SUMMER INTERNSHIP-REPORT
On
ANALYSIS OF FINANCIAL VIABILITY OF DISTRIBUTION TARIFF ORDER
Under the guidance of,
Mr. Chandra Prakash
Deputy Chief (Engineering)
Central Electricity Regulatory Commission
Submitted by
Rahul Saini
Roll no- 64
MBA-POWER MANAGEMENT
2012-14
August 2013
CENTRE FOR ADVANCED MANAGEMENT & POWER STUDIES
NATIONAL POWER TRAINING INSTITUTE, FARIDABAD
(Under the Ministry of Power, Government of India)
Affiliated to
1
DECLARATION
I am Rahul Saini ( Roll No. 64), MBA (Power Management), Batch 2012-14 of the National Power
Training Institute, Faridabad, hereby declare that the summer training report entitled “Analysis Of
Financial Viability Of Distribution Tariff order” 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 26th Aug, 2013 and the suggestions as approved
by the faculty were duly incorporated.
Presentation Incharge
Signature of the Candidate
Amit Mishra
Rahul Saini
Asst. Director
CAMPS,NPTI
Countersigned
Director/Principal of the Institute
2
CERTIFICATE
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ACKNOWLEDGEMENT
I am first thank to my Project Convener Mr. Chandra Prakash Deputy Chief (Engineering), CERC
without his help and interest it would have been difficult to finish this work. I would also like to
acknowledge Mr. Tanmay Vyas ,Senior Research Officer, CERC for his valuable support and guidance
throughout this project.
Special thanks go to all the staff members of CENTRAL ELECTRICITY REGULATORY
COMMISSION specially Mr. Amit Paul Ekka ,Research Associate, CERC Without their insights and
helpful thoughts, I would not have gained as much information as we have. Their help has sparked our
interest even more!
Thanks!
I also thank Mr. S.K Chaudhary (Principle Director, NPTI), Ms. Manju Mam (Director, CAMPS), Ms. Indu
Maheswari, (Dy. Director, NPTI), & Dr. Rohit Verma, (Dy. Director, NPTI), and Ms. Farida Khan for
arranging my summer internship program with Central Electricity Regulatory Commission and providing
assistance and support whenever required.
I would like to extend our gratitude to Ms. Sughandha Aggarwal, (Mentor) for their continuous help and
motivation during summer internship.
Last but not the least; I would like to thank my family members without the efforts & moral support of
whom i would never have been able to accomplish all the achievements in our life.
Rahul Saini
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LIST OF ABBREVIATIONS
AERC
Assam Electricity Regulatory Commission
A&G
Administrative and General Expenses
ASEB
Assam State Electricity Board
ARR
Aggregate Revenue Requirement
BERC
Bihar Electricity Regulatory Commission
BPL
Below Poverty Line
BSEB
Bihar State Electricity Board
BST
Bulk Supply Tariff
CA
Commission Approval
CERC
Central Electricity Regulatory Commission
CAGR
Compound Annual Growth Rate
CAPEX
Capital Expenditure
CEA
Central Electricity Authority
CGS
Central Generating Station
COD
Commercial Date of Operation
CoS
Cost of Supply
CoS
Cost of Service
CPI
Consumer Price Index
CWIP
Capital Work in Progress
DERC
Delhi Electricity Regulatory Commission
DISCOMS
Distribution Companies
DS
Domestic Supply
5
EA
Electricity Act
ED
Electricity Duty
FSA
Fuel Surcharge Adjustment
FY
Financial Year
GFA
Gross Fixed Asset
GoP
Government of Punjab
HERC
Haryana Electricity Regulatory Commission
HT
High Tension
IPP
Independent power Plant
MoP
Ministry of Power
MPERC
Madhya Pradesh Electricity Regulatory Commission
MU
Million Units
MW
Megawatt
MYT
Multi year Tariff
NEP
National Electricity Policy
NTI
Non Tariff Income
NTP
National Tariff Policy
O&M
Operating and Maintenance
PGCIL
PLEC
Power Grid Corporation of India Limited
Plant load Exemption Charges
PLF
Plant Load Factor
PPA
Power purchase Agreement
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PPC
Power Purchase Cost
PS
Petition Submission
PSEB
Punjab State Electricity Board
PSERC
Punjab State Electricity Regulatory Commission
PSL
R&M
Public Street Lighting
Repair and Maintenance charges
ROCE
Return on Capital Employed
ROE
Return on Equity
ROR
Rate of Return
RST
Retail Supply Tariff
SBI
State Bank of India
SEB
State Electricity Board
SERC
State Electricity Regulatory Commission
SLDC
State load dispatch Center
TANGEDCO
Tamil Nadu Generation and Distribution Corporation
TNEB
Tamil Nadu Electricity Board
TNERC
Tamil Nadu Electricity Regulatory Commission
TOD
Time of Day
WPI
Whole Price Index
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TABLE OF CONTENTS
Declaration…………………………………………………………………………………..
Certificate..............................................................................................................................
Acknowledgement……………………………………………………………………………..
List of Abbreviations………………………………………………………………………..
Executive Summary………………………………………………………………………….
About the Organisation……………………………………………………………………..
Objective of the project……………………………………………………………………
Significance of the project…………………………………………………………………….
Research Methodology……………………………………………………………………….
Guiding Policies for Determining Tariff………………………………………………….
Introduction to ARR methodology and Tariff Order……………………………………
MADHYA PRADESH……………………………………………………………………….
Approaches adopted by Commission to determine ARR Components……………………….
Petitioner Submission vs Commission Approval…………………………………………….
Reason for Difference…………………………………………………………………………..
Highlights of the order………………………………………………………………………….
HARYANA………………………………………………………………………………….
Approaches adopted by Commission to determine ARR Components………………………..
Petitioner Submission vs Commission Approval……………………………………………
Reason for Difference………………………………………………………………………..
Highlights of the order………………………………………………………………………
PUNJAB…………………………………………………………………………………….
Approaches adopted by Commission to determine ARR Components………………………...
Petitioner Submission vs Commission Approval……………………………………………..
Reason for Difference…………………………………………………………………………
Highlights of the order……………………………………………………………………….
BIHAR…………………………………………………………………………………………
Page no
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Approaches adopted by Commission to determine ARR Components……………………….
Petitioner Submission vs Commission Approval…………………………………………….
Reason for Difference…………………………………………………………………………
Highlights of the
order…………………………………………………………………………………………..
ASSAM………………………………………………………………………………………..
Approaches adopted by Commission to determine ARR Components………………………
Petitioner Submission vs Commission Approval…………………………………………….
Reason for Difference………………………………………………………………………..
Highlights of the order……………………………………………………………………….
DELHI………………………………………………………………………………….……
Approaches adopted by Commission to determine ARR Components………………………
Petitioner Submission vs Commission Approval……………………………………………..
Reason for Difference…………………………………………………………………………
Highlights of the order………………………………………………………………………..
CONCLUSION……………………………………………………………………………….
RECOMMENDATIONS…………………………………………………………………….
REFRENCES………………………………………………………………………………….
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LIST OF TABLES
Table no 1 Consumer Category wise sales approved by MPERC………………………………
32
Table no 2 Methodology for computation of ROE (FY14)…………………………………..
37
Table no 3 Diff in amount of ARR Components by Petitioner & approved by
Commission………………………………………………………………………………….
38
Table no 4 Consumer Category wise sales approved by HERC……………………………
43
Table no 5 Diff in amount of ARR Components by Petitioner & approved by
Commission………………………………………………………………………………….
48
Table no 6 Consumer Category wise sales approved by PSERC……………………………
51
Table no 7 Diff in amount of ARR Components by Petitioner & approved by Commission….
56
Table no 8 Consumer Category wise sales approved by BERC………………........................
59
Table no 9 Diff in amount of ARR Components by Petitioner & approved by
Commission….……………………………………………………………………………
64
Table no 10 Consumer Category wise sales approved by AERC………………………….....
68
Table no 11 Diff in amount of ARR Components by Petitioner & approved by Commision…
71
Table no 12 Consumer Category wise sales approved by DERC……………………………
74
Table no 13 Consumer Category wise sales(NDMC) approved by DERC…………………
75
Table no 14 Consumer Category wise sales(NDMC FY13) approved by DERC…………..
75
Table no 15 Diff in amount of ARR Components by Petitioner & approved by
Commision…………………………………………………………………………...……
80
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List of Figures
Fig 1 Trend of PPC over three years…………………………………………………………
34
Fig 2 Trend of O&M Cost over three years………………………………………………
35
Fig 3 Trend of Depreciation over three years………………………………............................
