kept in mind while adapting ABT.
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2.0 About the Organization
2.1 Organizational Profile
Essar Energy, a first mover among the private-sector players in the Indian power
industry, currently has a total installed generation capacity of 3,910 MW.
Essar Energy is one of India's leading private power producers with a 15-year operating track
record. The company's power business currently has seven operational power plants in India and
one operational power plant in Algoma, Canada, with a total installed generation capacity of 3,910
MW.
Essar began as a construction company in 1969 and diversified into manufacturing, services and retail.
Over the last decade, it has grown through strategic global acquisitions and partnerships, or through
Greenfield and Brownfield development projects, capturing new markets and discovering new raw
material sources
This capacity is increasing to 6,700 MW by the end of March 2014. Essar Energy also has access
to approximately 500 mmt of coal resources across seven coal blocks in India and overseas.
.
Status Project Location Capacity
(MW)
Operational
Essar Power Hazira Gujarat 515
Vadinar Power Gujarat 120
Bhander Power Gujarat 500
15
Algoma Power Plant Canada 85
Vadinar P1 Gujarat 380
Salaya I Gujarat 1,200
Vadinar P2 Gujarat 510
Mahan I (Unit I) Madhya
Pradesh
600
Total current 3,910
Under
construction
Mahan I ( Unit II) Madhya
Pradesh
600
Hazira II Gujarat 270
Paradip Orissa 120
Tori I Jharkhand 1,200
Tori II Jharkhand 600
Total under construction 6,700
16
2.2. Vision of the Organization
“To be respected as global entrepreneur through the power of Positive Actions.”
People - Nurture our people with care.
Progress - Responsive with new opportunities
Power - Synergy through global presence
Passion - Winning spirit in everything we do
2.3. Mission
Be responsive to Customer needs, deliver optimal solutions and value added services.
To achieve excellence in project execution, quality, reliability, safety, and operational
efficiency.
Ensure sustainable growth and professional excellence using state-of-the-art technology,
process driven approach, eco-friendly solutions and IT enabled tools.
Foster a culture of mutual trust and employee empowerment to provide a conducive
atmosphere to work.
Adhere to fair, transparent and ethical practices in interactions with all shareholders and be
a good corporate citizen.
Be flexible and agile to continually adapt to changing business environment.
To improve the lives of local community in all our projects.
To be a partner in nation building and contribute towards the India‟s economic growth.
2.4. Portfolio of Businesses:
Steel Business
Oil & Gas Business
Power Business
BPO & Telecom Services Business
Shipping Business
Port Business
Projects Business
17
2.5. Size, Scale & Diversity:
Professional strength: 73,000 people (2013)
Presence (location): 25 countries
Total Revenue: US$ 39 Billion (2013)
Presence (sector): Steel, oil and gas, power, communications, shipping, ports and
logistics, projects, mineral, Real estates.
Salaya I - Gujarat (1,200 MW)
2x600 MW Thermal Power Project At Salaya
Project name: 2x600 MW Thermal Power Project
Location: Salaya, Dist. Jamnagar, Gujarat
Client: Essar Power Gujarat Ltd.
Contract duration: 45 months
Completion date: April 2012
Contract type: EPC
The Salaya I power plant, located near Essar Oil's refinery complex at Vadinar,
Jamnagar district, Gujarat, is an imported coal-fueled thermal power plant with two
600-MW generation units. Salaya I Unit 1 (600 MW) starts commercial operations
from April 2012.
Coal for the plant will be extracted from Essar Energy's captive coal mine in Indonesia.
18
3.0 Competitive Bidding
In India, electricity reforms started with the reevaluation of Electricity Supply Act, 1948 and
the Indian Electricity Act, 1910 which led to The Electricity Act, 2003.Electricity sector
reforms have enabled a transition from a vertically integrated private or public monopoly
market structure to one of competitive wholesale and retail mechanism with marketplaces like
power exchanges. Introducing competition in different segments of the electricity industry is
one of the key features of the Electricity Act, 2003. Competition will lead to significant
benefits to consumers through reduction in capital costs and also efficiency of operations. It
will also facilitate the price to be determined competitively.
When the power sector was opened up for private investment in 1991, the MoU route with a
cost plus approach was adopted to attract investment. However, as we learnt about the
intricacies of the private Power development emphasis was laid on adoption of competitive
bidding for project development. Government of India constituted an Inter-Ministerial
Committee under the Chairmanship of Secretary (Power) to examine the existing tariff
structure for private power projects and suggest the alternative tariff structure addressing the
concerns of the States and the developers. Based the recommendations of the Committee, an
alternative tariff structure has been finalized for tariff based bidding process. It is essentially
an availability based bulk power tariff structure for the private Power projects. The tariff
structure recommends bid evaluation on the basis of levelised tariff (for fixed cost
components), escalable and non-escalable components in the fixed cost and certain operational
parameters such as Heat Rate, Auxiliary Consumption etc. RFQ and RFP procedure has also
been recommended for award of project. Certain guidelines for preparation of project for bid
solicitation and a fixed time schedule for bid evaluation have also been recommended. On the
basis of the Report of the Committee on ‘Alternative Tariff Structure for Private power
Projects’ necessary notification for tariff based competitive bidding has been issued on dated
19th January, 2005.
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The Electricity Act, 2003 & Central Electricity Regulatory Commission
The Electricity Act, 2003 assigns the following functions to the Central Electricity Regulatory
Commission among others:
a) To regulate the tariff of generating companies owned or controlled by the Central
Government.
b) To regulate the tariff of generating companies other than those owned or controlled
by the Central Government specified in Clause (a), if such generating companies
enter into or otherwise have a composite scheme for generation and sale of
electricity in more than one state.
c) To regulate the Inter-state transmission of electricity.
d) To determine tariff for inter-state transmission of electricity.
Section 61 of the Act empowers the Commission to specify, by regulations, the terms and
conditions for the determination of tariff in accordance with the provisions of the said section and
the National Electricity Policy and Tariff Policy. In terms of clause (s) of sub-section (2) of section
178 of the Act, the Commission has been vested with the powers to make regulations, by
notification, on the terms and conditions of tariff under section 61. As per section 178(3) of the
Act, the Commission is required to make previous publication before finalizing any regulation
under the Act. Thus as per the provisions of the Act, the Central Commission is mandated to
specify, through notification, the terms and conditions of tariff of the generating companies and
inter- State transmission systems covered under clauses (a) ,(b) and (c) of sub-section (1) of section
79 of the Act.
Promotion of competition in the electricity industry in India is one of the key objectives of the
Electricity Act, 2003 (the Act). Power purchase costs constitute the largest cost element for
distribution licensees. Competitive procurement of electricity by the distribution licensees is
expected to reduce the overall cost of procurement of power and facilitate development of power
markets. Internationally, competition in wholesale electricity markets has led to reduction in prices
of electricity and in significant benefits for consumers.
20
Section 61 & 62 of the Act provide for tariff regulation and determination of tariff of generation,
transmission, wheeling and retail sale of electricity by the Appropriate Commission. Section 63 of
the Act states that –
“Notwithstanding anything contained in section 62, the Appropriate Commission shall adopt the
tariff if such tariff has been determined through transparent process of bidding in accordance with
the guidelines issued by the Central Government.”
3.1 Why competitive bidding
The gold standard for market structure is long believed to be competitive conditions. Defining
competitive bidding we could say that “Competitive bidding” is a Transparent procurement
method in which bids from competing contractors, suppliers, or vendors are invited by openly
advertising the scope, specifications, and terms and conditions of the proposed contract as well as
the criteria by which the bids will be evaluated. Competitive bidding aims at obtaining goods and
services at the lowest prices by stimulating competition, and by preventing favoritism.
Competitive bidding is one of the primary mechanism for procurement and the premise for
electricity sector reforms in India. Electricity Act, 2003 aspires to create a liberal framework for
the development of the power sector for taking measures conducive to development of electricity
industry, promoting competition therein, protecting interests of consumers and supply of electricity
to all areas.
Competitive procurement of electricity reduces the cost of power procurement for the discoms. It
prevents the formation of buyer/seller cartels. End-consumer gets electricity at optimum price as
80- 85% of what consumers pay as tariff is power procurement cost. Efficient power procurement
becomes important to ensure that Consumers get affordable power. The Generation and
transmission capacity owners and developers get attractive return on their investments.
Competitive tariffs ensure that operational and financial efficiencies are enhanced in a sector
largely dominated by state-owned companies used to working on the cost-plus methodology.
