OPTIMIZATION OF POWER PURCHASE COST FOR · PDF filesummer internship report on arr projection...

Summer Internship Report

On

ARR PROJECTION FOR BSES YAMUNA POWER LTD FOR 3RD MYT

CONTROL PERIOD

AND

OPTIMIZATION OF POWER PURCHASE COST FOR BSES YAMUNA POWER

LTD USING MERIT ORDER DISPATCH MODEL

Under the Guidance of

Mr. Rajul Agarwal, AVP, Regulatory Affairs, BSES Yamuna Power Ltd

Mr. P. Sai Krishna, DGM, Regulatory Affairs, BSES Yamuna Power Ltd

Ms. Manju Mam, Director, NPTI Faridabad

At

BSES Yamuna Power Limited

Submitted by

ANIRBAN BANDYOPADHYAY

Roll No – 12

MBA (Power Management)

(Under the Ministry of Power, Government of India)

Affiliated to

MAHARSHI DAYANAND UNIVERITY, ROHTAK

August, 2013

i

Declaration

I, Anirban Bandyopadhyay, Roll No. 12, student of MBA – Power Management (2012 – 14)

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

Report entitled “ARR PROJECTION FOR BSES YAMUNA POWER LTD FOR 3RD

MYT

CONTROL PERIOD AND OPTIMIZATION OF POWER PURCHASE COST FOR BSES

YAMUNA POWER LTD USING MERIT ORDER DISPATCH MODEL” 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 ______________________

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

ii

Training Completion Certificate

iii

Acknowledgement

Words could never be enough to express my true regards to all those who in some or the

other way helped me in completing this project. I can‟t in full measure, reciprocate the

kindness shown and contribution made by various persons on this endeavor of mine. I shall

always remember them with gratitude and sincerity. I take this opportunity to thank all those

who have been instrumental in completion of my training.

I would like to take the opportunity to thank my Project Guides Mr. Rajul Agarwal, AVP,

Regulatory Affairs, BSES Yamuna Power Ltd and Mr. P. Sai Krishna, DGM, Regulatory

Affairs, BSES Yamuna Power Ltd for their effective guidance and parental support

throughout the course of my project. I would forever be indebted to the team members of

Regulatory Affairs department – Mr. Abhishek Srivastava, Ms. Prachi Jain and Mr. Vikas

Dixit. The inputs provided by them have been invaluable for the completion of my project.

I feel deep sense of gratitude towards Mr .J.S.S. Rao, Principal Director, Corporate Affairs,

NPTI, Mr. S.K. Chaudhary, Principal Director, CAMPS, NPTI, my internal project guide Ms.

Manju Mam for arranging my internship at BSES Yamuna Power Ltd, and Mr. Amit Mishra,

Asst. Director, NPTI for being a constant source of motivation and guidance throughout the

course of my internship.

Thank you all for being there for me always.

Anirban Bandyopadhyay

iv

Executive Summary

Future of power sector in India is promising, owing to its huge demand. But it has a serious

weakness in form of its distribution section. The distribution sector is the final and the most

crucial link in the electricity supply chain, and unfortunately the weakest and the most loss

making one in our country. Reeling under a huge aggregate accumulated loss of over Rs. 2.46

lakh Crore by FY ‟13, as stated by Mr. Montek Singh Ahluwalia, Deputy Chairman, Planning

Commission, the sector needs a complete reform, both technically and financially.

One of the major causes behind this financial distress is regular increase of power purchase

cost and irregular hike of distribution tariff. The ideal situation of a cost-reflective

distribution tariff is yet to be achieved in most parts in our country. In order to improve this

situation, timely filing of ARR-s by distribution licensees and a focus to reduce power

purchase costs should be the need of the hour.

In this report, the ARR (Aggregate Revenue Requirement) for BSES Yamuna Power Ltd, a

distribution licensee supplying power to Central & East Delhi, for 3rd

MYT (Multi-Year

Tariff) Control Period (FY 2015-16 to FY 2017-18) has been projected. Another exercise has

been carried out to find the impact of application of Merit Order Dispatch concept on the

power purchase cost of the distribution licensee, in order to optimize the power purchase cost.

For stepwise calculation and projection of ARR, all its components including all the

uncontrollable and controllable cost factors are calculated first. The ARR as projected for 3

years of the 3rd

MYT Control Period are Rs. 4849.68 Cr, Rs. 5666.50 Cr and Rs. 6072.58 Cr

respectively against revenue collections of Rs. 4636.27 Cr, Rs. 4890.98 Cr and Rs. 5127.65

respectively, resulting in an increasing gap between the average cost of supply and average

billing rate (at existing tariff) of Rs. 0.35/unit, Rs. 1.20/unit and Rs. 1.39/unit respectively.

This increasing revenue gap (at existing tariff) calls for a tariff hike of 4.40% in FY 2015-16,

or a hike of 13.69% in FY 2016-17, or a hike of 15.56% in FY 2017-18 to abolish the

revenue gap and achieve a cost-reflective tariff.

An analysis of the ARR show that, power purchase cost covers about 70% of the total

expenses incurred by the distribution licensee. Hence in order to optimize the power purchase

cost, impact of merit order dispatch concept was examined.

v

It was seen that, implementation of the Merit Order Dispatch model can help in reducing

power purchase cost by a minimum amount of about Rs. 100 Cr, as was examined in this

study for FY 2012-13.

In addition, if share of BYPL is reduced from the present 27.24% to 23.97% along with re-

allocation of power purchase from selected costlier power stations, it would result in a saving

of about Rs. 390 Cr, as was examined in this study for FY 2012-13.

Although this report has several limitations which are discussed later in this report, it has

thrown light on usefulness of a cost reflective tariff, and importance of reducing the power

purchase cost using merit order dispatch concept in reduction of the overall expenses.

vi

List of Abbreviations

AAD Advance Against Depreciation

A&G Administrative and General

ABR Average Billing Rate

ARR Aggregate Revenue Requirement

AT&C Loss Aggregate Technical & Commercial Loss

BYPL BSES Yamuna Power Limited

BRPL BSES Rajdhani Power Ltd

CAGR Compound Annual Growth Rate

CERC Central Electricity Regulatory Commission

COD Commercial Operation Date

CPI Consumer Price Index

CWIP Capital work in progress

DERC Delhi Electricity Regulatory Commission

DMRC Delhi Metro Railway Corporation

DGVCL Dakshin Gujarat Vij Company Limited

DJB Delhi Jal Board

DTL Delhi Transco Limited

DVB Delhi Vidyut Board

ERPC Eastern Regional Power Committee

FPA Fuel Price Adjustment

FY Financial Year

GERC Gujarat Electricity Regulatory Commission

GFA Gross Fixed Asset

GoNCTD The Government of National Capital Territory of Delhi

GSECL Gujarat State Electricity Corporation Limited

GUVNL Gujarat Urja Vikas Nigam Limited

IEX Indian Energy Exchange

IPP Independent Power Producer

LIP Large Industrial Power

MDI Maximum Demand Indicator

vii

MU Million Units

MW Mega Watt

MYT Multi Year Tariff

NDHT Non-Domestic High Tension

NDLT Non-Domestic Low Tension

NDPL North Delhi Power Limited

NPC Nuclear Power Corporation

NRLDC Northern Regional Load Dispatch Centre

O&M Operation & Maintenance

PPA Power Purchase Agreement

PXIL Power Exchange India Ltd

R&M Repairs and Maintenance

REC Renewable Energy Certificate

RLDC Regional Load Despatch Centre

R-LNG Re-gasified Liquefied Natural Gas

RoCE Return on Capital Employed

RoE Return on Equity

RPO Renewable Purchase Obligation

RRB Regulated Rate Base

SERC State Electricity Regulatory Commission

SGS State Generating Station

SLDC State Load Despatch Centre

SIP Small Industrial Power

UI Unscheduled Interchange

WACC Weighted Average Cost of Capital

WPI Wholesale Price Index

viii

List of Tables

Table 1: Some statistics on BSES Yamuna Power Ltd & BSES Rajdhani Power Ltd ........................... 8

Table 2: Tariff Schedule for BYPL consumers w.e.f. 01.08.2013 ........................................................ 18

Table 3: Allocation of power to BYPL from NTPC stations ................................................................ 21

Table 4: Allocation of power to BYPL from NHPC stations ............................................................... 21

Table 5: Allocation of power to BYPL from NPCIL stations .............................................................. 22

Table 6: Allocation of power to BYPL from other central generating stations .................................... 22

Table 7: Allocation of power to BYPL from state generating stations ................................................. 22

Table 8: Allocation of power to BYPL from future stations ................................................................ 23

Table 9: Projected synchronization / COD dates of future stations ...................................................... 23

Table 10: Renewable Purchase Obligation (as per DERC RPO & REC Framework Implementation

Regulations, 2012) ................................................................................................................................ 25

Table 11: Actual CPI & WPI growth in last 5 years preceding FY 2011-12 (base year for 2nd MYT

Control Period)...................................................................................................................................... 28

Table 12: Projected CPI & WPI for 2nd MYT Control Period ............................................................. 29

Table 13: Inflation Factor for 2nd MYT Control Period ...................................................................... 29

Table 14: Actual CPI & WPI growth in last 5 years preceding FY 2014-15 (base year for 3rd MYT

Control Period)...................................................................................................................................... 29

Table 15: Projected CPI & WPI for 3rd MYT Control Period ............................................................. 30

Table 16: Inflation Factor for 3rd MYT Control Period ....................................................................... 30

Table 17: Number of Employees (function-wise) ................................................................................. 31

Table 18: Statement of Allocation of Employee Cost between Wheeling and Retail Supply .............. 31

Table 19: Statement of Allocation of A&G Expenses between Wheeling and Retail Supply .............. 32

Table 20: Depreciation Rates and Statement of Allocation of Depreciation between Wheeling and

Retail Supply ......................................................................................................................................... 34

Table 21: Number of Consumers .......................................................................................................... 41

Table 22: Connected Load (MW) ......................................................................................................... 42

Table 23: Energy Sales (MU) ............................................................................................................... 44

Table 24: Revenue collected at existing tariff in FY 2015-16 (Rs. Cr.) ............................................... 45



Table 27: Distribution Losses (%), AT&C Loss (%) & Energy Requirement (MU) ........................... 47

Table 28: Energy availability (MU) from NTPC stations ..................................................................... 47

Table 29: Energy availability (MU) from NHPC stations .................................................................... 48

Table 30: Energy availability (MU) from NPCIL stations ................................................................... 48

Table 31: Energy availability (MU) from other central generating stations ......................................... 49

Table 32: Energy availability (MU) from state generating stations ...................................................... 49

Table 33: Energy availability (MU) from future stations ..................................................................... 49

Table 34: Energy availability (MU) from renewable sources ............................................................... 50

Table 35: Power purchase cost (Rs. Cr.) for NTPC stations ................................................................. 50

Table 36: Power purchase cost (Rs. Cr.) for NHPC stations ................................................................ 51

Table 37: Power purchase cost (Rs. Cr.) for NPCIL stations ............................................................... 51

Table 38: Power purchase cost (Rs. Cr.) for other central generating stations ..................................... 51

ix

Table 39: Power purchase cost (Rs. Cr.) for state generating stations .................................................. 52

Table 40: Power purchase cost (Rs. Cr.) for future stations ................................................................. 52

Table 41: Power purchase cost (Rs. Cr.) for renewable energy sources ............................................... 52

Table 42: Inter & Intra-State Transmission Losses (% and MU) ......................................................... 53

Table 43: Inter & Intra-State Transmission Charges (Rs. Cr.) ............................................................. 53

Table 44: Energy Balance ..................................................................................................................... 53

Table 45: Total O&M Expenses ........................................................................................................... 54

Table 46: Allocation of Employee Expense into Wheeling & Retail Supply ....................................... 54

Table 47: Allocation of A&G Expenses into Wheeling & Retail Supply ............................................. 54

Table 48: Allocation of R&M Expenses into Wheeling & Retail Supply ............................................ 55

Table 49: Capital Expenditure & Capitalization Schedule (Rs. Cr.) .................................................... 55

Table 50: Consumer Contribution (Rs. Cr.) .......................................................................................... 55

Table 51: Depreciation (Rs. Cr.) ........................................................................................................... 56

Table 52: Allocation of Opening GFA & Depreciation (Rs. Cr.) ......................................................... 56

Table 53: Allocation of Accumulated Depreciation (Rs. Cr.) .............................................................. 56

Table 54: Advance Against Depreciation (Rs. Cr.) .............................................................................. 57

Table 55: Allocation of AAD into Wheeling and Retail Supply (Rs. Cr.) ........................................... 57

Table 56: Working Capital (Rs. Cr.) ..................................................................................................... 57

Table 57: RRB (Rs. Cr.) ....................................................................................................................... 58

Table 58: RRB allocation into Wheeling & Retail Supply (Rs. Cr.) .................................................... 58

Table 59: Means of Finance (Rs. Cr.) ................................................................................................... 58

Table 60: Equity (Rs. Cr.) ..................................................................................................................... 59

Table 61: Debt (Rs. Cr.) ........................................................................................................................ 59

Table 62: WACC & RoCE (Rs. Cr.) ..................................................................................................... 59

Table 63: RoCE allocation into Wheeling & Retail Supply (Rs. Cr.) .................................................. 59

Table 64: Income Tax (Rs. Cr.) ............................................................................................................ 60

Table 65: Income Tax allocation into Wheeling & Retail Supply (Rs. Cr.) ......................................... 60

Table 66: Non-Tariff Income (Rs. Cr.) ................................................................................................. 60

Table 67: ARR (Rs. Cr.) ....................................................................................................................... 61

Table 68: ARR for Wheeling Business (Rs. Cr.) .................................................................................. 61

Table 69: ARR for Retail Supply Business (Rs. Cr.) ............................................................................ 62

Table 70: Revenue Gap & ABR at existing tariff (Rs. Cr.) .................................................................. 62

Table 71: Merit Order Dispatch – Case - I ............................................................................................ 63

Table 72: Merit Order Dispatch – Case - II .......................................................................................... 63

Table 73: Merit Order Dispatch – Case - III ......................................................................................... 64

Table 74: Merit Order Dispatch – Case - IV ......................................................................................... 64

Table 75: Merit Order Dispatch – Case - V .......................................................................................... 65

Table 76: Merit Order Dispatch – Case - VI ......................................................................................... 65

x

List of Figures

Figure 1: Segregation of areas under three discoms in NCT Delhi ........................................................ 7

Figure 2: Components of ARR for FY 2015-16, FY 2016-17 and FY 2017-18 ................................... 66

xi

Contents

Declaration ............................................................................................................................................... i

Training Completion Certificate ............................................................................................................. ii

Acknowledgement ................................................................................................................................. iii

Executive Summary ............................................................................................................................... iv

List of Abbreviations ............................................................................................................................. vi

List of Tables ....................................................................................................................................... viii

List of Figures ......................................................................................................................................... x

Contents ................................................................................................................................................. xi

1. INTRODUCTION .............................................................................................................................. 1

1.1 ARR determination in Electricity distribution business under MYT framework ......................... 1

1.2 Merit Order Dispatch (MOD) for optimization of power purchase cost of a distribution licensee

............................................................................................................................................................ 4

1.3 Objective of the project ................................................................................................................. 5

1.4 Significance of the project ............................................................................................................ 5

1.5 Scope of the project ...................................................................................................................... 6

1.6 Organization profile : BSES Yamuna Power Ltd ......................................................................... 6

2. REVIEW OF LITERATURE ........................................................................................................... 10

2.1 ARR determination in Electricity distribution business under MYT framework ....................... 10

2.2 Merit Order Dispatch (MOD) for optimization of power purchase cost of a distribution licensee

.......................................................................................................................................................... 12

3. RESEARCH METHODOLOGY ..................................................................................................... 14

3.1 ARR projection for BSES Yamuna Power Ltd under MYT framework for 3rd

MYT Control

Period (FY 2015-16 to FY 2017-18)................................................................................................. 14