36
Fig 4 Trend of PPC over three years…………………………………………………………
45
Fig 5 Trend of O&M Cost over three years………………………………………………
46
Fig 6 Trend of Depreciation over three years……………………………………………….
47
Fig 7 Trend of PPC over three years………………………………………………………
52
Fig 8 Trend of O&M Cost over three years…………………………………………………
53
Fig 9 Trend of Depreciation over three years………………………………………………
54
Fig 10 Trend of PPC over three years…………………………………………………….
61
Fig 11 Trend of O&M Cost over three years……………………………………………….
62
Fig 12 Trend of Depreciation over three years……………………………………………
63
Fig 13 Trend of PPC over three years………………………………………………………
77
Fig 14 Trend of O&M Cost over three years………………………….…………………......
78
Fig 15 Trend of Depreciation over three years……………………………………………
79
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EXECUTIVE SUMMARY
The electricity sector in India has been operating under a monolithic structure. With the growing
requirements for improvement in the sector, various models to bring in improvements and investments into
the sector have been contemplated. Unbundling of the state electricity boards into functional companies is
already a reality. but even after these reforms , huge debt and financial losses are burden on DISCOM’s and
the whole power sector. In order to bring in accelerated improvements, further restructuring of the
distribution segment is being contemplated.
As a student of National Power Training Institute (NPTI), Faridabad and doing my MBA in Power
Management, we got this opportunity of working as a summer trainee with Central Electricity Regulatory
Commission (CERC) for a period of two months from June 10, 2013 to August 10, 2013.
As a part of summer training we got an opportunity to work on the issues related to ARR filing by the
distribution utilities and the approval of it by the SERCs after some normative modifications if required.
One major concern regarding the poor financial condition of DISCOM’s is that cost of ARR components
approved by regulatory commissions is so often less than petitioner’s demand and in few states tariff has
not been revised for years .as a result petitioner is not able to recover its cost of supply resulting in huge debt
and creation of regulatory assets which has become a regular practice today. Thus this project is carried out
to understand the different approaches adopted by the State Electricity Regulatory Commissions (SERCs) of
10 States while analyzing & approving the ARR Components like Power Purchase Cost, Operating and
Maintaining Cost (O&M Cost) ,Depreciation, Interest on Working Capital, Interest and Finance charges,
Return on equity, Non Tariff Income and annual tariff determination approach for fixing the Retail tariff for
DISCOMs under their jurisdiction.
For the treatment of revenue gap/surplus in each of the tariff order, ERC’s approach has varied as per the
requirement. In case when revenue gap is large, the Commission had used a mix of options to bridge the
revenue gap through increase in tariff of certain categories and creation of regulatory assets. In case when
gap is meager, Commission had hiked the tariff of all categories to meet the revenue gap and the surplus
come are utilized for the purpose of amortization of regulatory asset. The Average cost of Supply (in
Rs/unit) of ten States in each FY has also calculated in the Excel sheet.
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The enactment of Electricity Act 2003 has provided the legal framework to bring the reforms in electricity
sector. The Act has also empowered & given the responsibilities to the SERCs to deal with the operational
matters related to Distribution of electricity. The Section 61 (Tariff Regulations) & Section 62
(Determination of Tariff) of Electricity Act 2003, notifies the function ial viability ofof SERCs to determine
the tariff for Generation, Transmission, supply & wheeling charges for electricity, wholesale, bulk or retail
tariff as in the case may be, within their area of jurisdiction. SERCs have issued Tariff Orders for the
DISCOMs after analyzing & approving the Aggregate Revenue Requirement (ARR) of the DISCOMs. This
Project is an attempt to study the approaches adopted by SERCs & their effect on DISCOMs performance.
This Project has analyzed the Distribution ARR & Tariff Orders issued by the Six SERCs of
States namely Madhya Pradesh, Haryana, Bihar, Punjab, Delhi, Assam, during the three years i.e. from FY
2011-12 to FY 2013-14.The objectives of the project are as follows:
 Thorough study of the tariff orders to understand their design & structure
 Understanding of the approaches adopted by the SERCs on Annual Revenue
Requirement Components
 Comparing the Petitioner Submission and Commission Approval
 Find out the Reasons for Differences
 Highlights of the Tariff order
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ABOUT THE ORGANISATION
Central Electricity Regulatory Commission (CERC), a key regulator of power sector in India, is a statutory
body functioning with quasi-judicial status under sec - 76 of the Electricity Act 2003. CERC was initially
constituted on 24 July 1998 under the Ministry of Power’s Electricity Regulatory Commissions Act, 1998
for rationalization of electricity tariffs, transparent policies regarding subsidies, promotion of efficient and
environmentally benign policies, and for matters connected Electricity Tariff regulation. CERC was
instituted primarily to regulate the tariff of Power Generating companies owned or controlled by the
government of India, and any other generating company which has a composite scheme for power
generation and interstate transmission of energy, including tariffs of generating companies.
FORMULATION
The conceptualization of independent Regulatory Commission for the electricity sector dates back to early
1990s, when the National Development Council (NDC) Committee on Power headed by Shri Sharad Pawar,
the then Chief Minister of Maharashtra recommended in 1994, constitution of “independent professional
Tariff Boards at the regional level for regulating the tariff policies of the public and private utilities”. The
Committee reiterated that “the Tariff Boards will be able to bring along with them a high degree of
professionalism in the matter of evolving electricity tariffs appropriate to each region and each State”. The
need for constitution of the Regulatory Commission was further reiterated in the Chief Minister’s
Conference held in 1996. The Common Minimum National Action Plan for Power evolved in the
Conference inter-alia “agreed that reforms and restructuring of the State Electricity Boards are urgent and
must be carried out in definite time frame; and identified creation of Regulatory Commissions as a step in
this direction” Thus was enacted the Electricity Regulatory Commissions Act, 1998 paving way for creation
of the Regulatory Commissions at the Centre and in the States. The 1998 Act was enacted with the objective
of distancing Government from the tariff regulation. The Act provided for Electricity Regulatory
Commissions at the Center and in the States for rationalization of electricity tariff, transparent policies
regarding subsidies etc. Under the provisions of this Act, the Central Government constituted the Central
Electricity Regulatory Commission (CERC) in July, 1998. The ERC Act, 1998 has since been replaced by
the Electricity Act, 2003. The CERC created under the provisions of the ERC Act, 1998 has been recognized
as the Central Electricity Regulatory Commission under the Electricity Act, 2003. The Electricity Act, 2003
has significantly enlarged the spectrum of responsibility of CERC. Under the ERC Act, 1998 only the tariff
fixation powers were vested in CERC. The new law of 2003 has entrusted on the CERC several other
responsibilities in addition to the tariff fixation powers, for instance, the powers to grant license for inter-
14
State transmission, inter-State trading and consequently to amend, suspend and revoke the license, the
powers to regulate the licensees by setting performance standards and ensuring their compliance, etc.
MISSION STATEMENT
The Commission intends to promote competition, efficiency and economy in bulk power markets, improve
the quality of supply, promote investments and advise government on the removal of institutional barriers to
bridge the demand supply gap and thus foster the interests of consumers. In pursuit of these objectives the
Commission aims to –
Improve the operations and management of the regional transmission systems through Indian Electricity
Grid Code (IEGC), Availability Based Tariff (ABT), etc.

