104 jyotiranjan.pdf ntpc

Summer Internship Project Report

On

“Analysis of Energy Charges of NTPC Stations and

Optimization of Power Purchase Cost for DISCOM”

Under the guidance of

Dr. Manisha Rani, Sr. Fellow, NPTI &

Mr. RAJEEV CHOWDHURY, Head (Regulatory Affairs)

BSES Rajdhani power Limited

Submitted By

JYOTIRANJAN PRADHAN Roll No- 104

MBA (POWER MANAGEMENT)

2012-2014

Affiliated to

August 2013

ii

DECLARATION

I, JYOTIRANJAN PRADHAN, Roll No. 104, student of MBA (POWER MANAGEMENT) at

National Power Training Institute, Faridabad hereby declare that the Summer Training Report

entitled “Analysis of Energy Charges of NTPC Power Stations for Procurement of Fuel

Efficient Power & Optimization of Power Purchase Cost for DISCOM" 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 the 3rd September, 2013 on the same

and the suggestions as approved by the faculty were duly incorporated.

Presentation in charge Signature of the Candidate

(Faculty)

Countersigned

Director/Principal of the Institute

iii

ACKNOWLEDGEMENT

It gives me immense pleasure and satisfaction having completed the project successfully. I take

this opportunity to express my sincere gratitude to the people who have been instrumental behind

this success.

I express my sincere thanks to Mr. Rajeev Chowdhury, Head (Regulatory Affairs) BRPL and

Mr. Aditya Pyasi, D.G.M (Regulatory Affairs) for giving me a great opportunity to work in

such a dynamic organization and for guiding me in all stages of the project. I am thankful to Mr.

Kanishk Khettarpal, Asst. Manager for his guidance and support. I have a deep sense of

gratitude and respect for the entire staff of BRPL for sharing their knowledge and for assisting

me. Their help has sparked my interest even more.

I am indebted to Mr. S.K Choudhary, Principal Director, Mrs. Manju Mam, Director and Mr.

Amit Mishra, Asst. Director for providing me an opportunity to do my summer internship at

BRPL which was a great learning for me.

I would also like to thank my Project In-charge Dr. Manisha Rani, Sr. Fellow, National Power

Training Institute for her valuable inputs, assistance and support whenever required.

I would like to express my special thanks to my family and friends for their continuous

motivation, encouragement and support.

Jyotiranjan Pradhan

iv

EXECUTIVE SUMMARY

The DISCOMS of Delhi draw power mostly from various Central Generating stations and State

Generating Stations based on long term Power Purchase Agreements. The cost of long term

power is being fixed by the Central Electricity Regulatory Commission (CERC) for plants

supplying power to more than one State and by the Delhi Electricity Regulatory Commission

(DERC) for plants located within the NCT of Delhi and supplying only to distribution utilities in

Delhi. A small quantum of power is purchased in the short term during summer months to meet

the demand. The purchase/ sale of intra state power and intra state transmission charges are fixed

by the DERC. The short term purchases/ sale are through traders, bilateral contracts, banking,

and power exchanges at market determined prices. The tariffs of distribution companies are

determined by DERC.

In the ARR approved by the commission Power Purchase Cost constitutes more than 80% of

expenditure. The Commission approves the cost of power procurement after prudence check.

Power Purchase cost consists of fixed cost, Variable cost, Fuel Price Adjustment and

Transmission charges.

In recent times power tariff in Delhi has gone up to 65% tariff mostly due to increase in power

purchase cost of DISCOM. Since the power purchase costs vary based upon price(variable

charges) and calorific value of fuel (coal /gas) which is reflected in the bills submitted by the

generators every month, the entire power purchase cost process becomes unpredictable for the

distribution utilities, and hence, uncontrollable in nature. Also, the level of generation from these

stations each month determines the per unit impact of fixed charges.

In the present scenario when adequate availability of fuel continue to pose a serious challenge for

smooth running of thermal power plants, the use of imported coal or blended coal is the only

option available for attaining high plant availability, but has led to increase in the energy

charges of various central generating stations. However an in depth analysis of energy charges

billed various CGS and their Energy Charge Rate dependent on landed price of coal w.r.t. quality

of coal shows anomalous increase in the energy charges possibly due to inconsistency in both

price & quality of coal used. Hence there is a need for prudence check of energy charges billed

by GENCOS which is a direct pass through to DISCOMS and finally the Consumer tariff.

v

LIST OF FIGURES

FIGURE 1.1 Annual Power Purchase Cost Component in ARR of BRPL ………………….….04

FIGURE 1.2 Total Energy charges in Power Purchase Cost of BRPL………………………….05

FIGURE 1.3 Delhi Distribution area of BRPL…………………………………………………..09

FIGURE 2.1 Research Methodology followed for data collection……………………………....15

FIGURE 3.2 Average Revenue Requirement & Revenue Actually realized for BRPL………....29

FIGURE 4.3 Monthly Trend of LPPF & CVPF for BTPS for FY 12 & FY 13…………………34

FIGURE 4.7 Monthly Trend of LPPF & CVPF for Unchahar-I for FY 12 & FY 13………...…35

FIGURE 4.9 Monthly Trend of LPPF & CVPF for Unchahar-II for FY 12 & FY 13………..…36

FIGURE 4.12 Monthly Trend of LPPF & CVPF for Unchahar-III for FY 12 & FY 13……...…37

FIGURE 4.15 Monthly Trend of LPPF & CVPF for Farraka TPS for FY 12 & FY 13………...38

FIGURE 4.18 Monthly Trend of LPPF & CVPF for Kahelgaon-I TPS for FY 12 & FY 13……40

FIGURE 4.21 Monthly Trend of LPPF & CVPF for Kahelgaon-II TPS for FY 12 & FY 13…..41

FIGURE 4.24 Monthly Trend of LPPF & CVPF for NCPP-I for FY 12 & FY 13……………...42

FIGURE 4.27 Monthly Trend of LPPF & CVPF for NCPP-II for FY 12 & FY 13…………….43

FIGURE 4.30 Monthly Trend of LPPF & CVPF for Rihand-I for FY 12 & FY 13…………….44

FIGURE 4.33 Monthly Trend of LPPF & CVPF for Rihand-II for FY 12 & FY 13…………....45

FIGURE 4.36 Monthly Trend of LPPF & CVPF for Singrauli TPS for FY 12 & FY 13……….46

FIGURE 4.39 Monthly Trend of LPPF & CVPF for Aravali for FY 12 & FY 13……………...47

FIGURE 5.1 Correlation between month wise CVPF & LPPF of stations for FY 2011-12….....50

vi

FIGURE 5.2 Correlation factor derived between CVPF & ECR of stations for FY 2011-12…...51

FIGURE 5.3 Correlation between month wise CVPF & LPPF of stations for FY 2012-13…….52

FIGURE 5.4 Correlation factor derived between CVPF & ECR of stations for FY 2012-13…...52

FIGURE 5.7 Short Term Power Purchase/Sales Rate for FY 2010-12 to FY 2013-14………….54

LIST OF TABLES

TABLE 1.1 Consumer Profile of BRPL & BSES (DELHI Division)……………...……………02

TABLE 3.1 Build UP Revenue gap since FY2009-10 to FY 12-13…………………………......29

TABLE 3.3 ARR approved & Revenue surplus/deficit for FY 2013-14 ……………………….30

TABLE 4.1 Plant wise calculation of ECR & its components for FY 2011-12…………………33

TABLE 4.2 Plant wise calculation of ECR & its components for FY 2012-13………………....33

TABLE 4.42 Sale/Purchase Quantum & Rate of Short term power from FY 11 to FY 14……..48

TABLE 4.43 Category wise break up of Short Term Power purchase/Sale for FY 2011-12……49

TABLE 5.5 Comparison of Average Rate for FY 13-14 with Average ECR for FY 12 & 13….53

TABLE 5.6 Availability of power from New GENCOS for FY 2013-14…………………….....55

vii

LIST OF ABBREVIATIONS

Act / EA Electricity Act, 2003

ABR Average Billing Rate

AT&C Aggregate Technical & Commercial

CEA Central Electricity Authority

CERC Central Electricity Regulatory Commission

DERC Delhi Electricity Regulatory Commission

DISCOM Distribution Company

GENCOS Generation Companies

SGS State generating Stations

CGS Central generating Stations

DTL Delhi Transco Limited

SLDC State Load Dispatch Centre

STU State Transmission Utility

T&D Transmission & Distribution

UI Unscheduled Interchange

PPC Power Purchase Cost

ARR Average Revenue Requirement

ECR Energy Charge Rate

CVPF Calorific Value of Primary Fuel

LPPF Landed Price of Primary Fuel

CVSF Calorific Value of Secondary Fuel

LPSF Landed Price of Secondary Fuel

GHR Gross Station Heat rate

AUX Auxiliary Consumption

PPAC Power Purchase Adjustment Cost

FPA Fuel Price Adjustment

viii

TABLE OF CONTENTS

ACKNOWLEDGEMENT..............................................................................................................iii

EXECUTIVE SUMMARY............................................................................................................iv

LIST OF FIGURES.........................................................................................................................v

LIST OF TABLES..........................................................................................................................vi

ABBREVIATIONS.......................................................................................................................vii

CONTENTS.................................................................................................................................viii

CHAPTER-1

INTRODUCTION

1.1. HISTORY OF ELECTRICITY IN DELHI..............................................................................1

1.2. CHRONOLOGY OF DELHI PRIVATIZATION....................................................................1

1.3. CONSUMER PROFILE OF BRPL..........................................................................................2

1.4. PROBLEM STATEMENT.......................................................................................................3

1.5. OBJECTIVES OF THE PROJECT..........................................................................................3

1.6 BACKGROUND OF THE PROJECT......................................................................................6

1.7 ORGANIZATION PROFILE………........................................................................................7

1.7.1. About BSES Group....................................................................................................8

1.7.2 BSES Delhi……….....................................................................................................9

1.7.2.1. BSES Rajdhani Power Limited (BRPL).....................................................9

1.7.2.2. Business of the Organization……………………………………… ...…10

1.7.2.3. Classification of Supply………………………………………………....10

ix

CHAPTER-2

LITERATURE SURVEY, POLICY & RESEARCH METHODOLOGY

2.1. LITERATURE REVIEW.......................................................................................................11

2.2.1. Policies & Regulations.............................................................................................11

2.2.1.1 Determination of Tariff..............................................................................11

2.2.1.2. Multi Year Tariff Mechanism...................................................................11

2.1.1.3. Determination of Wheeling Tariff & Retail Supply of Tariff…………...13

2.2. RESEARCH METHODOLOGY...........................................................................................15

2.2.1. Correlation Analysis................................................................................................16

CHAPTER-3

ENERGY CHARGES DETERMINATION & MYT MODEL

3.1. COMPUTATION OF ENERGY CHARGES BY GENCOS.................................................17

3.1.1. Definitions................................................................................................................17

3.1.2. Components of Tariff...............................................................................................18

3.1.3. Computation and Payment of Capacity Charge and Energy Charge.......................18

3.2. MYT MODEL FOR DISTRIBUTION LICENSEE...............................................................22

3.2.1. ATE’s directive to SERCs for timely tariff determination......................................28

3.2.2. Revenue Gap............................................................................................................28

3.2.2.1. Treatment of Revenue Gap.......................................................................30

3.2.2.2. Fuel Price Adjustment Charges................................................................30

CHAPTER-4

RESULTS & DISCUSSION

4.1 RESULTS FROM STUDY OF ECR NTPC STATIONS ......................................................33

x

4.1.1. Variation of ECR with LPPF & CVPF FOR FY 2011-12.......................................33

4.1.2. Variation of ECR with LPPF & CVPF FOR FY 2012-13………………………...33

4.1.3. Plant wise analysis of LPPF & CVPF for NTPC stations.......................................34

4.2. STUDY OF SHORT TERM POWER PURCHASE/SALES.........................................48

CHAPTER-5

CONCLUSION & WAY FORWARD

5.1. CONCLUSION.......................................................................................................................50

5.1.1. Need for prudence check of Energy Charges billed……………………………50

5.1.2. Surrender of Power from Costly Power Plants ……………………………….......53

5.1.3. Better Scope of Management for Short term Power Purchase & Sales………...…54

5.2. WAY FORWARD..................................................................................................................54

5.3. LIMITATIONS OF THE PROJECT......................................................................................55

REFERENCES

ANNEXURE

1

CHAPTER -1

INTRODUCTION

1.1 History of Electricity in Delhi

The history of electricity in Delhi dates back to 1905 when M/s John Fleming Company was

awarded the license as per Indian Electricity Act, 1903, for generation and Distribution of power

in Delhi. Electricity those days was a luxury and the privilege of the high ranking British

officials and a few rich people. It was a rare and costly commodity with a perception of being

dangerous. In fact, even rich Indian accepted this at a much later stage. M/s John Fleming

Company was replaced by the Delhi Tramway and Lighting Company, which was subsequently

renamed as Delhi Electricity Supply & Traction Company. In 1939, The Delhi Central Electric

Power Authority (DCEPA) was formed to run the services. In 1951, the DCEPA was taken over

by the Delhi State Electricity Board, constituted under Indian Electricity (Supply) Act 1948. In

1958, Delhi Electricity Supply Undertaking came into existence and was once again converted to

Delhi Vidyut Board in 1997. In July 2002, Delhi Vidyut Board unbundled into five Successor

entities – the three distribution companies, a transmission and a holding Company. Two of the

three distribution companies have been handed over to BSES, and third to TATA POWER.