21
3.2 CBG Framework
The Electricity Act 2003, in its preamble lays emphasis on promoting competition. For
procurement of power by distribution licensees through competitive bidding, Section 63 of the
Act, has been provided whereby the Regulatory Commission adopts tariff discovered through
bidding, if the due process as per the Competitive Bidding Guidelines (CBG) notified by the
Government of India has been followed. CBG framework was notified to make power procurement
process by the utilities more fair and transparent and for this purpose standard templates for
bidding documents such as RFQ, RFP and PPA were prescribed.
With the notification of CBG private sector participation in the power generation segment got the
much needed fillip as it provided a strong platform for investor to conduct business. The outcome
has been considerably low tariff discoveries vis-a-vis the traditional cost plus regime. Lower tariff
discoveries surely augur well for the end consumer
These guidelines are being issued under the provisions of Section 63 of the Electricity Act, 2003
for procurement of electricity by distribution licensees (Procurer) for:
a) long-term procurement of electricity for a period of 7 years and above;
b) Medium term procurement for a period of upto 7 years but exceeding 1 year.
The objectives of Competitive Bidding Guidelines are :
Promote competitive procurement of electricity
Facilitate transparency and fairness in procurement processes
Transparency ensured by Guidelines & Standard Bid Documents for tariff based bidding
Enhance standardization and reduce ambiguity and time for materialization of projects
Standardization of Bid documents, Bid submission and evaluation process, timeline for
bidding process, tariff structure.
Provide flexibility to suppliers on internal operations while ensuring certainty on
availability of power and tariffs for buyers.
22
Tariff to be quoted upfront for life of plant and Regulator to adopt tariff arrived at through
transparent bidding process as specified by the Guidelines.
Developer has the flexibility to choose optimum unit configuration.
Provides incentive to Developer to adopt innovative financial modelling and tax planning
to ensure competitive tariff & return on investment.
As per the National Electricity policy 2006 the government of India has issued the guideline for
the competitive bidding of power projects. Historically Indian power projects had been developed
through the cost plus basis and mostly by govt. owned utilities.
3.2.1 Bidding Process
Two-stage process
As per the guideline given by Ministry of power government of India for Determination of Tariff
by Bidding Process for Procurement of Power by Distribution Licensees, the bidding in done by
two stage bidding process.
5.1For long-term procurement under these guidelines, a two-stage process featuring separate
Request for Qualification (RFQ) and Request for Proposal (RFP) stages shall be adopted for the
bid process under these guidelines. The procurer may, at his option, adopt a single stage tender
process for medium term procurement, combining the RFP and RFQ processes. Procurer or
authorized representative shall prepare bid documents including the RFQ and RFP in line with
these guidelines and standard bid documents.
5.2The procurer shall publish a RFQ notice in at least two national newspapers, company website
and preferably in trade magazines also to accord it wide publicity. The bidding shall necessarily
be by way of International Competitive Bidding (ICB). For the purpose of issue of RFQ minimum
conditions to be met by the bidder shall be specified by the procurer in the RFQ notice.
5.3. Procurer shall provide only written interpretation of the tender document to any bidder /
participant and the same shall be made available to all other bidders. All parties shall rely solely
on the written communication and acceptances from the bidders.
23
5.4. Standard documentation to be provided by the procurer in the RFQ shall include,
(i) Definition of Procurer’s requirements, including:
Quantum of electricity proposed to be bought in MW. To provide flexibility to the bidders,
this may be specified as a range, within which bids would be accepted. Further, the procurer
may also provide the bidders the flexibility to bid for a part of the tendered quantity, subject
to a given minimum quantity.
The procurer may separately specify distinct baseload requirements and peakload
requirements through the same bid process. Seasonal power requirements, if any, shall also
be specified;
Term of contract proposed; (as far as possible, it is advisable to go for contract coinciding
with life of the project in case of long term procurement). The bidder shall be required to
quote tariff structure for expected life of the project depending upon fuel proposed by him.
The expected life project is estimated to be 15 years for gas/liquid fuel based projects, 25
years for coal based projects and 35 years for hydro projects.
Normative availability requirement to be met by seller (separately for peak and off-peak
hours, if necessary);
Definition of peak and off-peak hours;
Expected date of commencement of supply;
Point(s) where electricity is to be delivered;
Wherever applicable, the procurer may require construction milestones to be specified by
the bidders;
Financial requirements to be met by bidders including, minimum net-worth, revenues, etc
with necessary proof of the same, as outlined in the bid documents;
(ii) Model PPA proposed to be entered into with the seller of electricity. The PPA shall include
necessary details on:
Risk allocation between parties;
Technical requirements on minimum load conditions;
Assured offtake levels;
24
Force majeure clauses as per industry standards;
Lead times for scheduling of power;
Default conditions and cure thereof, and penalties;
Payment security proposed to be offered by the procurer.
(iii) Period of validity of offer of bidder;
(iv) Requirement of transfer of assets by the selected bidder (if any) to the procurer at the end of
the term of the PPA.
(v) Other technical, operational and safety criteria to be met by bidder, including the provisions of
the IEGC/State Grid Code, relevant orders of the Appropriate Commission (e.g – the ABT Order
of the CERC), emission norms, etc., as applicable.
(vi) The procurer may, at his option, require demonstration of financial commitments from lenders
at the time of submission of the bids. This would accelerate the process of financial closure and
delivery of electricity;
(vii) The procurer and the supplier may exercise exit option subject to the condition that the new
player satisfies all RFP conditions.
5.5. RFP shall be issued to all bidders who have qualified at the RFQ stage. In case the bidders
seek any deviations and procurer finds that deviations are reasonable, the procurer shall obtain
approval of the Appropriate Commission before agreeing to deviation. The clarification/revised-
bidding document shall be distributed to all who had sought the RFQ document informing about
the deviations and clarifications. Wherever revised bidding documents are issued, the procurer
shall provide bidders at least two months after issue of such documents for submission of bids.
5.6. Standard documentation to be provided by the procurer in the RFP shall include,
a) Structure of tariff to be detailed by bidders;
b) PPA proposed to be entered with the selected bidder.
25
The model PPA proposed in the RFQ stage may be amended based on the inputs received
from the interested parties, and shall be provided to all parties responding to the RFP. No
further amendments shall be carried out beyond the RFP stage.
c) Payment security to be made available by the procurer.
The payment security indicated in the RFQ stage could be modified based on feedback
received in the RFQ stage. However no further amendment to payment security would be
permissible beyond the RFP stage.
d) Bid evaluation methodology to be adopted by the procurer including the discount
rates for evaluating the bids.
The bids shall be evaluated for the composite levellised tariffs combining the capacity and
energy components of the tariff quoted by the bidder. In case of assorted enquiry for
procurement of base load, peak load and seasonal power, the bid evaluation for each type
of requirement shall be carried out separately. The capacity component of tariffs may
feature separate non-escalable (fixed) and escalable (indexed) components. The index to
be adopted for escalation of the escalable component shall be specified in the RFP. For the
purpose of bid evaluation, median escalation rate of the relevant fuel index in the
international market for the last 30 years for coal and 15 years for gas / LNG (as per
CERC’s notification in (vi) below) shall be used for escalating the energy charge quoted
by the bidder. However this shall not apply for cases where the bidder quotes firm energy
charges for each of the years of proposed supply, and in such case the energy charges
proposed by the bidder shall be adopted for bid evaluation. The rate for discounting the
combination of fixed and variable charges for computing the levellised tariff shall be the
prevailing rate for 10 year GoI securities;
e) The RFP shall provide the maximum period within which the selected bidder must
commence supplies after the PPA is entered into by the procurer with the selected bidder,
subject to the obligations of the procurer being met. This shall ordinarily not be less than
four years from the date of signing of the PPA with the selected bidder in case supply is
26
called for long term procurement. The RFP shall also specify the liquidated damages that
would apply in event of delay in supplies.
f) Following shall be notified and updated by the CERC every six months for the purpose of
bid evaluation:
1. Applicable discount rate
2. Escalation rate for coal
3. Escalation rate for gas /LNG
4. Inflation rate to be applied to indexed capacity charge component.
Bid submission and evaluation
5.7 To ensure competitiveness, the minimum number of qualified bidders should be at least two
other than any affiliate company or companies of the procurer. If the number of qualified
bidders responding to the RFQ/RFP is less than two, and procurer still wants to continue with
the bidding process, the same may be done with the consent of the Appropriate Commission.
5.8 Formation of consortium by bidders shall be permitted. In such cases the consortium shall
identify a lead member and all correspondence for the bid process shall be done through the
lead member. The procurer may specify technical and financial criteria, and lock in
requirements for the lead member of the consortium, if required.