Formulate an efficient tariff setting mechanism, which ensures speedy and time bound disposal of
tariff petitions, promotes competition, economy and efficiency in the pricing of bulk power and
transmission services and ensures least cost investments.

Facilitate open access in inter-state transmission

Facilitate inter-state trading

Promote development of power market

Improve access to information for all stakeholders.

Facilitate technological and institutional changes required for the development of competitive
markets in bulk power and transmission services.

Advise on the removal of barriers to entry and exit for capital and management, within the limits of
environmental, safety and security concerns and the existing legislative requirements, as the first step
to the creation of competitive markets.
ORGANISATION STRUCTURE
The Central Commission consists of a Chairman and three full time Members and the Chairman of Central
Electricity Authority (CEA) as the Member, Exofficio. The Commission is having a right mix of persons
having adequate knowledge and experience in engineering, law, economics, commerce, finance and
management. The Qualifications of Chairman and Members are also prescribed in Section 77 of the
Electricity Act 2003. The Chairman and Members are appointed by the President of India on the
recommendations of a selection committee constituted by the Central Government as prescribed under the
15
Act. The Section 91 of the Act also provides for the appointment of a Secretary of the Commission whose
powers and duties are defined by the Commission Section 79 of the Electricity Act, 2003.
FUNCTIONS
Mandatory Functions:
To regulate the tariff of generating companies owned or controlled by the Central Government;

To regulate the tariff of generating companies other than those owned or controlled by the Central
Government specified in clause (a), if such generating companies enter into or otherwise have a
composite scheme for generation and sale of electricity in more than one State;

To regulate the inter-State transmission of electricity ;

To determine tariff for inter-State transmission of electricity;

To issue licenses to persons to function as transmission licensee and electricity trader with respect to
their inter-State operations;

Improve access to information for all stakeholders.

To adjudicate upon disputes involving generating companies or transmission licensee in regard to
matters connected with clauses (a) to (d) above and to refer any dispute for arbitration;

To levy fees for the purposes of the Act;

To specify Grid Code having regard to Grid Standards;

To specify and enforce the standards with respect to quality, continuity and reliability of service by
licensees;

To fix the trading margin in the inter-State trading of electricity, if considered, necessary;

To discharge such other functions as may be assigned under the Act.
Advisory Functions:
formulation of National Electricity Policy and Tariff Policy;

promotion of competition, efficiency and economy in the activities of the electricity industry;

promotion of investment in electricity industry;

Any other matter referred to the Central Commission by the Central Government.
16
OBJECTIVE OF PROJECT
This Project has analyzed the Distribution ARR & Tariff Orders issued by State Electricity Regulatory
Commission (SERCs) of the Six States during the three years i.e. from FY 2011-12 to FY 2013-14.In the
early 2000s, the Govt. of India introduced a number of reform measures for the power sector. These
included the passing of the Electricity Act 2003, National Electricity Policy & the National Tariff Policy.
These initiatives aimed to create a competitive marketplace & ensure availability of power at affordable
price. They also aimed to ensure commercial viability of the state utilities & promote transparency,
predictability & consistency as well as competition among the supplier. This project has also carried out
with the aim whether these policies have resulted in achievement of above said objectives as well as tariff
rationalization & a reduction in cross subsidy levels.
Under this study, a comprehensive survey of tariff orders issued by SERCs was undertaken and the findings
were compiled in a uniform format for all the states. In particular, the study had attempted to bring out the
following:

Comparison of approaches followed by SERCs towards different elements of annual revenue
requirement (ARR).

Compliance attained by the regulated utility with the costs approved and the directives issued by
SERCs.

Highlights of the order.
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SIGNIFICANCE OF PROJECT
This project is important in a way to study the role of Regulatory Commission in the post reform period &
aftermaths of the enactment of Electricity Act 2003. The enactment of Electricity Act 2003 has brought
radical changes in electricity sector by empowering the Electricity Regulatory Commissions (CERC &
SERC) to deal with most of the operational functions related to generation, Transmission & distribution of
electricity previously carried out by Govt. The State Electricity Regulatory Commission (SERC) determines
the tariff for Distribution Licensees.
The guidelines framed by the SERCs for Revenue and Tariff filings of licenses which seeks it’s calculations
related to ARR of each licenses for the ensuing financial year regarding (i) its expected aggregate revenue
from proposed sale under its existing approved tariff; (ii) its expected cost of service and (iii) its expected
revenue gap (if any) and a general explanation on how it proposes to deal with the revenue gap. The
Commission then analyses the data filed in ARR with previous year’s trend under the reference of Tariff
regulations issued by SERC with reference to NEP and NTP guidelines as notified under section 3 of
Electricity Act 2003. The energy business is a concurrent business. Being a quasi-judicial autonomous body
the approaches held by SERCs regarding approval of ARR differs. This Project aims to analyze different
approaches held by respective SERCs to approve the required ARR Components like O&M Expenses,
Depreciation, Interest on Working Capital etc.
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RESEARCH METHODOLOGY
The report has been compiled on the basis of secondary data sources. Data on units sold, power purchase,
power procurement cost, distribution losses, transmission losses, connected load, sales mix, O&M cost,
depreciation, capital expenditure, GFA, interests on loans, non tariff incomes, etc. have been collected from
the information available on the internet validated from various recognized websites like Ministry of Power
(India), CERC, CEA & other Electricity Regulatory Commissions. Besides this, data has been collected
from the faculty of the institute and other officials of the mentioned distribution utilities & state electricity
boards and state electricity regulatory commissions.
Steps followed for the project work are as under:
1) Selection of the project title
2) Selecting the states & utilities for the purpose of study and analysis
3) Downloading of all available ARR petitions and Tariff Orders of all the utilities in the states
undertaken for analysis
4) Understanding the design, structure and contents included in ARR petitions and Tariff Orders
5) Thorough study of all ARR petitions and Tariff Orders to understand the viewpoints of licensee
and commission and issues of contradiction between the two
6) Scrutinizing the data & Collecting the relevant data from the available documents and literatures
7) Arranging the data year and utility wise on excel sheet in a lucid manner
8) Comparison of data
9) Calculating the values of various important empirical & derived parameters for all utilities
10) Developing models on excel sheets
11) Plotting the trends for different parameter
12) Drawing of inferences and conclusions
13) Giving suggestions & recommendations
14) Drafting of report
15) Submission of report to the mentor for review, suggestions and modifications
16) Final draft of report incorporating suggested modifications
17) Final submission to the external and internal guides for evaluation
The above mentioned steps were followed for the successful accomplishment of the project work.
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GUIDING POLICIES FOR DETERMINING TARIFF
The Commissions are guided by the Electricity Act 2003 (the Act) and its own Regulations i.e. SERC
(Terms and Conditions for Determination of Tariff) Regulations. The Commission is also guided by the
National Electricity Policy and the National Tariff Policy in the determination of tariffs. The Commission
also proposes to take into account the issues raised in the Draft Report of the Expert Committee on
Integrated Energy Policy published by the Planning Commission, Government of India.
Electricity Act 2003
Main features of Electricity Act 2003 related to distribution and tariff determination are
listed below:
Distribution to be licensed by SERCs

Distribution licensee free to take up generation & Generating co. free to take up distribution license.
This would facilitate private sector participation without Government guarantee/ Escrow. (Sections
7, 12).

Retail tariff to be determined by the Regulatory Commission (Section 62)

Metering made mandatory. (Section 55)

Provision for suspension/revocation of licence by Regulatory Commission as it is an essential
service which can not be allowed to collapse. (Sections 19, 24)

Open access in distribution to be allowed by SERC in phases. (Section 42)

In addition to the wheeling charges provision for surcharge if open access is allowed before
elimination of cross subsidies, to take care of current level of cross subsidy

Licensee’s obligation to supply. (Section 42) 15

This would give choice to customer.

Regulatory Commission to determine tariff for supply of electricity by generating co. on
long/medium term contracts. (Section 62)

No tariff fixation by regulatory commission if tariff is determined through competitive bidding or
where consumers, on being allowed open access enter into agreement with generators/traders.