3.1.1 Sales Forecast ....................................................................................................................... 14

3.1.2 Calculation of revenue ......................................................................................................... 17

3.1.3 AT&C Loss, Distribution Losses, Collection Efficiency & Energy Requirement .............. 19

3.1.4 Energy availability from generating stations ....................................................................... 21

3.1.5 Power purchase cost ............................................................................................................. 25

3.1.6 Transmission Losses & Charges .......................................................................................... 26

3.1.7 Operation & Maintenance (O&M) Expenses ....................................................................... 27

3.1.8 Capital Expenditure and Capitalization ............................................................................... 33

xii

3.1.9 Depreciation ......................................................................................................................... 34

3.1.10 Advance Against Depreciation (AAD) .............................................................................. 35

3.1.11 Working Capital ................................................................................................................. 35

3.1.12 Regulated Rate Base (RRB) ............................................................................................... 36

3.1.13 Means of Finance ............................................................................................................... 38

3.1.14 Return on Capital Employed (RoCE) ................................................................................ 38

3.1.15 Income Tax ........................................................................................................................ 39

3.1.16 Non Tariff Income ............................................................................................................. 39

3.1.17 Determination of ARR ....................................................................................................... 39

3.2 Merit Order Dispatch (MOD) for optimization of power purchase cost of BYPL ..................... 40

4. RESULTS & DISCUSSION ............................................................................................................. 41

4.1 ARR projection for BSES Yamuna Power Ltd under MYT framework for 3rd

MYT Control

Period (FY 2015-16 to FY 2017-18)................................................................................................. 41

4.1.1 Sales Forecast ....................................................................................................................... 41

4.1.2 Revenue collected at existing tariff ...................................................................................... 45

4.1.3 AT&C Loss, Collection Efficiency, Distribution Losses & Energy Requirement .............. 47

4.1.4 Energy availability from generating stations ....................................................................... 47

4.1.5 Power purchase cost ............................................................................................................. 50

4.1.6 Transmission Losses & Charges .......................................................................................... 53

4.1.7 Energy balance ..................................................................................................................... 53

4.1.8 Operation & Maintenance (O&M) Expenses ....................................................................... 54

4.1.9 Capital Expenditure and Capitalization ............................................................................... 55

4.1.10 Depreciation ....................................................................................................................... 56

4.1.11 Advance Against Depreciation (AAD) .............................................................................. 57

4.1.12 Working Capital ................................................................................................................. 57

4.1.13 Regulated Rate Base (RRB) ............................................................................................... 58

4.1.14 Means of Finance ............................................................................................................... 58

4.1.15 Return on Capital Employed (RoCE) ................................................................................ 59

4.1.16 Income Tax ........................................................................................................................ 60

4.1.17 Non-Tariff Income ............................................................................................................. 60

4.1.18 Aggregate Revenue Requirement (ARR) ........................................................................... 61

4.1.19 Revenue Gap & Average Billing Rate at existing tariff, and proposed tariff hike ............ 62

4.2 Merit Order Dispatch (MOD) for optimization of power purchase cost of BYPL ..................... 63

5. SUMMARY & CONCLUSION ....................................................................................................... 66

xiii

6. LIMITATIONS OF STUDY ............................................................................................................ 68

7. FUTURE SCOPE & RECOMMENDATIONS ................................................................................ 70

8. BIBLIOGRAPHY ............................................................................................................................. 71

[ 1 ]

1. INTRODUCTION

1.1 ARR determination in Electricity distribution business under MYT

framework

The electricity supply chain can be broadly divided into three main businesses, namely

generation, transmission and distribution. Each of these three businesses has some inherent

cost components, which the business incurs in its day-to-day operations. In order that the

business survives, these costs have to be recovered on a regular and structured basis by

earning revenue. Revenue is earned through the route of a structured tariff schedule,

designated for the specific kind of business and for the specific kind of consumers served.

Calculation of ARR or Aggregate Revenue Requirement is the prime necessity for

determination of tariff. ARR refers to the revenue requirement by the generating company or

the transmission or distribution licensee for recovery, through tariff, of the allowable

expenses and return on capital pertaining to its licensed business, in accordance with the

regulations specified by CERC or the concerned SERC.

Prior to FY 2007-08, the tariff determination process in NCT Delhi was exercised in yearly

basis. According to this system of tariff determination, the Generating Company or Licensee

(Distribution or Transmission) was required to submit an annual filing of expected revenues

from various charges, or the ARR, and the Delhi Electricity Regulatory Commission or

DERC after scrutinizing and validating every part of the ARR filed, approves wholly or

partly the tariff proposed by the licensee. However this system of annual tariff determination

was too unpredictable.

Accordingly, an incentive based Multi Year Tariff (MYT) determination process was

designed with the intention to make the tariff setting exercise more predictable and to impart

greater regulatory certainty to the process of tariff determination. A Multi Year Tariff (MYT)

framework is defined as a framework for regulating the Generating Company or licensees

over a period of time wherein the principles of regulating the returns/profits of licensees and

the trajectory of individual cost and revenue elements of the Utility are determined in

advance. The concept of MYT gives an element of certainty to all stakeholders. The basic

premise is that tariffs would not fluctuate beyond a certain bandwidth unless there are force

[ 2 ]

majeure conditions. The consumer would have a fair idea of what to expect in the next three

to five years and the Utility would also be able to plan its business having known the

principles for tariff determination for the control period. Multi Year Tariff does not imply

that the Regulatory Commissions need to fix an identical tariff, year after year, throughout

the control period though, of course, there is no bar if the Regulatory Commission chooses to

do so. It is more likely that the Regulatory Commission would fix the guidelines which would

determine the retail tariffs and having fixed the guidelines, it is expected that the tariffs would

operate within a certain band.

The shift from an annual tariff determination exercise to MYT framework is expected to

bring the following benefits:

i. Provide Regulatory Certainty to the investors and consumers by promoting

transparency, consistency and predictability of regulatory approaches thereby

minimizing perceptions of regulatory risk.

ii. Ensure financial viability of the sector to attract investments and safeguard

consumers.

iii. Provide incentivisation framework to reward performance, promote efficiency and

competition.

iv. Address risk sharing mechanism between utility and consumers based on controllable

and uncontrollable factors.

DERC has defined the periodicity that will apply for a number of years for MYT Framework

called the Control Period. The first control period was of five financial years starting from FY

2007-08 to FY 2011-12. The second or current control period is of three financial years

starting from FY 2012-13 to FY 2014-15. For the purpose of this project work, the third

control period is also assumed to be of three financial years starting from FY 2015-16 to FY

2017-18.

The ARR and tariffs for generation, transmission, retail supply business and the network

business of distribution licensees would be determined for each year of the Control Period at

the beginning of the Control Period. The MYT framework shall inter alia consist of the

parameters within the control of Utilities. The MYT framework shall be finalized considering

[ 3 ]

all the parameters duly specifying targets for these parameters under the control of the

licensees. Some of the critical parameters in the distribution business are as follows:

i. Volume of Energy Sales – Individual consumers decide the quantity and the pattern of

their consumption, which would be influenced by demand side management

measures, energy efficiency, weather conditions, industrial activity, etc. It shall also

be determined by the consumer mix of the Licensee.

ii. Power purchase cost – This is the most significant cost for any Distribution Licensee,

driven by external factors such as fuel price changes, exchange rate fluctuations,

inflation, etc.

iii. System Losses – Losses incurred due to technical and commercial loss, are considered

to be within the Licensee‟s control, and are expected to be handled by the licensee.

iv. Operating Costs – O&M Expenses are considered to be within the control of

licensees, and it is expected to run its operations in an efficient manner with suitable

allocation of costs between different heads, based on its individual requirements.

v. Financing Costs– The network of the licensee in Delhi is being upgraded and

expanded to meet the rapidly increasing demand for power. The cost of financing the

expansion in network is a significant expense for the licensee.

While considering regulated nature of power industry, it is useful to consider the split of costs

into those that the management of the company can control and those it cannot. The

Regulations seeks to provide the owners and management of a company with incentives to

cut costs that are under their control and to insulate them from abnormal profits and losses

arising from costs that are outside their control.

DERC stipulates the following factors as un-controllable factors for a distribution licensee:

i. Force Majeure Events, such as natural disaster or fire;

ii. Changes in law, judicial pronouncements and Orders of the Central Government,

State Government or Commission;

iii. Economy-wide influences, such as unforeseen changes in inflation rate, market-

interest rates, taxes and statutory levies;

iv. Cost of power purchase;

v. Change in consumer mix;

[ 4 ]

vi. Quantum of energy sales.

The Utilities shall not bear the burden of items that are considered beyond their control or

“uncontrollable”, and the consequent financial gain or loss shall be adjusted in the annual

revenue requirement.

The following factors are stipulated as controllable factors for a distribution licensee:

i. AT&C Loss;

ii. Distribution losses;

iii. Collection efficiency;

iv. O&M Expenses;

v. Return on Capital Employed;

vi. Depreciation;

vii. Quality of Supply.

Targets shall be set for such controllable factors at beginning of each control period. Any

financial loss arising from the performance falling short of the targets in these controllable

items shall be borne by the licensee and not be included in the ARR. Any financial gain

arising from performing better than targets shall be as per the incentive mechanism specified

in the Regulations.

1.2 Merit Order Dispatch (MOD) for optimization of power purchase cost

of a distribution licensee

Cost incurred by a distribution licensee for purchasing power covers about 70% of its total

cost. Any reduction in power purchase cost would help in reduction of the total cost of the

distribution business to a great extent. The distribution licensee purchases power from one or

more sources that may be both short term and long term. Electricity purchased from the long

term sources are those purchased from power plants through long term PPAs. Short term

sources include purchasing power through short term PPAs, power purchased from power

exchanges, power purchased through banking route or unscheduled power purchase (UI).

One way of reducing the power purchase cost is to purchase power from the long term

sources following a merit order dispatch principle, wherein priority will be given to the

[ 5 ]

cheaper long term sources while purchasing power from them. Power will be purchased first

from those sources that will provide power at a cheaper rate. Then the remaining power will

be purchased from the costlier sources. The distribution licensee has to draw power from

various long term sources according to the cost of the power supplied by those sources or

power plants. This will help in reducing the power purchase cost, and subsequently the

overall cost of the distribution licensee.

1.3 Objective of the project

Two objectives are served in this project work:

i. Projection of ARR for third MYT Control Period (FY 2015-16 to FY 2017-18) for

BSES Yamuna Power Ltd (BYPL) – this includes projection of all the controllable

and uncontrollable expenses incurred by BYPL and calculation of ARR;

ii. Optimization of Power Purchase Cost by applying the Merit Order Dispatch (MOD)

principle – this includes calculation of power purchase costs from individual power

plants, and sorting them according to ascending order of their variable costs. Some

specific types of power plants, namely hydro-electric plants, nuclear plants and

renewable energy plants are excluded from merit order regime.

1.4 Significance of the project

Under the present scenario of financial distress experienced by most of the distribution

companies in India, it is important that the distribution tariff should be cost reflective, and

regulatory assets should be abolished gradually. For that purpose, a proper projection of ARR

is of utmost importance, as based on this ARR, the Commission would determine the tariff.

In case of wrong projection or improper estimation, the calculated tariff may end up at a

figure far away from the actual incurred cost. Besides the Commission may also find it

inadequate to validate a filed ARR that is calculated with vague assumptions without any

through study. So it is essential that the ARR projections are made with all the factors taken

into account up to the highest possible extent. This will help the distribution licensee to

justify its filings before the Commission, and subsequently to have a cost reflective tariff.

Moreover, in a mission to reduce the overall cost, the distribution licensee should first focus

on reducing power purchase cost, as it alone covers 70% of the total cost. One way of

[ 6 ]

reducing the power purchase cost is to apply merit order dispatch principle. In this project

work, an attempt is made to find the benefit of following the MOD principle in terms of

money. The saving in cost is found out by calculating the difference between the power

purchase cost without merit order dispatch model and that with merit order dispatch. This

project work will show a way to the distribution licensee to reduce its power purchase cost

with help of the MOD model.

1.5 Scope of the project

The project work is carried out to estimate the ARR for the third MYT control period (FY

2015-16 to FY 2017-18) and to examine the impact of MOD model on power purchase cost

for BSES Yamuna Power Ltd, which is a distribution licensee supplying power to Central &

East Delhi.

In this context, the ARR is projected for:

i. Wheeling Business; and

ii. Retail Supply Business

of the distribution licensee, i.e. BYPL.

1.6 Organization profile : BSES Yamuna Power Ltd

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

Board (DVB) in July 2002, the business of power distribution in NCT Delhi was divided into

three Distribution Companies by the name of Central-East Delhi Electricity Distribution

Company Ltd, South-West Delhi Electricity Distribution Company Ltd and North-North

West Delhi Electricity Distribution Company Ltd. Through a competitive bidding process,

these three discoms were rechristened under the Transfer Scheme Rules (effective from July

1, 2002) as BSES Yamuna Power Ltd (BYPL), BSES Rajdhani Power Ltd (BRPL), and

North Delhi Power Ltd (NDPL) respectively by forming Joint Venture between GoNCTD

and Reliance Infra (for BYPL and BRPL), and GoNCTD and Tata Power (for NDPL) with

51% of equity shares in each of the three discoms owned by the private investors.

[ 7 ]

BYPL distributes power to an area spread over 200 sq kms with a population density of 6750

per sq km. It‟s 13.5 lakh customers are spread over 14 districts across Central and East areas

including Chandni Chowk, Daryaganj, Paharganj, Shankar Road, Patel Nagar, G T Road,

Karkardooma, Krishna Nagar, Laxmi Nagar, Mayur Vihar, Yamuna Vihar, Nand Nagri and

Karawal Nagar.

Since taking over distribution, BSES‟ singular mission has been to provide reliable and

quality electricity supply. BSES has invested over Rs 4500 Cr. on upgrading and augmenting

the infrastructure which has resulted in a record reduction of AT&C losses. From a high of

63.1 % AT&C losses in BYPL area in 2002 the losses have come down to 17.83% a record

reduction of 45.3%.

Figure 1: Segregation of areas under three discoms in NCT Delhi

[ 8 ]

Table 1: Some statistics on BSES Yamuna Power Ltd & BSES Rajdhani Power Ltd

Sl No Particulars Unit BYPL (East &

Central)

BRPL (South &

West)

1 Area sq km 200 750

2 Customer Density (as of

Mar ‟13)

Cons /

sq km 6750 2465

3 Total Registered Customers

(as of Mar ‟13) Million 1.35 1.85

4 Peak Demand (FY ‟13) MW 1461 2338

Vision of BSES:

i. To be amongst the most admired and most trusted integrated utility companies in the

world.

ii. To deliver reliable and quality products and services to all customers at competitive

costs, with international standards of customer care- thereby creating superior value

for all stakeholders.

iii. To set new benchmarks in: standards of corporate performance and governance,

through the pursuit of operational and financial excellence, responsible citizenship

and profitable growth.

Mission of BSES:

i. To attain global best practices and become a world-class utility.

ii. To provide: uninterrupted, affordable, quality, reliable, safe and clean power to our

customers.

iii. To achieve excellence in: service, quality, reliability, safety and customer care.

iv. To earn: trust and confidence of all customers and stakeholders by exceeding their

expectations, and make the company a respected household name.

v. To work with vigour, dedication and innovation keeping total customer satisfaction as

the ultimate goal.

vi. To consistently achieve: high growth with the highest levels of productivity.

vii. To be: a technology driven, efficient and financially sound organization.

[ 9 ]

viii. To be a responsible corporate citizen nurturing human values and concern for society,

the environment and above all, people.

ix. To contribute: towards community development and nation building.

x. To promote a work culture that fosters individual growth, team sprit and creativity to

overcome challenges and attain goals.

xi. To encourage: ideas, talent and value systems.

xii. To uphold the guiding principles of: trust, integrity and transparency in all aspects of

interactions and dealings.