5.9 The procurer shall constitute a committee for evaluation of the bids with at least one member
external to the procurer’s organisation and affiliates. The external member shall have expertise
in financial matters / bid evaluation. The procurer shall reveal past associations with the
external member - directly or through its affiliates - that could create potential conflict of
interest.
5.10.Eligible bidders shall be required to submit separate technical and price bids. Bidders shall
also be required to furnish necessary bid-guarantee along with the bids. Adequate and
reasonable bid-guarantee shall be called for to eliminate non-serious bids. The bids shall be
27
opened in public and representatives of bidders desiring to participate shall be allowed to
remain present.
5.11.The technical bids shall be scored to ensure that the bids submitted meet minimum eligibility
criteria set out in the RFP documents on all technical evaluation parameters. Only the bids
that meet all elements of the minimum technical criteria set out in the RFP shall be considered
for further evaluation on the price bids.
5.12.The price bid shall be rejected if it contains any deviation from the tender conditions for
submission of price bids.
5.13.Wherever applicable, the price bid shall also specify the terminal value payable by the
procurer for the transfer of assets by the selected bidder in accordance with the terms of the
RFP.
5.14.The bidder may quote the price of electricity at the generating station bus-bar (net of
auxiliaries), or at the interface point with the State transmission network. For purposes of
standardization in bid evaluation, the tariffs shall be compared at the interface point of the
generator/supplier with the State transmission network. In case the bidder quotes his rate at
the generating station bus-bar, normative transmission charges for the regional/inter-regional
network, if applicable, based on the prevailing CERC orders shall be added to the price bid
submitted. The charges for the State transmission network shall be payable by the procurer,
and shall not be a part of the evaluation criteria.
5.15.The bidder who has quoted lowest levellised tariff as per evaluation procedure, shall be
considered for the award. The evaluation committee shall have the right to reject all price bids
if the rates quoted are not aligned to the prevailing market prices.
28
Deviation from process defined in the guidelines
5.16. In case there is any deviation from these guidelines, the same shall be subject to approval by
the Appropriate Commission. The Appropriate Commission shall approve or require
modification to the bid documents within a reasonable time not exceeding 90 days.
Arbitration
5.17.The procurer will establish an Amicable Dispute Resolution (ADR) mechanism in
accordance with the provisions of the Indian Arbitration and Conciliation Act, 1996. The
ADR shall be mandatory and time-bound to minimize disputes regarding the bid process and
the documentation thereof.
If the ADR fails to resolve the dispute, the same will be subject to jurisdiction of the
appropriate Regulatory Commission under the provisions of the Electricity Act 2003.
Contract award and conclusion
6.1 The PPA shall be signed with the selected bidder/SPV (after its acquisition by the selected
bidder under Case-2) consequent to the selection process in accordance with the terms and
conditions as finalized in the RFP bid documents.
For cases referred to in clause 3.4 of these Guidelines, the PPA and other project documents
may be executed by the SPV and the concerned parties prior to the last date of submission of
RFP bids.
6.2 After the conclusion of bid process, the Evaluation Committee constituted for evaluation of
RFP bids shall provide appropriate certification on conformity of the bid process evaluation
according to the provisions of the RFP document. The procurer shall provide a certificate on
the conformity of the bid process to these guidelines.
6.3 For the purpose of transparency, the procurer shall make the bids public by indicating all the
components of tariff quoted by all the bidders, after signing of the PPA or PPA becoming
effective, whichever is later. While doing so, only the name of the successful bidder shall be
29
made public and details of tariffs quoted by other bidders shall be made public anonymously.
The procurer shall also make public the PPA signed in accordance with clause 6.1.
For above purpose, a notice will be published in at least two national newspapers and full
details shall be posted on the website of the procurer for at least thirty days.
6.4 The signed PPA along with the certification certificates provided by the evaluation committee
and by the procurer as provided in clause 6.2 shall be forwarded to the Appropriate
Commission for adoption of tariffs in terms of Section 63 of the Act.
Time Table for Bid Process
5.18.A suggested time-table for the bid process is indicated below. The procurer may give
extended time-frame indicated herein based on the prevailing circumstances and such
alterations shall not be construed to be deviation from these guidelines.
Table 1 : Time Table for two stage bid process for Case -2
Event Elapsed Time from Zero date
Publication of RFQ Zero date
Submission of Responses of RFQ 60 days
Shortlisting based on responses and issuance of RFP 90 days
Bid clarification, conferences etc 150 days
Final clarification and revision of RFP 180 days
Technical and price bid submission 360 days
Shortlisting of bidder and issue of LOI 390 days
Signing of Agreements 425 days
30
5.19.A suggested time-table for the Single stage bid process is indicated below. The procurer may
give extended time-frame indicated herein based on the prevailing circumstances and such
alterations shall not be construed to be deviation from these guidelines.
Table 2 : Time Table for two stage bid process for Case -1
3.3 Bidding Structure
The whole bidding process is divided into two case studies. The two Cases are as follows:
Figure 1 : Bidding Structure
Competitive Bidding
Case 1
Bidding
Case 2
Bidding
Event Elapsed Time from Zero date
Publication of RFP Zero date
Bid clarification, conferences etc. & revision of RFP 90 days
Technical and price bid submission 180 days
Short-listing of bidder and issue of LOI 210 days
Signing of Agreements 240 days
31
3.3.1 Case 1 Bidding
Where the location, technology and fuel is not specified by the procurer (Distribution Company
or its agent). Case 1 is an open bid where the developer / entrepreneur has to decide for fule and
location and compete against any other developer in general. The project developer can bid on the
basis of:
Any fuel
Any location
Any technology
The project developer bid for the portion or the total power generated. The bidder is responsible
for clearances/approvals etc. this kind of bidding is more relevant for state with limited fuel
sources. Such bidding entails higher risk for developer and lower risk for the state.
Case 1 Bid - Qualification Requirement
Technical
Land
Bidder should have acquired and have taken possession of at least
50% of the area of the land.
In case of land to be acquired under the Land Acquisition Act, the
Bidder shall submit copy of notification issued for such land under
Section 4 of the Land Acquisition Act
Fuel
Domestic Coal – Firm arrangement – mine allocation/fuel linkage
Imported Coal - either acquired mines having proven reserves for at
least 50% of the quantity of coal required to generate power.
OR shall have fuel supply agreement for at least 50% of the quantity
of fuel equired for a term of at least 5 years or the term of the PPA
(which ever is less)
Domestic Gas - Firm arrangements for fuel tie up by way of long
term fuel supply agreement for the quantity of fuel required to
generate power from the generation source for the total installed
capacity
32
The project site shall be transferred to the successful bidder at a price to be intimated at least 15
days before the due date for submission of RFP bid.
Trends - Historical Case I Bids
Water Bidder should have acquired approval for quantity of water required.
Environment &
Forest Clearance
Bidder should have submitted proposal for Environment & Forest
Clearance.
State Bid Date Bidder
Capacity (MW) Tariff (₹/kWh)
Dec-06 Aryan Coal 200 2.250
Gujarat Dec-06 Adani Power 1000 2.350
Dec-06 Essar 1000 2.401
Haryana Nov-07 Adani Power 1424 2.940
Nov-07 PTC-GMR 300 2.860
Nov-07 Lanco 600 2.340
Madhya Pradesh Nov-07 R-Power 1241 2.700
Nov-07 Essar 300 2.950
Feb-08 Adani 1320 2.642
Maharashtra Feb-08 Lanco 680 2.700
Feb-08 JSW Energy 300 2.716
Sep-09 GMR-EMCO 200 2.880
Maharashtra Sep-09 India Bulls 450 3.270
Sep-09 Adani Power 1200 3.290
Bihar Oct-09 Essar 450 2.640
Rajasthan Dec-09 Adani Power 1200 3.248
Jan-10 KSK Energy 1010 2.340
Gujarat Jan-10 Shapoorji Pallonji 800 2.800
33
Table 3 : Historical Case I Bids
Figure 2 : Trends - Historical Case I Bids
Expectedly, prices have observed a linear growth trend owing to increase fuel cost, land
procurement and equipment costs. Impact of transmission charges is important as plant away from
procuring state are at a cost disadvantage at delivery point.E
xpectedly, pr
Jan-10 Essar 1000 2.800
Jan-10
Thermal Powertech 430 3.770
Karnataka Jan-10
East Coast Energy 400 3.890
Jan-10 NCC 400 3.890
34
3.3.2 Case 2 Bidding
In case 2 bids the developer is expected to bid on the basis of :
Specific fuel
Specific location
Where the specifics are provided by the central/state government which is calling for bids. The
government (state or central) offers to assist private developers to set up large power plants in
securing land, water and mandatory clearances, signing of power purchase agreement, establishing
of fule linkage, etc. Thus, the government is but facilitator with the private promoters owing the
responsibility of development. Many state government have gone in for such case-2 bidding. Case
2 bidding can be called by one or more state states by one or more states where fuel sources are
available or coastal areas exist (for imported fuel). Such an arrangement entails higher risk for the
state and lower risk for the developer.