Consumer tariff should progressively reduce cross subsidies and move towards actual cost of supply.
(Section 61 (g), (h))

State Government may provide subsidy in advance through the budget for specified target groups if
it requires the tariff to be lower than that determined by the Regulatory Commission. (Section 65)
20

Regulatory Commissions may undertake regulation including determination of multi-year tariff
principles, which rewards efficiency and is based on commercial principles. (Section 61 (e), (f))
National Electricity Policy
The Government of India has issued the National Electricity Policy in accordance with Section 3 of the
Electricity Act 2003 which aims at laying guidelines for accelerated development of the power sector,
providing supply of electricity to all areas, and protecting interests of consumers and other stakeholders.
National Electricity policy lays down that the amount of cross subsidy & the additional surcharge to be
levied from consumers who are permitted open access should not be so onerous that it eliminates
competition which is intended to be fostered in generation & supply of power directly to the consumers
through open access.
Open access consumers need to pay generator’s charges, transmission usage charges, and wheeling charges
plus cross subsidy surcharge to compensate the distribution licensee. Sections 42(distribution licensee &
open access) of the Electricity Act, 2003, which permit open access, enjoin upon Commissions to fix the
surcharge which shall be utilized to meet the current level of cross-subsidy. The Commissions under study
have issued open access regulations & the charges based on voltage wise cost to serve & T&D losses.
Cross subsidy surcharge formula used by SERCs is as follows:
S=T-[C (1+L/100) +D]
Where
S is the surcharge
T is the tariff payable by the relevant category of consumers;
C is the weighted average cost power purchase of top 5% at the margin excluding liquid fuel based
generation & renewable power.
D is the wheeling charges.
L is the system losses for the applicable voltage level, expressed as a percentage.
The open access is allowed for HT consumers having contract demand more than1MVA
Open access is aimed to bring competition in retail business.
National Tariff Policy
The Government of India has issued the National Tariff Policy in accordance with Section 3 of the
Electricity Act 2003 which aims at Ensure availability of electricity to consumers at reasonable and
competitive rates, Ensure financial viability of the sector and attract investments, Promote transparency,
21
consistency and predictability in regulatory approaches across jurisdictions and minimise perceptions of
regulatory risks and Promote competition, efficiency in operations and improvement in quality of supply.
Based on the guiding principles of the National Tariff Policy, Commission proposes to adopt certain
measures for tariff determination as stated below:

Commission will institute a system and undertake independent scrutiny of financial, commercial and
technical data submitted by the licensees. The above exercise is envisaged to be completed by
March, 2008 for every distribution circle of the licensee

Commission would develop a policy for treatment of bad debts based on the proposed methodology
of the utility – during the course of the deliberations with the licensee during the process of tariff
determination for the ensuing year.

While allowing the total capital cost of generation projects, the Commission would ensure that these
are reasonable and to achieve this objective. The Commission would evolve requisite benchmarks on
capital costs.
Commission would like to promote projects under Clean Development Mechanism (CDM). Tariff
fixation for all electricity projects (generation, transmission and distribution) that result in lower Green
House Gas (GHG) emissions than the relevant base line would take into account the benefits obtained from
the CDM so as to provide adequate incentive to project developers.
INTEGRATED ENERGY POLICY
The broad vision behind the Integrated Energy Policy is to reliably meet the demand for energy services of
all sectors including the lifeline energy needs of vulnerable households, in all parts of the country, with safe
and convenient energy at the least cost in a technically efficient, economically viable and environmentally
sustainable manner.
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CONCEPTUALIZATION
Introduction to ARR and Tariff orders
An ARR petition is a request to regulatory body made by a utility/licensee for approval of all its annual
expenses to be recovered from consumers through tariff. It also includes a normative profit (ROE) for the
utility. Through an ARR file the licensee shows its various expenses & costs in detail along with the details
of number of consumers, quantum of power purchase & sale, losses, ROE, etc. The respective regulatory
commission of a state studies the ARR petition filed by the Petitioner to check that whether the projections
of costs are in accordance with the terms & conditions of tariff or not and to what extent these are meeting
the norms of Regulations. After going through the ARR file, the commission approves the expenses of a
licensee after some corrections, suggestions and modifications, if felt necessary for Meeting the regulatory
norms. This document of approved ARR petition is sent back to the licensee as an order from the
Commission and it is commonly known as the tariff order. The honorary commission may issue tariff order
every year based on the ARR petition filed by the licensee or on suo moto basis.
The Commission of all states in exercise of the powers vested in it under section 62(1)(d) read with Section
62(3) and Section 64 (3)(a) of the Electricity Act, 2003 and Electricity Regulatory Commission’s (Terms
and Conditions for Determination of Tariff) Regulations and other enabling provisions in this behalf, issues
the tariff order, determining the Aggregate Revenue Requirement (ARR) and the Distribution Tariff of
Financial Year for supply of electricity. The Tariff Regulations specify that the Distribution Licensee shall
file Aggregate Revenue Requirement (ARR) and the Tariff Petition complete in all respect along with
requisite fee as prescribed in the Commission’s Fees, Fines and charges, Regulation on or before 15th
November of the preceding year.It means if Licensee want to file for FY 2011-12 then he should have filed
the ARR and Tariff Petition on or before 15th November, 2010.
The ARR report shall contain the following information:

The licensee‘s demand forecast by consumer class for the succeeding twelve month period ensuing
financial year and the derivation of the forecast;

A calculation of expected aggregate revenue that would result from the above demand during the
same period under the currently approved tariff by consumer class;

A calculation of the licensee‘s estimated costs of providing the service required by the level of
demand for each consumer class during the same period calculated in accordance with the financial
23
principles and their applications in the Sixth Schedule to the Electricity (Supply) Act, 1948 or such
other principles the Commission may prescribe from time to time;
The licensee shall furnish to the Commission when required such information, particulars, and documents as
the Commission may require from time to time for the purpose of validating the report submitted
Once the licensee has provided all the requisite information, particulars, and comments required by the
Commission, the Commission shall notify the licensee of its decision within the time set forth in the Act.
If the Commission determines that a licensee‘s expected revenues differ significantly from the revenue it is
permitted to recover under its licence, it may order the licensee to file an application again within the
specified time to amend its tariffs appropriately.
Within 7 days after the Commission has notified the licensee that it has received all necessary information,
the licensee shall arrange for publication of a notice of its tariff application and send copies to the
Commission Advisory Committee and relevant local authorities in accordance with the Conduct of Business
Regulations. The notice shall include a general description of the tariff amendment being applied for and its
effect on the typical residential consumer‘s bill, and an invitation to submit written comments and objections
to the tariff application to the Commission within 30 days. The licensee shall also post the notification in
each of its offices. After receiving all the comments and objections commission should organize the public
hearing process. The time and venue of the hearing will be advertised by the licensees. In the public hearing
licensee will respond to all the objections raised by the stakeholders. And commission will take the note of
all the objections and responses given by licensees depending on whether it‘s satisfied or not. After the
public hearing process, commission should hold a meeting with state advisory committee. After considering
all the conclusions in this meeting commission should come out with the final tariff order.
Structure of tariff orders
In a broad sense a Tariff Order consists of following items in sequence:1. Background & features
i.
Functions of the commission
ii.
Regulations
iii.
Advices
iv.
Procedural background
v.
Salient features of the order
2. Public hearing process
i.
Objections and issues raised by consumers during public hearing
24
ii.
Response of licensee over the issues raised
iii.
Commission’s ruling on the issues
3. True up of year preceding to the preceding year of ensuing year
4. Annual performance review for the preceding year
5. Determination of ARR for the ensuing year
i.
Components of ARR
ii.
Summary
6. Tariff philosophy and design
i.
MYT framework
ii.
TOD tariff
iii.
Subsidy schemes
iv.
Incentives/disincentives
7. Tariff schedule
i.
Category wise fixed/demand charges
ii.
Category wise energy charges
iii.
Scheme for rebates/penalties
8. Other issues related to tariff determination
The above mentioned 8 basic elements of a TO explain the design and structure of any tariff order (TO). As
my project is based on determination of ARR so our basic focus area will be components of ARR.
POWER PURCHASE COST
Cost of power is the most important item of expenditure for the licensees. Every Commission examines the
projected availability of power from different sources in details & the requirement of sales. In the ARR
power purchase are reckoned only from those sources which have long term contracts with the DISCOMs.
The rates of power purchases from individual generators are on the basis of their respective agreements. As
25
regards energy costs for DISCOMs, the methodology adopted is to take the total energy cost, commonly
known as Bulk Supply Tariff (BST), comprising:
1. Energy costs;
2. Transmission costs;
3. SLDC charges.
While approving the cost of power procurement, the Commission determines the quantum of electricity to
be procured, consistent with power procurement plan, from various sources of supply in accordance with the
principle of merit order scheduling and dispatch, based on a ranking of all approved sources of supply in the
order of their respective variable costs, with certain exceptions, as in the case of Non-Conventional Energy
(NCE) projects, Nuclear projects & some hydro projects accorded by various general and specific orders of
the Commission the status of ‘must-run’ projects. In order to arrive at the quantum and cost of power
procurement, the Commissions had adopted the Sales Forecast, the Transmission & Distribution loss
trajectory. The power purchase cost is an uncontrollable expenditure item & is trued up through Fuel
Surcharge Adjustment (FSA) mechanism.
The relevant clause of National Tariff Policy (Clause 5.3 (h) (4) and Clause 8.2.1 (1))
says:
“Uncontrollable costs should be recovered speedily to ensure that future consumers are not burdened with
past costs. Uncontrollable costs would include (but not limited to) fuel costs, costs on account of inflation,
taxes and cess, variations in power purchase unit costs including on account of hydro-thermal mix in case of
adverse natural events.”
And
“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.”
Variations in power purchase costs for the purpose of true-up will rarely occur as the Fuel Surcharge
Adjustment (FSA) formula issued by the Commission attempts to capture both the price variance and the
fuel variance during the course of the year itself. Any further variations would arise mainly on account of
purchases exceeding the limits approved in the Tariff Order. All extra purchases of power do not
automatically qualify for true-up. If the purchases are for categories where the Commission has fixed a
ceiling or quota as in the case of agriculture in Andhra Pradesh whose consumption is controllable by proper
monitoring and vigilance, extra purchases will not qualify for true-up.
26
OPERATION & MAINTAINANCE EXPENSES:
The O&M expenses have three components.
1. Employee expenses
2. A&G expenses
3. R& M expenses
The employee expenses includes following components.