[ 10 ]

2. REVIEW OF LITERATURE

2.1 ARR determination in Electricity distribution business under MYT

framework

As per Electricity Act 2003, Section 62 (1):

“The Appropriate Commission shall determine the tariff in accordance with the 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:

Provided that in case of distribution of electricity in the same area by two or more

distribution licensees, the Appropriate Commission may, for promoting competition

among distribution licensees, fix only maximum ceiling of tariff for retail sale of

electricity.”

As per Electricity Act 2003, Section 62 (5):

“The Commission may require a licensee or a generating company to comply with such

procedures as may be specified for calculating the expected revenues from the tariff and

charges which he or it is permitted to recover.”

Clause 8.1 (1) of National Tariff Policy states that:

[ 11 ]

“…This (Multi Year Tariff Framework) would minimize risks for utilities and consumers,

promote efficiency and appropriate reduction of system losses and attract investments and

would also bring greater predictability to consumer tariffs on the whole by restricting tariff

adjustments to known indicators on power purchase prices and inflation indices. The

framework should be applied for both public and private utilities.”

Clause 2.1(b) of Regulation A2 of DERC (Terms & Conditions for Determination of

Wheeling Tariff & Retail Supply Tariff) Regulations, 2011 defines ARR as:

“Aggregate Revenue Requirement or ARR means for each Financial Year, the costs

pertaining to the Licensed business which are permitted, in accordance with these

Regulations, to be recovered from the tariffs and charges determined by the Commission.”

Clause 7.3 of Regulation A7 of DERC (Terms & Conditions for Determination of Wheeling Tariff &

Retail Supply Tariff) Regulations, 2011 explains Business Plan Filings as a part of Multi-Year Filings

for the Control Period as:

“The Distribution Licensee shall file for the Commission’s approval, on 1st

April of the year

preceding the first year of the Control Period or any other date as may be directed by the

Commission, a Business Plan approved by the Board of Directors.”


Retail Supply Tariff) Regulations, 2011 explains Tariff Filings as a part of Multi-Year Filings for the

Control Period as:

“The Distribution Licensee shall file an application for approval of Wheeling Tariff and

Retail Supply Tariff for each year of the Control Period, not less than 120 days before the

commencement of the first year of the Control Period or such other date as may be directed

by the Commission.”

Clauses 4.1 & 4.2 of Regulation A4 of DERC (Terms & Conditions for Determination of Wheeling

Tariff & Retail Supply Tariff) Regulations, 2011 state that:

“4.1 : The Commission shall adopt Multi Year Tariff framework for approval of ARR and

expected revenue from tariffs and charges.

[ 12 ]

4.2 : The Multi Year Tariff framework shall be based on the following:

(a) Business Plan of the Distribution Licensee for the entire Control Period to be

submitted to the Commission for approval, prior to the start of the Control Period;

(b) Applicant’s forecast of expected Wheeling Tariff and Retail Supply Tariff for each

year of the Control Period, based on reasonable assumptions of the underlying

financial and operational parameters, as submitted in the Business Plan;

(c) Trajectory for specific parameters shall be stipulated by the Commission, where the

performance of the applicant is sought to be improved through incentives and

disincentives;

(d) Annual review of performance shall be conducted based on the actual vis-à-vis the

approved forecast and categorization of variations in performance into controllable

factors and uncontrollable factors;

(e) The Distribution Licensee’s performance vis-à-vis the AT&C loss targets specified by

the Commission shall be appropriately incentivize / penalise; and

(f) Variation in revenue / cost on account of uncontrollable factors like sales, power

purchase and controllable factors - RoCE and Depreciation shall be trued up

annually.”


of a distribution licensee

Clause 8.2.1 (1) of National Tariff Policy states that:

“All power purchase costs need to be considered legitimate unless it is established that the

merit order principle has been violated or power has been purchased at unreasonable rates.”

Para 11 of Regulation 6.5 of the CERC (Indian Electricity Grid Code) Regulations states that:

“Since variation of generation in run-of-river power stations shall lead to spillage, these

shall be treated as must run stations. All renewable energy power plants, except for biomass

power plants, and non-fossil fuel based cogeneration plants whose tariff is determined by the

CERC shall be treated as ‘MUST RUN’ power plants and shall not be subjected to ‘merit

order dispatch’ principles.”

[ 13 ]


Retail Supply Tariff) Regulations, 2011 state that:

“While approving the cost of 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 dispatch based on a ranking of all approved sources of supply in the

order of their variable cost of power purchase.”

Gujarat Electricity Regulatory Commission (GERC) in its MYT tariff order dated Sep 6,

2011 for Dakshin Gujarat Vij Company Limited (DGVCL) stated in Para 6.8.12 that:

“…GUVNL, in order to optimize the power purchase costs, has worked out a comprehensive

merit order dispatch (MOD), as shown below:

The dispatch from individual generating station is worked out, based on merit order

of variable cost of each generating unit.

NPC power plants, renewable sources, captive power plants and hydro power plants

have been considered as must run power plants. Hence, they have been excluded from

merit order calculations.

R-LNG spot gas based power plants PLF is considered at 30% for FY 2011-12 and @

5% for the FY 2012-13 onwards due to high variable costs. The power purchase from

these plants has been capped by GUVNL in order to minimize the impact of higher

variable cost of generation from these plants.

During merit order dispatch, at least 50% availability of each plant has been

considered to take care of the peak loads and peak seasons.

Fixed cost and variable cost for GSECL plants have been taken as approved by the

Commission for the control period in the Order dated 31st March, 2011.

For IPPs and central sector stations, fixed cost and variable costs are taken as per

actuals of FY 2009-10.”

[ 14 ]

3. RESEARCH METHODOLOGY

3.1 ARR projection for BSES Yamuna Power Ltd under MYT framework

for 3rd

MYT Control Period (FY 2015-16 to FY 2017-18)

The steps for ARR projection are discussed below in details.

3.1.1 Sales Forecast

The Licensee shall forecast sales for each customer category and sub-categories for each year

of the Control Period in their filings, for the Commission‟s review and approval. The

Commission shall examine the forecasts for their reasonableness and consistency based on

growth in the number of consumers, pattern of consumption, losses and demand of electricity

in previous years and anticipated growth in the next year and any other factor, which the

Commission may consider relevant and approve the sales forecast with such modifications as

deemed fit for each year of the Control Period.

3.1.1.1 Forecast of Number of Consumers

1) 2nd

Control Period (FY 2012-13 to FY 2014-15):

Here the projection for number of consumers for FY 2013-14 & FY 2014-15 has been

carried out from actual figures for FY 2007-08 to FY 2012-13.

A. Domestic Lighting / Fan & Power:

(a) Up to 2 KW Load: After implementation of MDI since 2011, number of

consumers in this category has shown a declining trend. The % decrease was

high (-20.21%) from FY 2010-11 to 2011-12, as revision of connected load

was started from FY 2011-12. Since then, it has been a continuous practice.

Following this, the % decrease from FY 2011-12 to 2012-13 was -5.26%.

Considering this practice will continue in years to come, the % change in

number of consumers in this category has been taken as -5.26%.

(b) 2 to 5 KW Load: Same as (a). The % effective growth rate is taken as 24.47%

(YoY growth rate from FY 2011-12 to FY 2012-13). In addition, a year-wise

declining factor in consumer growth rate has been considered keeping in mind

the high consumer density in BYPL area, and a probable upcoming saturation

in terms of consumer growth. For calculating this declining factor, the year-

[ 15 ]

wise decline in growth rate in the number of consumers under category

'Domestic lighting / fan and power' has been considered.

(c) Above 5 KW Load: Same as (b). The % effective growth rate is taken as

17.94% (YoY growth rate from FY 2011-12 to FY 2012-13).

B. Domestic Lighting / Fan & Power on 11 KV single delivery point for CGHS: 5

year CAGR (FY 2012-13 over 2008-09) has been taken as the effective growth

rate.

C. Non-Domestic Low Tension (NDLT): 5 year CAGR (FY 2012-13 over 2008-09)

has been taken as the effective growth rate.

D. Non-Domestic High Tension (NDHT): There is much deviation in YoY variation

in growth rates. Hence 3 year CAGR (FY 2012-13 over 2010-11) has been taken

as the effective growth rate for the coming years.

E. Small Industrial Power (SIP): Projected growth has been taken as 0%, as change

in consumers in this category will depend upon Govt. policies and cannot be

predicted based on previous years' figures.

F. Large Industrial Power (LIP): Projected growth has been taken as 0%, as change



G. Agricultural Consumers: Projected growth has been taken as 0%, as it cannot be


H. Mushroom Cultivation: Projected growth has been taken as 0%, as it cannot be


I. DMRC: 5 year CAGR (FY 2012-13 over 2008-09) has been taken as the effective

growth rate.

J. Own Consumption: Growth rate is taken same as that for NDLT consumers.

K. DJB: Projected growth has been taken as 0%.

L. 11 KV - Worship / Hospital: 5 year CAGR (FY 2012-13 over 2008-09) has been

taken as the effective growth rate.

M. DVB Staff: 5 year CAGR (FY 2012-13 over 2008-09) has been taken as the

effective growth rate.

2) 3rd

Control Period (FY 2015-16 to FY 2017-18):

[ 16 ]

For 3rd Control period, growth rates have been majorly taken equal to the prevailing

growth rate in the previous control period, i.e. 3 yr CAGR figures (for FY 2014-15

over FY 2012-13).

A. Domestic Lighting / Fan & Power:

(a) Up to 2 KW Load: 3 year CAGR (FY 2014-15 over 2012-13) has been taken

as the effective growth rate.

(b) 2 to 5 KW Load: 3 year CAGR (FY 2014-15 over 2012-13) plus a year-wise

declining factor has been taken as the effective growth rate.

(c) Above 5 KW Load: 3 year CAGR (FY 2014-15 over 2012-13) plus a year-

wise declining factor has been taken as the effective growth rate.

B. Domestic Lighting / Fan & Power on 11 KV single delivery point for CGHS: 3

year CAGR (FY 2014-15 over 2012-13) has been taken as the effective growth

rate.

C. Non-Domestic Low Tension (NDLT): 3 year CAGR (FY 2014-15 over 2012-13)


D. Non-Domestic High Tension (NDHT): 3 year CAGR (FY 2014-15 over 2012-13)


E. Small Industrial Power (SIP): Projected growth has been taken as 0%, as change



F. Large Industrial Power (LIP): Projected growth has been taken as 0%, as change



G. Agricultural Consumers: Projected growth has been taken as 0%, as it cannot be


H. Mushroom Cultivation: Projected growth has been taken as 0%, as it cannot be


I. DMRC: 3 year CAGR (FY 2014-15 over 2012-13) has been taken as the effective

growth rate.

J. Own Consumption: 3 year CAGR (FY 2014-15 over 2012-13) has been taken as

the effective growth rate.

K. DJB: Projected growth has been taken as 0%.

L. 11 KV - Worship / Hospital: 3 year CAGR (FY 2014-15 over 2012-13) has been

taken as the effective growth rate.

[ 17 ]

M. DVB Staff: 3 year CAGR (FY 2014-15 over 2012-13) has been taken as the

effective growth rate.

3.1.1.2 Forecast of Connected Load (MW)

Forecasting of connected load for different consumer categories is done in the same way as

number of consumers.

3.1.1.3 Forecast of Energy Sales (MU)

Forecasting of energy sales (MU) is done in two parts.

First the future values of energy sales (MU) are forecasted based on projected values of

number of consumers & connected load. For this purpose, the sales growth rate in any

consumer category has been considered as the geometric mean of the growth rates in number

of consumers & connected load for the same consumer category. Accordingly the sales

figures for various years are projected.

The future values of energy sales are projected again in a different way using CAGR

technique. This is done in the same way as that in case of projecting number of consumers.

The final forecasted figures of energy sales are obtained by taking average of the projected

sales figures from CAGR method, and the projected sales figures obtained from the number

of consumers & connected load data.

3.1.2 Calculation of revenue

Based on the consumer-wise energy sales (MU) data, the revenue collected (Rs. Cr.) can be

projected at the existing tariff schedule effective from 01.08.2013 as declared by DERC in its

tariff order dated 31.07.2013.

[ 18 ]

Table 2: Tariff Schedule for BYPL consumers w.e.f. 01.08.2013

TARIFF SCHEDULE W.E.F. 01.08.2013 (AS DETERMINED BY DERC IN ITS TARIFF ORDER DATED

31.07.2013)

SL

NO CATEGORY FIXED CHARGES

ENERGY

CHARGES

1 Domestic

1.1 Domestic Lighting / Fan and Power

a. Upto 2 KW connected load

0 - 200 Units 40 Rs/month 390 Paisa/KWh



Above 800 Units 40 Rs/month 700 Paisa/KWh

b. 2 to 5 KW connected load




Above 800 Units 100 Rs/month 700 Paisa/KWh

c. Above 5 KW connected load

0 - 200 Units 20 Rs/KW/month 390 Paisa/KWh



Above 800 Units 20 Rs/KW/month 700 Paisa/KWh

1.2 Single delivery point on 11KV for CGHS

First 55% 20 Rs/KW/month 580 Paisa/KWh

Next 40% 20 Rs/KW/month 680 Paisa/KWh

Balance 5% 20 Rs/KW/month 700 Paisa/KWh

2 Non-Domestic

2.1 Non-Domestic Low Tension (NDLT)

Up to 10 KW 100 Rs/KW/month 790 Paisa/KWh

> 10 KW (11 KVA) to 100 KW (108 KVA) 115 Rs/KVA/month 760 Paisa/KVAh

Above 100 KW (108 KVA) (400 V)

(No supply on LT for load>215 KVA) 150 Rs/KVA/month 890 Paisa/KVAh

2.2 Non-Domestic High Tension (NDHT)

For supply at 11KV and above (for load greater

than 108KVA) 125 Rs/KVA/month 750 Paisa/KVAh

3 Industrial

3.1 Small Industrial Power (SIP) (<200 KW / 215

KVA)


> 10 KW (11KVA) to 100 KW (108KVA) 90 Rs/KVA/month 700 Paisa/KVAh

Above 100 KW (108 KVA) (400 V)


[ 19 ]

3.2 Industrial power on 11KV Single Point

Delivery for group of SIP consumers 90 Rs/KVA/month 630 Paisa/KVAh

3.3 Large Industrial Power (LIP)

(Supply at 11KV and above) 125 Rs/KVA/month 660 Paisa/KVAh

4 Agriculture 20 Rs/KW/month 275 Paisa/KWh

5 Mushroom Cultivation 40 Rs/KW/month 550 Paisa/KWh

6 Public Lighting

6.1 Metered

Street Lighting

700 Paisa/KWh

Signals & Blinkers

700 Paisa/KWh

6.2 Unmetered

Street Lighting

750 Paisa/KWh

Signals & Blinkers

750 Paisa/KWh

7 Delhi Jal Board

Supply at LT


> 10 KW (11KVA) to 100 KW (108KVA) 90 Rs/KVA/month 700 Paisa/KVAh

Above 100 KW (108 KVA) (400 V)


Supply at 11KV and above 125 Rs/KVA/month 660 Paisa/KVAh

8 Delhi International Airport Ltd 150 Rs/KVA/month 710 Paisa/KVAh

9 Railway Traction 150 Rs/KVA/month 610 Paisa/KVAh

10 DMRC (Supply at 220 KV & 66 KV) 125 Rs/KVA/month 550 Paisa/KVAh

11 Advertisements & Hoardings 500 Rs/month/hoarding 1000 Paisa/KVAh

3.1.3 AT&C Loss, Distribution Losses, Collection Efficiency & Energy

Requirement

AT&C Loss shall be measured as the difference between the units input into the distribution

system for sale to all its consumer and the units realized wherein the units realized shall be

equal to the product of units billed and collection efficiency, provided that units billed shall

include the units realized on account of theft measured on actual basis i.e. number of units

against which payment of theft billing has been realized.