A multipart tariff structure featuring separate capacity and energy components of tariff forms the
basis for bidding. For medium term procurement the procurer may call for bids on a single part
tariff basis. In case of long term procurement with specific fuel allocation (Case 2), the procurer
may invite bids on the basis of capacity charge and net quoted heat rate.
Case 2 Bid - Qualification Requirement
Technical
Experience of developing projects (not necessarily
in the power sector) in the last 10 years, whose
aggregate capital costs must not be less than the
amount equivalent to Rs. 0.75 Crore.
Out of these projects, the capital cost of
at least one project should be equivalent
or more than ₹ 0.125 Crore.
Developing project means successful
commissioning of a project in which the
Bidder/Parent/Affiliate, as the case may be, held
35
equity stake of not less than 26% from the time of
financial closure till the time of commissioning of
such project.
Trends - Historical Case II Bids
Project Bid Date Bidder Capacity(MW) Tariff(₹/KWh)
Anpara C May-06 Lanco 1000 2.088
Sasan Jul-07 R-Power 3960 1.196
Mundra Dec-07 Tata Power 4000 2.264
Krishnapatnam Oct-07 R-Power 4000 2.333
Tilaiya Jan-09 R-Power 4000 1.770
Bhaiyathan Jan-08 India Bulls 1500 0.810
Jhajjar Mar-08 CLP 1320 2.996
Bara Nov-08 Jaypee 1980 3.020
Talwandi Jul-08 Sterlite 1980 2.864
Karchana Feb-09 Jaypee 1320 2.970
Rajpura Dec-09 L&T 1320 2.890
Table 4 : Historical Case II Bids
36
Figure 3 : Trends - Historical Case II Bids
While UMPPs in case II bidding have witnessed lower tariffs, most of the other projects have
witnessed price in range of ₹ 3/kwh of late. Bhaiyathan seems to be an exception but has 35% of
installed capacity reserved for merchant sales.
37
3.4 Tariff component
Component
Designated To Consideration To be Quoted
Fixed Charges Capacity Charge Escalable
Capacity
Charge
First year charges escalated
as per rates prescribed by
CERC.
Fixed Charges Capacity Charge Non Escalable Same Value for the term of
agreement
Variable Charges Energy Charges Escalable
Capacity
Charge
First year charges escalated
as per rates prescribed by
CERC.
Variable Charges Energy Charges Non Escalable
Capacity
Charge
Same Value for the term of
agreement
Table 5: Tariff Component
For procurement of electricity under these guidelines, tariff shall be paid and settled for each
payment period (not exceeding one month). A multi-part tariff structure featuring separate capacity
and energy components of tariff shall ordinarily form the basis for bidding. However, for medium
term procurement the procurer may, at his option, permit bids on a single part basis, and the same
shall be clearly specified in the Request for Qualification (RFQ) / Request for Proposal (RFP).
38
In case of long term procurement with specific fuel allocation (Case 2), the procurer shall invite
bids on the basis of capacity charge and net quoted heat rate. The net heat rate shall be ex-bus
taking into account internal power consumption of the power station. The energy charges shall be
payable as per the following formula :
Energy Charges = Net quoted heat rate X Scheduled Generation X Monthly Weighted
Average Price of Fuel / Monthly Average Gross Calorific Value of Fuel.
If the price of the fuel has not been determined by the Government of India, government approved
mechanism or the Fuel Regulator, the same shall have to be approved by the appropriate
Regulatory Commission.
In case of coal / lignite fuel, the cost of secondary fuel oil shall be factored in the capacity charges.
Tariffs shall be designated in Indian Rupees only. Foreign exchange risks, if any, shall be borne
by the supplier. Transmission charges in all cases shall be borne by the procurer.
3.4.1 Capacity charges
Capacity charge shall be paid based on actual availability in kwh, as per charges quoted in ₹/kwh
and shall be limited to the normative availability (or normative capacity index for hydro electric
stations). The normative availability shall be aligned to the level specified in the tariff regulations
of the Central Electricity Regulatory Commission (CERC) prevailing at the time of the bid process,
and shall be computed on annual basis. The capacity component of tariffs may feature separate
non-escalable (fixed) and escalable (indexed) components. The indices to be adopted for escalation
of the escalable component shall only be Wholesale Price Index (WPI) or Consumer Price Index
(CPI) and the Base year shall be specified in the bid document.
Capacity charges for supply beyond the normative availability shall be a pre-specified percentage
of the non-escalable component of the capacity charges, and shall be based on the availability of
the plant beyond the normative availability. The percentage applicable shall be specified in the
RFP, and shall be limited to a 40% of the non-escalable component of the capacity charges. For
procurement of Case-2 type (in reference to para 2.2.), the procurer shall have first right of refusal
on energy generated beyond normative availability. In case actual availability is less than the
normative availability, capacity charges shall not be payable for the shortfall compared to the
39
normative availability. In such case a penalty at the rate of 20% of the capacity charge shall be
applicable to the extent of the shortfall in availability.
The seller (successful bidder) shall declare availability on a daily basis in accordance with the
scheduling procedure as stipulated in the Indian Electricity Grid Code (IEGC) from time to time.
Further the seller and procurer shall comply with all relevant provisions of the IEGC. If the
procurer does not avail generation up to declared availability, the same can be sold in market by
the seller, and sale realization in excess of variable charges shall be equally shared with the
procurer.
Any change in tax on generation or sale of electricity as a result of any change in Law with respect
to that applicable on the date of bid submission shall be adjusted separately.
Ratio of minimum and maximum capacity charge for any year shall not be less than 0.7 to avoid
excessive front loading or back loading during the period of contract.
In case peak load or seasonal requirements are distinct from base load requirements, the bidders
shall indicate distinct prices for such peak load or seasonal supply which shall be evaluated
separately. Differential rates quoted for the same source of power for base and peak/seasonal
load shall not constitute violation of guideline or unfair practice.
Adequate payment security shall be made available to the bidders. The payment security may
constitute:
(i)Letter of Credit (LC)
(ii) Letter of Credit (LC) backed by credible escrow mechanism.
In the case the seller does not realize full payment from the procurer by the due date as per payment
cycle, the seller may after 7 days, take recourse to payment security mechanism by encashing the
LC to the extent of short fall or take recourse to escrow mechanism. The procurer shall restore the
payment security mechanism prior to the next date of payment. Failure to realize payment even
through payment security mechanism shall constitute an event of payment default. In the event of
payment default the seller, after giving 7 days’ notice, can sell up to 25% of the contracted power
to other parties without losing claim on the capacity charges due from the procurer. If the payment
security mechanism is not fully restored within 30 days of the event of the payment default, the
seller can sell full contracted power to other parties without losing claim on the capacity charges
40
due from the procurer. The surplus over energy charges recovered from sale to such other parties
shall be adjusted against the capacity charge liability of the procurer. In case the surplus over
energy charges is higher than the capacity charge liability of the procurer, such excess over the
capacity charge liability shall be retained by the seller.
3.4.2 Energy Charges
Where applicable, the energy charges payable during the operation of the contract shall be related
on the base energy charges specified in the bid with suitable provision for escalation. In case the
bidder provides firm energy charge rates for each of the years of the contract term, the same shall
be permitted in the tariffs. In other cases, the energy charges shall be payable in accordance with
fuel escalation index used for evaluation of the bid. In case of bids based on net heat rate, the price
of fuel shall be taken as stipulated under para 4.2. However, the fuel escalation will be subject to
any administered price mechanism of Government or independent regulatory price fixation in case
of fuel produced within the country. The applicable indices for various fuels shall be identified in
the RFP documents.
No adjustment shall be provided for heat rate degradation of the generating stations. Even in case
of bids based on net heat rate, the bidder shall factor in site conditions, loading conditions,
frequency variations etc. and no adjustment shall be allowed on the quoted net heat rate for the
duration of the contract.
In case a bidder offers hydro power, under Case 1 or the procurer invites bids of hydro power
under Case 2, the hydrological risk shall be borne by the Procurer, provided the hydrological data
of such a project is based on authentic sources and is known to the parties in advance. Any
hydrological advantages resulting in energy availability beyond the design energy shall be passed
on to the Procurer without any charge. The geological risk for the hydro project shall be borne by
the developer.