1.2 Chronology of the Delhi Privatization

February 1999

Delhi Government issues strategy paper outlining its intention to unbundled DVB, creates an

independent regulatory entity, and privatizes distribution while protecting employee interests.

May 1999

DERC established, it was initially created under an act of the Central Government and then later

notified under the state reform act.

October 2000

Delhi Electricity Reform Act formalized. In March 2001, the ordinance was given a stronger

legal foundation through conversion into an act. Tri-partite agreement between DVB, its

employees and the Delhi government, that protects the employment and pension rights of the

employees.

2

February 2001

Privatization process began with the Request for Qualification.

November 2001

Delhi Government issues Request for Proposals, issues a Policy Directive and announces the

transfer scheme.

February 2002

DERC issues an order that specifies opening loss levels and the initial Bulk Supply Tariff for

purchases made by the Discom from the Transco.

April 2002

Bids were received. The Cabinet of the Delhi government considers the bids to be unacceptable

“in present form” and creates a “Core Committee to explore alternatives including negotiation.

June 2002

Privatizations documents were signed with BSES and Tata.

July 2002

Date of privatization. June 2003 DERC issues first post-privatization tariff order.

1.3 BRPL CONSUMER PROFILE

S.N Particular Unit BRPL(South &

West) BSES DELHI

1 Area sq. km 750 950

2 Customer Density (As of Mar ‟13) Cons/sq

km 2465 3667

3 Total Registered Customers (As of

Mar ‟13) Million 1.85 3.2

4 Peak Demand (YTM FY 13)* Delhi

peak demand 5642 MW MW 2338 3799

Table 1.1: Shows Consumer Profile of BRPL & BSES (DELHI Division)

3

1.4 Problem Statement

1. The average power purchase cost of Delhi discoms has been increasing each year due to

escalation in fuel prices resulting in increase in the Average Revenue Requirement of the

discoms.

2. Increase in ARR has a direct impact on Consumer Tariff.

3. Increase in Regulatory Assets due to difference in Actual Cost of Supply & ARR realized

from tariff allowed pose a challenge to financial health of Discoms

1.5 Objectives of Project

1. To understand the day to day business & operations of regulatory department with respect to

ARR filings, True up filing and other related aspects of the commission.

2. To optimize the power purchase cost component in the ARR of discoms.

3. To analyze the energy charges & its various components used in calculation of ECR of

Central generating stations supplying power to Delhi discoms.

4

1.6 Background of Project

National Capital Territory of Delhi receives power from central generating stations, state

generating stations through the long-term power purchase agreements and short term purchases.

The Distribution Licensees procure power from various available sources and supply power to

consumers at retail tariffs determined by the Commission. The power purchase cost accounts for

about 80% of Annual Revenue Requirement of the distribution licensees(Figure 1.1) and

includes the cost paid for procurement of power, transmission charges, UI charges, SLDC/

RLDC charges and is netted off with revenue earned from sale of surplus power.

FIGURE 1.1: Annual Power Purchase Cost Component in ARR of BRPL

Source: ARR Petitions filed by BRPL & True UP Order of DERC

The cost of long term power being procured by the distribution licensees is being fixed by the

Central Electricity Regulatory Commission (CERC) for plants supplying power to more than one

state and by the Delhi Electricity Regulatory Commission (DERC) for plants located within the

State of Delhi. The charges for unscheduled interchanges and Inter State transmission charges

including RLDC charges are being fixed by the CERC. The charges for purchase / sale of intra

state power and intra state transmission charges are fixed by the DERC. The short term purchase/

sale are through traders, bilateral contracts, banking, and power exchanges at market determined

prices.

Thus, it can be seen that power purchase cost are uncontrollable in nature and are volatile

making it difficult to accurately estimate power purchase costs at the time of annual tariff

4351.695235.64

6109.016892.00

6131.17

3558.014506.40

5614.95 5969.006796.00

ARR Power Purchase Cost

5

fixation. The power purchase cost is beyond the control of distribution licensees and dependent

upon following factors:

Price of Fuel (Coal /Gas) which are highly unpredictable as has been seen from past few

years.

Availability of Power from New Sources.

Weather conditions such as extreme harsh summers/ cold which have direct impact on

the demand.

Demand Supply Gap of the power within the country.

The divergence in fixing of cost reflective tariffs by Central and State regulators has been one of

the main factors for the problems of the Distribution sector, which is now burdened with a

cumulative aggregate loss of about Rs. 2 lakh crores due to financially unviable distribution

sector. Apart from other things, the crippling financial situation of Discoms has led to inadequate

capitalization, depletion of legacy assets and insufficient introduction of technology and IT.

It is noteworthy that while the fuel charges are a complete pass through for Generation

utilities, the variation is energy charges and resultant power purchase cost are yet to be

implemented in line with the orders of Hon’ble ATE. There is hardly any prudence check on

the energy charges billed by GENCOS.

FIGURE 1.2 Total Energy charges in Power Purchase Cost of BRPL

Source: ARR Petitions filed by BRPL & True UP Order of DERC

4506.405614.95 5969.00

6796.00

1674.15

3926.493369

4434

FY 10-11 FY 11-12 FY 12-13 FY 13-14

Power Purchase Cost pf BRPL Energy Charges billes by Gencos

6

From the above figure we can estimate that the energy charges for DISCOM is above 60 % of

power purchase cost of discoms , thus reducing the energy charges by any means would cause a

substantial relief to customers.

Further, the distribution utilities are bound by the Hon’ble Commission’s Regulation of Power

Supply to make timely payments while the Generation companies are allowed to delay payments

for disputed coal quality and at the same time keep charging for the same delayed payments from

the consumers ultimately to be reflected in tariff exercise of discoms.

In this context I would like to draw attention towards some of the recent news articles from

leading newspapers related to non settlement of dues by NTPC towards Coal India Limited for

inferior quality of coal supply.

From article published in the Business Line print edition dated June 30, 2013 titled “CIL may

stop supply to NTPC Plants”,

“NTPC deducted over Rs 1,000 crore worth of payments, payable to the ailing CIL subsidiary,

against supplies during the past six months, citing quality issues. Though the coal produced from

the mine is graded between G-10 and G-13 in terms of heat value, NTPC claimed that the

supplies were of much inferior quality and paid Eastern Coalfields at the rate of the lowest rank

coal (G-17).”

According to The Economic Times article titled “Stones in coal cost NTPC over Rs 11,000 crore

per year”, dated Apr 3, 2013;

“With such a huge amount of unusable coal, power generation cost goes as high as Rs 5.5 per

unit in some cases," said a senior NTPC official. The power generation cost otherwise is around

Rs 2-3 per unit when the quality of coal is better."Ultimately, electricity consumers pay the price,

as all our costs are pass through under the pact,".

As per Govt. of India , notification CIL:S&M:GF:Pricing: 1813 dated 31.12.2011 CIL shifted

from existing Useful Heat Value(UHV) based grading and pricing of non-coking coal produced

from its subsidiaries to full Gross Calorific Value (GCV) based system .

7

GCV based grading system classifies non coking coal into 17 categories based on calorific

values(energy content) of coal ranging from 2200 Kcal/kg to 7000 Kcal/kg and above along with

a defined price for particular range in each category. NTPC and its subsidiaries requires coal

minimum of 3100 Kcal/kg for its operation which are based on sub-critical technology. NTPC

which fulfills its fuel requirements based on legally enforceable FSA‟s from CIL, had refused to

pay the amount of Rs 1100 Cr towards ECL alleging that it supplied inferior quality fuel and

billed for another grade.

Notably NTPC stations of Kahelgaon & Farraka also cater to the power needs of Delhi as per the

Long term PPA‟s act between Delhi Govt. & NTPC. Any increase in cost of generation on

account of low fuel quality by these stations would also pass on to the power purchase cost via.

Energy charges billed towards discoms including BRPL & hence an increase in consumer tariff.

So it is imperative to devise a mechanism in order to have a prudence check on energy bills of

GENCOS.

In case of Central generation/transmission entities once tariffs are fixed, there is little incentive

/penalty to improve on productivity/efficiency norms and they function in a very protected tariff

regime where costs are routinely passed on to them. Any benefits in improvement in

efficiencies/productivity are entirely retained by these entities whereas in the case of State

distribution utilities it is supposed to be passed on to the consumers.

While the regulatory regime for the CPSUs is conducive, with little political influence on tariff

determination, it is unfavorable for the Distribution utilities where retail tariff determination is a

highly politicized issue. As a result, while on one hand Central Public Sector Utilities (CPSUs)

in Power sector like NTPC, NHPC, PGCIL , DVC etc are showing enviable profits, the state

distribution utilities are becoming financially unviable.

1.7 Organization Profile

1.7.1. About BSES Group

BSES is the leading private sector power utility company in the country. BSES Limited is India's

premier utility engaged in the distribution of electricity. Formerly, known as Bombay Suburban

Electric Supply Limited, it was incorporated on 1st October 1929, for the distribution of

8

electricity in the suburbs of Mumbai, with a pioneering mission to make available

uninterrupted, reliable, and quality power to customers and provide value added services for

the development of the power and infrastructure sectors.

1. BSES‟s total consumer base is over 5 million covering substantial areas of Delhi, Goa,

Orissa and Mumbai.

2. Distribution area spans about 1.24 lakh sq. km covering an estimated population of 45 million.

3. Nearly 16,000 million units of electricity billed to industrial, commercial and residential

consumers with distribution capacity of nearly 6,000 MW. With 7 decades in the field of power

distribution, the Electricity Supply Division of BSES has achieved the distinction of operating its

distribution network with 99.98% on-line reliability and has a distribution loss of only 11.6%.

BSES is amongst the first utilities in India to adopt computerization in 1967 to meet the

increasing workload.

With a view to optimally utilize trained manpower and expertise in the field of power, the

company commenced contracting activities in 1966 by undertaking turnkey electrical contracts,

thermal, hydro and gas turbine installations and commissioning contracts, transmission line

projects etc. BSES set up its own 500 MW Thermal Power Plant and the first 2 x 250 MW units

of Dahanu Power Station were synchronized and began commercial operation during 1995-

1996. A dedicated 220 kV double circuit transmission line network with three 220 / 33kV

receiving stations have been installed to evacuate the power to the distribution area of the

Company. BSES through international competitive bidding acquired an equity stake of 51% in

three of the four Distribution Companies of Orissa.

1.7.2. BSES Delhi

Following the privatization of Delhi‟s power sector and unbundling of the Delhi Vidyut Board in

July 2002, the business of power distribution was transferred to BSES Yamuna Power Limited

(BYPL) and BSES Rajdhani Power Limited (BRPL). These two of the three successor entities

distribute electricity to 28.34 lakh customers in two thirds of Delhi. The Company acquired

9

assets, liabilities, proceedings and personnel of the Delhi Vidyut Board as per the terms and

conditions contained in the Transfer Scheme.

1.7.2.1 BSES Rajdhani Power Limited (BRPL)

BRPL distributes power to an area spread over 750 sq. km with a population density of 2192

per sq. km. It‟s over 16.44 lakh customers are spread over 19 districts across South and West

areas including Alaknanda, Khanpur, Vasant Kunj, Saket, Nehru Place, Nizamuddin, Sarita

Vihar, Hauz Khas, R.K. Puram, Janakpuri, Najafgarh, Nangloi, Mundka, Punjabi Bagh, Tagore

Garden, Vikas Puri, Palam and Dwarka. Since taking over distribution, BSES‟ singular mission

has been to provide reliable and quality electricity supply. BSES has invested over Rs 4500 crore

on upgrading and augmenting the infrastructure which has resulted in a record reduction of

AT&C losses. In BRPL area AT&C losses have been reduced from 51.2% to 18.09% in FY 11-

12 based on new norms (MYT Regulations, 2011) & propose to reduce it further to 16.43% by

FY 13-14 , a reduction of 34.7%.

FIGURE 1.3: Delhi Distribution area of BRPL.

10

1.7.2.2 Business of the Organization: Delhi Supply Division

Caters to an area of 950 sq. kms

Supply Area covers South Delhi, East Delhi, West Delhi and Central Delhi.

Consumers include houses, residential complexes, high rise buildings, commercial

Complex medium and large industrial houses, government establishment like Airport,

Worship places, Milk Dairy, Mother Dairy and Municipal Hospitals, Sewerage

projects etc.

Caters to more than 33 lakh consumers.

40% reduction in losses post takeover, current loss level 17%.

BSES forms 68% of Delhi‟s demand serving 3800 MW peak demand.

Invested close to Rs. 6000 Cr in last 10 years.

Provides highly reliable and continuous supply.

1.7.2.3. Classification of Supply

The Various categories of consumers served by BSES Rajdhani are as follows:-

1. Domestic connection

2. Non Domestic Low Tension

3. Mix Load High Tension

4. Small Industrial Power (SIP)

5. Large Industrial Power (LIP)

6. Agriculture Connection

7. Street Lighting & Signals

8. Delhi Airport Authority India Ltd (DAIL)

9. Delhi Metro Rail Corporation Ltd (DMRC)

10. Delhi Jal Board (DJB)

11

CHAPTER-2

LITERATURE SURVEY, POLICIES & RESEARCH

METHODOLOGY

2.1 Literature Review

2.1.1 Policies & Regulation

Electricity Act, 2003 confers the power of Policies & Regulation formulation in hands of

regulatory commissions. CERC (Central Electricity Regulatory Commissions) does the same for

central agencies and SERCs (State Electricity Regulatory Commissions) is for entities under

respective state government.