AT&C Loss = (Units input into the distribution system for sale to all its consumer – Units

realized)

Units Realized = Units Billed × Collection Efficiency

[ 20 ]

Distribution losses shall be measured as the difference between the net units input into the

distribution system for sale to all its consumer and sum of the total energy billed in its

License area in the same year.

Distribution Losses = (Net units input into the distribution system for sale to all its consumer

– Sum of the total energy billed in its License area in the same year)

Collection efficiency shall be measured as ratio of total revenue realized to the total revenue

billed in the same year, provided that revenue realization from electricity duty and late

payment surcharge shall not be included for computation of collection efficiency.

Collection Efficiency Total revenue realized (Rs. Cr.)

Total revenue billed (Rs. Cr.) × 100%

Hence it can be written as

AT&C Loss (%) = 100% - Collection Efficiency (%) × (100% - Distribution Losses (%))

The quantum of power purchase is decided by the expected sale of energy by the Licensee, as

well as the targeted loss levels. Higher expected sales require a greater quantum of power to

be purchased. Similarly, higher loss levels also require a proportionately greater amount of

power purchase by the Licensee because it needs to meet the expected sales (in MU) after

accounting for various losses in the process of supplying electricity. The energy sale for each

year is grossed up by the distribution loss level for the year, to arrive at the required quantum

of power purchase for that year in the following manner:

Quantum of power purchase (MU) Energy Sales (MU)

(100% - Distribution Loss(%))

Distribution losses for FY 2012-13, FY 2013-14 & FY 2014-15 are taken as specified by

DERC in its tariff order for FY 2013-14 dated 31.07.2013. Average declining rate of

distribution losses over FY 2013-14 & FY 2014-15 has been taken as the declining rate for

the 3rd Control Period. The collection efficiency for future is taken as 99.50%. AT&C loss is

calculated from distribution loss & collection efficiency figures.

[ 21 ]

3.1.4 Energy availability from generating stations

Energy availability (MU) to BYPL from various generating stations is calculated based on

allocation of power to BYPL (in MW) from those generating stations (as per long term

PPAs), and % energy availability for past 3 years.

Table 3: Allocation of power to BYPL from NTPC stations

SL

NO SOURCE

INSTALLED

CAPACITY

(MW)

TOTAL

SHARE OF

BYPL (%)

TOTAL

SHARE OF

BYPL (MW)

1 ANTA GAS 419.33 2.86% 11.99

2 AURAIYA GAS 663.36 2.96% 19.62

3 BTPS 705.00 28.46% 157.45

4 DADRI GAS 829.78 2.99% 24.77

5 FARAKKA 1600.00 0.38% 6.06

6 KAHALGAON 840.00 1.65% 13.89

7 NCPP 840.00 28.46% 186.19

8 RIHAND –I 1000.00 2.72% 27.24

9 RIHAND –II 1000.00 3.43% 34.32

10 SINGRAULI 2000.00 2.04% 40.86

11 UNCHAHAR-I 420.00 1.56% 6.53

12 UNCHAHAR-II 420.00 3.05% 12.80

13 UNCHAHAR-III 210.00 3.76% 7.90

14 KAHALGAON STAGE-II 1500.00 2.86% 42.86

15 Talcher 1000.00 0.00% 0.00

16 Dadri Ext 980.00 20.43% 200.21

17 Aravali Power Corporation Ltd 1500.00 3.21% 48.17

Table 4: Allocation of power to BYPL from NHPC stations

SL

NO SOURCE

INSTALLED

CAPACITY

(MW)

TOTAL

SHARE OF

BYPL (%)

TOTAL

SHARE OF

BYPL (MW)

1 BAIRA SIUL 180.00 3.00% 5.39

2 CHAMERA-I 540.00 2.15% 11.62

3 CHAMERA-II 300.00 3.63% 10.89

4 DHAULIGANGA 280.00 3.60% 10.08

5 DULHASTI 390.00 3.49% 13.63

6 SALAL 690.00 3.17% 21.84

[ 22 ]

7 TANAKPUR 94.20 3.49% 3.29

8 URI 480.00 3.01% 14.44

9 SEWA-II 120.00 3.63% 4.36

Table 5: Allocation of power to BYPL from NPCIL stations

SL

NO SOURCE

INSTALLED

CAPACITY

(MW)

TOTAL

SHARE OF

BYPL (%)

TOTAL

SHARE OF

BYPL (MW)

1 RAPS - 5 & 6 440.00 3.46% 15.21

2 NPCIL – NAPS 440.00 2.91% 12.80

Table 6: Allocation of power to BYPL from other central generating stations

SL

NO SOURCE

INSTALLED

CAPACITY

(MW)

TOTAL

SHARE OF

BYPL (%)

TOTAL

SHARE OF

BYPL (MW)

1 TEHRI HEP 1000.00 2.81% 28.06

2 Koteshwar 400.00 2.69% 10.74

3 NJPC (SATLUJ) 1500.00 2.58% 38.69

4 TALA HEP 1020.00 0.80% 8.17

5 DVC (Mejia #6) 250.00 3.20% 8.01

Table 7: Allocation of power to BYPL from state generating stations

SL

NO SOURCE

INSTALLED

CAPACITY

(MW)

TOTAL

SHARE OF

BYPL (%)

TOTAL

SHARE OF

BYPL (MW)

1 Rajghat 135.00 28.46% 38.42

2 GAS TURBINE 270.00 28.46% 76.83

3 Pragati -I 330.00 28.46% 70.75

[ 23 ]

Table 8: Allocation of power to BYPL from future stations

SL

NO SOURCE

INSTALLED

CAPACITY

(MW)

TOTAL

SHARE OF

BYPL (%)

TOTAL

SHARE OF

BYPL (MW)

1 Chamera-III 231.00 3.47% 8.01

2 Parbati –III 520.00 2.20% 11.44

3 Uri –II 240.00 2.16% 5.18

4 Pragati -III, Bawana 1370.20 19.30% 264.45

5 Mejia TPS Extn 1000.00 23.84% 238.40

6 Chandrapur Extn 500.00 21.79% 108.95

7 Koderma TPS 1000.00 21.11% 211.10

8 Koldam HEP 800.00 2.96% 23.68

9 Rihand-III 500.00 3.59% 17.97

10 Sasan UMPP(6*660) 3960.00 3.10% 122.76

11 Barh -II(2*660 )Mw 660.00 1.30% 8.58

Except future power stations, the % energy availability from all the existing power stations

for FY 2013-14 & FY 2014-15 are taken as the average of % energy availability for last 3

years. Further, % energy availability for 3rd control period for individual power stations is

taken as the average % energy availability in the 2nd control period for that station.

For future power stations, the % energy availability is projected according to their projected

synchronization / COD dates.

Table 9: Projected synchronization / COD dates of future stations

SL

NO

GENERATING

STATION

PROJECTED

SYNCHRONIZATION

DATE

REMARKS SOURCE OF

INFORMATION

1 Chamera-III

(3x77 MW)

Unit #1: June 2012

Unit #2: Aug 2012

Unit #3: Oct 2012

Actual dates

CEA targetted generation

capacity addition in 2012-

13

2 Parbati-III

(4x130 MW)

Unit #1: Aug 2013

Unit #2: Aug 2013

Unit #3: Dec 2013

Unit #4: Dec 2013

Parbati-III will be operational

at 50% capacity till 2017, due

to delay in upstream Parbati-II

project. Till then, it will not

generate more than 1000 MU

in a year. Design energy of

Parbati-III is 1963 MU

(@60% PLF)

CEA status of hydro

electric projects under

execution;

http://www.tribuneindia.c

om/2013/20130615/himac

[ 24 ]

hal.htm#6

3 Uri-II

(4x60 MW)

Unit #1: Sep 2013

Unit #2: Sep 2013

Unit #3: Oct 2013

Unit #4: Oct 2013

Design energy of Uri-II is

1123.76 MU

CEA status of hydro


execution;

http://www.greaterkashmi

r.com/news/2013/Jun/16/

prime-minister-to-

inaugurate-uri-ii-power-

project-on-kashmir-visit-

32.asp

4 Koderma TPS

(2x500 MW)

Unit #1: Jul 2011

Unit #2: Feb 2013

Expected energy availability is

assumed to be 85%

5 Koldam

(4x200 MW)

2014-15 Design energy is 3054 MU

CEA status of hydro


execution

6 Rihand-III

(2x500 MW)

Unit #5 (500 MW)

synchronization date:

19.05.2012


assumed to be 85%

CEA MONTHLY

REPORT ON BROAD

STATUS OF THERMAL

POWER PROJECTS IN

THE COUNTRY May-

2013

7 Sasan UMPP

(6x660 MW)

Unit #3 (660 MW)

synchronization date:

30.03.2013.

Expected

synchronization dates of

remaining units:

Unit #4: Nov 2013

Unit #2: Feb 2014

Unit #1: Jun 2014

Unit #5: Sep 2014

Unit #6: Jan 2015


assumed to be 85%.

8 Barh-II

(2x660 MW)

Unit #4: Oct 2013

Unit #5: Sep 2014


assumed to be 85%

CEA MONTHLY

REPORT ON BROAD

STATUS OF THERMAL

POWER PROJECTS IN

THE COUNTRY May-

2013

[ 25 ]

Pragati-III Bawana, Mejia-TPS & Chandrapur Extn energy availability figures are taken to be

equal to that in 2012-13.

For meeting RPO and purchasing renewable energy, targets set by DERC as mentioned in

DERC RPO & REC Framework Implementation Regulations, 2012 are followed.

Table 10: Renewable Purchase Obligation (as per DERC RPO & REC Framework

Implementation Regulations, 2012)

RPO (% of total energy consumption) Solar Non-Solar Total

2013-14 0.20% 4.60% 4.80%

2014-15 0.25% 5.95% 6.20%

2015-16 0.30% 7.30% 7.60%

2016-17 0.35% 8.65% 9.00%

2017-18 (estimated) 0.40% 10.00% 10.40%

Energy availability (MU) from various generating stations can be calculated by multiplying

the % projected energy availability to the energy sent out from the various generating stations

according to the MW power allocated to BYPL.

3.1.5 Power purchase cost

Cost of purchasing power from various generating stations consists of fixed charges, variable

charges and other charges (like income tax, ED, cess etc).

Fixed charges paid by BYPL to any generating station (except hydro power plants) can be

calculated as:

Fixed Charges (Rs. Cr.) = (% share of BYPL) × (Annual Fixed Charges of the station)

Actual Plant Availability Factor (%)

Normative Plant Availability Factor (%)

For hydro power plants, fixed charges can be calculated as:

[ 26 ]

Fixed Charges (Rs. Cr.) = 0.5 × (% share of BYPL) × (Annual Fixed Charges of the station)

Actual Plant Availability Factor (%)

Normative Plant Availability Factor (%)

Annual fixed charges for NTPC, NHPC, SGS, Tehri HEP, Koteshwar & NJPC (Satluj) are

obtained from their respective tariff orders.

Actual energy charge rates (Rs/KWh) ex-bus for NTPC & SGS for FY 2012-13 are obtained

from the bills raised by individual generating stations, and projections for further years are

made by assuming 5% escalation in energy charges / variable charges each year. This

escalation is accounted for as FPA.

Energy charge rates (Rs/KWh) for hydro power plants can be calculated as:

Energy Charge Rate (Rs/KWh)

0.5 Annual Fixed Charges of the station in Rs. Cr. 10

Design Energy (MU) (100% %Aux Cons) (100% % Free Energy for Home State)

For nuclear power plants, single-part tariffs (Rs/KWh) for different stations are obtained from

Dept. of Atomic Energy website and a 5% escalation is assumed year wise. This escalation is

accounted for as FPA.

For future power plants, due to absence of any information regarding fixed or variable

charges, a single part tariff (Rs/KWh) is considered on the basis of similar existing power

plants.

For renewable energy sources (solar and non-solar), the average market clearing price

through power exchanges (IEX & PXIL) is considered as the single part tariff (Rs/KWh).

3.1.6 Transmission Losses & Charges

Intra-state transmission loss is taken as 1.21% as per DTL letter no

F.DTL/207/DGM(SO)/2012‐13/170 dated 28.06.2012.

[ 27 ]

In absence of consolidated data of regional transmission losses for eastern grid, the average

eastern regional transmission loss for eastern grid is calculated by taking mean of the weekly

transmission loss data as reported in ERPC website in its weekly UI & congestion charge

account from 04.06.2012 to 15.07.2013. Transmission loss for northern grid is calculated by

taking mean of last 52 weeks (28.05.2012 to 26.05.2013) transmission loss data of northern

grid, as reported in NRLDC annual report for FY 2012-13.

The average inter-state transmission loss is calculated by taking mean of the average eastern

grid & northern grid transmission losses.

Base inter-state (PGCIL) transmission charge is taken as Rs. 210.48 Cr for FY 2013-14 as

approved by DERC in its tariff order for BYPL. Subsequently a 5% escalation is considered

year-wise. Base inter-state (DTL) transmission charge is taken as Rs. 150 Cr for FY 2013-14

as approved by DERC in its tariff order for DTL, wherein it is mentioned that allocation of

monthly charges toward BYPL is Rs. 12.50 Cr.

3.1.7 Operation & Maintenance (O&M) Expenses

As per DERC MYT Regulations 2011, Operation and Maintenance (O&M) expenses of a

distribution licensee include:

(a) Employee expenses – Salaries, wages, pension contribution and other employee costs;

(b) Administrative and General (A&G) expenses which shall also include expense related

to raising of loans;

(c) Repairs and Maintenance (R&M) expenses; and

(d) Other miscellaneous expenses, statutory levies and taxes (except corporate income

tax).

The O&M expenses for the Base Year shall be approved by the Commission taking into

account the latest available audited accounts, business plan filed by the Licensees, estimates

of the actuals for the Base Year, prudence check and any other factor considered appropriate

by the Commission.

O&M expenses permissible towards ARR for each year of the Control Period shall be

determined using the formula detailed below:

[ 28 ]

O&Mn = (R&Mn + EMPn + A&Gn) * (1 – Xn)

Where,

i. R&Mn = K * GFAn-1;

ii. EMPn + A&Gn = (EMPn-1 + A&Gn-1) * (INDX);

iii. INDX = 0.55 * CPI + 0.45 * WPI;

iv. Xn is an efficiency factor for nth

year. Value of Xn shall be determined by the

Commission in the MYT Tariff order based on Licensee‟s filing, benchmarking,

approved cost by the Commission in past and any other factor the Commission feels

appropriate;

v. EMPn – Employee Costs of the Licensee for the nth

year;

vi. A&Gn – Administrative and General Costs of the Licensee for the nth

year;

vii. R&Mn – Repair and Maintenance Costs of the Licensee for the nth

year;

viii. „K‟ is a constant (could be expressed in %). Value of K for each year of the Control

Period shall be determined by the Commission in the MYT Tariff order based on

Licensee‟s filing, benchmarking, approved cost by the Commission in past and any

other factor considered appropriate by the Commission;

i. INDX - Inflation Factor to be used for indexing. Value of INDX shall be a

combination of the Consumer Price Index (CPI) and the Wholesale Price Index (WPI)

for immediately preceding five years before the base year.