Energy charges shall be payable by the procurer to the seller for the scheduled energy. Deviations
beyond agreed energy schedules shall be settled under the ABT/UI mechanism.
3.4.3 Combined capacity and energy charges
In cases where the procurement process permits bidders to submit combined capacity and energy
charges, the charges proposed shall be firm for each of the years of the term of the Power Purchase
41
Agreement (PPA), and no escalation of tariffs shall be permitted over and above the rates proposed
by the seller in the price bid.
The bidder shall specify the normative availability from the project on an annual basis. The model
PPA made available to the bidders at the RFQ/RFP stage shall feature appropriate provisions for
penalties in event of the normative availability not being met by the seller. The RFQ/RFP shall
also specify minimum offtake conditions for procurement from such stations.
The per kwh rates payable to the seller for offtake by the procurer over and above the normative
levels shall be the same as the rates applicable till normative availability. In case the procurer does
not schedule the energy made available by the seller as per the contract, the seller shall be free to
sell to other parties. The seller shall not be required to make any payments to the procurer for such
sales to third parties.
3.5 Indicative Cost Comparison b/w MOU Case-I, and Case-II
Figure 4: Indicative Cost Comparison b/w MOU Case-I, and Case-II
The bidding mechanism is a marked difference from the earlier cost plus mechanism.
42
4.0 Availability Based Tariff
Now, after knowing about competitive bidding we would move further and start our discussion on
the second part of project i.e. ABT system. We start with defining the Availability based tariff and
describing its working mechanism and consequent improvements in the grid operation.
Defining ABT, we could say that Availability Based Tariff (ABT) is a rational tariff structure
based on average availability (MW delivering capability) of the plant over the year for supply of
power from Central Generating Stations to its beneficiaries on a long term contracted basis. It
requires both generators and beneficiaries to commit to day-ahead schedules according to which
they should supply/draw power from the grid. Variations may be permitted if notified in advance
as per specified provisions.
The aim of implementing ABT in the Indian scenario is to bring about more responsibility and
accountability in power generation and consumption. By providing rewards/penalties for
deviations from schedule for helping/disturbing the GRID as the case may be it has brought the
grid operations under regulation.
CERC (Central Electricity Regulatory Commission) is the apex body in India when it comes to
Regulations in the power sector. Through this mechanism, it looks forward to improve the quality
of power and curtail the following disruptive trends in power sector:
i. Unacceptably rapid and high frequency deviations (from 50 Hz) causing damage and
disruption to large scale industrial consumers.
ii. Frequent grid disturbances resulting in generators tripping, power outages and power Grid
disintegration.
This objective is to be brought about by encouraging generators to produce more during peak load
hours and curtail generation adequately during off-peak hours on one hand and discouraging
consumers from overdrawing on the other hand. However, the most significant aspect of ABT is
the splitting of the existing monolithic energy charge structure into three components viz. capacity
charges (fixed), energy charges (variable) and UI (unscheduled interchange) charges. It is the last
component that is expected to bring about the desired grid discipline. The unscheduled interchange
by providing incentives or by levying penalties as and when required, aims to bring about more
stability in the grid.
43
The introduction of ABT in India was done in phases. Availability Based Tariff (ABT) has been
implemented with effect from:
01.07.2002 in Western Region
01.12.2002 in Northern Region
01.01.2003 in Southern Region
01.04.2003 in Eastern Region
01.11.2003 North - Eastern Region
4.1 Components of Availability based tariff
The most significant aspect of ABT is the splitting of the tariff into three components viz. capacity
charges (fixed), energy charges (variable) and UI (unscheduled interchange) charges. When we
look at the various costs that a power plant bears then we get two components namely fixed cost
and variable cost. The fixed cost elements are interest on loan, return on equity, depreciation, O&M
expenses, insurance, taxes and interest on working capital. The variable cost comprises of the fuel
cost, i.e., coal and oil in case of thermal plants and nuclear fuel in case of nuclear plants. The third
charge (UI) which was introduced was aimed at bringing in more stability in the grid. It also made
power generators and beneficiaries more accountable.
44
Figure 5: Components of Availability Based Tariff
The payment of fixed cost to the generating company is linked to availability of the plant, that is,
its capability to deliver MWs on a day-by-day basis. The total amount payable to the generating
company over a year towards the fixed cost depends on the average availability (MW delivering
capability) of the plant over the year. In case the average actually achieved over the year is higher
than the specified norm for plant availability, the generating company gets a higher payment. In
case the average availability achieved is lower, the payment is also lower. This is the first
component of Availability Tariff, and is termed ‘capacity charge’.
45
Figure 6: Components of Fixed Cost of a Power Plant
The second component of Availability Tariff is the ‘energy charge’, which comprises of the
variable cost (i.e., fuel cost) of the power plant for generating energy as per the given schedule for
the day. It may specifically be noted that energy charge (at the specified plant-specific rate) is not
based on actual generation and plant output, but on scheduled generation. In case there are
deviations from the schedule (e.g., if a power plant delivers 800 MW while it was scheduled to
supply only 700 MW), the energy charge payment would still be for the scheduled generation (700
MW), and the excess generation (100 MW) would get paid for at a rate dependent on the system
conditions prevailing at the time. If the grid has surplus power at the time and frequency is on the
higher side, the rate would be lower. If the excess generation takes place at the time of generation
shortage in the system (in which condition the frequency would be on the lower side), the payment
for extra generation would be at a higher rate.
4.1.1 Capacity charges: They are levied towards reimbursement of the fixed cost of the plant,
linked to the plant's declared capacity to supply MWs. Fixed charges are payable to the
generating station, by the intended beneficiaries of the generation facility (state
governments of the region in most cases. Under the ABT regime, fixed charges are payable
against the availability (declared capacity) of the generating facility.
46
These charges are:
Paid in proportion to the share of the beneficiaries in respective plants.
Shares of beneficiaries in Central Generating Stations of different stations are
notified by MOP as per Gadgil Formula.
Payment dependent on declared output capability of the plant for the day and
beneficiary’s percentage share in the plant and not on power/ energy intended to
be drawn or actually drawn.
The total amount payable to the generating company over a year towards the fixed cost
depends on the average availability (MW delivering capability) of the plant over the year.
In case the average actually achieved over the year is higher than the specified norm for
plant availability, the generating company gets a higher payment. In case the average
availability achieved is lower, the payment is also lower. It can be summarized in a tabular
form as:
PLANT AVAILABILITY FIXED COST RECOVERY
As per specified norms Full F.C.
Higher than norms Full F.C. + Incentive
Lower than Norms Prorata reduced F.C.
4.1.2 Energy charges:
Variable charges are to be paid against the actual energy consumed. These are levied
to reimburse the fuel cost for scheduled generation.
These charges are:
Paid as per the Energy Scheduled to be supplied from the plant to the
beneficiary during the day and not as per his actual drawal.
47
Any excess drawal beyond schedule shall be governed at rate dependent on
system frequency.
4.1.3 UI charges:
This is a payment for deviations from schedule, at a rate dependent on system
conditions. Variation between actual generation /drawal and scheduled
generation/drawal are accounted for through unscheduled interchange (UI) charges.
UI for generating station shall be equal to its actual generation minus its scheduled
generation. UI for a beneficiary shall be equal to its total actual drawal minus its
total scheduled drawal. UI charges are worked out for each 15 minute time block.
Charges for all UI transactions are based on average frequency of the time block
and the rates linked with the same.
The ABT regime stipulates that UI (Unscheduled Interchange) charges are payable under
the following conditions:
i. A generator generates more/less than the schedule causing grid frequency to deviate
upwards/downwards.
ii. A beneficiary draws more/less than the schedule causing grid frequency to deviate
downwards/upwards.
- 48 -
4.2 Need for ABT
Prior to the introduction of Availability Tariff, the regional grids had been operating in a
very undisciplined and haphazard manner. There were large deviations in frequency from
the rated frequency. The earlier tariff mechanisms did not provide any incentive for either
backing down generation during off-peak hours or for reducing consumer load / enhancing
generation during peak-load hours. In fact, it was profitable to go on generating at a high
level even when the consumer demand had come down. In other words, the earlier tariff
mechanisms encouraged grid indiscipline.
To enunciate we can say the need for implementing ABT grew up due to the following reasons:
1. Undisciplined and haphazard operation of Regional Grids
2. Large deviations in frequency from that of normal frequency
3. Chronic surpluses in Eastern & North-Eastern Region and shortages in Northern &
Western Regions resulted in substantial functioning of Regional Grids at frequencies which
are far beyond even the normal band liberally defined by IEGC i.e. 49.0 to 50.5 Hz
4. Continued operation at abnormal frequencies results in long term damages to generation
and end-user equipment’s.