Salaries

Overtime

Dearness allowance

Other allowance

Bonus

Medical expenses

Earned leave encashment

Payment under workmen compensation Act

Payment to helpers/Employees of storm & monsoon gang

Staff Welfare expenses

Terminal Benefits

Increase in employee cost on account of pay revision
The A&G expenses includes following components.

Rent rates & taxes

Security arrangement

Telephone, Electricity, Water & Postage charges

Legal, audit, consultancy & other professional charges

Travelling, Conveyance & vehicle charges

Vehicle license & registration charges

Books, periodical, computer stationary & printing stationary

Staff expenses

Freight
The A&G expenses also include licensee & Expected Revenue Charges (ERC) filing fees & other
purchase related expenses.
27
The R&M expenses include expenses on maintenance of T&D network. It includes

Repairs and maintenance of plant machinery

vehicles, furniture and fixtures, office equipment, line materials and cables,

Transformers and related equipment, meters and metering equipment etc.
R & M also stands for Renovation & Modernization expenses which is beyond my scope of analysis.
DEPRECIATION
Depreciation is directly related to the capital assets. The Original Cost of Fixed Assets (OCFA) and
capitalization of capital works form the basis of the Fixed Assets. For Electricity industry, the depreciation
rates are the rates, notified by the Ministry of Power, Government of India(rates specified in 1992 & 1994),
rates specified by the CERC which are generally accepted by the SERCs & are issued in their tariff
regulations. Depreciation is applied on the opening balances of the Fixed Assets for the ensuing year at
specific rates applicable to particular assets subject to a limit of 90% of the Fixed Asset value (the balance
being treated as scrap value). In this regard, the crucial factor that varies the computations is the additions to
the Fixed Assets which are entirely dependent on the capitalization of the Capital Works-in-progress during
the year.
From an accounting perspective, Depreciation is a charge to the Profit and Loss account and represents a
measure of the wearing out, consumption or other loss in value of an asset arising from use, efflux of time or
obsolescence through technology and market changes4. From a regulatory perspective, depreciation is a
small amount of the original cost of the capital assets, built into the tariff computation every year with a
view to providing the utility a source of funding to repay installments of debt capital. From the investor’s
point of view, depreciation is a non cash expense which reduces tax burden but generates internal cash for
investments. The regulators have two view points on depreciation. One view is depreciation is the refund of
capital & the other view is a constant charge against an asset to create a fund for its replacement. As the
asset is used over its operational life, Depreciation is proportionately charged over the useful life of the
asset. Advance against depreciation (AAD)5 is required in certain conditions like if the debt redemption
obligation is not matching with the existing depreciation allowed. It is necessary that all the SERCs should
follow same depreciation rate to bring uniform approach in tariff orders.
INTEREST ON WORKING CAPITAL
Working capital is required to maintain cash flow liquid. Usually the SERCs have taken working capital as a
% of O&M expenses, average cost of store & average cash & bank balance etc. The interest rate for working
capital is the short term Prime Lending Rate of State Bank of India.
28
Working capital shall be computed as provided in these Regulations and Rate of interest on working
capital shall be equal to the State Bank of India Advance Rate as on April 1 of the relevant Year. The
interest on working capital shall be payable on normative basis notwithstanding that the Licensee has not
taken working capital loan from any outside agency or has borrowed in excess of the working capital loan
computed on normative basis.
INTEREST AND FINANCE CHARGES
Approved interest on loans is directly related to the loans taken into the Capital Base computations. The
loans drawn for CAPEX and interest thereon are a pass-through in the tariffs. The interest rates are
computed on the basis of the rates on loans filed by the Licensees for the current year and the ensuing year.
Lease rentals and other finance charges are also included under this heading. Other finance charges include
discounts to consumers, such as, incentive, etc. The weighted average rate of interest & normative
repayments so worked out is taken to the ARR. The SERCs analyses the source wise break up of loan &
interest thereon. All the Commissions had considered actual loan portfolio & interest to be paid for such
project. Capital projects are being funded from loan, consumer contribution, depreciation (internal accruals)
& Govt. grant & loans etc.
It is necessary to consider the difference between the capitalization schedule and the
new borrowings considered for interest expenditure and rules that the SERCs shall not consider borrowings
due to revenue / cash deficit, unapproved investments and capital work in progress for determination of
interest expenditure. Further, the SERCs shall only consider loans borrowed for use and useful assets (assets
capitalized) and any other loans borrowed / swapped for reducing the interest cost on such loans. The
interest amount is subject to claw-back as the interest being allowed is for the capital works, and any
variations in the capital expenditure program (under spending or overspending) have to be adjusted if
Capital Work In Progress (CWIP) remains in the Capital Base computations as per the Sixth Schedule to the
Electricity (Supply) Act, 1948.
In Indian context, loans are available for 10-15 years. In some rare cases long term loan is extended for a
longer period of over 20 years. If loan is available for 15 years annual repayment would be around 4.67% of
the total investments taking into consideration 70% of debt of the total investment. Approved interest on
loans is directly related to the loans taken into the Capital Base computations. The loans drawn for CAPEX
and interest thereon are a pass-through in the tariffs. The interest on loans drawn for other than the regulated
29
business or for meeting the working capital requirements over and above what has been allowed in the
capital base, shall not be allowed in the tariffs. However, the loans drawn for meeting Debt Redemption
Obligation for which approval has been granted by the Commission shall be allowed to figure in the Capital
Base and the interest thereon shall be allowed in the tariffs. The interest amount is subject to claw-back as
the interest being allowed is for the capital works, and any variations in the capital expenditure programmed
(under spending or overspending) have to be adjusted if CWIP remains in the Capital Base computations as
per the Sixth Schedule to the Electricity (Supply) Act, 1948.
RATE OF RETURN (ROE or ROCE)
The ROCE is allowed on the Net Capital base (Asset base or regulated rate base) for the ensuing year. The
Capital Base of the Licensees is divided into two parts - the positive part and the negative part, to derive the
net capital base on which a return is provided. The positive part consists of the original cost of fixed assets
(OCFA) excluding consumer contributions; intangible assets; the original cost of Capital Works-in-Progress
(CWIP); compulsory investments, and working capital. On the negative side are depicted, the matching
financials of the assets created, like Accumulated depreciation, loans from Government and other approved
institutions, consumer deposits by way of security and amounts outstanding in the Tariffs and Dividends
Control Reserve and Development Reserve at the close of the year. The ROE is allowed on the average of
opening& closing equity & free reserves for the ensuing year. The total capital is normatively divided in the