Table 11: Actual CPI & WPI growth in last 5 years preceding FY 2011-12 (base year for

2nd MYT Control Period)

YEAR CPI

(OVERALL)

% CPI

GROWTH

YoY

WPI

(OVERALL)

% WPI

GROWTH

YoY

2005-06 117.12

104.47

2006-07 125.00 6.73% 111.35 6.59%

2007-08 132.75 6.20% 116.63 4.74%

2008-09 144.83 9.10% 126.02 8.05%

2009-10 162.75 12.37% 130.81 3.80%

2010-11 179.75 10.45% 143.32 9.56%

AVERAGE

8.97%

6.55%

[ 29 ]

Source: CPI data – Labour Bureau, Govt of India, http://labourbureau.nic.in/;

WPI data – Office of the Economic Advisor to the Govt of India, Ministry of

Commerce & Industry, http://eaindustry.nic.in/

Table 12: Projected CPI & WPI for 2nd MYT Control Period

YEAR CPI

(OVERALL)

% CPI

GROWTH

YoY

WPI

(OVERALL)

% WPI

GROWTH

YoY

2011-12

(Base

Year)

195.87 8.97% 152.71 6.55%

2012-13 213.44 8.97% 162.71 6.55%

2013-14 232.58 8.97% 173.36 6.55%

2014-15 253.45 8.97% 184.71 6.55%

Table 13: Inflation Factor for 2nd MYT Control Period

INFLATION FACTOR FOR 2ND

CONTROL PERIOD

YEAR

WTD

AVG

INDEX

ESCALATION

FACTOR

2010-11 163.36

2011-12 176.45 1.08

2012-13 190.61 1.08

2013-14 205.93 1.08

2014-15 222.52 1.08

Table 14: Actual CPI & WPI growth in last 5 years preceding FY 2014-15 (base year for

3rd MYT Control Period)

YEAR CPI

(OVERALL)

% CPI

GROWTH

YoY

WPI

(OVERALL)

% WPI

GROWTH

YoY

2008-09 144.83

126.02

2009-10 162.75 12.37% 130.81 3.80%

2010-11 179.75 10.45% 143.32 9.56%

2011-12 194.83 8.39% 156.13 8.94%

2012-13 215.17 10.44% 167.62 7.36%

2013-14 228.33 6.12% 171.87 2.54%

AVERAGE

9.55%

6.44%

[ 30 ]

Source: CPI data – Labour Bureau, Govt of India, http://labourbureau.nic.in/;

WPI data – Office of the Economic Advisor to the Govt of India, Ministry of

Commerce & Industry, http://eaindustry.nic.in/

Table 15: Projected CPI & WPI for 3rd MYT Control Period

YEAR CPI

(OVERALL)

% CPI

GROWTH

YoY

WPI

(OVERALL)

% WPI

GROWTH

YoY

2014-15

(Base

Year)

250.14 9.55% 182.94 6.44%

2015-16 274.04 9.55% 194.72 6.44%

2016-17 300.22 9.55% 207.26 6.44%

2017-18 328.89 9.55% 220.60 6.44%

Table 16: Inflation Factor for 3rd MYT Control Period

YEAR

WTD

AVG

INDEX

ESCALATION

FACTOR

2013-14 202.92

2014-15 219.90 1.08

2015-16 238.34 1.08

2016-17 258.38 1.08

2017-18 280.16 1.08

3.1.7.1 Employee Expenses

Base year for 3rd

MYT Control Period is taken as FY 2014-15. Employee expenses in the

base year is taken as the same as approved by DERC in its MYT tariff order dated

13.07.2012. Employee expenses for subsequent years are found out by multiplying the

escalation factor to the previous years‟ expenses.

Also it has been assumed that 7th

Pay Commission will come into force with effect from

01.01.2016, and there will be an expected 3-fold hike in pay scale with respect to the 6th

Pay

Commission. Effect of the 7th

Pay Commission has been implemented in the employee

expenses calculation by considering that 75% of the employee cost is covered by FRSR

employees who will be under the 7th

Pay Commission regime, and rest 25% of the employee

cost is covered by Non-FRSR employees, expenses of whom are assumed to escalate as per

the escalation factor.

[ 31 ]

For the purpose of allocation of employee expenses into Wheeling and Retail Supply, first the

net employee expenses are allocated into the different employee functions in proportion of

the number of employees in the respective function to the total number of employees. FY

2014-15 is considered as base year for number of employees. Number of employees for that

year is taken from DERC MYT tariff order dated 13.07.2012. A year-on-year increase

(average of year-on-year increase for previous three years) is applied to FY 2014-15 expenses

to find out expenses for subsequent years.

Table 17: Number of Employees (function-wise)

PARTICULARS FY 2015-16 FY 2016-17 FY 2017-18

O&M 3505 3748 4009

Technical Services 190 203 217

Business 2070 2214 2367

Shared 865 924 988

Total 6630 7090 7581

Then the function-wise expenses are allocated to wheeling & retail supply businesses based

on the allocation statement submitted by BYPL in its MYT petition for 1st Control Period.

Table 18: Statement of Allocation of Employee Cost between Wheeling and Retail

Supply

FUNCTIONS WHEELING RETAIL

SUPPLY

O&M 90% 10%

Technical Services 90% 10%

MRBD 0% 100%

Business 0% 100%

Shared 50% 50%

3.1.7.2 Administrative & General (A&G) Expenses

Base year for 3rd

MYT Control Period is taken as FY 2014-15. A&G expense in the base year

is taken as the same as approved by DERC in its MYT tariff order dated 13.07.2012. A&G

[ 32 ]

expenses for subsequent years are found out by multiplying the escalation factor to the

previous years‟ expenses.

For the purpose of allocation of A&G expenses into Wheeling and Retail Supply, individual

components of A&G expense are apportioned into wheeling & retail supply based on

allocation statement submitted by BYPL in its MYT Petition for 1st Control Period.

Table 19: Statement of Allocation of A&G Expenses between Wheeling and Retail

Supply

FUNCTIONS WHEELING RETAIL

SUPPLY

Administrative Expenses

Rent rates and taxes 50% 50%

Insurance 80% 20%

Revenue Stamp Expenses Account 50% 50%

Consultancy Charges 10% 90%

Technical Fees and Other Professional Charges 50% 50%

Conveyance And Travel 64% 36%

DERC License fee 50% 50%

Vehicle related expenses 64% 36%

Other Expenses

Fee And Subscriptions Books And Periodicals 50% 50%

Printing And Stationery 30% 70%

Advertisement Expenses 30% 70%

Contributions/Donations To Outside Institute/Association 10% 90%

Electricity Charges To Offices & Establishments 50% 50%

Water Charges 50% 50%

Entertainment Charges 50% 50%

Miscellaneous Expenses 50% 50%

Legal Charges 10% 90%

Auditor's Fee 50% 50%

Material Related Expenses 90% 10%

3.1.7.3 Repair & Maintenance (R&M) Expenses

„K‟ factor for 3rd

MYT Control Period is taken as 3.11%, which has been approved by DERC

for 2nd

Control Period in its MYT tariff order dated 13.07.2012.

Revised opening GFA figures are taken for FY 13, 14 & 15 as per DERC tariff order for FY

2013-14 dated 31.07.2013.

[ 33 ]

Total R&M expenses is apportioned into wheeling and retail supply business by 92.84% and

7.16% respectively as per DERC MYT tariff order dated 13.07.2012, in absence of detailed

asset-wise R&M allocation figures.

3.1.7.4 Efficiency Factor

Efficiency factor for each year of the 3rd

MYT Control Period is taken as 4%, which has been

fixed by DERC for FY 2014-15 in its MYT tariff order dated 13.07.2012.

3.1.8 Capital Expenditure and Capitalization

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.

Capital investment plan submitted by the Licensee shall also provide details of ongoing

projects that will spill into the Control Period and new projects that will commence during

the Control Period but may extend beyond the Control Period.

However at this point of time, due to unavailability of any concrete capital investment plan in

BYPL for FY 2015-16 onwards, the Capital Expenditure for each year of the 3rd MYT

control period has been taken as Rs 230 Cr (approved provisionally by DERC in its MYT

tariff order dated 13.07.2012 for 2nd control period). DERC would true-up the capital

investment for each year at the end of each year of the Control Period based on the actual

capital investment carried out by BYPL.

Capitalization schedule for each year of the 3rd MYT control period has been taken as Rs 230

Cr. For fresh capital investment during the control period, 50% capitalization on fresh

investment is assumed to be taken up in the year, and the remaining 50% capitalization in the

next year. Capitalization for each year is subject to true-up at the end of each year of the

Control Period based on the actual capital investment made and schemes commissioned by

BYPL.

Opening consumer contribution and capitalization figures for FY 13, 14 & 15 are taken as per

the revised figures as stated by DERC in its tariff order dated 31.07.2013. For subsequent

[ 34 ]

years, i.e. the 3rd Control Period, the capitalization figures are taken as Rs 23.69 Cr, same as

the base year, i.e. FY 2014-15.

3.1.9 Depreciation

Depreciation is calculated for each year of the Control Period, on the amount of Original Cost

of the Fixed Assets considered for calculation of the Regulated Rate Base of the

corresponding year, provided that depreciation is not allowed on assets funded by consumer

contribution (i.e., any receipts from consumers that are not treated as revenue) and capital

subsidies/grants.

Depreciation shall be calculated annually, based on the straight line method, over the useful

life of the asset. The base value for the purpose of depreciation shall be original cost of the

asset. The residual value of assets shall be considered as 10% and depreciation shall be

allowed to a maximum of 90% of the original cost of the asset. Land is not a depreciable

asset and its cost shall be excluded while computing 90% of the original cost of the asset.

Asset wise depreciation and their allocation into wheeling & retail supply businesses are done

based on the following data, wherein depreciation rates for various assets are approved by

DERC, and allocation of GFA into Wheeling & Retail Supply was submitted by BYPL in its

MYT Petition for 1st Control Period.

Table 20: Depreciation Rates and Statement of Allocation of Depreciation between

Wheeling and Retail Supply

SL

NO ASSET CLASS

DEPRECIATION

RATE (%)

ALLOCATION

FOR

WHEELING

(%)

ALLOCATION

FOR RETAIL

SUPPLY (%)

A Land & Land rights 0.00%

B Building and Civil Works

1 Office Building 1.80% 64.00% 36.00%

2 Temporary Structure 1.80% 100.00% 0.00%

3 Others 1.80% 100.00% 0.00%

4 Other Civil Works 1.80% 100.00% 0.00%

C Plant & Machinery

1 Transformer +100kVa 3.60% 100.00% 0.00%

2 Transformer -100kVa 3.60% 100.00% 0.00%

3 Switchgears, Control gear & 3.60% 100.00% 0.00%

[ 35 ]

Protection

4 Batteries 18.00% 100.00% 0.00%

D Line Cable Networks etc.

1 Overhead lines up to 11kV 3.60% 100.00% 0.00%

2 Underground cables up to 11kV 2.57% 100.00% 0.00%

3 Lightening Arrestors (Station Type) 3.60% 100.00% 0.00%

4 Communication equipment 6.00% 50.00% 50.00%

5 Meters 6.00% 0.00% 100.00%

6 Vehicles 18.00% 64.00% 36.00%

7 Furniture & fixtures 6.00% 64.00% 36.00%

8 Office Equipments 6.00% 64.00% 36.00%

9 Computers 6.00% 50.00% 50.00%

10 Motor and Pump 6.00% 64.00% 36.00%

11 Fault Locating Equipment 18.00% 100.00% 0.00%

12 Any other items 3.60% 100.00% 0.00%

3.1.10 Advance Against Depreciation (AAD)

The Distribution Licensee is entitled to Advance Against Depreciation (AAD), computed in

the manner given hereunder:

AAD = Loan (raised for capital expenditure) repayment amount based on loan repayment

tenure, subject to a ceiling of 1/10th of loan amount minus depreciation as calculated

on the basis of these Regulations

Advance Against Depreciation shall be permitted only if the cumulative repayment up to a

particular year exceeds the cumulative depreciation up to that year, provided that Advance

Against Depreciation in a year shall be restricted to the extent of difference between

cumulative repayment and cumulative depreciation up to that year.

Allocation of AAD into wheeling and retail supply is done as per allocation of GFA.

3.1.11 Working Capital

As per DERC MYT Regulations 2011, working capital for wheeling business of electricity

shall consist of

(a) Receivables for two months of Wheeling Charges.

[ 36 ]

Working capital for retail supply of electricity shall consist of

(a) Receivables for two months of revenue from sale of electricity;

(b) Less: Power purchase costs for one month;

(c) Less: Transmission charges for one month; and

(d) Less: Wheeling charges for two month.

3.1.12 Regulated Rate Base (RRB)

The Regulated Rate Base (RRB) shall be used to calculate the total capital employed which

shall include the original cost of assets and working capital, less the accumulated

depreciation. Capital work in progress (CWIP) shall not form part of the RRB. Consumer

Contribution, capital subsidies / grants shall be deducted in arriving at the RRB. The RRB

shall be determined for each year of the Control Period at the beginning of the Control Period

based on the approved capital investment plan with corresponding capitalization schedule and

normative working capital.

The Regulated Rate Base (RRB) for the ith

year of the Control Period shall be computed in the

following manner:

RRBi = RRB i-1 + ΔABi /2 + ΔWCi

Where,

ΔABi: Change in the Regulated Rate Base in the ith

year of the Control Period. This

component shall be the average of the value at the beginning and end of the year as

the asset creation is spread across a year and is arrived at as follows:

ΔABi = Invi – Di – CCi;

Where,

Invi: Investments projected to be capitalized during the ith

year of the Control Period

and approved;

Di: Amount set aside or written off on account of Depreciation of fixed assets for the

ith

year of the Control Period;

[ 37 ]

CCi: Consumer Contributions, capital subsidy / grant pertaining to the ΔABi and

capital grants/subsidies received during ith

year of the Control Period for

construction of service lines or creation of fixed assets;

RRB i-1: Regulated Rate Base for the Financial Year preceding the ith

year of the Control

period. For the first year of the Control Period, RRB i-1 shall be the Regulated Rate Base for

the Base Year i.e. RRB0;

RRB0 = OCFA0 – AD0 – CC0;

Where;

OCFA0: Original Cost of Fixed Assets at the end of the Base Year available for use

and necessary for the purpose of the Licensed business;

AD0: Amounts written off or set aside on account of depreciation of fixed assets

pertaining to the regulated business at the end of the Base Year;

CC0: Total contributions pertaining to the OCFA0, made by the consumers, capital

subsidy / grants towards the cost of construction of distribution/service lines by

the Distribution Licensee and also includes the capital grants/subsidies received

for this purpose;

ΔWCi: Change in normative working capital requirement in the ith

year of the Control Period,

from the (i-1)th

year. For the first year of the Control Period (i=1), ΔWC1 shall be

taken as the normative working capital requirement of the first year.

For the purpose of allocating the RRB into wheeling & retail supply, following methods are

adopted:

(a) OCFA allocated as per GFA allocation;

(b) Depreciation allocated as per GFA allocation;

(c) Investment capitalized as per GFA allocation;

(d) Consumer Contribution has been considered fully for Wheeling business.

[ 38 ]

3.1.13 Means of Finance

For the purpose of projecting future funding requirement, a normative debt-equity ratio of

70:30 has been considered on the asset capitalized each year after utilizing the consumer

contribution.

3.1.14 Return on Capital Employed (RoCE)

Return on Capital Employed (RoCE) shall be used to provide a return to the Distribution

Licensee, and shall cover all financing costs, without providing separate allowances for

interest on loans and interest on working capital.

Return on Capital Employed (RoCE) for the year „i‟ shall be computed in the following

manner:

RoCE = WACCi × RRBi

Where,

WACCi - Weighted Average Cost of Capital for each year of the Control Period. It can be

calculated as:

WACC = d e

D / E 1r r

1 D / E 1 D / E

Where,

D/E = Debt to Equity Ratio;

rd = Cost of debt;

re = Return on Equity and shall be considered at 16% post tax;

RRBi - Regulated Rate Base is the asset base for each year of the Control Period based on the

capitalization and working capital.

For allocation of RoCE into Wheeling & Retail Supply, allocation of debt and equity are

done in proportion of allocation of total GFA into Wheeling & Retail Supply each year.

[ 39 ]

3.1.15 Income Tax

Tax on income, if any, liable to be paid on the Licensed business of the Distribution Licensee

shall be limited to tax on return on the equity component of capital employed. Any additional

tax other than this shall not be a pass through, and it shall be payable by the Distribution

Licensee itself.

Allocation of tax expenses into Wheeling & Retail Supply is done in the ratio of allocation of

RoCE into Wheeling & Retail Supply.