5. There were no incentives in earlier Tariff mechanisms for the following :-
Backing down of generation during off-peak hours
Reducing consumer load/ enhancing of generation during peak-load hours
1. It was profitable to go on generating at a high level even when consumer demand had
come down.
2. In totality, earlier Tariff Mechanisms had no provisions to introduce grid-discipline and
rather it encouraged grid-indiscipline.
As an example let us consider the grid indiscipline that used to frequently haunt the officials
at Kerala state electricity board (KSEB).
- 49 -
The Availability Tariff directly addresses these issues. Firstly, by giving incentives for enhancing
output capability of power plants, it enables more consumer load to be met during peak load hours.
Secondly, backing down during off-peak hours no longer results in financial loss to generating
stations and the earlier incentive for not backing down is neutralized. Thirdly, the shares of
beneficiaries in the Central generating stations acquire a meaning, which was previously missing.
The beneficiaries now have well-defined entitlements, and are able to draw power up to the
specified limits at normal rates of the respective power plants. In case of over-drawal, they have
to pay at a higher rate during peak load hours, which discourages them from overdrawing further.
This payment then goes to beneficiaries who received less energy than was scheduled, and acts as
an incentive/compensation for them.
Pre – ABT Regime: In the Southern Grid, there was a wide variation between the demand
and supply. The distinct features of the Southern Grid before introducing ABT are:
Low frequency during peak-load hours, with frequency going down to 48.0 – 48.5 Hz
for many hours every day.
High frequency during off-peak hours, with frequency going up to 50.5 – 51.0 Hz for
many hours every day.
Rapid and wide changes in frequency, one Hz change in 5-10 minutes being a common
phenomenon.
Very low voltages for substantial period.
High voltages during off-peak hours, to the extent that even 400 KV trunk lines are
required to be switched off to contain the over-voltages.
Very frequent grid disturbances, causing tripping of generating stations, interruption of
supply to large blocks of consumers, and disintegration of the Regional grids.
- 50 -
4.3 IEGC Specifications
The IEGC brings together a single set of technical and commercial rules, encompassing all the
Utilities connected to/or using the inter-State transmission system (ISTS) and provides the
following:
1. Documentation of the principles and procedures which define the relationship between the
various Users of the inter-State transmission system (ISTS), National Load Dispatch Centre,
as well as the Regional and State Load Dispatch Centers.
2. Facilitation of the optimal operation of the grid, facilitation of coordinated and optimal
maintenance planning of generation and transmission facilities in the grid and facilitation of
development and planning of economic and reliable National / Regional Grid.
3. Facilitation for functioning of power markets and ancillary services by defining a common
basis of operation of the ISTS, applicable to all the Users of the ISTS.
4. Facilitation of the development of renewable energy sources by specifying the technical and
commercial aspects for integration of these resources into the grid.
According to the latest IEGC Regulations 2010, all Users, SEB,, SLDCs , RLDCs, and
NLDC shall take all possible measures to ensure that the grid frequency always remains
within the 49.5 –50.2 Hz band.1
All Users, CTU and STUs shall endeavor to operate their respective power systems and
power stations in an integrated manner at all times.1
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4.3.1 Voltage Specifications:
According to the latest IEGC Signed Regulations 2010:
All Users, RLDC, SLDC STUs, CTU and NLDC shall take all possible measures to ensure
that the grid voltage always remains within the following operating range.
Voltage – (kV rms)
Nominal Maximum Minimum
765 800 728
400 420 380
220 245 198
132 145 122
110 121 99
66 72 60
33 36 30
According to CERC (Indian Electricity Grid Code) Regulations, 2010
Table 6: IEGC Voltage Specification
All Users, CTU and STUs shall provide adequate voltage control measures through voltage
relay as finalized by RPC, to prevent voltage collapse. and shall ensure its effective
application to prevent voltage collapse/ cascade tripping.
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i. Reactive Power Charges:
Reactive power compensation should ideally be provided locally, by generating
reactive power as close to the reactive power consumption as possible. The
Regional Entities except Generating Stations are therefore expected to provide local
VAr compensation/generation such that they do not draw VArs from the EHV grid,
particularly under low-voltage condition.
To discourage VAr drawls by Regional Entities except Generating Stations, VAr
exchanges with ISTS shall be priced as follows:
The Regional Entity except Generating Stations pays for Var drawal when voltage at the
metering point is below 97%
The Regional Entity except Generating Stations gets paid for Var return when voltage is
below 97%
The Regional Entity except Generating Stations gets paid for Var drawal when voltage is
above103%
The Regional Entity except Generating Stations pays for Var return when voltage is above
103%
Provided that there shall be no charge/payment for Var drawal/return by a Regional Entity
except Generating Stations on its own line emanating directly from an ISGS.
4. 4 How ABT Works
ABT works on the principals of day ahead scheduling i.e the schedule for supply/drawal of power
has to be fixed one day before the actual action is taken. There are various agencies which are
involved in the ABT operating mechanism. These include the Central generating stations, Regional
load dispatch centers (RLDC), the State load dispatch centers (SLDC), and the various governing
SEB’s in the various states.
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How the day ahead scheduling for the various agencies involved is done can be outlined as follows:
The process starts with the Central generating stations in the region declaring their expected
output capability for the next day to the Regional Load Dispatch Centre (RLDC).
The RLDC breaks up and tabulates these output capability declarations as per the
beneficiaries' plant-wise shares and conveys their entitlements to State Load Dispatch
Centre’s (SLDCs).
SLDC’s then carry out an exercise to see how best they can meet the load of their
consumers over the day, from their own generating stations, along with their entitlement in
the Central stations. They also take into account the irrigation release requirements and
load curtailment etc. that they propose in their respective areas. The SLDCs then convey
to the RLDC their schedule of power drawl from the Central stations (limited to their
entitlement for the day).
The RLDC aggregates these requisitions and determines the dispatch schedules for the
Central generating stations and the drawl schedules for the beneficiaries duly incorporating
any bilateral agreements and adjusting for transmission losses. These schedules are then
issued by the RLDC to all concerned and become the operational as well as commercial
datum.
However, in case of contingencies, Central stations can prospectively revise the output
capability declaration, beneficiaries can prospectively revise requisitions, and the
schedules are correspondingly revised by RLDC.
Example:
Let us assume that a 1000 MW Central coal-fired power station has three beneficiaries
(States – X, Y and Z) with allocated shares of 40, 30 and 30% respectively.
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Suppose the station foresees a capability to deliver 1000 MW on the next day, and
advises the same to the RLDC by 9 AM. The RLDC would break it up, and advise the
three SLDCs by 10 AM that their entitlements in the Central station are 400, 300, 300
MW respectively, for the next day. Entitlements in the other Central stations would
also be advised by RLDC to the SLDCs similarly.
Simultaneously, the SLDCs would receive availability status from their intra - State
stations as well. They would then carry out a detailed exercise as to how best to meet
the expected consumer demand in their respective States over the 24 hours. For this,
they would compare the variable costs of various intra - State power stations inter-se,
and with energy charge rates of the Central stations, and also consider the irrigation
release requirements vs. energy availability of the hydro-electric stations. After this
exercise, the SLDCs will issue the dispatch schedules for the intra - State stations, and
their requisition from the Central stations.
Summation of the three requisitions would thus produce, for the Central generating
station, the total dispatch schedule of 1000 MW. This would be issued by the RLDC
by 5 PM, and would be effective from the following midnight (unless modified in the
intervening hours).
Capacity charges:
States – X, Y and Z shall pay capacity charge for the whole day corresponding to plant
availability of 400, 300 and 300 MW, and the generating station would get capacity charge
corresponding to 1000 MW.
Energy charges:
Now, assume that States – X and Y fully requisition their shares from the Central station
under consideration, while State – Z requisitions 200 MW during the day time (16 hrs), but
only 150 MW during the night hours (8hrs). Energy charge payments by the three States
would then be for 400 x 24 MWh, 300 x 24 MWh, and (200 x 16 + 150 x 8) MWh of
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energy respectively, at the specified energy charge rate of the generating station for the
three states X, Y and Z respectively.
Figure 7: Pictorial representation of Day Ahead Scheduling for ABT
The above figure is a pictorial representation of the entire process of the day ahead
scheduling that takes place amongst the various agencies during the current ABT regime.