2.1.1.1. Determination of Tariff

Section 62 (1) of EA 2003 states that the Appropriate Commission shall determine the tariff in

accordance with provisions of this Act for –

(a) Supply of electricity by a generating company to a distribution licensee:

Provided that the Appropriate Commission may, in case of shortage of supply of electricity, fix

the minimum and maximum ceiling of tariff for sale or purchase of electricity in pursuance of an

agreement, entered into between a generating company and a licensee or between licensees, for a

period not exceeding one year to ensure reasonable prices of electricity;

(b) transmission of electricity ;

(c) wheeling of electricity;

(d) retail sale of electricity.

2.1.1.2 MYT Mechanism

Statutory framework

Section 61 of EA 2003 requires the Appropriate Commission to be guided by MYT Principles

while specifying the Terms and Conditions for determination of tariff.

Clause 5.3 (h) of the Tariff Policy stipulates that:

1. “The MYT framework is to be adopted for any tariffs to be determined from April 1, 2006.

The framework should feature a five-year control period. The initial control period may however

be of 3-year duration for transmission and distribution if deemed necessary by the Regulatory

12

Commission on account of data uncertainties and other practical considerations. In cases of

lack of reliable data, the Appropriate Commission may state assumptions in MYT for first

control period and a fresh control period may be started as and when more reliable data

becomes available

2. In cases where operations have been much below the norms for many previous years the

initial starting point in determining the revenue requirement and the improvement trajectories

should be recognized at “relaxed” levels and not the “desired” levels. Suitable benchmarking

studies may be conducted to establish the “desired” performance standards. Separate studies

may be required for each utility to assess the capital expenditure necessary to meet the minimum

service standards.

3. Once the revenue requirements are established at the beginning of the control period, the

Regulatory Commission should focus on regulation of outputs and not the input cost elements. At

the end of the control period, a comprehensive review of performance may be undertaken.

4. Uncontrollable costs should be recovered speedily to ensure that future consumers are not

burdened with past costs. Uncontrollable costs would include (but not limited to) fuel costs, costs

on account of inflation, taxes and cess, variations in power purchase unit costs including on

account of hydro-thermal mix in case of adverse natural events.”

Some states have notified MYT Regulations, and many have also issued MYT Orders, namely

Maharashtra, Delhi, Andhra Pradesh, and West Bengal.

Principles & Objectives of MYT

The Commission through these Tariff Regulations aims to meet the following objectives:

(a) Continue and improve upon the existing incentivisation framework to reward performance

and promote efficiency.

(b) Provide regulatory certainty to the investors and consumers by promoting transparency,

consistency and predictability of regulatory approaches.

(c) Ensure financial viability of the sector to attract investments & safeguard consumer‟s interest.

(d) Develop equitable risk sharing mechanism between utility and consumers

13

2.1.1.3. Determination of Wheeling Tariff & Retail Supply of Tariff

In accordance with Terms and conditions for DERC’s Determination of Wheeling tariff & Retail

Supply of Tariff-2011, the commission shall determine Average Revenue Requirement and

(ARR) and Tariff for-

i) Wheeling business &

ii) Retail supply business

Principles for Determination of ARR

ARR for Wheeling Business

The Aggregate Revenue Requirement for wheeling Business of the Distribution Licensee for

each year of the Control Period shall contain the following items;

I. Operation & Maintenance expenses;

II. Return on Capital employed;

III. Depreciation;

IV. Income Tax;

V. Interest on consumer security Deposit;

VI. Less: Non Tariff Income;

VII. Less: Income from other business; and

VIII. Less: Income from wheeling of electricity.

ARR for Retail Supply of Business

The Aggregate Revenue Requirement for Retail Supply Business of the Distribution Licensee for

each year of the Control Period shall contain the following items;

I. Cost of Power Procurement;

II. Transmission & Load Dispatch charges;

III. Return on Capital employed;

IV. Operation & Maintenance expenses;

V. Depreciation;

VI. [Income Tax;

VII. Interest on consumer security Deposit;

14

VIII. Less: Non Tariff Income;

IX. Less: Income from other business; and

X. Less: Receipts On account of Cross Subsidy Surcharge and additional surcharge for

open access customers.

Cost of Power Procurement

i) Quantum of Power Purchase – The commission approved category –wise sales forecast

shall be applied along with distribution loss trajectory foe estimating the Licensees‟

power procurement requirement for each year of control period.

ii) Distribution Licensee shall be allowed to recover the net cost of power it procures from

the sources approved by the commission, viz-Intra-state and inter–state Trading

Licensees, Bilateral purchases, Bulk suppliers ,State generators ,Independent Power

producers, Central generating Stations<non-conventional energy generators, generation

business of the distribution licensee and others, assuming maximum normative rebate

available fr4om each source of payment of bills through letter of credit on presentation of

bills for supply to consumers of Retail Supply Business;

a. Provide that the Distribution Licensee shall propose the cost of Power Procurement

taking into account the fuel adjustment formula specified for the generating stations and

net revenues through Bilateral exchanges and Unscheduled Interchange(UI) transactions;

b. Provided further that where the Licensees utilizes a part of power purchase approved or

bulk supply allocated or Contacted for the Retail Supply business, the Distribution

licensee shall provide an Allocation Statement clearly specifying the cost of power

purchase that is attributable to such trading activity.

iii) While approving the Power Purchase, the commission shall determine the quantum of

power to be purchased from various sources in accordance with the principles of merit

order schedule and dispatched based on ranking of all approved sources of supply in their

order of their variable cost of purchase. All power purchase shall be considered legitimate

unless it is established that the merit order principle has been violated or power has been

purchased at an unreasonable rates or the power procurement guidelines as laid down by

the commission from time to time has not be followed.

15

iv) To promote economic procurement of power as well as maximizing revenue from sale of

surplus power the commission may evolve an appropriate mechanism to

incentivize/penalize the Distribution Licensee.

v) The renewable purchase obligation shall be as per the order issued by the commission

from time to time.

2.2 Research Methodology

FIGURE 2.1 Research Methodology followed for data collection

Plant wise quantitative analysis for determining irregularities in energy charges & increase in PPC of BRPL

Correlation analysis between LPPF & CVPF & ECR of NTPC Stations

Calculation of ECR of various CGS from actual generation bills rose to BRPL for FY12 & 13

Study of ARR petitions & Tariff orders of BRPL for analyzing Power Purchase Cost

Study of regulations & orders of CERC for Tariff Determination for CGS & DERC for determination of ARR for Discoms

16

2.2.1 Correlation Analysis

The correlation measures the strength of the linear relationship between numerical variables, for

example, the height of men and their shoe size or height and weight. Pearson’s Correlation is

used in case of quantitative variables and is denoted by letter (r).

In these situations the goal is not to use one variable to predict another but to show the strength

of the linear relationship that exists between the two numerical variables.

The strength of linear association between two numerical variables in a population is determined

by the correlation coefficient, whose range is -1 to +1.

Graphically the greater the density of the points around the line, the greater the strength of the

Correlation between two variables.

In example I, the correlation is high; in example II, the correlation is low.

17

CHAPTER -3

ENERGY CHARGES & MYT MODEL

3.1. COMPUTATION OF ENERGY CHARGES BY GENCOS FOR TARIFF

DETERMINATION

3.1.1. Definitions

a. 'auxiliary energy consumption' or 'AUX' in relation to a period in case of a generating

station means the quantum of energy consumed by auxiliary equipment of the generating

station, and transformer losses within the generating station, expressed as a percentage of

the sum of gross energy generated at the generator terminals of all the units of the

generating station;

b. „beneficiary‟ in relation to a generating station means the person purchasing electricity

generated at such a generating station whose tariff is determined under these regulations;

c. „declared capacity‟ or „DC' in relation to a generating station means, the capability to

deliver ex-bus electricity in MW declared by such generating station in relation to any

time-block of the day or whole of the day, duly taking into account the availability of fuel

or water, and subject to further qualification in the relevant regulation;

d. 'design energy' means the quantum of energy which can be generated in a 90%

dependable year with 95% installed capacity of the hydro generating station;

e. „gross calorific value‟ or „GCV‟ in relation to a thermal generating station means the

heat produced in kCal by complete combustion of one kilogram of solid fuel or one litre

of liquid fuel or one standard cubic meter of gaseous fuel, as the case may be;

f. `gross station heat rate‟ or „GHR‟ means the heat energy input in kCal required to

generate one kWh of electrical energy at generator terminals of a thermal generating

station;

g. „installed capacity' or 'IC‟ means the summation of the name plate capacities of all the

units of the generating station or the capacity of the generating station (reckoned at the

generator terminals), approved by the Commission from time to time;

h. 'plant availability factor (PAF)' in relation to a generating station for any period means

the average of the daily declared capacities (DCs) for all the days during that period

18

expressed as a percentage of the installed capacity in MW reduced by the normative

auxiliary energy consumption

i. 'scheduled energy' means the quantum of energy scheduled by the concerned Load

Despatch Centre to be injected into the grid by a generating station over a day ;

j. „scheduled generation‟ or „SG' at any time or for any period or time-block means

schedule of generation in MW or MWh ex-bus, given by the concerned Load Despatch

Centre;

3.1.2. Components of Tariff.

The tariff for supply of electricity from a thermal generating station shall comprise two parts,

namely, capacity charge (for recovery of annual fixed cost consisting of the components

specified to in regulation 14 ) and energy charge (for recovery of primary fuel cost and limestone

cost where applicable)as per CERC’s Terms and Conditions of Tariff,2009 regulations.

The annual fixed cost (AFC) of a generating station or a transmission system shall consist of the

following components –

(a) Return on equity;

(b) Interest on loan capital;

(c) Depreciation;

(d) Interest on working capital;

(e) Operation and maintenance expenses;

(f) Cost of secondary fuel oil (for coal-based and lignite fired generating stations only);

(g) Special allowance in lieu of R&M or separate compensation allowance, wherever applicable

3.1.3. Computation and Payment of Capacity Charge and Energy Charge for Thermal

Generating Stations

1) The fixed cost of a thermal generating station shall be computed on annual basis, based on

norms specified under these regulations, and recovered on monthly basis under capacity

charge. The total capacity charge payable for a generating station shall be shared by its

19

beneficiaries as per their respective percentage share / allocation in the capacity of the

generating station.

2) The capacity charge (inclusive of incentive) payable to a thermal generating station for a

calendar month shall be calculated in accordance with the following formulae :

i) Generating stations in commercial operation for less than ten (10) years on 1st April of

the financial year :

AFC x ( NDM / NDY ) x ( 0.5 + 0.5 x PAFM / NAPAF ) (in Rupees);

Provided that in case the plant availability factor achieved during a financial year (PAFY) is

less than 70%, the total capacity charge for the year shall be restricted to AFC x ( 0.5 + 35 /

NAPAF ) x ( PAFY / 70 ) (in Rupees).

ii) For generating stations in commercial operation for ten (10) years or more on 1st

April of the year:

AFC x ( NDM / NDY ) x ( PAFM / NAPAF ) (in Rupees).

Where,

AFC = Annual fixed cost specified for the year, in Rupees.

NAPAF = Normative annual plant availability factor in percentage

NDM = Number of days in the month

NDY = Number of days in the year

PAFM = Plant availability factor achieved during the month, in percent:

PAFY = Plant availability factor achieved during the year, in percent

(3) The PAFM and PAFY shall be computed in accordance with the following formula:

N

PAFM or PAFY = 10000 x Σ DCi / { N x IC x ( 100 - AUX ) } %

20

i = 1

Where,

AUX = Normative auxiliary energy consumption in percentage.

DCi = Average declared capacity (in ex-bus MW), subject to clause (4) below, for the ith

day of the period i.e. the month or the year as the case may be, as certified by the

concerned load dispatch centre after the day is over.

IC = Installed Capacity (in MW) of the generating station

N = Number of days during the period i.e. the month or the year as the case may be.

Note : DCi and IC shall exclude the capacity of generating units not declared under

commercial operation. In case of a change in IC during the concerned period, its average

value shall be taken.

(4) In case of fuel shortage in a thermal generating station, the generating company may

propose to deliver a higher MW during peak-load hours by saving fuel during off-peak

hours.

The concerned Load Despatch Centre may then specify a pragmatic day-ahead schedule

for the generating station to optimally utilize its MW and energy capability, in

consultation with the beneficiaries. DCi in such an event shall be taken to be equal to the

maximum peak-hour expower plant MW schedule specified by the concerned Load

Despatch Centre for that day.

(5) The energy charge shall cover the primary fuel cost and limestone consumption cost

(where applicable), and shall be payable by every beneficiary for the total energy

scheduled to be supplied to such beneficiary during the calendar month on ex-power

plant basis, at the energy charge rate of the month (with fuel and limestone price

adjustment). Total Energy charge payable to the generating company for a month shall

be:

(Energy charge rate in Rs./kWh) x {Scheduled energy (ex-bus) for the month in kWh.}

(6) Energy charge rate (ECR) in Rupees per kWh on ex-power plant basis shall be

determined to three decimal places in accordance with the following formulae:

21

a) For coal based and lignite fired stations

ECR = { (GHR – SFC x CVSF) x LPPF / CVPF + LC x LPL } x 100 / (100 – AUX)

(b) For gas and liquid fuel based stations

ECR = GHR x LPPF x 100 / {CVPF x (100 – AUX)}

Where,

AUX = Normative auxiliary energy consumption in percentage.