3.1.16 Non Tariff Income

Non-tariff income for 3rd

MYT Control Period is taken as Rs. 78.95 Cr, which was approved

by DERC for 2nd

MYT Control Period in its MYT tariff order dated 13.07.2012.

3.1.17 Determination of ARR

3.1.17.1 ARR for Wheeling Business

The Aggregate Revenue Requirement for the Wheeling Business of the Distribution

Licensees for each year of the Control Period, shall contain the following items;

(a) Operation and Maintenance expenses;

(b) Return on Capital Employed;

(c) Depreciation;

(d) Income Tax;

(e) Interest on Consumer Security Deposit;

(f) Less: Non-Tariff Income;

(g) Less: Income from Other Business; and

(h) Less: Income from wheeling of electricity.

3.1.17.2 ARR for Retail Supply Business

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

Licensee, for each year of the Control Period, shall contain the following items;

(a) Cost of power procurement;

[ 40 ]

(b) Transmission & Load Dispatch charges;

(c) Operation and Maintenance expenses;

(d) Return on Capital Employed;

(e) Depreciation;

(f) Income Tax;

(g) Interest on Consumer Security Deposit;

(h) Less: Non-Tariff Income;

(i) Less: Income from Other Business; and

(j) Less: Receipts on account of cross subsidy surcharge and additional surcharge from

open access customers.


of BYPL

Following steps are adapted to implement Merit Order Dispatch (MOD) model and to

examine its impact on power purchase cost of BYPL:

(a) All nuclear power plants, renewable power plants and hydro power plants are

considered as must run power plants. Hence they are excluded from merit order

calculations. Whatever energy is available from those plants is drawn irrespective of

their costs.

(b) All the remaining power plants (Central & State thermal power stations) are sorted

according to their per unit variable charges. Merit order principle is complied by

giving priority to the power plants with lesser per unit variable charges.

(c) A reference variable charge is considered for those plants under merit order regime.

For those plants whose variable charges are lower than the reference variable charge,

whatever energy is available from those plants are drawn.

(d) For those plants whose variable charges are higher than the reference variable charge,

a defined % of energy (of the whole energy available from the plant) is drawn from

those plants.

(e) The reference variable charge shall preferably be the selling price of surplus power to

open market.

(f) Surplus power, if any, is sold to open market.

[ 41 ]

4. RESULTS & DISCUSSION

4.1 ARR projection for BSES Yamuna Power Ltd under MYT framework

for 3rd

MYT Control Period (FY 2015-16 to FY 2017-18)

4.1.1 Sales Forecast

4.1.1.1 Forecast of Number of Consumers

Table 21: Number of Consumers

SL NO PARTICULARS

NUMBER OF CONSUMERS TAKING

NEW SLABS (AS PER DERC TARIFF

ORDER DATED 31.07.2013) INTO

ACCOUNT

FY 2015-16 FY 2016-17 FY 2017-18

1 Domestic 1139360 1193230 1244103

1.1 Domestic Lighting / Fan and Power 1139346 1193216 1244089

1.1.1 Upto 2 KW Load 471158 454473 438378

0 - 200 Units 359651 346914 334629

200 - 400 Units 91907 88652 85513

401 - 800 Units 15680 15125 14589

Above 800 Units 3920 3781 3647

1.1.2 2 to 5 KW Load 586532 650487 711323

0 - 200 Units 266086 295100 322698

200 - 400 Units 203927 226163 247314

401 - 800 Units 93215 103379 113048

Above 800 Units 23304 25845 28262

1.1.3 Above 5 KW Load 81655 88257 94388

0 - 200 Units 16397 17723 18954

200 - 400 Units 20016 21634 23137

401 - 800 Units 36194 39120 41838

Above 800 Units 9048 9780 10459

1.2

Domestic Lighting / Fan and Power on

11KV single delivery point for CGHS

and other similar group housing

complexes

14 14 14

1.2.1 201 - 400 Units (first 55%) 8 8 8

1.2.2 401 - 800 Units (next 40%) 6 6 6

1.2.3 Above 800 Units (balance 5%) 1 1 1

2 Non-Domestic 361867 373825 386179

2.1 Non-Domestic (Low Tension): NDLT 361598 373546 385888

2.1.1 Up to 10 KW 339181 350389 361966

2.1.2 > 10 KW to 100 KW 22251 22986 23746

[ 42 ]

2.1.3 Above 100 KW 165 171 176

2.2 NDHT (Supply at 11 KV and above) 270 280 290

3 Industrial 11663 11663 11663

3.1 SIP - Small Industrial Power 11642 11642 11642

3.1.1 Up to 10 KW 7192 7192 7192

3.1.2 > 10 KW to 100 KW 4443 4443 4443

3.1.3 Above 100 KW 7 7 7

3.2 Large Industrial Power (as per tariff

order dated 26.08.2011) 21 21 21

4 Agriculture 44 44 44

5 Mushroom Cultivation 9 9 9

6 DMRC (supply at 66 KV) 1 1 1

7 Own Consumption 199 206 213

8 DJB (supply at 11 KV) 67 67 67

9 DJB Low Tension 523 523 523

9.1 Up to 10 KW 229 229 229

9.2 > 10 KW to 100 KW 289 289 289

9.3 Above 100 KW 5 5 5

10 11 KV - Worship / Hospital 27 28 29

11 Staff 6960 6930 6900

12 Advertisement and Hoarding 175 175 175

TOTAL 1520895 1586702 1649905

4.1.1.2 Forecast of Connected Load

Table 22: Connected Load (MW)

SL NO PARTICULARS

CONNECTED LOAD (MW) TAKING

NEW SLABS (AS PER DERC TARIFF


ACCOUNT

FY 2015-16 FY 2016-17 FY 2017-18

1 Domestic 3935 4396 4921


1.1.1 Upto 2 KW Load 996 1036 1077

0 - 200 Units 735 765 796

200 - 400 Units 213 222 231

401 - 800 Units 38 39 41

Above 800 Units 9 10 10

1.1.2 2 to 5 KW Load 2243 2593 2996

0 - 200 Units 975 1127 1302

200 - 400 Units 782 904 1044

401 - 800 Units 389 450 520

Above 800 Units 97 112 130

[ 43 ]

1.1.3 Above 5 KW Load 684 756 835

0 - 200 Units 132 146 161

200 - 400 Units 152 167 185

401 - 800 Units 320 354 391


1.2




complexes

12 12 12

1.2.1 201 - 400 Units (first 55%) 7 7 7

1.2.2 401 - 800 Units (next 40%) 5 5 5


2 Non-Domestic 1780 1903 2035

2.1 Non-Domestic (Low Tension): NDLT-I 1520 1628 1743

2.1.1 Up to 10 KW 918 983 1053

2.1.2 > 10 KW to 100 KW 573 613 657

2.1.3 Above 100 KW 29 31 34


3 Industrial 216 216 216


3.1.1 Up to 10 KW 24 24 24

3.1.2 > 10 KW to 100 KW 172 172 172

3.1.3 Above 100 KW 1 1 1


order dated 26.08.2011) 19 19 19

4 Agriculture 0 0 0


6 DMRC (supply at 66 KV) 24 25 25

10 Own Consumption 6.34 6.79 7.27

12 DJB (supply at 11 KV) 69 69 69

13 DJB Low Tension 7.14 7.14 7.14

13.1 Up to 10 KW 1.3 1.3 1.3

13.2 > 10 KW to 100 KW 5.13 5.13 5.13

13.3 Above 100 KW 0.71 0.71 0.71


15 Staff 31 34 37

16 Advertisement and Hoarding 0.57 0.57 0.57

TOTAL 6104 6693 7354

[ 44 ]

4.1.1.3 Forecast of Energy Sales

Table 23: Energy Sales (MU)

SL NO PARTICULARS

ENERGY SALES (MU) TAKING NEW

SLABS (AS PER DERC TARIFF


ACCOUNT

FY 2015-16 FY 2016-17 FY 2017-18

1 Domestic 3402 3634 3859


1.1.1 Upto 2 KW Load 886 876 871

0 - 200 Units 417 413 410

200 - 400 Units 326 323 321

401 - 800 Units 114 113 112


1.1.2 2 to 5 KW Load 1879 2073 2259

0 - 200 Units 334 369 402

200 - 400 Units 686 756 824

401 - 800 Units 688 759 827

Above 800 Units 172 190 207

1.1.3 Above 5 KW Load 623 671 715

0 - 200 Units 17 19 20

200 - 400 Units 71 77 82

401 - 800 Units 427 460 491

Above 800 Units 107 115 123

1.2




complexes

14 14 14

1.2.1 201 - 400 Units (first 55%) 8 8 8

1.2.2 401 - 800 Units (next 40%) 5 5 5


2 Non-Domestic 1810 1885 1963

2.1 Non-Domestic Low Tension (NDLT) 1411 1470 1531

2.1.1 Up to 10 KW 683 711 741

2.1.2 > 10 KW to 100 KW 685 714 744

2.1.3 Above 100 KW 43 45 46


3 Industrial 337 337 337


3.1.1 Up to 10 KW 27 27 27

3.1.2 > 10 KW to 100 KW 268 268 268

3.1.3 Above 100 KW 3 3 3


order dated 26.08.2011) 39 39 39

[ 45 ]

4 Agriculture 0 0 0


6 Public Lighting 107 108 109

6.1 Street Light 107 108 109

7 DMRC (supply at 66 KV) 162 173 185

8 Enforcement 25 23 21

9 Own Consumption 74 82 89

10 DJB (supply at 11 KV) 124 124 124

11 DJB Low Tension 6.77 6.77 6.77

11.1 Up to 10 KW 1.44 1.44 1.44

11.2 > 10 KW to 100 KW 4.34 4.34 4.34

11.3 Above 100 KW 0.99 0.99 0.99


13 Staff 28 28 29

14 Advertisement and Hoarding 0.4 0.4 0.4

TOTAL 6157 6484 6808

4.1.2 Revenue collected at existing tariff

Table 24: Revenue collected at existing tariff in FY 2015-16 (Rs. Cr.)

SL

NO PARTICULARS

FY 2015-16

FIXED

CHARGES

ENERGY

CHARGES

SURCHARGE

ON FC

SURCHARGE

ON EC

TOTAL

REVENUE

BILLED

1 Domestic 109.70 1987.49 8.78 159.00 2264.96

2 Non-Domestic 235.95 1416.85 18.88 113.35 1785.02

3 Industrial 26.11 258.01 2.09 20.64 306.86

4 Agriculture 0.01 0.06 0.00 0.00 0.07

5 Mushroom Cultivation 0.00 0.01 0.00 0.00 0.01

6 Public Lighting 0.00 75.12 0.00 6.01 81.13

7 DMRC (supply at 66 KV) 3.59 89.31 0.29 7.15 100.34

8 Enforcement 19.23

9 DJB (supply at 11 KV) 11.54 1.06 0.92 0.08 13.61

10 DJB Low Tension 0.38 5.24 0.03 0.42 6.07

11 11 KV - Worship / Hospital 5.46 63.55 0.44 5.08 74.54

12 Staff 7.14

13 Advertisement and

Hoarding 0.11 0.44 0.01 0.04 0.59

TOTAL 392.85 3897.15 31.43 311.77 4659.57

COLLECTION

EFFICIENCY 99.5%

TOTAL REVENUE

COLLECTED 4636.27

[ 46 ]


SL

NO PARTICULARS

FY 2016-17

FIXED

CHARGES

ENERGY

CHARGES

SURCHARGE

ON FC

SURCHARGE

ON EC

TOTAL

REVENUE

BILLED

1 Domestic 118.30 2129.49 9.46 170.36 2427.61

2 Non-Domestic 262.01 1475.48 20.96 118.04 1876.49

3 Industrial 26.11 258.01 2.09 20.64 306.86

4 Agriculture 0.01 0.06 0.00 0.00 0.07


6 Public Lighting 0.00 75.12 0.00 6.01 81.13

7 DMRC (supply at 66 KV) 3.70 95.17 0.30 7.61 106.78

8 Enforcement 19.23

9 DJB (supply at 11 KV) 11.54 1.06 0.92 0.08 13.61

10 DJB Low Tension 0.35 5.30 0.03 0.42 6.10

11 11 KV - Worship /

Hospital 5.57 65.78 0.45 5.26 77.06

12 Staff 0.02


Hoarding 0.11 0.44 0.01 0.04 0.59

TOTAL 427.69 4105.93 34.22 328.47 4915.56

COLLECTION

EFFICIENCY 99.5%

TOTAL REVENUE

COLLECTED 4890.98


SL

NO PARTICULARS

FY 2017-18

FIXED

CHARGES

ENERGY

CHARGES

SURCHARGE

ON FC

SURCHARGE

ON EC

TOTAL

REVENUE

BILLED

1 Domestic 126.74 2266.50 10.14 181.32 2584.69

2 Non-Domestic 280.06 1523.37 22.40 121.87 1947.70

3 Industrial 26.11 258.01 2.09 20.64 306.86

4 Agriculture 0.01 0.06 0.00 0.00 0.07


6 Public Lighting 0.00 75.12 0.00 6.01 81.13

7 DMRC (supply at 66 KV) 3.81 101.50 0.30 8.12 113.74

8 Enforcement 19.23

9 DJB (supply at 11 KV) 11.54 1.06 0.92 0.08 13.61

10 DJB Low Tension 0.35 5.30 0.03 0.42 6.10

11 11 KV - Worship / Hospital 5.67 68.10 0.45 5.45 79.67

12 Staff 0.01

[ 47 ]


Hoarding 0.11 0.44 0.01 0.04 0.59

TOTAL 454.39 4299.48 36.35 343.96 5153.41

COLLECTION

EFFICIENCY 99.5%

TOTAL REVENUE

COLLECTED 5127.65

4.1.3 AT&C Loss, Collection Efficiency, Distribution Losses & Energy

Requirement

Table 27: Distribution Losses (%), AT&C Loss (%) & Energy Requirement (MU)

DISTRIBUTION LOSS (%) & AT&C LOSS (%)


Distribution Loss (%) 13.00% 12.01% 11.09%

Collection Efficiency (%) 99.50% 99.50% 99.50%

AT&C Loss (%) 13.43% 12.45% 11.53%

Sales (MU) 6156.64 6483.66 6808.36

Energy Requirement (MU) 7076.32 7368.22 7657.52

4.1.4 Energy availability from generating stations

Table 28: Energy availability (MU) from NTPC stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

1 ANTA GAS 46.63 46.63 46.63

2 AURAIYA GAS 62.18 62.18 62.18

3 BTPS 941.68 941.68 941.68

4 DADRI GAS 98.78 98.78 98.78

5 FARAKKA 31.94 31.94 31.94

6 KAHALGAON 80.81 80.81 80.81

7 NCPP 1281.30 1281.30 1281.30

8 RIHAND -I 174.35 174.35 174.35

9 RIHAND -II 251.94 251.94 251.94

10 SINGRAULI 285.41 285.41 285.41

11 UNCHAHAR-I 45.24 45.24 45.24

[ 48 ]

12 UNCHAHAR-II 90.19 90.19 90.19

13 UNCHAHAR-III 56.45 56.45 56.45

14 KAHALGAON STAGE-II 231.26 231.26 231.26

15 Talcher

16 Dadri Ext 1242.62 1242.62 1242.62

17 Aravali Power Corporation Ltd 50.07 50.07 50.07

NTPC Total 4970.85 4970.85 4970.85

Table 29: Energy availability (MU) from NHPC stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

1 BAIRA SIUL 17.92 17.92 17.92

2 CHAMERA-I 45.43 45.43 45.43

3 CHAMERA-II 46.12 46.12 46.12

4 DHAULIGANGA 37.40 37.40 37.40

5 DULHASTI 64.63 64.63 64.63

6 SALAL 91.38 91.38 91.38

7 TANAKPUR 12.02 12.02 12.02

8 URI 75.48 75.48 75.48

9 SEWA-II 14.41 14.41 14.41

NHPC Total 404.79 404.79 404.79

Table 30: Energy availability (MU) from NPCIL stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