ratio of 70:30 & the equity component is calculated to derive Return on Equity to be allowed.
One of the Key issues related to approach for rate of return-the issue posed was which approach should be
adopted return on capital employed (ROCE) approach or the existing return on equity (ROE) approach.
There are different approaches towards rate of return.
The CERC in its T&C of tariff regulations 2009-14 has preferred ROE approach. Some States like Delhi
used ROCE Approach but mostly states like Haryana,Punjab ,MP used ROE Approach.
In case of both the ROCE & ROE approach the ROE is estimated one. The Cost of Debt
(CoD) in case of ROCE approach is estimated whereas in case of ROE approach CoD is actual .so is the
case of Debt –equity mix. The ROCE approach is consistent with the performance based regulations. The
ROCE approach has strong base in economics too.However the ROCE approach sounds theoretical perfect.
In Indian context the cost of debt for PSU is lower compared to cost of debt raised by Private companies
from capital market. So, Normative COD will not work for all companies.
30
CAPITAL STRUCTURE
Capital Structure includes Debt component & equity component. The utility is allowed to get reasonable
return on the capital investment done. The normative Debt equity ratio is 70:30.
NON TARIFF INCOME
Non tariff income shall be the revenue in excess of the revenue collected on account of tariffs as approved
by the Commission, and shall include such items as Delayed Payment Surcharge (DPS) and Meter rent.
So, NTI (Non Tariff Income) consists of: DPS shall be estimated taking into account the uncollected amount and the prevailing bank rate
 The meter rent shall be based on the amount being charged on this account and the number of
metered consumers
 Supervision charges
31
MADHYA PRADESH
INTRODUCTION
The Madhya Pradesh Electricity Regulatory Commission (MPERC) was Constituted by Govt of
Madhya Pradesh under 20th August 1998 under Electricity Regulatory Commission Act, 1998.The
Electricity Act 2003 enacted by the parliament came into the force wef 10th June 2003 and the Commission
is now deemed to have been constituted and functioning under the Provisions of Electricity Act 2003.
The Government of Madhya Pradesh (GoMP) on 31st May, 2005 restructured the functions and undertakings
of Generation, Transmission, Distribution and Retail supply of electricity earlier being carried out by
Madhya Pradesh State Electricity Board (MPSEB) and transferred the same to five following companies:
a) M.P Power Generating Company Ltd , Jabalpur (MPPGCL)
b) M.P Power Transmission Company Ltd , Jabalpur (MPPTCL)
c) M.P Poorv Kshetra Vidyut Vitran Company Ltd , Jabalpur (MPPKVVCL)
d) M.P Madhya Kshetra Vidyut Vitran Company Ltd, Bhopal (MPMKVVCL)
e) M.P Paschim Kshetra Vidyut Vitran Company Ltd , Indore (MPPKVVCL)
With effect from 1st June 2005 the Operation and Management Agreement that existed between MPSEB
and the five companies came to an end and three Distribution Companies started functioning independently
as distribution licensees in their respective area of license.
Appropriate estimation of category wise energy sales is essential to arrive at the quantum of power to be
purchased and the likely revenue by sale of energy which shows its importance. The consumer’s categorywise energy sales Approved by Commission shown below:
FY
2011-12
Consumer Categories
MU’s
2012-13
MU’s
2013-14
% of total
%of total
%of total
2011-12
2012-13
2013-14
MU’s
LT
LV-1: Domestic Consumers
7790
7899.2 15413.26
28.10
24.70
35.85
LV-2: Non Domestic
1622
2057.2 2283.91
5.85
6.43
5.31
LV-3: PWW and Street Light
641
877.4 1118.19
2.31
2.74
2.60
LV-4: Industrial
867
1067.6 1243.35
3.12
3.33
2.89
LV-5.1: Irrigation Pumps
7526
9834.1 11889.31
27.14
30.75
27.65
LV-5.2 Agriculture related use
32
.11
0.03
0.02
11.6 12.33
32
LT Units (MU)
18479
21747 31960.35
66.65
68
74.34
HV-1: Railway Traction
1685
1731.9 1896.32
6.07
5.41
4.41
HV-2: Coal Mines
548
531.1 529.25
1.97
1.66
1.23
HV-3.1: Industrial
5076
6599.6 6483.27
18.31
20.63
15.08
HV-3.2: Non Industrial
831
HV-4:Seasonal
14
16.8 19.69
.05
0.05
0.04
HV-5: Irrigation, PWW & Others
355
596.3 520.73
1.28
1.86
1.21
HV-6: Bulk Residential Users
527
584.9 588.63
1.90
1.82
1.36
HV-7: Bulk Supply to Exempted
206
0
0.53
0
HT Units(MU)
9243
10231 11027.31
33.34
31.99
25.65
Total LT + HT Units (MU)
27722
31978 42987.66
100
100
100
HT
988.72
.74
170.5
2.99
2.30
Table 1 Consumer Category wise Energy sales Approved by MPERC
The above table clearly shows the sales are increasing year by year. The % of total Sales shows the
consumer wise sales however here the portion of agriculture sales is small as compare to other states.
The Approaches followed by the Commission to determine the key components of ARR are explained in
detailed manner as below:
POWER PURCHASE COST
The power purchase cost has two elements i.e. fixed cost and the variable cost. For Central
Generating Stations and State generating stations the Commission has considered latest available tariff order
issued by CERC for individual station for determination of fixed cost. The rate provided in these orders for
purchase of power from Captive Power Plants is the maximum ceiling rate for firm power during normal
time. Purchase of power from Captive Power Plants should be done as per procedure prescribed in MPERC
(Power purchase and other matters with respect to conventional fuel based Captive Power Plants)
Regulations (Revision – 1) 2009 dated 31st January, 2009.
For MP Genco stations (FY 13 & 14) the Fixed Cost has been taken from MYT Tariff order of FY
2011-12. These fixed costs have been adjusted based on availability considered from the Generating Stations
in the order and as per Recovery of Annual Capacity (fixed) charges provided in the Madhya Pradesh
Electricity Regulatory Commission (Terms and Conditions for Determination of Generation Tariff)
(Revision –I) Regulations, 2009.
The Variable Energy Charges as computed on the basis of the availability considered for
purchase after applying the principle of merit order dispatch at Ex-Bus.
33
Interstate transmission charges- The Commission has projected inter-state transmission charges as per the
actual bills of FY 2010-11 for the tariff period FY 12 & 13.For FY 14 the Commission has reviewed interstate transmission charges as per the actual bills available for FY 2012-13 up to Dec, 2012.
Intrastate transmission charges-The Commission had determined the annual transmission charges payable by
each Discom to MPPTCL vide Transmission Tariff Order for FY 2009-10 to FY 2011-12.For FY 14
Commission considered Transmission tariff order of previous year and some allowance for expected
increase for FY 14.
SLDC Charges-Commission determined as per SLDC Tariff order.
PPC
18000
16000
14000
12000
10000
8000
6000
4000
2000
0
17077.8
13091.04
10014.31
PPC
FY12
FY13
FY14
Fig 1 Trend of PPC over three years
O&M COST EXPENSES
The Commission’s Regulations on Terms and Conditions for Determination of Tariff for Supply and
Wheeling of Electricity and methods and Principles for Fixation of Charges) Regulations, 2009 define the
norms of O&M Expenses of each licensee.There are three components of o&m expenses which are
explained as below-:
Employee expenses- have been taken as provided in the Regulations. For first financial year of the control
period, the impact of implementation of 6th Pay Commission recommendations has been considered in
employees cost, which has been escalated @ 6.14% in subsequent years.
R&M expenses-shall be allowed on the opening GFA of the financial year @ 2% for East Discom, 2% for
West Discom and 2.3% for Central Discom for FY 12 &13.In FY 14 allowed % is 2.3% for each discom.
A&G expenses-Commission apply escalation rate of 6.14% on previous A&G expenses as per Tariff
regulations.
34
Total O&M Cost
FY
2011-12
TOTAL O&M COST
2012-13
1708.16
2013-14
1824.08
2391.95
TOTAL O&M COST
3000
2500
2391.95
2000
1500
1824.08
1708.16
TOTAL
O&M COST
1000
500
0
2011-12
2012-13
2013-14