CVPF = Gross calorific value of primary fuel as fired, in kCal per kg, per litre or per

standard cubic metre, as applicable.

CVSF = Calorific value of secondary fuel, in kCal per ml.

ECR = Energy charge rate, in Rupees per kWh sent out.

GHR = Gross station heat rate, in kCal per kWh.

LC = Normative limestone consumption in kg per kWh.

LPL = Weighted average landed price of limestone in Rupees per kg.

LPPF = Weighted average landed price of primary fuel, in Rupees per kg, per litre or

per standard cubic metre, as applicable, during the month.

SFC = Specific fuel oil consumption, in ml per kWh.

(7) The landed cost of fuel for the month shall include price of fuel corresponding to the

grade and quality of fuel inclusive of royalty, taxes and duties as applicable,

transportation cost by rail / road or any other means, and, for the purpose of computation

of energy charge, and in case of coal/lignite shall be arrived at after considering

normative transit and handling losses as percentage of the quantity of coal or lignite

dispatched by the coal or lignite supply company during the month as given below :

Pithead generating stations : 0.2%

Non-pithead generating stations : 0.8%

22

(8) The landed price of limestone shall be taken based on procurement price of limestone for

the generating station, inclusive of royalty, taxes and duties as applicable and

transportation cost for the month.

(9) The tariff structure as provided in this regulation may be adopted by the Department of

Atomic Energy, Government of India for the nuclear generating stations by specifying

annual fixed cost (AFC), normative annual plant availability factor (NAPAF), installed

capacity (IC), normative auxiliary power consumption (AUX) and energy charge rate

(ECR) for such stations.

3.2 MYT Model for Distribution Licensee

Uncontrollable & Controllable parameter

Regulatory Commission has segregated the costs and performance elements into controllable and

uncontrollable based on the ability of the licensee to manage each of them.

Uncontrollable Parameters

Those parameters which are beyond the control of utility, following are some of the

uncontrollable factors

(a) Power purchase expenses due to increase in fuel costs and change in sales quantum.

(b) Sales quantum & sales mix.

(c) Interest expense on long term loan & working capital

(d) Increase in expenses due to force majeure such as fire, war, natural calamities, etc.

Targets for Controllable Parameters

The Commission shall set targets for each year of the Control Period for the parameters that are

deemed to be “controllable” and which include

23

(a) AT&C Loss, which shall be measured as the difference between the units input into the

distribution system and the units realized (units billed and collected) wherein the units

realized shall be equal to the product of units billed and collection efficiency.

(b) Distribution losses, which shall be measured as the difference between total energy input

for sale to all its consumers and sum of the total energy billed in its License area in the

same year.

(c) Collection efficiency, which shall be measured as ratio of total revenue realized to the

total revenue billed for the same year.

(d) Operation and Maintenance Expenditure which includes employee expenses, repairs and

maintenance expenses, administration and general expenses and other miscellaneous

expenses viz. audit fees, rents, legal fees etc.

(e) Return on Capital Employed.

(f) Depreciation.

(g) Quality of Supply.

Operation & Maintenance Expenses (O&M) expenses comprise of costs incurred on a

day to- day basis in order to run the business efficiently. These costs include:

Employee Cost

Employee cost shall be computed as per the approved norm escalated by consumer price index

(CPI), adjusted by provisions for expenses beyond the control of the Distribution Licensee and

one time expected expenses, such as recovery/adjustment of terminal benefits, implications of

pay commission, arrears and Interim Relief, governed by the following formula:

EMPn = (EMPb * CPI inflation) + Provision

Where:

EMPn: Employee expense for the year n

EMPb: Employee expense as per the norm

24

CPI inflation: is the average increase in the Consumer Price Index (CPI) for immediately

preceding three years. Provision: Provision for expenses beyond control of the Distribution

Licensee and expected one-time expenses as specified above

Repairs and Maintenance Expense

Repairs and Maintenance expense shall be calculated as percentage (as per the norm defined) of

Opening Gross Fixed Assets for the year governed by following formula:

R&Mn = Kb* GFAn

Where:

R&Mn: Repairs & Maintenance expense for nth year

GFAn: Opening Gross Fixed Assets for nth year

Kb: Percentage point as per the norm

Administrative and General Expense

A&G expense shall be computed as per the norm escalated by wholesale price index (WPI) and

adjusted by provisions for confirmed initiatives (IT etc. initiatives as proposed by the

Distribution Licensee and validated by the Commission) or other expected one-time expenses,

and shall be governed by following formula:

A&Gn = (A&Gb * WPI inflation) + Provision

Where:

A&Gn: A&G expense for the year n

A&Gb: A&G expense as per the norm

WPI inflation: is the average increase in the Wholesale Price Index (WPI) for

immediately preceding three years

Provision: Cost for initiatives or other one-time expenses as proposed by the Distribution

Licensee and validated by the Commission.

Mechanism for sharing of gains or losses on account of controllable factors

The approved aggregate gain to the Distribution Licensee on account of controllable factor of

aggregate technical and commercial (AT&C) losses shall be dealt with in the following manner:

a) One-third of the amount of such gain shall be passed on as a rebate in tariff over such period

as may be stipulated in the Order of the Commission.

25

b) The balance amount, which will amount to two-third of such gain, may be utilized at the

discretion of the Distribution Licensee.

The approved aggregate loss to the Distribution Licensee on account of controllable factor of

aggregate technical and commercial (AT&C) losses shall be dealt with in the following manner:

a) Two-thirds of the amount of such loss may be passed on as an additional charge in tariff

over such period as may be stipulated in the Order of the Commission.

b) The balance amount of loss shall be absorbed by the Distribution Licensee. The gain or loss

on account of other controllable factors, unless otherwise specifically provided by the

Commission shall be to the account of the Distribution Licensee.

Annual Truing-up mechanism

The Commission shall review variations in approved values of uncontrollable parameters

through an annual truing up mechanism while there shall be no adjustment for variations in

controllable items. Annual truing-up shall be carried out for variations due to sales and power

purchase costs.

Return

The principle for providing return to the transmission and distribution licensee has been based on

the principle of Return on Capital Employed (RoCE) on a regulated rate base, with the weighted

average cost of capital to be determined independently for each year of the Control Period. In

case of generating companies, the principle for providing return has been based on the Return on

Equity.

Sales forecast

a) The Commission based on the Licensee‟s filings, shall examine the forecasts for

reasonableness and consistency, and shall approve the sales forecast for each year of the

Control Period.

b) Sales shall be treated as uncontrollable. The open access transactions shall not form part of

sales. Power purchase quantum and cost for any Financial Year shall be computed on the

basis of AT&C loss targets and the estimated sales.

26

Capital Investment - The Commission shall approve capital investment plan of the Licensees

for the Control Period commensurate with load growth, distribution loss reduction and quality

improvement proposed in the Business Plan. The investment plan shall also include

corresponding capitalization schedule and financing plan.

Quality of Supply and Customer Service - The quality of supply and the customer service

parameters shall be monitored as per the norms to be prescribed by the Commission separately

from time to time.

a) Voltage fluctuations: Licensee shall maintain voltages at the point of commencement of

the supply to a consumer within the limits stipulated by the commission.

b) Meter complaints : The licensee shall perform the following meter related activities

subject to the provisions provided in the Supply Code and other associated regulations

and codes specified by the commission.

Other parameters of quality of supply should be followed as per the instruction by the

commission. Some of the parameters are listed below:-

1. Operation of call center

2. Restoration of supply

3. Shifting of meters/service lines

4. New connections/additional load

5. Transfer of ownership and change of category

6. Temporary supply of power

7. Consumer bills complaint

8. Disconnection of supply

9. Reconnection of supply following disconnection due to non-payment of bills

10. Street Light faults

Reliability Indices

The Commission shall impose a uniform system of recording and reporting of distribution

system reliability performance. The same reliability indices shall be imposed on all licensees

under that commission. The performance target levels set by the Commission shall be unique to

27

each licensee to be based initially on the historical performance of licensee. The licensee shall

compute the following distribution reliability indices:-

a. System Average Interruption Frequency Index (SAIFI = Total number of sustained

interruptions in a year / Total number of consumers

b. System Average Interruption Duration Index (SAIDI) = Total duration of sustained

interruptions in a year / Total number of consumers

c. Momentary Average Interruption Frequency Index (MAIFI) = Total number of

momentary interruptions in a year / Total number of consumers

Contingency Reserve

The Commission has also created a Contingency Reserve (CR) for each licensee at the start of

the Control Period for minimizing the impact of uncontrollable factors on retail tariffs and

ensures tariff stability across the Control Period.

Income Tax

Income Tax, if any, on the Licensed business of the Distribution Licensee shall be treated as

expense and shall be recoverable from consumers through tariff. However, tax on any income

other than that through its Licensed business shall not be a pass through, and it shall be payable

by the Distribution Licensee itself.

The income tax actually payable or paid shall be included in the ARR. The actual assessment of

income tax should take into account benefits of tax holiday, and the credit for carry forward

losses applicable as per the provisions of the IT Act 1961 shall be passed on to the consumers.

Non-Tariff Income

All incomes being incidental to electricity business and derived by the Licensee from sources,

including but not limited to profit derived from disposal of assets, rents, delayed payment

surcharge, meter rent (if any), income from investments other than contingency reserves,

miscellaneous receipts from the consumers and income to Licensed business from the Other

28

Business of the Distribution Licensee shall constitute Non-Tariff Income of the Licensee.

3.2.1. ATE‟s directive to SERCs for timely tariff determination

The Appellate Tribunal for Electricity (ATE) issued a judgment in its order dated 11 November

2011 and in its judgment has directed all SERCs to initiate suo-moto proceedings for tariff

determination in case of delays by the utilities in filing their tariff petitions. The key features of

ATE‟s directive are mentioned below:

1. It should be the endeavor of every State Commission to ensure that the tariff for the financial

year is decided before 1st April of the tariff year, for which tariff petition should be filed by the

end of November of the previous year. Truing-up should also be an annual exercise.

2. In the event of any delay in filing the ARR, truing-up and Annual Performance Review, one

month beyond the scheduled date of submission of the petition, the State Commission must

initiate suo-moto proceedings for tariff determination.

3. The recovery of the Regulatory Asset (RA) should be time-bound and within a period not

exceeding three years at the most and preferably within the control period. The carrying cost of

the RA should be allowed to the utilities in the ARR of the year in which the RA are created to

avoid the problem of cash flow to the distribution licensee.

4. Fuel and Power Purchase cost is a major expense of the distribution company, which is

uncontrollable. The Fuel and Power Purchase cost adjustment should preferably be on a monthly

basis but in no case exceed a quarter. Any State Commission that does not already have such a

formula/mechanism in place must put in place such a formula/ mechanism within 6 months of

the date of this order.

3.2.2. Revenue Gap

The gap between tariff and cost has increased over time, as in FY 2011-12, there was a need to

increase the tariff by about 22% in all categories to recover cost. This is primarily because of

mounting regulatory assets & fuel price driven costs -the largest component of the cost of supply

have grown quite significantly in the recent past.

29

TABLE 3.1 Build UP Revenue gap since FY2009-10 to FY 12-13

Revenue Gap BRPL BYPL TPDDL TOTAL

UPTO FY 2008-09 (611.50)

25.93 (351.10) (936.67)

FY 2009-10 (1,068.70) (532.58) (741.46) (2,352.11)

FY 2010-11(as approved by commission)

(1,545.72) (1,120.93) (963.61) (3,630.26)

FY 2011-12(Projected by DISCOMs)

(4,233.00) (2,216.00) (1,783.00) (8,282.00)

FY 2012-13(Projected by DISCOMs)

(1,779.00) (1,690.00) (885.00) (4,354.00)

Total Revenue Gap (9,237.39) (5,533.58) (4,734.17) (19,505.04)

SOURCE: Statutory advice of DERC dated 01.02.2013

The table below gives the revenue gap built due to difference between the ARR claimed by

BRPL & Revenue actually realized from the prevalent tariff philosophy as approved by

commission for respective year.

FIGURE 3.2 Average Revenue Required & Revenue Actually Realized by tariff for BRPL

Source: ARR approved FY 13-14, Review of FY 12-13 & True Up order FY-10, 11,12 of BRPL

4351.69

5235.64

6109.01

6892.006131.17

3408.323929.66

4572.58

5890.00

6785.90

-943.37 -1305.98

-1536.43

-1002.00654.73

FY 09-10 FY 10-11 FY 11-12 FY 12-13 FY 13-14

ARR of BRPL Revenue available from Tariff Revenue (Gap)/ Surplus

30

3.2.2.1. Treatment of Revenue Gap

In order to meet this revenue gap, DERC has decided to continue with a surcharge of 8% on

partial liquidation of accumulated deficit and meeting of carrying cost of the past deficit of three

DISCOMs BRPL, BYPL & TPDDL.