It gives timeline wise details of the various process that takes place when fixing the
schedules for the next day.
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Figure 8: ABT operating mechanism
Scheduling - Provisions for Revision
In the event of bottleneck in evacuation of power due to any constraint, outage, failure or
limitation in the transmission system, RLDC revise the schedule, which is effective from
4th time block.
In case of forced outage of a unit, the RLDC revise the schedules on the basis of declared
capacity by the ISGS, which is effective from 4th time block.
RLDC may refuse any revision of schedules if revision sought is less than two percent of
the previous schedules
For any Grid disturbance all schedules shall be deemed to have been revised as per actuals
for all time blocks affected by the disturbance
After completion of 24 hours operation RLDC shall issue the implemented schedule, which
shall be datum for Commercial Accounting.
Deviations from schedules are determined in 15-minute time blocks through special
metering, and these deviations are priced depending on frequency. As long as the actual
generation/drawal is equal to the given schedule, payment on account of the third
component of Availability Tariff is zero. In case of under-drawal, a beneficiary is paid back
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to that extent according to the frequency dependent rate specified for deviations from
schedule.
4.5. Mechanism of ABT:
The Mechanism of ABT for both central and state generating stations is as follow.
4.5.1. For Central Generating Units:
Central generating stations in the region declaring their expected output capabilities, to the
RLDC and RLDC breaks up and elaborate the declaration and convey their entitlement to the
SLDC. SLDC than carry out an exercise to see how best they can meet the load of their
consumers over the day, from their own generating stations, along with their entitlement in the
Central stations. They also take into account the irrigation release requirements and load
curtailment etc. that they propose in their respective areas. The SLDCs then convey to the
RLDC their schedule of power drawal from the Central stations (limited to their entitlement
for the day).
The RLDC aggregates these requisitions and determines the dispatch schedules for the Central
generating stations and the drawal schedules for the beneficiaries duly incorporating any
bilateral agreements and adjusting for transmission losses. These schedules are then issued by
the RLDC to all concerned and become the operational as well as commercial datum. However,
in case of contingencies, Central stations can prospectively revise the output capability
declaration, beneficiaries can prospectively revise requisitions, and the schedules are
correspondingly revised by RLDC.
While the schedules so finalized become the operational datum, and the regional constituents
are expected to regulate their generation and consumer load in a way that the actual generation
and drawls generally follow these schedules, deviations are allowed as long as they do not
endanger the system security. The schedules are also used for determination of the amounts
payable as energy charges, as described earlier. Deviations from schedules are determined in
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15-minute time blocks through special metering, and these deviations are priced depending on
frequency.
4.5.2. For State generating units:
In case of state generating units, the generating utilities, send their projected generation
capability for the next day to the SLDCs, than SLDCs carry out an exercise to see how best
they can meet the load of their consumers over the day, from their generating stations, as
well as their entitlement in the Central stations
The SLDC aggregates these requisitions and determines the dispatch schedules for the
generating stations and the drawal schedules for the beneficiaries. These Dispatch schedules
are than communicated to the generating units.
4.6. The UI Mechanism
As the main part of the ABT is Unscheduled Interchange so as concerned to ABT, The energy
charge, at the specified energy charge rate of a generating station, is payable for the scheduled
energy supply. The energy actually supplied by the generating station may differ from what
was scheduled. If actual energy supplied were higher than scheduled, the generating station
would be entitled to receive a payment for the excess energy at a rate dependent on the grid
frequency at that time. If the energy actually supplied is less than what was scheduled, the
generating station shall have to pay back for the energy shortfall, at the same frequency –
linked rate.
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Figure 9: UI rates on 15.04.2012
As according to above graph there are three frequency zones in above graph:
Case – 1: When the grid frequency is above 50.2 Hz:
In this case, the UI rate is zero, which means that the generating station would not get any payment
for the extra energy supplied. It would burn fuel for producing this extra energy, but would not get
reimbursed for it at all. Conversely, if the actual energy supplied were less than scheduled energy,
the generating station would still be paid for the scheduled energy (at its energy charge rate)
without having to pay back anything for the energy shortfall. It would thus be able to save on fuel
cost (for the energy not generated) and retain the energy charge as net saving. Thus ABT motivates
the generators to cut down on power supply during times of high grid frequency and consequently
helps in bringing down the grid frequency.
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Case.2.When the frequency is below 49.5 Hz
At a frequency of 49.5 Hz, the UI rate is Rs. 8.73 per kWh presently. Under this condition, any
extra energy sent into the grid would get the generating station a UI payment at the rate of Rs. 8.73
per kWh. For any shortfall, the generating station shall have to pay back at the same rate. It would
thus have a strong commercial incentive to maximize its generation during periods of such low
frequency and bring the grid frequency near the normative value of 50 Hz.
Case.3. When Frequency is between 49.5Hz to 50.2 Hz:
In this case the UI rates falls rapidly from 49.5 Hz to 49.7 Hz at the rate of 53paisa per 0.02 Hz.
And after it, from 49.5 Hz to 50.2 Hz it falls slowly ate the rate 14.5 paisa per 0.02 Hz.
Now, as stated before, for the calculation of UI, the whole day is broken into blocks of 15 minutes
as grid frequency keeps on changing. Then the average supply/drawal is calculated for each of the
15 minute block and is compared with the scheduled supply/drawal to calculate the UI. The
calculated UI is then used to decide the payment on the basis of the average grid frequency for that
particular block.
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Table 7: Calculation of UI Charge
In the above example the generating station is generating less than the scheduled generation.
So the UI calculated is used to determine the amount it have to pay, according to the UI rate
applicable during that time block, to the UI pool.
Actual payment calculated according to GERC guidelines. The generator will pay @ 105% of
basic UI rate for all under-injection and receive payment for all over-injection@ 95% of the basic
UI rate at that frequency. Similarly, a beneficiary will receive payment @ 95% of the basic UI rate
for under-consumption and has to pay @ 105% of the basic UI rate for over-consumption.
The generator will still get its payment according for the scheduled supply and the UI charges will
be paid by him differently. Similar is the case with the beneficiary where it gets paid for under-
consumption. In the reverse scenario, the generating company will receive payment for over-
injection and the beneficiary will be charged for over-consumption as per the guidelines.
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4.6.1. Revised UI Rates :
The UI rates have been revised 2 times after the implementation of intra-state ABT in Gujarat. The
latest ones are given below which had been implemented after Order 6 of 2010.
Frequency UI Rate (paise/kwh)
Below (Hz) Not Below (Hz)
50.2 00.00
50.20 50.18 15.50
50.18 50.16 31.00
50.16 50.14 46.50
50.14 50.12 62.00
50.12 50.10 77.50
50.10 50.08 93.00
50.08 50.06 108.50
50.06 50.04 124.00
50.04 50.02 139.50
50.02 50.00 155.00
50.00 49.98 170.50
49.98 49.96 186.00
49.96 49.94 201.50
49.94 49.92 217.00
49.92 49.90 232.50
49.90 49.88 248.00
49.88 49.86 263.50
49.86 49.84 279.00
49.84 49.82 294.50
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49.82 49.80 310.00
49.80 49.78 325.50
49.78 49.76 341.00
49.76 49.74 356.50
49.74 49.72 372.00
49.72 49.70 387.50
49.70 49.68 403.00
49.68 49.66 450.00
49.66 49.64 497.00
49.64 49.62 544.00
49.62 49.60 591.00
49.60 49.58 638.00
49.58 49.56 685.00
49.56 49.54 732.00
49.54 49.52 779.00
49.52 49.50 826.00
49.50 873.00
(Each 0.02 Hz step is equivalent to 15.5 paise/kWh in the 50.2-49.68
Hz frequency range and 47.0 Paise/kWh in the 49.68-49.50 Hz
frequency range).
Table 8: Revised UI rates
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The graph for the corresponding UI rates according to Frequency is as shown below:
Figure 10: UI Rate Graph
In addition to these UI rates, additional UI rates are applicable for generators/consumers when grid
frequency goes in the lower regions.
Additional UI rate = 20% (generators) and 40% (consumers) of the basic UI rate when
frequency<49.5 Hz.
Additional UI rate = 40% (generators) and 100% (consumers) of the basic UI rate when
frequency<49.2 Hz.
4.7 Improvements in Grid Operation
Grid operation and subsequent stability has increased a lot after the implementation of ABT
regime. The Improvement of Grid condition due to the implementation of ABT can be seen in the
following:
1. There has been considerable improvement in frequency profile of the Regional Grids
month after month after the implementation of ABT. During the entire year (2005-06) of
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ABT period grid frequency in Northern grid remained in the normal band of 49.5Hz-50.50
Hz for 72.25 % of the time. The average frequency was 49.37% against 76% for the
corresponding pre-ABT period. It remained below 49.0 Hz for 26.76% of time and above
50.5 Hz for only 0.98% of the time.
2. The voltage profile has also shown considerable improvement after the implementation of
ABT.