Fig-2 Trend of O&M Cost over three years
DEPRECIATION-As per MPERC (Terms and Conditions for Determination of Tariff for Supply and
Wheeling of Electricity and Methods and Principles for Fixation of Charges) Regulations,2009, depreciation
is to be calculated annually based on straight line method‖ and at the rates specified in Annexure III to these
Regulations for the assets of the Distribution System declared in commercial operation after 31/03/2010,
provided that, the remaining depreciable value as on 31st March of the Year closing after a period of 12
Years from Date of Commercial Operation shall be spread over the balance useful life of the assets.
Commission computed depreciation taking assets base as closing balance of assets existing as on 31st
March 2010 plus the Average of Addition in GFA in last three years of audited balance sheet for FY 11 plus
half of average addition in GFA in last three year for FY12.
For FY13 closing balance of assets of FY12 plus half of average addition in GFA in last three years for
FY13. The GFA has been considered for allowing depreciation for FY 14 on the basis of opening GFA of
FY 2013-14 plus half of the average addition during FY 2012-13 after netting off consumer contribution.
FY
DEPRECIATION
2011-12
185.19
2012-13
183.40
2013-14
240.37
35
DEPRECIATION
300
250
200
240.37
185.19
183.4
150
100
DEPRECIATION
50
0
2011-12
2012-13
2013-14
Fig-3 Trend of Depreciation amount over three years
INTEREST ON WORKING CAPITAL-The MPERC (Terms and Conditions for Determination of Tariff
for Supply and Wheeling of Electricity and methods and Principles for Fixation of Charges) Regulations,
2009 provides that the Working capital shall consist of expenses that are required for supply activity and
wheeling activity.
The method used by Commission in the Tariff order to find working capital of wheeling
activity is addition of 2 month inventory and 1 month of O&M Cost then apply Interest rate on this working
capital. Same is for Retail activity and net interest amount on working capital is the addition of wheeling and
retail activity. The Interest rates of FY 12, 13 &14 are 11.75%, 14% and 13.50% respectively.
INTEREST & FINANCE CHARGES-The MPERC (Terms and Conditions for Determination of Tariff
for Supply and Wheeling of Electricity and methods and Principles for Fixation of Charges) Regulations,
2009 allows interest charges only for those loans to be a pass through in the ARR for which the associated
capital works have been completed and put to use.
The Commission takes the following steps to calculate Interest and Finance charges of FY14a) Debt identified with GFA as on 1st April, 2013
b) 70% of addition to net GFA considered as funded through loan net of consumer contribution.
c) Debt Repayment
d) Total debt associated with GFA as on 31st march, 2013
e) Average of loan balance for FY 2012-13
f) Weighted average rate of interest (%)
g) Interest Charges
h) Other Charges
i) Interest and Finance Charges on Project loans
36
The Commission is aware that the Licensees may have completed some capital works during the course of
previous FY and shall complete some work during present FY, which shall be capitalized and added to the
asset base. The Licensees’ past performance with respect to actual capitalization of assets is far less than the
projections of assets addition that the Licensee has made. The Commission thus finds it appropriate not to
consider the estimated capitalization that is projected for all three FY.But to consider the interest expenses
attributable to such assets only when such assets are actually added to the asset base. This shall also serve as
an incentive for the Licensee to expedite the completion of works and improve its accounting practices to
ensure quick and efficient transfer of assets from CWIP to GFA.
There is a increase of 56% from FY12 to FY 13 and 68% increase from FY13 to FY14 in
Interest and Finance Charges. This is the 1.7% of net ARR Approved in FY14 which is highest among all
3FY’s.
RETURN ON EQUITY-The MPERC (Terms and Conditions for Determination of Tariff for Supply and
Wheeling of Electricity and methods and Principles for Fixation of Charges) Regulations, 2009 provides that
Return on Equity shall be computed on pre tax basis @16%.
The methodology used by Commission to compute ROE is explained belowSuppose we want to find ROE of FY14, the methodology is:
FY 2013-14
DISCOM
30% of addition to net GFA considered
as funded through equity net of consumer
contribution
Total Equity identified with GFA as on
31st March, 2014
ROE @ 16%
Table no-2 Methodology for Computation of Return on Equity( FY14)
The Petitioner claimed Rs 455 Crore and Commission approved Rs 314 Crore in FY12.In FY13 and 14 the
petitioner claimed more ROE as compare to previous FY which is Rs 561 Crore and Rs 682 Crore and
Commission approved Rs 360 Crore and Rs 509 Crore respectively.
37
The key components of Annual Revenue Requirement filed by Petitioner and approved by MPERC are as follows:
Rs Crore
FY
2011-12
CA
ARR
COMPONENT
PS
PPC
O&M COST
DEPRECIATION
INTEREST &
FINANCE
CHARGES
INTEREST ON
WC
ROE
11399
2303.8
412.01
10014.31
1708.16
185.19
385
ARR
NON TARIFF &
OTHER
INCOME
NET ARR*
DIFF
PS
2012-13
CA
1384.7
595.64
226.82
% of net
ARR
Approved
80.4
13.7
1.48
17642.1
2756.2
470.99
13091.1
1824.1
183.24
138.59
246.41
1.1
524.52
59.29
38.84
20.45
.31
455
17537.8
314.21
11851.64
140.79
5686.16
2.5
200
17337.8
300
12444.28
-100
4893.52
DIFF
PS
2013-14
CA
4551.03
932.13
287.75
%of net
ARR
Approved
83.5
11.6
1.16
DIFF
19095
3047.6
559.13
17077.8
2391.95
240.37
2017.2
655.6
318.7
%of net
ARR
Approved
82.9
3.1
1.16
216.99
307.53
1.38
634.05
365.92
268.1
1.7
105.83
0.32
105.51
.002
15.26
0
15.26
0
561.75
26323.3
360.35
14916.8
201.4
11406.5
2.3
682.26
24399.4
509.82
19874.2
172.44
4525.2
2.47
317.17
26323.3
450
15666.6
-132.83
10656
179.72
24219.7
725.35
20599.2
-545.6
3530.4
*Sardar Sarovar order diff. and MP Genco FY 07-08 true up
*FY 2013-14 Impact on a/c of true up/final orders of Transco/Genco stations
Table No-3 Diff in amount of ARR Components filed by Petioner and approved by the Commission
38
REASON FOR DIFFERENCES (filed vs. approval)
FY 2011-12 to 2013-14
1) Power Purchase Cost-Petitioner approach is not given in the tariff order therefore; the reason for
such huge difference can’t be explained. However sales approved is less as proposed by petitioner
which may one of the reasons for difference.
2) Interest on working capital-The petitioners has stated that the working capital requirement has been
estimated based on the norms as per the Regulations. The Commission considered interest rate which
is different from discoms considerations. The Approach used by Commission to compute interest is
discussed earlier.
HIGHLIGHTS OF THE ORDER
FY 2011-12
 New power intensive consumer category under HV tariff.
 Revision in structure of load factor incentive.
 Reduction in minimum consumption charges.
FY 2012-13
 Commission allows billing for rural areas unmetered domestic consumers @ of 42units/connection.
 The trading margin is yet to be determined by the commission hence has not been consider in this
order.
 Change of slabs in domestic category.
FY 2013-14
 Removal of HV-7: Bulk supply to exempted
 Change in Tariff category for hostels run by Tribal welfare dept,GoMP
 Separate Tariff Schedule for Synchronization and start up power for generators connected to the
grid.
 Modification in the load Calculation Formula
39
HARYANA
INTRODUCTION
Uttar Haryana Bijli Vitran Nigam Limited (UHBVNL) and Dakshin Haryana Bijli
Vitran Nigam Limited (DHBVNL) are the two State Government owned distribution companies, registered
under the companies Act, 1956, engaged in the business of distribution and retail supply of electricity in the
state of Haryana. UHBVNL hold the Distribution and Retail Supply License No. DRS-1 of 2004 to cater
distribution and retail supply of electricity in the North Zone of Haryana and DHBVNL hold Distribution
and Retail Supply License No. DRS-2 of 2004 to cater distribution and retail supply of electricity in the