TABLE 3.3 ARR approved & Revenue surplus/deficit for FY 2013-14

Particulars BRPL BYPL TPDDL TOTAL NDMC

ARR claimed 7,802.11 5,118.98 6,123.08 19,044.17 1,368.95

ARR approved 6,131.17 3,625.12 4,692.62 14,448.91 1,036.69

Revenue at existing tariff excluding 8 % surcharge

6,785.90 3,584.19 4,989.93 15,360.02 920.91

Revenue(gap)/surplus 654.73 (40.13) 297.31 911.91 (115.48)

Surcharge 542.87 286.80 399.19 1,228.86 -

Total (gap)/surplus 1,197.60 246.67 696.50 2,140.77 (115.48)

SOURCE: DERC’s Press Release Tariff orders of DISCOMs during FY 13-14

3.2.2.2. Fuel Price Adjustment Charge

Any fluctuation in the cost of fuel is a pass through for the generator through a fuel price

adjustment formula and is payable by the distribution licensees in their monthly bills.

However, power purchase cost being uncontrollable, in nature, is pass-through to the consumers

but the difference in actual cost of procurement of power and the estimated cost of purchase of

power gets trued up only after 2 years. The time lag of two years puts additional burden on

consumers by way of interest charges which have to be borne by the consumers, additionally.

The DERC vide its Order dated August 26, 2011 in Petition Nos 22/2010, 23/2010 and 24/2010 has

given the Fuel Price Adjustment mechanism on quarterly basis for thermal power generating

stations having long-term PPAs with distribution licensees of Delhi. The Distribution licensee is

allowed to adjust the difference between the actual variable fuel cost and variable fuel cost

approved in the Tariff Order for the financial year on a quarterly basis, in respect of thermal power

stations having long term power purchase agreements.

31

a. The Fuel Price Adjustment would be done according to the formula given below:

Where, VC = Variable Cost/Charges billed by the generating companies for the concerned power

station for the relevant period

Average Rate of FPA nth Qtr. (Rs. /Kwh) = Avg. VC (n-1) th Qtr. (Rs. /Kwh) – Avg.VC (Base) (Rs. /Kwh)

V.C. per unit in (n-1)th Qtr x units procured from respective Thermal plants in (n-1)th Quarter

Avg. VC (n-1)th Qtr (Rs/kWh) = ___________________________________________________________

Total units procured from all thermal stations in (n-1) th Quarter.

b. The percentage increase on account of FPA will be applied as a surcharge on the total

energy charges (excluding fixed charges, theft bills, arrears, LPSC, E. Tax etc.) billed to a

consumer of the utility

c. The FPA calculated for any quarter shall be applied prospectively for 3 months after

approval is received from the Commission.

d. In view of the fact that FPA computed for any quarter will be applied after a time delay for

a subsequent 3-month period, there would necessarily be a difference between the actual

fuel cost increase and the recovery by the distribution utility through the quarterly

32

adjustments. The difference will be adjusted at the time of annual True-up undertaken by

the Commission for that year.

e. This Fuel Price Adjustment (FPA) formula shall remain applicable till it is amended,

reviewed, revised or otherwise amended.

The Commission via Press Release during Tariff orders of DISCOMs during FY 13-14 informed

that the prevailing Tariff for Fy 2013-14 includes 3 % to 4.5 % of PPAC in tariff for all

category of consumers.

33

CHAPTER-4

RESULTS & DISCUSSION

4.1 RESULTS FROM STUDY OF ENERGY CHARGE RATE OF NTPC STATIONS

4.1.1 The correlation values derived from the comparison of various pit /non pit head

stations from April 2011 to March 2012:

TABLE 4.1 Plant wise calculations of ECR & its components for FY 2011-12

4.1.2. The correlation values derived from the comparison of various pit /non pit head

stations from April 2012 to March 2013:

TABLE 4.2 Plant wise calculations of ECR & its components for FY 2012-13

1 Non Pit BTPS 2825 3100 3.2 3.2 0.72 0.89 0.33

2 Non Pit Unchahar-I 2500 3361 2.7 2.2 0.12 0.83 -0.46

3 Non Pit Unchahar-II 2500 3365 2.7 2.2 0.11 0.80 -0.51

4 Non Pit Unchahar-III 2500 3363 2.7 2.2 0.11 0.80 -0.51

5 Non Pit NCPP-I 2500 3777 4.1 2.9 0.13 0.84 -0.42

6 Non Pit NCPP-II 2424 3919 4.1 2.7 -0.54 0.95 -0.78

7 Non Pit Aravali 2421 2876 3.4 3.0 0.34 0.87 -0.18

8 Pit head Farraka 2453 3517 4.5 3.4 0.61 0.95 0.32

9 Pit head KHTPS-I 2500 2786 2.8 2.7 0.71 0.96 0.50

10 Pit head Rihand-I 2385 3539 1.9 1.4 -0.13 0.98 -0.31

11 Pit head Rihand-II 2425 3458 1.9 1.4 0.03 0.99 -0.12

12 Pit head Singrauli 2463 3366 1.7 1.3 -0.66 0.98 -0.81

13 Pit head KHTPS-II 2425 2786 2.8 2.6 0.71 0.96 0.50

SOURCE : Actual bills raised by various power plants to BRPL in FY 2011-12

Avg. ECR

(Rs./kWh)

SHR

(Kcal/kWh)S.No.

FY 2011-12

Correlation

b/w

LPPF & ECR

Correlation

b/w

CVPF & ECR

Pit Head

/Non Pit

Head

Station NameAvg. CVPF

(Kcal/Kg)

Avg. LPPF

(Rs./Kg)

Correlation

b/w

CVPF & LPPF

1 Non Pit BTPS 2825 3117 3.49 3.49 -0.26 0.97 -0.47

2 Non Pit Unchahar-I 2500 3473 2.87 2.27 -0.44 0.95 -0.70

3 Non Pit Unchahar-II 2500 3470 2.87 2.27 -0.50 0.95 -0.74

4 Non Pit Unchahar-III 2500 3470 2.87 2.27 -0.49 0.95 -0.73

5 Non Pit NCPP-I 2500 3759 3.93 2.84 0.83 0.93 0.57

6 Non Pit NCPP-II 2424 3670 3.90 2.73 0.62 0.95 0.36

7 Pit head Farraka 2453 3024 2.90 2.49 0.73 0.95 0.48

8 Pit head KHTPS-I 2500 2612 2.04 2.14 0.42 0.97 0.17

9 Pit head Rihand-I 2385 3494 1.49 1.11 -0.08 0.96 -0.34

10 Pit head Rihand-II 2425 3386 1.49 1.13 -0.11 0.98 -0.28

11 Pit head Singrauli 2463 3422 1.39 1.08 -0.72 0.99 -0.81

12 Pit head KHTPS-II 2425 2612 2.04 2.02 0.42 0.97 0.17

SOURCE : Actual 1st bills raised by various power plants to BRPL in FY 2012-13

Correlation

b/w

CVPF & ECR

FY 2012-13

S.No.

Pit Head

/Non Pit

Head

Station NameSHR

(Kcal/kWh)

Avg. CVPF

(Kcal/Kg)

Avg. LPPF

(Rs./Kg)

Avg. ECR

(Rs./kWh)

Correlation

b/w

CVPF & LPPF

Correlation

b/w

LPPF & ECR

34

4.1.3. Plant wise Statistical analysis of components of Energy Charge Rate using Pearson‟s

Correlation (Refer to ANNEXURE –I for Plant wise details of ECR components)

BTPS

The FIGURE 4.3 below shows the variations in price of coal for the calorific value of coal used

in respective months:

FIGURE 4.5 Correlation for ECR & CVPF FIGURE 4.6 Correlation for ECR & LPPF

.

Inference:

In FY 11-12 the calorific value of coal varied from 2754 kCal/Kg in Sep-11 to a maximum value

of 3300 kCal/Kg in May-11.Within a year we observe that during Apr-11 , for CVPF of

3258kcal/Kg ,the LPPF charged was Rs 3.22/Kg while the next year during Apr-12 the LPPF

rose to Rs 4.1/Kg for almost the same CVPF of Coal. As a result ECR too rose above Rs 4/unit.

35

On UHV basis the quality remained within the range of F Grade throughout the FY12 & FY 13.

UNCHAHAR-I

The Figure 4.7 below shows the variations in price of coal for the calorific value of coal used in

respective months: -

FIGURE 4.8 Correlation between ECR & CVPF FIGURE 4.9 Correlation ECR & LPPF

Inference:

From the trend & correlation we find that very little correlation between LPPF & CVPF was

established during FY-12 & 13 due to fact that both “E” & “F” grade as on UHV basis of fuel

36

was used. The minimum ECR was Rs 1.89/Unit during Apr-11 and rose to Rs 2.57/Unit during

Jun-12.

UNCHAHAR –II



Figure 4.10 Correlation between ECR & CVPF Figure 4.11Correlation between ECR & LPPF

37

UNCHAHAR –III

The FIGURE 4.12 below shows the variations in price of coal for the calorific value of coal

used in respective months:

Figure 4.13 Correlation between ECR & CVPF Figure 4.14 Correlation between ECR & LPPF

Inference:

From the trend between LPPF & CVPF we find that both “E” as well as “F” grade of coal was

used durimg FY 12& FY 13 for Unchahar-I, II & III. However the correlation between ECR &

CVPF was negative as desired in FY 12 & 13 which shows good linearity between both the

components & less fluctuation in calorific value of coal if landed price is kept constant. The

38

average CVPF for all three stations was around 3365 kCal/Kg for which average LPPF was

charged at Rs. 2.70/kg and the average ECR calculated was Rs 2.20/Unit.

FARAKKA TPS



Figure 4.16 Correlations between ECR & CVPF Figure 4.17 Correlation b/w ECR & LPPF

39

Inference

From the graph, we can observe that for CVPF of Coal about 3600 kcal/kg, the landed price

charged varies widely. For a CVPF of about 3600 kcal/kg the price was Rs 5.4 /kg in the month

of Jun‟11 whereas another higher variety of coal at around 3900kcal/kg fetched Rs 4.6/kg in the

month of April‟11.In another case, a variety of coal at 3600kcal/kg is charged at two different

prices in the month of Sep‟11 & Oct‟11at Rs 5/kg & Rs 4.3/kg respectively.

For FY 12 “F” grade coal was used towards the end of the year but for FY -13, “F” grade of coal

was used throughout the year.

However the correlation between ECR & CVPF was found to be negative when ideally it must

have been as close to -1. This is because use of higher grade of coal during FY 12 & 13 did not

bring any benefit in reducing ECR of station, rather in FY 12 the average ECR was Rs.3.37/Unit

when average CVPF was 3500kcal/Kg.

While in the FY 13, the average ECR was Rs 2.49/Unit, despite of using low calorific value of

fuel at an average of 3000kCal/Kg.

40

KHTPS- I



FIGURE 4.19 Correlation between ECR & CVPF ; FIGURE 4.20 Correlation between ECR & LPPF

0

1000

2000

3000

4000

1.50 2.50 3.50 4.50

CV

PF

(kC

al./

Kg)

ECR (Rs./kWh)

Correlation between ECR &

CVPF for KHTPS-I for FY 12

& FY 13

…

41

KHTPS-II



FIGURE 4.22 Correlation between ECR & CVPF; FIGURE 4.23 Correlation between ECR & LPPF

Inference for KHTPS-I & II:

From the monthly trend of CVPF & LPPF we find that in FY-12 the LPPF was higher compared

to FY-13 for the same CVPF of coal i.e. average of 2600-2700 kcal/Kg. As a result ECR for both

the stations were high for FY-12 than FY-13.

42

Average ECR for KHTPS-I was Rs 2.72/Kg in FY 12 & in FY 13 was Rs.2.14/Kg .Average

ECR for KHTPS-II was Rs 2.57/Kg in FY 12 & in FY 13 was Rs.2.02/Kg.

The negative correlation between ECR & CVPF suggests that increase in calorific value of fuel

did not result in decrease in ECR, since the advantage of having low ECR by using better CVPF

of coal was offset by comparatively higher prices charged for nearly same grade of primary fuel

used.

NCPP-I



FIGURE 4.25 Correlation between ECR & CVPF ; FIGURE 4.26 Correlation between ECR & LPPF

43

Inference

From the trend we can figure out that the price of coal month wise continued to remain above

Rs4/Kg from June -11 although the quality if coal used decreased from 4000kCal/Kg to

3500kCal/Kg.

NCPP-II



INFERENCE

From the trend line between CVPF & LPPF, we find that there exists a negative correlation for

FY 2011-12, due to the fact that the prices remained above Rs 4. /Kg from June -11 onwards

throughout even if the calorific value of the coal varied to low levels for rest of the year i.e.

below 4000kCal/Kg.

44

FIGURE 4.28 Correlation between ECR & CVPF; FIGURE 4.29Correlation between ECR & LPPF

Inference for NCPP-I & II:

The correlation between LPPF & CVPF for FY-12 was negative or least positive. This is

because the fuel of a given Calorific value has been charged differently during the year. For

instance a 4000 kcal/kg of coal was charged at Rs 3.4/Kg during Apr-11 & within two months

the same coal was priced at Rs.4.4/kg, an increase in landed price by 30%.In another case during

FY-13 , a lower calorific value of fuel at 3753kCal/kg was priced at Rs 4.59/Kg in Jun-12.