1 RAPS - 5 & 6 108.11 108.11 108.11

2 NPCIL - NAPS 57.13 57.13 57.13

Nuclear Total 165.25 165.25 165.25

[ 49 ]

Table 31: Energy availability (MU) from other central generating stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

1 TEHRI HEP 93.14 93.14 93.14

2 Koteshwar 30.78 30.78 30.78

3 NJPC (SATLUJ) 173.69 173.69 173.69

4 TALA HEP 26.19 26.19 26.19

5 DVC (Mejia #6) 54.26 54.26 54.26

Table 32: Energy availability (MU) from state generating stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

1 Rajghat 198.08 198.08 198.08

2 GAS TURBINE 358.25 358.25 358.25

3 Pragati -I 515.34 515.34 515.34

SGS Total 1071.67 1071.67 1071.67

Table 33: Energy availability (MU) from future stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

1 Chamera-III 22.88 22.88 22.88

2 Parbati -III 22.00 22.00 43.19

3 Uri -II 24.27 24.27 24.27

4 Pragati -III, Bawana 365.06 365.06 365.06

5 Mejia TPS Extn 808.91 808.91 808.91

6 Chandrapur Extn 521.95 521.95 521.95

7 Koderma TPS 1430.38 1430.38 1430.38

8 Koldam HEP 90.40 90.40 90.40

9 Rihand-III 125.08 125.08 125.08

10 Sasan UMPP(6*660) 859.23 859.23 859.23

11 Barh -II(2*660 )Mw 58.14 58.14 58.14

Future Stations Total 4328.31 4328.31 4349.50

[ 50 ]

Table 34: Energy availability (MU) from renewable sources

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

ENERGY

PURCHASED

EX-BUS (MU)

1 Non Solar 449.43 560.84 680.84

2 Solar 18.47 22.69 27.23

Total 467.90 583.53 708.07

4.1.5 Power purchase cost

Table 35: Power purchase cost (Rs. Cr.) for NTPC stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

1 ANTA GAS 29.89 31.01 32.18

2 AURAIYA GAS 42.57 44.16 45.82

3 BTPS 544.33 564.68 586.06

4 DADRI GAS 63.57 65.99 68.52

5 FARAKKA 13.06 13.52 13.99

6 KAHALGAON 29.90 30.88 31.92

7 NCPP 624.70 646.66 669.73

8 RIHAND -I 42.23 43.42 44.67

9 RIHAND -II 62.19 63.93 65.75

10 SINGRAULI 56.33 58.18 60.13

11 UNCHAHAR-I 18.21 18.87 19.57

12 UNCHAHAR-II 38.23 39.55 40.93

13 UNCHAHAR-III 25.81 26.64 27.51

14 KAHALGAON STAGE-II 83.62 86.28 89.08

15 Talcher

16 Dadri Ext 662.02 682.90 704.82

17 Aravali Power Corporation Ltd 58.08 59.05 60.07

NTPC Total 2394.74 2475.72 2560.74

[ 51 ]

Table 36: Power purchase cost (Rs. Cr.) for NHPC stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

1 BAIRA SIUL 3.17 3.17 3.17

2 CHAMERA-I 7.44 7.44 7.43

3 CHAMERA-II 14.15 14.17 14.19

4 DHAULIGANGA 11.70 11.69 11.68

5 DULHASTI 38.81 38.80 38.78

6 SALAL 17.09 17.07 17.06

7 TANAKPUR 3.26 3.26 3.26

8 URI 15.83 15.84 15.85

9 SEWA-II 6.98 6.98 6.98

NHPC Total 118.43 118.41 118.40

Table 37: Power purchase cost (Rs. Cr.) for NPCIL stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

1 RAPS - 5 & 6 43.22 45.37 47.63

2 NPCIL - NAPS 16.53 17.32 18.14

Nuclear Total 59.75 62.69 65.78

Table 38: Power purchase cost (Rs. Cr.) for other central generating stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

1 TEHRI HEP 52.12 52.34 52.57

2 Koteshwar 14.82 14.82 14.82

3 NJPC (SATLUJ) 54.19 54.40 54.62

4 TALA HEP 5.29 5.29 5.29

5 DVC (Mejia #6) 27.43 28.80 30.24

[ 52 ]

Table 39: Power purchase cost (Rs. Cr.) for state generating stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

1 Rajghat 126.13 130.30 134.68

2 GAS TURBINE 281.17 292.58 304.56

3 Pragati -I 273.16 283.62 294.59

SGS Total 680.45 706.49 733.83

Table 40: Power purchase cost (Rs. Cr.) for future stations

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

1 Chamera-III 10.36 10.36 10.36

2 Parbati -III 9.96 9.96 19.55

3 Uri -II 10.99 10.99 10.99

4 Pragati -III, Bawana 365.77 384.05 403.26

5 Mejia TPS Extn 308.37 323.79 339.98

6 Chandrapur Extn 219.47 230.44 241.96

7 Koderma TPS 601.44 631.52 663.09

8 Koldam HEP 40.92 40.92 40.92

9 Rihand-III 36.99 37.72 38.48

10 Sasan UMPP(6*660) 112.73 118.36 124.28

11 Barh -II(2*660 )Mw 13.39 14.06 14.77

Future Stations Total 1730.37 1812.16 1907.63

Table 41: Power purchase cost (Rs. Cr.) for renewable energy sources

SL

NO SOURCE

FY 2015-16 FY 2016-17 FY 2017-18

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

TOTAL

CHARGES

(Rs Cr)

1 Non Solar 67.42 84.13 102.13

2 Solar 22.06 27.10 32.52

Total 89.47 111.23 134.65

[ 53 ]

4.1.6 Transmission Losses & Charges

Table 42: Inter & Intra-State Transmission Losses (% and MU)

SL

NO PARTICULARS UNIT FY 2015-16 FY 2016-17 FY 2017-18

1 Inter-state transmission loss % 3.00% 3.00% 3.00%

MU 353.43 356.89 361.26

2 Intra-state transmission loss % 1.21% 1.21% 1.21%

MU 86.67 90.25 93.79

Table 43: Inter & Intra-State Transmission Charges (Rs. Cr.)

SL

NO TRANSMISSION CHARGES (Rs Cr) FY 2015-16 FY 2016-17 FY 2017-18

1 Inter-State (PGCIL) 232.05 243.66 255.84

2 Intra-State (DTL) 165.38 173.64 182.33

4.1.7 Energy balance

Table 44: Energy Balance

SL

NO PARTICULARS UNIT FY 2015-16 FY 2016-17 FY 2017-18

1 Energy Purchased MU 11786.83 11902.46 12048.18

2 Inter-state transmission loss

% 3.00% 3.00% 3.00%

3 MU 353.43 356.89 361.26

4 Energy Available at State periphery MU 11433.41 11545.56 11686.92

5 Energy Sales MU 6156.64 6483.66 6808.36

6 Distribution Loss

% 13.00% 12.01% 11.09%

7 MU 919.68 884.57 849.17

8 Energy Requirement at Distribution periphery MU 7076.32 7368.22 7657.52

9 Intra-state transmission loss

% 1.21% 1.21% 1.21%

10 MU 86.67 90.25 93.79

11 Energy Requirement at State periphery MU 7162.99 7458.47 7751.31

12 Energy Surplus (4 - 11) MU 4270.41 4087.09 3935.60

[ 54 ]

4.1.8 Operation & Maintenance (O&M) Expenses

Table 45: Total O&M Expenses

PARTICULARS FY 2015-

16

FY 2016-

17

FY 2017-

18

Employee Expense 269.80 722.70 783.61

A&G Expense 66.30 71.88 77.93

R&M Expense 88.64 95.80 102.95

TOTAL O&M Expenses 424.74 890.37 964.50

Efficiency Improvement 4% 4% 4%

Add SVRS Pension 5.33 13.44 14.58

NET O&M Expenses 413.08 868.20 940.49

Table 46: Allocation of Employee Expense into Wheeling & Retail Supply


Net Employee Cost

(Wheeling) 152.92 409.63 444.16

Pension Liability (Wheeling) 3.02 7.62 8.26

Total - Wheeling 155.94 417.25 452.43

Net Employee Cost (Retail

Supply) 116.88 313.07 339.45

Pension Liability (Retail

Supply) 2.31 5.82 6.31

Total - Retail Supply 119.19 318.89 345.76

Table 47: Allocation of A&G Expenses into Wheeling & Retail Supply

ALLOCATION OF A&G EXPENSES (Rs Cr)


Wheeling 30.14 32.68 35.43

Retail Supply 36.16 39.20 42.50

[ 55 ]

Table 48: Allocation of R&M Expenses into Wheeling & Retail Supply


16

FY 2016-

17

FY 2017-

18

R&M - Wheeling 82.30 88.94 95.58

R&M - Retail Supply 6.35 6.86 7.37

4.1.9 Capital Expenditure and Capitalization

Table 49: Capital Expenditure & Capitalization Schedule (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

Opening CWIP 115.00 115.00 115.00

Capital Expenditure during the year 230.00 230.00 230.00

Capitalization during the year 230.00 230.00 230.00

Investment capitalized out of opening CWIP 115.00 115.00 115.00

Investment capitalized out of fresh investment 115.00 115.00 115.00

Closing CWIP 115.00 115.00 115.00

Table 50: Consumer Contribution (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

Opening Consumer Contribution (Not Capitalized) 11.84 11.84 11.84

Consumer Contribution in the Investment 23.69 23.69 23.69

Opening Consumer Contribution already capitalized 277.85 301.54 325.23

Consumer Contribution Capitalized during the year 23.69 23.69 23.69

Closing Consumer Contribution (Not Capitalized) 11.84 11.84 11.84

Closing Consumer Contribution and Grants 301.54 325.23 348.92

Average Consumer Contribution and Grants 289.70 313.39 337.08

[ 56 ]

4.1.10 Depreciation

Table 51: Depreciation (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

Opening Balance of GFA 2850.25 3080.25 3310.25

Asset Additions 230.00 230.00 230.00

Reduction 0.00 0.00 0.00

Closing Balance of GFA 3080.25 3310.25 3540.25

Average GFA 2965.25 3195.25 3425.25

Less: Average Consumer Contribution 289.70 313.39 337.08

Average Asset net of Contribution 2675.56 2881.87 3088.18

Average rate of depreciation 3.70% 3.71% 3.71%

Depreciation 99.10 106.79 114.48

Accumulated Depreciation 1013.60 1120.39 1234.87

Table 52: Allocation of Opening GFA & Depreciation (Rs. Cr.)


Total GFA (Opening) 2850.25 3080.25 3310.25

GFA – Wheeling 2426.36 2622.15 2817.95

GFA - Retail Supply 423.89 458.10 492.30

Total Depreciation 99.10 106.79 114.48

Depreciation - Wheeling 75.60 81.47 87.33

Depreciation - Retail Supply 23.50 25.32 27.14

Table 53: Allocation of Accumulated Depreciation (Rs. Cr.)


Wheeling

Opening Balance 723.93 799.53 881.00

Depreciation for the year 75.60 81.47 87.33

Closing Balance 799.53 881.00 968.34

Retail Supply

Opening Balance 190.57 214.07 239.39

Depreciation for the year 23.50 25.32 27.14

Closing Balance 214.07 239.39 266.54

[ 57 ]

4.1.11 Advance Against Depreciation (AAD)

Table 54: Advance Against Depreciation (Rs. Cr.)

SL

NO PARTICULARS

FY 2015-

16

FY 2016-

17

FY 2017-

18

1 1/10th of Opening Loan (A) 211.76 228.81 245.01

2 Debt Repayment as considered for working out

Interest on Loan(B) 193.51 228.65 246.64

3 Minimum of A & B 193.51 228.65 245.01

4 Depreciation during the year 99.10 106.79 114.48

5 Excess of Min (A,B) over Depreciation (C) 94.41 121.86 130.53

6 Cumulative Repayment of Loan as considered for

working out Interest on Loan (D) 2068.73 2297.38 2544.03

7 Cumulative Depreciation (E) 1013.60 1120.39 1234.87

8 Excess of (D) over (E) (F) 1055.13 1176.99 1309.16

9 AAD = Min (C,F) / Zero if negative 94.41 121.86 130.53

Table 55: Allocation of AAD into Wheeling and Retail Supply (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

Wheeling 80.37 103.74 111.12

Retail Supply 14.04 18.12 19.41

4.1.12 Working Capital

Table 56: Working Capital (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

Total Working Capital – Wheeling 81.45 85.81 90.12

Total Working Capital - Retail Supply 355.71 368.88 378.19

Total Working Capital 437.17 454.69 468.32

Opening Balance 411.07 437.17 454.69

Closing Balance 437.17 454.69 468.32

Total Working Capital Requirement 26.10 17.52 13.63

[ 58 ]

4.1.13 Regulated Rate Base (RRB)

Table 57: RRB (Rs. Cr.)

SL

NO PARTICULARS REFERENCE

FY 2015-

16

FY 2016-

17

FY 2017-

18

1 RRB Opening A 1806.97 1845.86 1841.04

2 Investments Capitalized B 230.00 230.00 230.00

3 Depreciation C 99.10 106.79 114.48

4 AAD D 94.41 121.86 130.53

5 Consumer Contribution E 23.69 23.69 23.69

6 DAB (Change in RRB) F = B - C - D - E 12.80 (22.34) (38.70)

7 Change in Working Capital G 26.10 17.52 13.63

8 RRB Closing H = A + F + G 1845.86 1841.04 1815.98

9 RRBi I = A + (F/2) + G 1839.46 1852.21 1835.33

Table 58: RRB allocation into Wheeling & Retail Supply (Rs. Cr.)

SL

NO PARTICULARS

FY 2015-

16

FY 2016-

17

FY 2017-

18

1 RRB Opening – Wheeling 1356.01 1362.62 1353.87

2 RRB Opening - Retail Supply 450.96 483.24 487.17

3 RRB Closing – Wheeling 1362.62 1353.87 1331.85

4 RRB Closing - Retail Supply 483.24 487.17 484.13

5 RRBi – Wheeling 1354.56 1360.43 1345.02

6 RRBi - Retail Supply 484.91 491.79 490.30

4.1.14 Means of Finance

Table 59: Means of Finance (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

Capitalization 230.00 230.00 230.00

Less: Consumer Contribution for Fresh Investments 23.69 23.69 23.69

Net Capitalization 206.31 206.31 206.31

Equity 61.89 61.89 61.89

Debt 144.42 144.42 144.42

[ 59 ]

Table 60: Equity (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

Opening Equity 611.48 673.37 735.26

Addition during the year 61.89 61.89 61.89

Closing Equity 673.37 735.26 797.16

Average Equity 642.42 704.32 766.21

Table 61: Debt (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

Opening Loan 2117.63 2288.15 2450.08

Addition: CAPEX Loan 144.42 144.42 144.42

Addition: Working Capital Loan 26.10 17.52 13.63

Closing Loan 2288.15 2450.08 2608.13

Average Loan 2202.89 2369.11 2529.11

4.1.15 Return on Capital Employed (RoCE)

Table 62: WACC & RoCE (Rs. Cr.)

SL

NO PARTICULARS

FY 2015-

16

FY 2016-

17

FY 2017-

18

1 RRBi 1839.46 1852.21 1835.33

2 Equity (Average) 642.42 704.32 766.21

3 Debt (Average) 2202.89 2369.11 2529.11

4 Rate of Return on Equity (%) 16.00% 16.00% 16.00%

5 Rate of Return on Debt (%) 10.45% 10.73% 11.01%

6 WACCi (%) 11.70% 11.94% 12.17%

7 RoCE 215.27 221.11 223.36

Table 63: RoCE allocation into Wheeling & Retail Supply (Rs. Cr.)