3. Merit order dispatch is now also being followed by the constituents going by their station-
wise requisition. After implementation of ABT, the pithead stations are being scheduled
upto 99% of their DC, combined cycle ISGS is being scheduled to only 81.3% of the DC
(on account of less off-take from liquid fuel firing). This is in contrast to the pre-ABT
period when the requisition from pithead was lower than the post-ABT period while that
from combined cycle was higher than the post-ABT period.
4. With improved Grid conditions, chances of damages to Generation & other equipment
down the line got reduced substantially
5. Hydro electric generation is being harnessed more optimally than before.
6. Open access, wheeling of captive generations and power trading has become possible
through the UI mechanism for handling deviations/ mismatches.
The ABT mechanism has addressed the deficiencies in the existing system by:
Streamlining Grid Operations & Infusing Grid discipline among the players of Grid by
introducing incentives/disincentives for helping/disturbing the grid.
Maximizing generation from power plants through incentives for increased plant
availability.
More load demand has been met during peak-hours by enhancing output capability of
plants.
No financial loss to generators due to backing down during off-peak hours.
Encouraged ‘Merit-Order-Operation’ through clear separation of fixed and variable
charges and pit Head stations do not have to back down normally.
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Allocation of power to the beneficiaries from CGS could get a real meaning which was
previously missing.
Beneficiaries are discouraged for overdrawal during peak hours due to separate frequency
based higher rate for such over drawals.
Extra payment so collected (U.I. charges) goes to beneficiaries who received less than
scheduled energy as incentive/compensation.
As an illustration consider a typical day profile of the northern grid before and after
implementation of ABT.
Figure 11: Daily frequency profile before implementation of ABT
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Figure 12: Daily frequency profile post implementation of ABT
As, we can see there is a marked improvement in the grid stability after the implementation of
ABT.
As another example consider the case of Dadri thermal power station. As we can see post
ABT there has been a marked improvement in the operational Grid frequency.
Figure 13: Smoothened grid frequency curve recorded at Dadri TPS post implementation of ABT
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4.8 Effects of Adopting ABT
Prior to the introduction of Availability Tariff, the regional grids had been operating in a very
undisciplined and haphazard manner. There were large deviations in frequency from the rated
frequency of 50 cycles per second (Hz). It was taking place because of the Demand and supply
patterns. Low frequency was resulted by lacking of supply with respect to demand. High
frequency is a result of insufficient backing down of generation when the total consumer demand
has fallen during off-peak hours. Continuous functioning at non-standard frequency results in long-
term damages to both generation and end use equipment. This is a “hidden cost” which is borne
by the customer in the long term.
According to previous regulations, the generators were deemed to pay a penalty in case of
falling in the category of Deemed Non Generation (DNG). DNG condition was true
whenever the supplier under-supplied by an excess of 5% of the DC.
In such a case the generator will have to pay a penalty for (DC during that period – Actual
Supply. This is huge as compared to present scenario where such situations are handled by
UI in a relatively less strict way.
Previously, the generator could supply energy in a non-uniform fashion without getting
penalized. If the supplier pumped larger power during the beginning of a hour then it could
cover its schedule by supplying lesser power during the remaining time of the hour to meet
its supply schedule. This caused variation in the grid frequency and consequently grid
indiscipline.
ABT helps to control grid indiscipline in the following manner:
By giving incentives for enhancing output capability of power plants, it enables more
consumer demand to be met during peak load hours.
Backing down during off-peak hours (higher frequency) no longer results in financial loss
to generating stations, and the earlier incentive for not backing down is neutralized.
In case of over-drawal, the beneficiaries have to pay at a higher rate during peak load hours
(lower frequency), which discourages them from overdrawing further. This payment then
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goes to beneficiaries who received less energy than was scheduled, and acts as an
incentive/compensation for them.
Economic efficiency dictates that least cost power should be dispatched in preference to
more costly power (merit order dispatch). This becomes difficult without a two part tariff
for all stations. States tend to compare the total cost of central generators with the variable
cost of their own stations; since for them the fixed costs of state level stations are sunk
costs (Sunk Costs are the costs which have already been incurred. In this case the setting
up of transmission lines, transformers etc. that the state already has installed are counted
in sunk costs). This results in making the central generation appear artificially more
expensive than state level stations even though on variable cost basis the former may be
cheaper. The two part tariff system of ABT addresses this issue by making the payment of
fixed cost a fixed liability of the states. This levels the playing field between the central
and state generating plants.
Prior to the introduction of ABT beneficiaries were not liable to pay the fixed cost
associated with the share of capacity allocated to them. So, if a beneficiary decided not to
draw any energy he could escape payment of the fixed charge, which would then be paid
by the person drawing energy. This was unfair since it increased the cost of energy even
for those beneficiaries who would be drawing energy within their entitlements. Again, the
two-part tariff of the ABT assures that each beneficiary will be liable for payment of the
fixed cost associated with its share of allocated generation capacity.
ABT has led to stabilization of frequency by collective control thereby keeping it close to the
normative value of 50 Hz for maximum amount of time. This has increased grid discipline,
reduced grid losses and has paved the way for the establishment of an integrated national grid.
It has also lead to optimum utilization of resources in the power industry and has motivated
generating stations to increase their generation capacity.
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5.0 Limitations of the study
The report has tried to cover all the necessary details as in the broader sense but as it is just a report
certain shortcomings might be there. The reader is asked to please point them out and bring them
in the notice of the writer.
As the report was made in a very short period of time certain discrepancies might have crept in.
Although all due care has been taken to make the report as appropriate and correct as possible, but
still certain discrepancies might have crept in. the reader is requested to please bear with us and
point them out as necessary. Also, the data may become outdated after certain period of time,
hence the reader is requested to update as accordingly required.
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6.0 Conclusion
6.1 Conclusion and Findings:
The implementation of competitive bidding Indian power sector through the EA 2003 and the
NEP has promoted competition to get better tariff.
The bidding mechanism is a marked difference from the earlier cost plus mechanism
Likely Equity IRR for the first four UMPPS averages to 16%
Competitive bidding is one of the ways to introduce transparency and accountability in the
sector.
Competition will bring in optimization of resources, bring in operational and other
efficiencies and ultimately, lead to greater customer satisfaction
Tariff determined through competitive bidding has been found to be lower than cost
plus mechanism
CERC analysis indicated that tariff through competitive bidding is lower than cost plus
structure.
However, Cost Plus mechanism is still actively being deployed NTPC has undertaken a
massive PPA signing exercise with State discoms to the tune of 75,000 MW capacity to
come up by March 2017
The implementation of ABT philosophy has bought about various positive changes in the
Indian Power scenario.
Payment of Capacity Charges based on capacity available rather than energy generated has
drastically reduced unwanted generation.
The introduction of UI has increased power supply at low frequency (when demand is high)
and reduced power supply at high frequency (when supply is high).
ABT has led to better grid discipline leading to better grid frequency profile.
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If it is forecasted better about the load and availability than ABT can be better system for
earnings.
ABT promoted economically viable power with right pricing and it also promoted
competition and efficiency
Interface options to various stakeholders in the ABT mechanism online to enable effective
implementation and benefits to all Capability of power producers to be able to control their
cost of production as well as flexibility in operation
But ABT system is not a fool-proof system. It also has certain shortcomings.
The system of ABT requires regular and timely payment of the UI Energy Account for the
week issued by GERC.Payment of UI charges have a high priority. If the payment process
is disturbed even by a single generating station, then this can cause irregular
demand/supply forecasting leading to irregularities in quantity of electrical energy
supplied/consumed.
Demand forecasting becomes crucial and a lot of time and money of SLDC/ALDC gets
spent on it.
Requires special meters, remote metering with open protocols and communication
mechanisms to read meters timely
ABT need a better control over generation level and demand.
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7.0 Bibliography
CBG amendment 2005.
Revised CBG amendment, 2010.
IEGC draft regulations, 2010.
Electricity (Amendment) Act, 2003
Electricity (Amendment) Act, 2007
Introduction to ABT: A concept paper by Kalki Technologies.
ABC of ABT by Mr. Bhanu Bhushan.
www.sldcguj.com
www.cercind.gov.in
www.cea.nic.in
www.powermin.nic.in
www.essar.com
www.google.com
www.wikipedia.org