RIHAND-I


in respective months

45

FIGURE 4.31 Correlation between ECR & CVPF FIGURE 4.32 Correlation between ECR & LPPF

RIHAND-II



46

FIGURE 4.34Correlation between ECR & LPPF FIGURE 4.35 Correlation between ECR & CVPF

The trend line between CVPF & LPPF shows a comparatively higher price charged i.e. above

Rs2.5/Kg for lower grade of coal in August &September than April & May.

Inference for Rihand –I &II:

Both the stations used “E” grade UHV of coal which was around 3400-3500 Kcal/Kg. The

average LPPF for the same was Rs. 1.93/Kg for both the stations during FY11-12 & Rs 1.49/Kg

for FY 12-13.Average ECR for both the stations in FY 12 was Rs 1.45/Unit & in FY13 Rs

1.13/Unit, the lowest amongst all NTPC stations.

SINGRAULI


47


Inference:

The higher negative correlation between ECR & CVPF shows the cost advantage of using higher

quality of fuel resulting in lowering the ECR.

The average ECR for FY11-12 was Rs. 1.32/Kg & for FY 12-13 was Rs 1.08/Kg, being the

cheapest source of power for the DISCOM.

ARAVALI



48


4.2. ANALYSIS OF SHORT TERM PURCHASE/SALE OF POWER THROUGH

VARIOUS SOURCES

The short purchases/ sales are through traders, bilateral contracts, banking, and power exchanges

at market determined prices. As regards the Short Term Power Purchase Cost of BRPL, it was

observed that the power was procured at a higher rate while the same was sold in short term

markets at a lower rate during surplus sale of power.

TABLE 4.42 Sale/Purchase Quantum & Rate of Short term power from FY 2010-11 to FY 2013-14

Year

Short

Term

energy

purchase

(MU)

Short

Term

Purchase

(Cr.)

Short

Term

Power

purchase

(Rs./unit)

Surplus

Sales

(MU)

Short

Term

power

sales

(Cr.)

Surplus

Power

Sales

(Rs./Unit)

Net Power

Purchase Rate

incl. Inter-

state & Intra-

state charges

(Rs./Unit)

2010-11 2576.46 1319.8 5.12 2289.83 735.03 3.21 4.31

2011-12 1714 671 3.91 2393 773.18 3.23 5.18

2012-13 1282 535 4.17 3771 1202 3.19 5.26

2013-14 0 0 0.00 7742 2501 3.23 5.16

SOURCE: True Up order for FY 2010-11& 11-12, ARR approved for FY 2012-13 &13-14

0.00

1.00

2.00

3.00

4.00

0.00 2.00 4.00 6.00

LPP

F (R

s./K

g)

ECR (Rs./kWh)

Correlation between ECR & LPPF for Aravali for FY 12 & FY 13

EC…

49

From the above table, it is observed that a gap of Rs. 1.91/unit for FY 10-11, Rs.0.68/unit for FY

11-12 & Rs. 0.99/unit for FY 12-13 was incurred due to procurement & then sale of surplus

power in short term markets.

The category wise purchase & sales figures for FY 11-12 in the table below shows that sale of

power through Bilateral (IEX) & Banking mechanism involved higher units of about 2000 MU‟s

with a gap of Rs 0.70/Unit. This resulted to the rise in net energy cost of power procurement to

Rs 4.19/Unit (after considering surplus sale of 773 MU at Rs 3.23/Unit) from Rs 4.02/Unit (after

considering short term purchase at Rs. 3.91/Unit) in FY 2011-12.

Table 4.43 Category wise break up of Short Term Power purchase/Sale for FY 2011-12

FY 2011-12 Power Purchase from other sources Power Sold to other Sources

PARTICULARS MU Rs Cr. Rs./Unit MU Rs Cr. Rs./Unit

Intra State Power 93 35 3.82 12 4 3.33

BILATERAL / IEX 502 182 3.63 1080 313 2.90

Banking 954 386 4.04 999 371 3.71

UI 166 67 4.06 303 86 2.84

TOTAL 1714 671 4.79 2393 774 3.23

SOURCE: True Up Petition for FY 11-12 However, it is notable that the quantum of short term purchase has been reduced significantly

over the years & has been proposed to be nil for FY 2013-14. This is due to increase in quantum

of long term procurement of power from new additional units from Central as well as State

Generating Stations approved by respective commissions. The DERC has approved the sale of

2501 MU‟s of surplus power by BRPL for FY 2013-14 and has assumed the rate for the same at

Rs 4.00/Unit.

If this rate as per DERC is considered, the Net power purchase cost (after sale of surplus power)

can be reduced provided the average purchase rate of both existing & new Central/State

GENCOS is less than Rs 4/Unit.

50

CHAPTER -5

CONCLUSION & WAY FORWARD

5.1 CONCLUSION 5.1.1. Need for prudence check of Energy Charges billed

It is imperative to perform the prudence check of Energy Charges billed by the generation

companies. An analysis of energy charges billed by generating companies shows that there is a

hardly any correlation between the Landed price of primary fuel (LPPF), Calorific value to

primary fuel (CVPF) and the resultant Energy Charges billed.

In general, the correlation between the Landed Price of Primary Fuel (LPPF) and Calorific

Value of Primary Fuel (CVPF) should be high for a particular plant. But the analysis of the

same proves to be otherwise. The correlation for most of the Central Generating stations

supplying power to Delhi is insignificant and even negative for some.

The correlation values derived from the comparison of CVPF & LPPF of various pit /non pit

head stations are found to be as per the following figure 5.1;

Figure 5.1 Correlation between month wise CVPF & LPPF of stations for FY 2011-12

51

From the Figure 5.1, we find that correlation coefficient is significantly less or negative for

various stations. Ideally the coefficient should attain nearest possible value to 1, but the lower

levels or negative values signifies that possibility of price charged for the coal used at a constant

station heat rate is inconsistent with the quality of coal used.

The correlation is negative for NCPP-II & Singrauli power stations. Thus the price charged in

LPPF component for computation of ECR is either higher for lower grade of coal or differs

widely from station to station for the same grade of coal used.

The correlation values derived from the comparison of CVPF &ECR of various pit /non pit head

stations from March 2011 to April 2012 are found to be as per the following figure;

Figure 5.2 Correlation factor derived between CVPF & ECR of stations for FY 2011-12

As per CERC‟s guidelines for the calculation of energy charge rate, ECR of stations, the ECR

varies inversely proportional to the CVPF used at a fixed station heat rate (SHR).

Thus the correlation factor should be as close as possible to -1.

But from the analysis we find that (r) is positive for BTPS, Farraka, KHTPS-1, & KHTPS-2.

This indicates fluctuations in the landed price of coal used for calorific value within a particular

range.

52

Figure 5.3 Correlation between month wise CVPF & LPPF of stations for FY 2012-13

From the figure 5.3, we find that correlation coefficient is significantly less or negative for

various stations. Ideally the coefficient should attain nearest possible value to + 1.The correlation

shows high irregularities in price & grade if primary fuel for BTPS, Unchahar I, II, III &

Singrauli. Thus the price charged in LPPF component for computation of ECR is either higher

for lower grade of coal or differs widely from station to station for the same grade of coal used.

Figure 5.4 Correlation factor derived between CVPF & ECR of stations for FY 2012-13

53

As per CERC‟s guidelines for the calculation of energy charge rate, ECR of stations, the ECR

varies inversely proportional to the CVPF used at a fixed station heat rate (SHR) .

Thus the correlation factor should be as close as possible to -1.But from the analysis we find that

(r) is positive for NCPP-I, II, Farraka, KHTPS-I, II. This indicates fluctuations in the landed

price of coal used for calorific value within a particular range.

5.1.2. Surrender of Power from Costly Power Plants

The total quantum of energy requirement at the distribution periphery for FY 2013-14 approved

for FY 2013-14 on the distribution loss at 12.89% is 11348 MU. Of this, the total share

contributed by various CGS of NTPC is 75% and amounts to 8827 MU. A major share of which

belong to APCPL, BTPS, NCPP-I & II procured at an average rate of Rs 5.9/Unit, Rs 4.74/Unit,

Rs.4.06/Unit & Rs 4.41/Unit respectively, which are the costliest source of power amongst Non

Pit Head stations.

Similarly , Farraka and KHTPS-I & II continue to be costliest source of power delivering to

Delhi at Rs 3.5/Unit, Rs 3.27 & Rs 3.26/Unit respectively, despite of being Pit head stations and

are at par with the average rate of power purchase of some of the non pit head stations.(Refer to

Table 5.5)

TABLE 5.5 Comparison of Average Rate for FY 13-14 with Average ECR for FY 12 & 13

Sl No Pit/Non Pit

NTPC Stations BRPL's share FY 14 (MU)

Average Rate FY 2013-14 (Rs./Unit)

Average ECR for FY 2012-13 (Rs./Unit)

Average ECR for FY 2011-12 (Rs./Unit)

1 Non Pit BTPS 1413 4.74 3.49 3.2

2 Non Pit NCPP - DADRI 1943 4.06 2.84 2.9

3 Non Pit DADRI EXTENSION 2195 4.41 2.73 2.7

4 Non Pit APCPL 444 5.9 - 3

5 Non Pit UNCHAHAR - I 75 3.51 2.27 2.2

6 Non Pit UNCHAHAR - II 138 3.99 2.27 2.2

7 Non Pit UNCHAHAR - III 93 3.95 2.27 2.2

8 Pit Head FARAKKA 54 3.51 2.49 3.4

9 Pit Head KAHALGAON - I 139 3.27 2.14 2.7

10 Pit Head RIHAND - I 305 2.23 1.11 1.4

54

11 Pit Head RIHAND - II 435 2.12 1.13 1.4

12 Pit Head SINGRAULI 506 1.7 1.08 1.3

13 Pit Head KAHALGAON - II 404 3.26 2.02 2.6

SOURCE: ARR order for FY 13-14 & Actual bills rise to BRPL for FY 12 & 13

Thus it is necessary to reconsider the quantum of power purchased from costly stations &

surrender the power wherever alternative a source of power is feasible.

5.1.3. Better Scope of Management for Short term Power Purchase & Sales

Since earlier it was observed that the short term sales through various sources were at a lesser

rate than the short term purchase rate in the past 3 years, it is necessary to have adequate banking

arrangements & less UI mechanism for sale of surplus power at a comparatively higher rate .

FIGURE 5.7 Short Term Power Purchase/Sales Rate for FY 2010-12 to FY 2013-14

SOURCE: TRUE UP order of FY 10-11, 11-12, ARR OF FY 13-14, Review OF FY 12-13

As per DERC order on ARR of BRPL for FY 2013-14, the commission has approved that no

additional purchase o power is required from short term transactions. However the commission‟s

assumptions on sale of surplus units at Rs 4/Unit is challenging since past trend shows power

sales at a lower rate in short term markets.

5.2 WAY FORWARD

Alternative sources of power from new or existing stations must be looked for future

requirements subject to availability & technical constraints. The commission vide its order on

ARR for FY 13-14 has approved the quantum of 1001 MU from GENCOS for supplying power

to BRPL as per Table given below;

55

TABLE 5.6 Availability of power from New GENCOS for FY 2013-14

New Generating Stations Capacity in

(MW)

Energy available to BRPL (MU)

Average Rate (Rs. /Unit)

Chamera - III 231 65 4.46

Chandrapur Extn ( U7 & U8) 500 564 3.55

Parbati - III 520 42 4.50

Rihand - III 500 54 2.94

Sasan UMPP 3960 215 1.19

Uri - II 240 61 4.50

Total 5951 1001 3.17

The power procurement from Sasan UMPP at Rs 1.19/Unit would help in optimizing the Gross

Power purchase Cost to some level. Thus it is imperative for BRPL to undergo PPA with more

such UMPP‟s in future for procurement of fuel efficient power.

5.3. Limitations of the Project

1. Gross station heat rate (GHR) has been considered as per specified by the Hon‟ble

Commission for MYT 2009-14.

2. The same GHR has been quoted by the GENCOS in their bills.

3. The correlation between Landed Price of Primary Fuel & Calorific Value of Primary fuel

Coal has been considered to be linear corresponding to supply of coal from a single mine

throughout the year via the same route to a particular thermal generating station.

4. Correlation has been performed through Pearson‟s correlation on the actual first billed

data for FY 2011-12 and FY 2012-13.

56

REFERENCES

[1] “New CERC Regulations To Encourage Investment, Efficiency In Power Sector”, 2009,

ICRA Limited.

[2] Li Yingde; “Study on Whole Process Quality Control in Coal Production Based on Industry

Engineering”, College of Mechanical Engineering, Zhejiang University of Technology,

Hangzhou, P.R, China.

[3] Nobuo Tanaka, Roger Wicks “Power Generation From Coal- Measuring & Reporting

efficiency Performance”, International Energy Agency.

[4] Daniel Mahr, “Major issues relating to coal quality from the perspective of Thermal power

generation”, P.E of US based Energy Associates, P.C.

[5] “Price Notification”, Coal India Limited, May 27, 2013, India.

[6] U.S. Department of Energy Office of Energy Efficiency and Renewable Energy, “Power

Purchase Agreement Checklist for State and Local Governments”, 2009, NREL publication, U.S.