SL

NO PARTICULARS

FY 2015-

16

FY 2016-

17

FY 2017-

18

1 RoCE – Wheeling 158.53 162.40 163.69

2 RoCE - Retail Supply 56.75 58.71 59.67

[ 60 ]

4.1.16 Income Tax

Table 64: Income Tax (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

RRB (Average) (Rs Cr) 1839.46 1852.21 1835.33

Equity (Rs Cr) 642.42 704.32 766.21

Debt (Rs Cr) 2202.89 2369.11 2529.11

% of Equity 22.58% 22.92% 23.25%

Equity Considered for Income Tax (Rs Cr) 415.32 424.46 426.74

Rate of Return (%) 16.00% 16.00% 16.00%

Return on Equity (Rs Cr) 66.45 67.91 68.28

MAT Rate (%) 20.01% 20.01% 20.01%

Income Tax (Rs Cr) 16.62 16.99 17.08

Table 65: Income Tax allocation into Wheeling & Retail Supply (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

Wheeling 12.24 12.48 12.52

Retail Supply 4.38 4.51 4.56

4.1.17 Non-Tariff Income

Table 66: Non-Tariff Income (Rs. Cr.)


16

FY 2016-

17

FY 2017-

18

Non Tariff Income (NTI) 78.95 78.95 78.95

NTI – Wheeling 11.55 11.55 11.55

NTI - Retail Supply 67.40 67.40 67.40

[ 61 ]

4.1.18 Aggregate Revenue Requirement (ARR)

Table 67: ARR (Rs. Cr.)

SL

NO PARTICULARS

FY 2015-

16

FY 2016-

17

FY 2017-

18

1 Power Purchase Cost 3675.72 3957.59 4248.84

2 Inter-State Transmission Charges 232.05 243.66 255.84

3 Intra-State Transmission Charges 165.38 173.64 182.33

4 O&M Expenses 430.07 903.81 979.07

a Employee Expenses 275.13 736.14 798.19

b A&G Expenses 66.30 71.88 77.93

c R & M Expenses 88.64 95.80 102.95

5 Depreciation 99.10 106.79 114.48

6 AAD 94.41 121.86 130.53

7 Return on Capital Employed 215.27 221.11 223.36

8 Income tax 16.62 16.99 17.08

9 Total ARR 4928.63 5745.45 6151.53

10 Less: Other Income/NTI 78.95 78.95 78.95

11 Aggregate Revenue Requirement 4849.68 5666.50 6072.58

Table 68: ARR for Wheeling Business (Rs. Cr.)

SL

NO PARTICULARS

FY 2015-

16

FY 2016-

17

FY 2017-

18

1 O&M Expenses 268.38 538.86 583.44


b A&G Expenses 30.14 32.68 35.43

c R & M Expenses 82.30 88.94 95.58

2 Depreciation 75.60 81.47 87.33

3 AAD 80.37 103.74 111.12


5 Income tax 12.24 12.48 12.52

6 Total ARR 595.12 898.95 958.10



[ 62 ]

Table 69: ARR for Retail Supply Business (Rs. Cr.)

SL

NO PARTICULARS

FY 2015-

16

FY 2016-

17

FY 2017-

18

1 Power Purchase Cost 3675.72 3957.59 4248.84

2 Inter-State Transmission Charges 232.05 243.66 255.84

3 Intra-State Transmission Charges 165.38 173.64 182.33

4 O&M Expenses 161.69 364.95 395.63


b A&G Expenses 36.16 39.20 42.50

c R & M Expenses 6.35 6.86 7.37

5 Depreciation 23.50 25.32 27.14

6 AAD 14.04 18.12 19.41


8 Income tax 4.38 4.51 4.56

9 Total ARR 4333.51 4846.50 5193.43



4.1.19 Revenue Gap & Average Billing Rate at existing tariff, and proposed tariff

hike

Table 70: Revenue Gap & ABR at existing tariff (Rs. Cr.)

SL

NO PARTICULARS

FY 2015-

16

FY 2016-

17

FY 2017-

18

1 Revenue Gap at existing tariff (Rs. Cr.) (213.41) (775.52) (944.93)

2 Units Realized (MU) 6125.86 6451.24 6774.32

3 Amount Realized at existing tariff (Rs Cr) 4636.27 4890.98 5127.65

4 Average Billing Rate at existing tariff (Rs/unit) 7.57 7.58 7.57

5 Average Cost of Supply (Rs/unit) 7.92 8.78 8.96

6 Ratio of ABR to ACS 95.60% 86.31% 84.44%

7 Proposed % avg tariff hike 4.40% 13.69% 15.56%

[ 63 ]


of BYPL

Year : FY 2012-13

Defined % for costlier plants : 60%

Reference Variable Charge : Rs 3.70 / unit

Case – I: All power requirement to be met from long term sources only. Surplus power will

be sold to the open market.

Table 71: Merit Order Dispatch – Case - I

FY 2012-13 With Merit Order Without Merit Order

Total cost of Power Purchase 3021.46 Rs. Cr 3143.6 Rs. Cr

Reduction in Cost 122.14 Rs. Cr

Long Term Power Purchase 8387.32 MU 8765.49 MU

Short Term Power Purchase 0.00 MU 556.00 MU

Short Term Power Sale 1605.72 MU 2539.89 MU

Energy Input to Discom 6341.38 MU 6341.38 MU

Case – II: All power requirement to be met from long term sources only. No power may be

drawn from costly sources, if demand is met from cheaper sources. Surplus power will be

sold to the open market.

Table 72: Merit Order Dispatch – Case - II








[ 64 ]

Case – III: Specified minimum power will be purchased from BTPS, Rajghat & Gas

Turbine. Balance requirement to be met through short term purchase. Surplus power will be

sold to the open market.

Table 73: Merit Order Dispatch – Case - III








Case – IV: Re-allocation of power purchase for selected central & state generating stations

whose variable costs are higher.

Table 74: Merit Order Dispatch – Case - IV








[ 65 ]

Case – V: Reallocation of BYPL share in Delhi power from 27.24% to 23.97%.

Table 75: Merit Order Dispatch – Case - V








Case – VI: Case – IV + Case - V.

Table 76: Merit Order Dispatch – Case - VI








[ 66 ]

5. SUMMARY & CONCLUSION

The ARR projection shows that ARR for 3 years of the 3rd

MYT Control Period are

Rs. 4849.68 Cr, Rs. 5666.50 Cr and Rs. 6072.58 Cr respectively against revenue

collections of Rs. 4636.27 Cr, Rs. 4890.98 Cr and Rs. 5127.65 respectively, resulting

in an increasing gap between the average cost of supply and average billing rate (at

existing tariff) of Rs. 0.35/unit, Rs. 1.20/unit and Rs. 1.39/unit respectively.

This increasing revenue gap (at existing tariff) calls for a tariff hike of 4.40% in FY

2015-16, or a hike of 13.69% in FY 2016-17, or a hike of 15.56% in FY 2017-18 to

abolish the revenue gap and achieve a cost-reflective tariff.

Different components of the ARR for the 3 years of 3rd

MYT Control Period are

shown below in form of pie charts:

Figure 2: Components of ARR for FY 2015-16, FY 2016-17 and FY 2017-18

[ 67 ]

It is seen that power purchase cost occupies a major portion (about 70%) of the ARR.

Hence reducing the power purchase cost can reduce the overall expenses of a

distribution licensee to a great extent.

Implementation of the Merit Order Dispatch model can help in reducing power

purchase cost by a minimum amount of about Rs. 100 Cr, as has been examined in

this study for FY 2012-13.

In addition, if share of BYPL is reduced from the present 27.24% to 23.97% along

with re-allocation of power purchase from selected costlier power stations, it would

result in a saving of about Rs. 390 Cr, as has been examined in this study for FY

2012-13.

[ 68 ]

6. LIMITATIONS OF STUDY

Projecting the future energy demand is the primary important task for ARR

calculation. However this process involves several variables, predictions of which

themselves may prove wrong with high probability.

Number of consumers and connected load are not under the control of distribution

licensee, and hence their future trajectories cannot be predicted accurately, and this

may result in erroneous results in the energy demand figures.

Quantum of power purchase from future stations had historically fallen well below the

targets specified in the tariff orders, resulting in power purchase from costly short

term sources. This was majorly due to delay in commissioning of those power stations

because of various legal and technical reasons. Hence prediction of this parameter

also poses a serious challenge toward ARR calculation.

Inflation, which is a macro-economic phenomenon and is not under control of the

distribution licensee, may lead to increase in O&M Expenses beyond the predicted

figures, resulting in loss to the licensee. The escalation factor taken to account for

inflation may prove wrong in case of inflation higher than predicted.

As of now, due to unavailability of capital expenditure schedule for FY 2015-16

onwards, capital expenditure for each year for the 3rd

Control Period has been taken

as Rs. 230 Cr as approved provisionally by DERC in its MYT tariff order dated

13.07.2012 for 2nd

Control Period.

Increase in interest rate on debt has been taken same as the increase from FY 14 to FY

15, as movement of interest rate cannot be predicted easily and is not under the

control of the licensee. Interest rate on fresh loan has been taken as 10%.

Working capital requirement for wheeling business includes wheeling expenses for 2

months, which is obtained from the ARR for wheeling business. However calculation

for ARR requires RoCE figure, which in turn is calculated from working capital.

Hence it results in a cyclic calculation. To avoid this, voltage wise energy sales (MU)

[ 69 ]

are calculated, and then voltage wise wheeling charges (Rs. Cr.) are calculated on the

basis of per unit voltage wise wheeling charges (Rs. / unit sales) determined by DERC

in its tariff order dated 31.07.2013. Adding all the wheeling charges give the total

wheeling expenses. Working capital is calculated from this figure.

Although Merit Order Dispatch model is a great way to reduce power purchase cost

for the licensee, it is not always under the control of licensee to choose among the

suppliers according to the price of power supplied, particularly under the condition of

shortage of power supply. Rather it is the function of the RLDC-s and the SLDC to

look after the matter and ensure merit order dispatch.

Besides the above fact, although in calculations, merit order dispatch shows huge

monetary savings, real time operations are much more complicated and involve

several unprecedented factors. Hence although apparently there may be scope of

savings, but it is the real time situation which would decide whether there is actually

scope for following merit order dispatch or not.

[ 70 ]

7. FUTURE SCOPE & RECOMMENDATIONS

Inflation is an uncontrollable factor, and its impact shall be made a pass through to the

consumers. Any increase in O&M expense due to inflation should be validated

properly and then be passed on.

True status of progress in erection and commissioning works in future power stations

including their expected synchronization date & COD should be conveyed to discoms,

so that a fair prediction can be made of the energy availability from these sources.

ARR calculation provides an insight on various expenses incurred by the licensee, and

presents an opportunity to find ways to reduce such expenses.

Although there is not much scope for discoms to implement merit order dispatch, and

it is mainly in the hands of the load dispatch centers, but discoms should focus more

and more on this concept of power procurement. Any power station supplying

electricity at high price than the average rate should not be encouraged to sell power,

unless it brings down its cost to a level similar to that of similar power plants.

Discoms should have the right to scrutinize the bills raised by generating companies,

in case the bills are abnormally high. Passing of all the costs of power generation to

discoms sometimes hide the inefficiency of the generators.

[ 71 ]

8. BIBLIOGRAPHY

[1] Central Electricity Authority, (2013), „Monthly Report on broad status of Thermal

Power Projects in the Country‟, Thermal Power Monitoring Division, Central

Electricity Authority, New Delhi

[2] Central Electricity Authority, (2013), „Status of Hydro Electric Projects under

execution‟

[3] Central Electricity Authority, (2013), „Targeted Generation Capacity Addition During

2012-13‟

[4] Central Electricity Regulatory Commission, (2010), „Central Electricity Regulatory

Commission (Indian Electricity Grid Code) Regulations, 2010‟

[5] Delhi Electricity Regulatory Commission, (2011), „Concept Note on MYT

Regulations‟

[6] Delhi Electricity Regulatory Commission, (2012), „Order on True Up for FY 2010-11,

Aggregate Revenue Requirement for FY 2012-13 to FY 2014-15 and Distribution

Tariff (Wheeling & Retail Supply) for FY 2012-13 for BSES Yamuna Power Limited

(BYPL)‟


Aggregate Revenue Requirement and Distribution Tariff (Wheeling & Retail Supply)

for FY 2013-14 for BSES Yamuna Power Limited (BYPL)‟


Aggregate Revenue Requirement and Transmission Tariff for FY 2013-14 for Delhi

Transco Limited (DTL)‟

[9] Delhi Electricity Regulatory Commission, (2011), „Delhi Electricity Regulatory

Commission (Terms & Conditions for Determination of Wheeling Tariff & Retail

Supply Tariff) Regulations, 2011‟

[10] Delhi Transco Limited, (2012), „Final Intra-State ABT based Energy Account for the

month of MAR 2011‟, Delhi Transco Limited, State Load Despatch Centre, Fax No:

F.DTL/207/20010-11/DGM(SO)/

[11] Delhi Transco Limited, (2012), „Provisional Intra-State ABT based Energy Account

for the month of March-2012‟, Delhi Transco Limited, State Load Despatch Centre,

Fax No: F.DTL/207/20011-12/DGM(SO)/EAC/33

[12] Delhi Transco Limited, (2013), „Provisional Intra-State ABT based Energy Account

for the month of March-13‟, Delhi Transco Limited, State Load Despatch Centre, Fax

No: F.DTL/207/20012-13/DGM(SO)/EAC/12

[13] Department of Atomic Energy, Government of India, http://dae.nic.in/

http://dae.nic.in/

[ 72 ]

[14] Eastern Regional Power Committee, (2011), „Provisional Regional Energy

Accounting (REA) of Eastern Region for the month of March 2011‟, Fax No:

ERPC/COM-I/REA/2011/ 53-92



ERPC/COM-I/REA/2012/ 183-223



ERPC/COM-I/REA/2013/ 147-85

[17] Eastern Regional Power Committee, Ministry of Power, http://www.eastrpc.org/

[18] Gujarat Electricity Regulatory Commission, (2011), „Multi-Year Tariff Order for

Dakshin Gujarat Vij Company Limited‟

[19] ICRA Limited, (2013), „Gas Price Hike: Impact Analysis‟

[20] Indian Energy Exchange, http://www.iexindia.com/

[21] Labour Bureau, Govt of India, http://labourbureau.nic.in/

[22] Ministry of Power, Government of India, (2003), „The Electricity Act, 2003‟

[23] Ministry of Power, Government of India, (2006), „National Tariff Policy‟

[24] Northern Regional Load Despatch Centre, (2013), „Annual Report, 2012-13‟

[25] Northern Regional Power Committee, (2011), „Final REA for the month of March,

2011‟, Letter No: NRPC/SE(C)/ABT-REA/2010-11/322-356, Northern Regional

Power Committee, Ministry of Power, Government of India

[26] Northern Regional Power Committee, (2012), „Final REA for the month of March,

2012‟, Letter No: NRPC/SE(C)/ABT-REA/2012-13/221-55, Northern Regional

Power Committee, Ministry of Power, Government of India

[27] Northern Regional Power Committee, (2013), „Amendments in Final REAs for the

months of January, February and March, 2013‟, Letter No:

NRPC/Comml/201/REA/2012-13/, Northern Regional Power Committee, Ministry of

Power, Government of India

[28] Northern Regional Power Committee, (2013), „Revision of Allocation of Unallocated

Power of Central Generating Stations of Northern region‟, Revision #5 / 2013-14, Fax

Message No: NRPC/ OPR/ 103/ 02/ 2012-13, Northern Regional Power Committee,

Ministry of Power, Government of India

[29] Office of the Economic Advisor to the Govt of India, Ministry of Commerce &

Industry, http://eaindustry.nic.in/

[30] Power Exchange India Ltd, http://www.powerexindia.com/pxil/

http://www.eastrpc.org/

http://www.iexindia.com/

http://labourbureau.nic.in/

http://eaindustry.nic.in/

http://www.powerexindia.com/pxil/

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