[7] “MYT Generation Terms and Conditions for Determination of Generation Tariff)

Regulations, 2007”, Delhi Electricity Regulatory Commission

[8] “Terms & Conditions for Determination of Wheeling Tariff and Retail Supply”, Delhi

Electricity Regulatory Commission, 2011,India,

[9] “Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations,

2009, India.

[10] “State-Owned Electricity Distribution Companies”, ICRA Research, March 2012, New

Delhi.

[11] “Emerging opportunities & challenges-Power sector”, PWC Consulting, Jan2012, New

57

Delhi.

[12] “New Pricing of Non Coking Based Coal” CIL Notification, December 31, 2011, India

[13] VINCENT MAZZONE “The Latest Sampling Techniques And Testing Processes Used In

Coal Quality Management, Sgs Group Management Ltd., 2011, Switzerland.

[14] Ashim Choudhury, Kalyan Sen “An Experience of third party sampling of coal”, Central

Fuel Research Institute.

[15]”Report of The Group for Studying Range of Blending of Imported Coal with Domestic

Coal” Central electricity Authority, April 19,2011,India.

[16] Tariff Order for DISCOMS & GENCOS in Delhi [Online]. Available:

http://www.derc.gov.in/

ANNEXURE

Badarpur TPS Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2825 9.5 1 9.47 3.22 3258 3.07 G14 F

May-11 2825 9.5 1 9.45 3.32 3300 3.13 G14 F

Jun-11 2825 9.5 1 9.46 3.48 3258 3.33 G14 F

Jul-11 2825 9.5 1 9.48 3.42 3294 3.23 G14 F

Aug-11 2825 9.5 1 9.47 3.37 3254 3.22 G14 F

Sep-11 2825 9.5 1 9.47 2.13 2754 2.41 G16 F

Oct-11 2825 9.5 1 9.47 2.81 2913 3.00 G15 F

Nov-11 2825 9.5 1 9.50 3.50 3099 3.51 G15 F

Dec-11 2825 9.5 1 9.48 3.36 2874 3.64 G15 F

Jan-12 2825 9.5 1 9.53 3.11 2991 3.23 G15 F

Feb-12 2825 9.5 1 9.52 3.27 3106 3.27 G14 F

Mar-12 2825 9.5 1 9.54 3.40 3100 3.41 G15 F

Apr-12 2825 9.5 1 9.47 4.10 3148 4.05 G14 F

May-12 2825 9.5 1 9.56 3.37 3080 3.40 G15 F

Jun-12 2825 9.5 1 9.47 3.55 3071 3.60 G15 F

Jul-12 2825 9.5 1 9.46 3.54 3072 3.59 G15 F

Aug-12 2825 9.5 1 9.47 3.55 3058 3.61 G15 F

Sep-12 2825 9.5 1 9.53 3.91 3070 3.97 G15 F

Oct-12 2825 9.5 1 9.53 3.60 3090 3.62 G15 F

Nov-12 2825 9.5 1 9.53 3.28 3060 3.34 G15 F

Dec-12 2825 9.5 1 9.51 3.28 3138 3.26 G14 F

Jan-13 2825 9.5 1 9.52 3.27 3177 3.20 G14 F

Feb-13 2825 9.5 1 9.52 3.15 3157 3.10 G14 F

Mar-13 2825 9.5 1 9.53 3.33 3285 3.16 G14 F

Unchahar-I Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2500 9 1 9.99 2.44 3522 1.90 G13 E

May-11 2500 9 1 9.99 2.73 3512 2.13 G13 E

Jun-11 2500 9 1 9.99 2.55 3316 2.10 G14 F

Jul-11 2500 9 1 9.99 2.63 3135 2.30 G14 F

Aug-11 2500 9 1 9.99 2.65 3306 2.19 G14 F

Sep-11 2500 9 1 9.99 2.96 3302 2.46 G14 F

Oct-11 2500 9 1 9.99 2.70 3200 2.31 G14 F

Nov-11 2500 9 1 9.99 2.78 3488 2.18 G13 E

Dec-11 2500 9 1 9.99 2.83 3553 2.18 G13 E

Jan-12 2500 9 1 9.99 2.57 3323 2.12 G14 F

Feb-12 2500 9 1 9.99 2.54 3295 2.11 G14 F

Mar-12 2500 9 1 9.99 2.99 3382 2.42 G14 E

Apr-12 2500 9 1 9.99 2.73 3466 2.15 G13 E

May-12 2500 9 1 9.99 3.12 3478 2.45 G13 E

Jun-12 2500 9 1 9.99 3.14 3344 2.57 G14 F

Jul-12 2500 9 1 9.99 2.81 3384 2.27 G14 E

Aug-12 2500 9 1 9.99 2.85 3368 2.32 G14 E

Sep-12 2500 9 1 9.99 2.99 3329 2.46 G14 F

Oct-12 2500 9 1 9.99 3.09 3532 2.40 G13 E

Nov-12 2500 9 1 9.99 2.99 3501 2.34 G13 E

Dec-12 2500 9 1 9.99 2.62 3535 2.03 G13 E

Jan-13 2500 9 1 9.99 2.65 3513 2.07 G13 E

Feb-13 2500 9 1 9.99 2.80 3590 2.14 G13 E

Mar-13 2500 9 1 9.99 2.68 3638 2.02 G13 E

Unchahar-II Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2500 9 1 9.99 2.44 3531 1.892 G13 E

May-11 2500 9 1 9.99 2.73 3651 2.046 G13 E

Jun-11 2500 9 1 9.99 2.55 3304 2.108 G14 F

Jul-11 2500 9 1 9.99 2.63 3128 2.301 G14 F

Aug-11 2500 9 1 9.99 2.65 3300 2.196 G14 F

Sep-11 2500 9 1 9.99 2.96 3301 2.456 G14 F

Oct-11 2500 9 1 9.99 2.70 3212 2.297 G14 F

Nov-11 2500 9 1 9.99 2.78 3466 2.195 G13 E

Dec-11 2500 9 1 9.99 2.83 3520 2.202 G13 E

Jan-12 2500 9 1 9.99 2.57 3300 2.134 G14 F

Feb-12 2500 9 1 9.99 2.54 3292 2.111 G14 F

Mar-12 2500 9 1 9.99 2.99 3376 2.42 G14 E

Apr-12 2500 9 1 9.99 2.73 3468 2.15 G13 E

May-12 2500 9 1 9.99 3.12 3458 2.468 G13 E

Jun-12 2500 9 1 9.99 3.14 3318 2.591 G14 F

Jul-12 2500 9 1 9.99 2.81 3382 2.273 G14 E

Aug-12 2500 9 1 9.99 2.85 3370 2.317 G14 E

Sep-12 2500 9 1 9.99 2.99 3333 2.453 G14 F

Oct-12 2500 9 1 9.99 3.09 3526 2.399 G13 E

Nov-12 2500 9 1 9.99 2.99 3496 2.341 G13 E

Dec-12 2500 9 1 9.99 2.62 3538 2.028 G13 E

Jan-13 2500 9 1 9.99 2.65 3517 2.064 G13 E

Feb-13 2500 9 1 9.99 2.80 3590 2.137 G13 E

Mar-13 2500 9 1 9.99 2.68 3641 2.015 G13 E

Unchahar-III Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2500 9 1 9.99 2.44 3527 1.89 G13 E

May-11 2500 9 1 9.99 2.73 3637 2.05 G13 E

Jun-11 2500 9 1 9.99 2.55 3309 2.11 G14 F

Jul-11 2500 9 1 9.99 2.63 3128 2.30 G14 F

Aug-11 2500 9 1 9.99 2.65 3301 2.20 G14 F

Sep-11 2500 9 1 9.99 2.96 3300 2.46 G14 F

Oct-11 2500 9 1 9.99 2.70 3197 2.31 G14 F

Nov-11 2500 9 1 9.99 2.78 3466 2.20 G13 E

Dec-11 2500 9 1 9.99 2.83 3519 2.20 G13 E

Jan-12 2500 9 1 9.99 2.57 3300 2.13 G14 F

Feb-12 2500 9 1 9.99 2.54 3292 2.11 G14 F

Mar-12 2500 9 1 9.99 2.99 3376 2.42 G14 E

Apr-12 2500 9 1 9.99 2.73 3471 2.15 G13 E

May-12 2500 9 1 9.99 3.12 3459 2.47 G13 E

Jun-12 2500 9 1 9.99 3.14 3320 2.59 G14 F

Jul-12 2500 9 1 9.99 2.81 3381 2.27 G14 E

Aug-12 2500 9 1 9.99 2.85 3368 2.32 G14 E

Sep-12 2500 9 1 9.99 2.99 3335 2.45 G14 F

Oct-12 2500 9 1 9.99 3.09 3526 2.40 G13 E

Nov-12 2500 9 1 9.99 2.99 3496 2.34 G13 E

Dec-12 2500 9 1 9.99 2.62 3534 2.03 G13 E

Jan-13 2500 9 1 9.99 2.65 3517 2.06 G13 E

Feb-13 2500 9 1 9.99 2.80 3591 2.14 G13 E

Mar-13 2500 9 1 9.99 2.68 3638 2.02 G13 E

Farraka Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2453.13 6.94 0.8 9.70 4.60 3943 3.07 G12 E

May-11 2453.13 6.94 0.8 9.71 5.01 3606 3.65 G13 E

Jun-11 2453.13 6.94 0.8 9.70 5.42 3697 3.85 G13 E

Jul-11 2453.13 6.94 0.8 9.72 5.13 3606 3.74 G13 E

Aug-11 2453.13 6.94 0.8 9.74 5.16 3460 3.92 G13 E

Sep-11 2453.13 6.94 0.8 9.69 5.09 3490 3.83 G13 E

Oct-11 2453.13 6.94 0.8 9.66 4.31 3591 3.15 G13 E

Nov-11 2453.13 6.94 0.8 9.71 3.87 3338 3.04 G14 F

Dec-11 2453.13 6.94 0.8 10.07 3.40 3332 2.68 G14 F

Jan-12 2453.13 6.94 0.8 9.71 3.99 3359 3.12 G14 F

Mar-12 2453.13 6.94 0.8 9.71 3.70 3261 2.98 G14 F

Apr-12 2453.13 6.94 1 9.61 3.90 3409 3.00 G13 E

May-12 2453.13 6.94 1 0.00 4.01 3347 3.16 G14 F

Jun-12 2453.12 6.94 1 9.65 4.10 3581 3.01 G13 E

Jul-12 2453.12 6.94 1 9.59 3.95 3277 3.17 G14 F

Aug-12 2453.12 6.94 1 9.61 3.10 2672 3.05 G16 F

Sep-12 2453.12 6.94 1 9.49 3.07 2816 2.86 G15 F

Oct-12 2453.12 6.94 1 9.59 3.03 2816 2.82 G15 F

Nov-12 2453.12 6.94 1 9.51 2.10 3070 1.79 G15 F

Dec-12 2453.12 6.94 1 9.55 1.88 3021 1.63 G15 F

Jan-13 2453.12 6.94 1 9.47 1.88 2697 1.83 G16 F

Feb-13 2453.12 6.94 1 9.61 1.66 2755 1.58 G16 F

Mar-13 2453.12 6.94 1 9.59 2.11 2826 1.96 G15 F

KHTPS-I Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2500 9 1 9.92 2.60 2782 2.56 G16 F

May-11 2500 9 1 9.92 2.41 2801 2.35 G15 F

Jun-11 2500 9 1 9.92 2.96 2625 3.08 G16 F

Jul-11 2500 9 1 9.91 2.77 2638 2.87 G16 F

Aug-11 2500 9 1 9.92 3.22 2885 3.06 G15 F

Sep-11 2500 9 1 9.94 3.73 2980 3.43 G15 F

Oct-11 2500 9 1 9.94 3.48 3050 3.12 G15 F

Nov-11 2500 9 1 9.93 2.43 2777 2.39 G16 F

Dec-11 2500 9 1 9.92 2.18 2651 2.25 G16 F

Jan-12 2500 9 1 9.91 2.57 2742 2.56 G16 F

Feb-12 2500 9 1 9.91 2.56 2701 2.60 G16 F

Mar-12 2500 9 1 9.91 2.47 2796 2.42 G16 F

Apr-12 2500 9 1 9.92 2.31 2716 2.33 G16 F

May-12 2500 9 1 9.91 2.59 2744 2.59 G16 F

Jun-12 2500 9 1 9.92 2.29 2807 2.23 G15 F

Jul-12 2500 9 1 9.91 2.82 2648 2.91 G16 F

Aug-12 2500 9 1 9.90 2.15 2394 2.46 G17 G

Sep-12 2500 9 1 9.91 1.91 2491 2.09 G17 F

Oct-12 2500 9 1 9.92 1.98 2631 2.05 G16 F

Nov-12 2500 9 1 9.91 1.80 2732 1.80 G16 F

Dec-12 2500 9 1 9.90 1.63 2645 1.69 G16 F

Jan-13 2500 9 1 9.91 1.67 2466 1.86 G17 F

Feb-13 2500 9 1 9.89 1.49 2540 1.61 G16 F

Mar-13 2500 9 1 9.90 1.86 2528 2.01 G16 F

KHTPS-II Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2425 6.5 0.8 9.91 2.60 2782 2.42 G16 F

May-11 2425 6.5 0.8 9.90 2.41 2801 2.22 G15 F

Jun-11 2425 6.5 0.8 9.90 2.96 2625 2.91 G16 F

Jul-11 2425 6.5 0.8 9.90 2.77 2638 2.71 G16 F

Aug-11 2425 6.5 0.8 9.92 3.22 2885 2.89 G15 F

Sep-11 2425 6.5 0.82 9.93 3.73 2980 3.24 G15 F

Oct-11 2425 6.5 0.82 9.94 3.48 3050 2.95 G15 F

Nov-11 2425 6.5 0.82 9.92 2.43 2777 2.26 G16 F

Dec-11 2425 6.5 0.82 9.91 2.18 2651 2.12 G16 F

Jan-12 2425 6.5 0.82 9.89 2.57 2742 2.42 G16 F

Feb-12 2425 6.5 0.82 9.89 2.56 2701 2.45 G16 F

Mar-12 2425 6.5 0.82 9.89 2.47 2796 2.28 G16 F

Apr-12 2425 6.5 1 9.89 2.31 2716 2.20 G16 F

May-12 2425 6.5 1 9.87 2.59 2744 2.44 G16 F

Jun-12 2425 6.5 1 9.89 2.29 2807 2.11 G15 F

Jul-12 2425 6.5 1 9.89 2.82 2648 2.75 G16 F

Aug-12 2425 6.5 1 9.89 2.15 2394 2.32 G17 G

Sep-12 2425 6.5 1 9.91 1.91 2491 1.98 G17 F

Oct-12 2425 6.5 1 9.89 1.98 2631 1.94 G16 F

Nov-12 2425 6.5 1 9.89 1.80 2732 1.70 G16 F

Dec-12 2425 6.5 1 9.88 1.63 2645 1.60 G16 F

Jan-13 2425 6.5 1 9.91 1.67 2466 1.75 G17 F

Feb-13 2425 6.5 1 9.89 1.49 2540 1.52 G16 F

Mar-13 2425 6.5 1 9.90 1.86 2528 1.90 G16 F

NCPP-I Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2500 8.5 1 9.71 3.41 3845 2.42 G12 E

May-11 2500 8.5 1 9.54 3.92 4052 2.64 G11 E

Jun-11 2500 8.5 1 9.60 4.42 4031 2.99 G11 E

Jul-11 2500 8.5 1 9.72 4.24 3899 2.96 G12 E

Aug-11 2500 8.5 1 9.81 4.34 3732 3.16 G12 E

Sep-11 2500 8.5 1 9.86 4.27 3848 3.02 G12 E

Oct-11 2500 8.5 1 9.39 4.31 3646 3.22 G13 E

Nov-11 2500 8.5 1 9.57 4.08 3629 3.06 G13 E

Dec-11 2500 8.5 1 9.67 4.14 3693 3.05 G13 E

Jan-12 2500 8.5 1 9.78 3.99 3674 2.96 G13 E

Feb-12 2500 8.5 1 9.73 3.75 3561 2.86 G13 E

Mar-12 2500 8.5 1 9.75 4.07 3717 2.98 G12 E

Apr-12 2500 8.5 1 9.66 3.96 3760 2.87 G12 E

May-12 2500 8.5 1 9.83 4.19 3846 2.97 G12 E

Jun-12 2500 8.5 1 9.57 4.59 3851 3.24 G12 E

Jul-12 2500 8.5 1 9.68 3.94 3657 2.94 G13 E

Aug-12 2500 8.5 1 9.77 3.19 3406 2.55 G13 E

Sep-12 2500 8.5 1 9.76 3.21 3407 2.56 G13 E

Oct-12 2500 8.5 1 9.87 4.05 3697 2.98 G13 E

Nov-12 2500 8.5 1 9.69 4.23 4005 2.88 G11 E

Dec-12 2500 8.5 1 9.70 4.33 4025 2.93 G11 E

Jan-13 2500 8.5 1 9.67 4.16 3856 2.93 G12 E

Feb-13 2500 8.5 1 9.65 3.70 3830 2.63 G12 E

Mar-13 2500 8.5 1 9.75 3.63 3763 2.63 G12 E

NCPP-II Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2424 6 1 9.71 3.41 4190 2.09 G11 E

May-11 2424 6 1 9.54 3.92 4038 2.50 G11 E

Jun-11 2424 6 1 9.60 4.42 4000 2.84 G12 E

Jul-11 2424 6 1 9.72 4.24 4047 2.69 G11 E

Aug-11 2424 6 1 9.81 4.34 3769 2.95 G12 E

Sep-11 2424 6 1 9.86 4.27 3868 2.84 G12 E

Oct-11 2424 6 1 9.39 4.31 3727 2.97 G12 E

Nov-11 2424 6 1 9.57 4.08 3774 2.78 G12 E

Dec-11 2424 6 1 9.67 4.14 3894 2.73 G12 E

Jan-12 2424 6 1 9.78 3.99 3895 2.63 G12 E

Feb-12 2424 6 1 9.73 3.75 3863 2.49 G12 E

Mar-12 2424 6 1 9.75 4.07 3959 2.64 G12 E

Apr-12 2424 6 1 9.96 3.96 3717 2.74 G12 E

May-12 2424 6 1 9.83 4.19 3873 2.78 G12 E

Jun-12 2424 6 1 9.57 4.59 3753 3.14 G12 E

Jul-12 2424 6 1 9.68 3.94 3500 2.90 G13 E

Aug-12 2424 6 1 9.77 3.19 3400 2.41 G14 E

Sep-12 2424 6 1 9.76 3.21 3491 2.36 G13 E

Oct-12 2424 6 1 9.87 4.05 3612 2.88 G13 E

Nov-12 2424 6 1 9.69 4.23 3850 2.83 G12 E

Dec-12 2424 6 1 9.70 4.33 3704 3.00 G12 E

Jan-13 2424 6 1 9.67 4.16 3691 2.89 G13 E

Feb-13 2424 6 1 9.65 3.70 3739 2.54 G12 E

Mar-13 2424 6 1 9.75 3.27 3711 2.26 G12 E

Rihand-I Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2385 8.5 1 9.65 1.98 3844 1.34 G12 E

May-11 2385 8.5 1 9.65 1.64 3725 1.14 G12 E

Jun-11 2385 8.5 1 9.65 1.88 3487 1.40 G13 E

Jul-11 2385 8.5 1 9.87 1.87 3459 1.40 G13 E

Aug-11 2385 8.5 1 9.87 2.58 3493 1.92 G13 E

Sep-11 2385 8.5 1 9.87 2.76 3439 2.08 G13 E

Oct-11 2385 8.5 1 9.87 1.95 3682 1.37 G13 E

Nov-11 2385 8.5 1 9.87 2.07 3461 1.55 G13 E

Dec-11 2385 8.5 1 9.87 1.73 3359 1.33 G14 F

Jan-12 2385 8.5 1 9.87 1.61 3419 1.22 G13 E

Feb-12 2385 8.5 1 9.87 1.61 3600 1.16 G13 E

Mar-12 2385 8.5 1 9.87 1.53 3499 1.13 G13 E

Apr-12 2385 8.5 1 9.87 1.66 3350 1.29 G14 F

May-12 2385 8.5 1 9.87 1.73 3430 1.31 G13 E

Jun-12 2385 8.5 1 9.87 1.70 3418 1.29 G13 E

Jul-12 2385 8.5 1 9.87 1.58 3260 1.26 G14 F

Aug-12 2385 8.5 1 9.87 1.55 3468 1.16 G13 E

Sep-12 2385 8.5 1 9.87 1.67 3664 1.18 G13 E

Oct-12 2385 8.5 1 9.87 1.54 3736 1.07 G12 E

Nov-12 2385 8.5 1 9.93 1.60 3619 1.15 G13 E

Dec-12 2385 8.5 1 10.16 1.12 3540 0.82 G13 E

Jan-13 2385 8.5 1 10.16 1.19 3487 0.89 G13 E

Feb-13 2385 8.5 1 10.16 1.23 3381 0.95 G14 E

Mar-13 2385 8.5 1 10.16 1.28 3569 0.93 G13 E

Rihand-II Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2425 6.5 1 9.65 1.98 3608 1.42 G13 E

May-11 2425 6.5 1 9.65 1.64 3583 1.18 G13 E

Jun-11 2425 6.5 1 9.65 1.88 3472 1.40 G13 E

Jul-11 2425 6.5 1 9.84 1.87 3389 1.42 G14 E

Aug-11 2425 6.5 1 9.84 2.58 3414 1.95 G13 E

Sep-11 2425 6.5 1 9.86 2.76 3391 2.10 G14 E

Oct-11 2425 6.5 1 9.86 1.95 3671 1.37 G13 E

Nov-11 2425 6.5 1 9.87 2.07 3502 1.53 G13 E

Dec-11 2425 6.5 1 9.84 1.73 3351 1.33 G14 F

Jan-12 2425 6.5 1 9.87 1.61 3349 1.24 G14 F

Feb-12 2425 6.5 1 9.87 1.61 3366 1.24 G14 E

Mar-12 2425 6.5 1 9.87 1.53 3396 1.16 G14 E

Apr-12 2425 6.5 1 9.87 1.64 3311 1.28 G14 F

May-12 2425 6.5 1 9.87 1.73 3332 1.34 G14 F

Jun-12 2425 6.5 1 9.87 1.70 3356 1.31 G14 F

Jul-12 2425 6.5 1 9.81 1.58 3243 1.26 G14 F

Aug-12 2425 6.5 1 9.87 1.55 3477 1.15 G13 E

Sep-12 2425 6.5 1 9.86 1.67 3542 1.22 G13 E

Oct-12 2425 6.5 1 9.87 1.54 3440 1.16 G13 E

Nov-12 2425 6.5 1 9.93 1.60 3366 1.23 G14 E

Dec-12 2425 6.5 1 10.16 1.12 3452 0.84 G13 E

Jan-13 2425 6.5 1 10.16 1.19 3433 0.90 G13 E

Feb-13 2425 6.5 1 9.93 1.23 3263 0.98 G14 F

Mar-13 2425 6.5 1 9.93 1.28 3414 0.97 G13 E

Singrauli Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2462.5 7.25 1 9.97 1.84 3322 1.47 G14 F

May-11 2462.5 7.25 1 9.98 1.56 3294 1.25 G14 F

Jun-11 2462.5 7.25 1 9.99 1.74 3298 1.39 G14 F

Jul-11 2462.5 7.25 1 9.99 1.81 3291 1.46 G14 F

Aug-11 2462.5 7.25 1 9.97 1.69 3163 1.42 G14 F

Sep-11 2462.5 7.25 1 9.98 1.98 3268 1.60 G14 F

Oct-11 2462.5 7.25 1 9.90 1.79 3316 1.43 G14 F

Nov-11 2462.5 7.25 1 9.97 1.53 3403 1.19 G13 E

Dec-11 2462.5 7.25 1 9.98 1.59 3498 1.21 G13 E

Jan-12 2462.5 7.25 1 9.99 1.55 3544 1.15 G13 E

Feb-12 2462.5 7.25 1 9.99 1.54 3448 1.18 G13 E

Mar-12 2462.5 7.25 1 9.97 1.49 3547 1.11 G13 E

Apr-12 2462.5 7.25 1 9.98 1.52 3439 1.17 G13 E

May-12 2462.5 7.25 1 9.99 1.50 3337 1.19 G14 F

Jun-12 2462.5 7.25 1 9.97 1.49 3304 1.19 G14 F

Jul-12 2462.5 7.25 1 9.97 1.51 3304 1.21 G14 F

Aug-12 2462.5 7.25 1 9.99 1.48 3319 1.18 G14 F

Sep-12 2462.5 7.25 1 9.97 1.46 3456 1.11 G13 E

Oct-12 2462.5 7.25 1 9.98 1.51 3406 1.17 G13 E

Nov-12 2462.5 7.25 1 9.99 1.51 3421 1.17 G13 E

Dec-12 2462.5 7.25 1 9.89 1.07 3450 0.82 G13 E

Jan-13 2462.5 7.25 1 9.98 1.23 3467 0.94 G13 E

Feb-13 2462.5 7.25 1 9.98 1.32 3515 0.99 G13 E

Mar-13 2462.5 7.25 1 9.89 1.07 3651 0.77 G13 E

Aravali Month-wise parameters for computation of Energy Charges

MonthGHR(kCA

L/kWh)AUX(%)

SFC(ml/k

Wh)

CVSF(kCa

l/ml)

LPPF(RS/

Kg)

CVPF(kCa

l/Kg)

ECR(Rs./k

Wh)

Grade of

Non

Coking

coal on

GCV

Grade of

coal

based on

UHV

Apr-11 2421 6 1 9.47 2.91 2889 2.59 G15 F

May-11 2421 6 1 9.45 2.82 2932 2.47 G15 F

Jun-11 2421 6 1 9.45 2.78 2890 2.46 G15 F

Jul-11 2421 6 1 9.45 3.56 2604 3.51 G16 F

Aug-11 2421 6 1 9.45 3.56 2637 3.46 G16 F

Sep-11 2421 6 1 9.45 3.83 2896 3.39 G15 F

Oct-11 2421 6 1 9.45 4.35 3284 3.40 G14 F

Nov-11 - - - - - - - - -

Dec-11 - - - - - - - - -

Jan-12 - - - - - - - - -

Feb-12 - - - - - - - - -

Mar-12 - - - - - - - - -

104 jyotiranjan.pdf ntpc

Documents