South Zone of Haryana.
These two electricity distribution companies (Discoms) were formed upon corporatisation / restructuring of
erstwhile Haryana State Electrical Board (HSEB) carried out by the State Govt. in its pursuit to revamp the
power sector and implement comprehensive power reforms in the State of Haryana under the aegis of
Haryana Electricity Reforms Act (HERA). The corporatisation / restructuring of erstwhile HSEB was
carried out through two statutory Transfer Schemes notified by the State Govt. under the provisions of
HERA. Through the first Transfer Scheme, titled ‘Haryana Electricity Reform (Transfer of undertakings,
Assets, Liabilities, Proceedings and personnel) Scheme Rules, 1998’, the Generation business (undertakings,
assets, liabilities, proceedings and personnel) was separated from Transmission and Distribution business
and vested in a separate State Govt. owned company, namely Haryana Power Generation Corporation Ltd.
(HPGCL) while Transmission and Distribution business was vested in another State Govt. owned company,
namely Haryana Vidyut Prasaran Nigam Limited (HVPNL).Through the second Transfer Scheme, titled
‘Haryana Electricity Reform (Transfer of Distribution Undertakings from Haryana Vidyut Prasaran Nigam
Limited to Distribution Companies) Rules, 1999’, the Transmission undertakings and business was
separated from Distribution undertakings and business. While the transmission business was retained by
HVPNL, the Distribution business was segregated into two successor Distribution companies namely
UHBVNL and DHBVNL
After restructuring of erstwhile HSEB, the Distribution and Retail Supply
licence was initially granted to HVPNL by the Commission vide its licensing order dated 04.02.1999
permitting it to carry out the distribution and Retail supply business in the entire state of Haryana.
Subsequently, after the implementation of second transfer scheme, the Commission permitted HVPNL to
continue with the Distribution and Retail Supply business through its newly formed subsidiaries namely
UHBVNL & DHBVNL vide its order dated 21.04.1999. Thereafter, on an application filed by HVPNL, the
Commission accepted the surrender of Distribution and Retail Supply (DRS) license vide its order dated 4th
40
November, 2004 and granted the DRS license no. DRS-1 of 2004 to UHBVNL and DRS license No. DRS-2
of 2004 to DHBVNL to conduct Distribution and Retail Supply business in the Northern and Southern
circles of Haryana respectively.
The rights relating to procurement and bulk supply of electricity or trading of electricity were initially vested
with the HVPNL at the time of restructuring of erstwhile HSEB. However, in view of HVPNL having been
declared State Transmission Utility (STU) vide State Govt. notification dated 9.12.2003 and in view of
sections 31 (2), 39 (1) and 41 of Electricity Act, 2003 which prohibit the STU from engaging in the business
of trading in electricity, the Govt. of Haryana vide its notification no. 1/6/2005-1/Power dated 9th June,
2005, transferred the rights relating to procurement and bulk supply of electricity or trading of electricity
from HVPNL to HPGCL. Subsequently, vide notification dated 11th April 2008 (No. 1/1/2008-1 Power),
the Govt. of Haryana transferred the rights relating to procurement of electricity / UI drawls / dispatches or
trading of electricity from HPGCL to UHBVNL and DHBVNL w.e.f 15/04/2008. Further with effect from
1st April 2008, the rights and obligations under agreements and contracts relating to procurement and bulk
supply of electricity or trading of electricity to which HSEB / HVPNL / HPGCL was originally a party, were
transferred and vested to Transferee companies i.e. UHBVNL and DHBVNL in 1:1 ratio. Firm allocations in
each of the Central Sector Generating Stations along with any allocations from the unallocated quota, as
determined by the Government of India for Haryana, was also reallocated to UHBVNL and DHBVNL in
50:50 ratio. The power sold by HVPNL from its shared projects i.e. IP Station (Delhi) and Bhakra Beas
Management Board (BBMB) to the extent of share owned by it was also allocated to UHBVNL and
DHBVNL for a period of five years w.e.f. 1st April 2008 in 1:1 ratio. The notification also provided that the
day to day procurement of power and related issues shall be the responsibility of Haryana Power Purchase
Centre (HPPC).
The Haryana Electricity Regulatory Commission (HERC) was established in August
1998 to regulate power sector in the state of Haryana, under the provisions of Haryana Electricity Reforms
Act 1997(Act 10 of 1998) which was enacted by the Government of Haryana in 1997 and came into force on
14th August, 1998 after presidential assent on 20th February,1998 .
The Electricity Act, 2003 (EA,2003) was enacted by the Govt. of India in June, 2003. However, the
Government of Haryana, in exercise of the powers conferred by clause (d) of section 172 of the Electricity
Act, 2003 , vide its notification no. 1/4/2003 -1 Power dated 8/09/2003 notified that all the provisions of the
Act except section 121, which had not been enforced by the Central Government vide notification no. S.O
699 (E) dated 10/6/2003 ,shall not apply in the State of Haryana for a period of six months from the
appointed date i.e. 10/6/2003. Resultantly, EA, 2003 came into force in the State of Haryana w.e.f.
10/12/2003. However, as the Haryana Electricity Reforms Act, 1997 (HERA, 1997) is a saved Act under sub
41
– section (3) of section 185 of the Electricity Act, 2003 (EA, 2003), the provisions of HERA, 1997 not
inconsistent with EA, 2003 continue to be applicable.
Appropriate estimation of category wise energy sales is essential to arrive at the quantum of power to be
purchased and the likely revenue by sale of energy which shows its importance. The consumer’s categorywise energy sales Approved by Commission shown below:
42
Consumer
Category
2011-12
UHBVNL
Metered Sales
Domestic
Non Domestic
HT Industry
LT Industry
MITC
Lift Irrigation
Railway
Traction
Bulk Supply
Street Light
PWW
Metro DMRC
SUB
TOTAL
AP Sales
Agri Metered
Agri
Unmetered
SUB
TOTAL
TOTAL
2012-13
2013-14
DHBVNL
%of Total Sales
In MU’s
% of Total Sales
% of Total Sales
DHBVNL
UHBVNL
UHBVNL DHBVNL UHBVNL DHBVNL UHBVNL DHBVNL
UHBVNL DHBVNL
2480
855
3003
778
4
34
3470
1216
5713
792
0
173
2995
965
2646
804
8
98
3840
2751
4477
815
0
160
3530
1031
2862
872
6
62
3968
2302
5457
867
2466
177
20.99
7.23
25.41
6.58
0.03
0.28
21.26
7.45
35
4.85
0
1.06
23.77
7.65
21
6.38
0.06
0.77
23.52
16.85
27.43
4.99
0
0.98
25.59
7.47
20.74
6.32
0.04
0.44
19.78
11.48
27.21
4.32
12.19
0.88
148
266
49
349
0
203
1307
37
445
26
120
309
40
486
0
135
344
48
447
210
115
341
44
534
0
140
502
56
383
21
1.25
2.25
0.41
2.95
0
0.12
8
0.22
2.72
0.15
0.95
2.45
0.31
3.85
0
0.82
2.1
0.29
2.73
1.28
0.83
2.47
0.31
3.87
0
0.69
2.5
0.02
1.91
0.1
7965
13382
8471
12927
9397
16339
67.41
82
67.24
79.2
68.12
81.48
1620
1832
1810
2281
2085
2466
13.71
11.22
14.36
13.97
15.11
12.29
2230
1105
2317
1112
2312
1246
18.87
6.77
18.39
6.81
16.76
6.21
3846
11815
2937
16319
4127
12598
3393
16320
4397
13794
3712
20051
32.55
100
17.99
100
32.75
100
20.79
100
31.87
100
18.51
100
Table no-4 Consumer Category wise Energy Sales Approved by HERC
43
The above table clearly indicate that sales mix in Haryana constitute 32.55%(UHBVNL) and
17.99%(DHBVNL) of AP Sales in FY2011-12 which has greater as compared to next FY.The contribution
of DHBVNL has more than UHBVNL in total sales of the State. It is very difficult to determine the Sales of
unmetered AP consumers. The Commission had to rely on the load factor of the metered sales to AP
consumers to assess the consumption of the un – metered AP consumers. However Commission clearly
directed that no new unmetered connection should be released.
The Approaches followed by the Commission to determine the key components of ARR are explained in
detailed manner as below:
POWER PURCHASE COST-.
The Commission had laid down the following approach for determination of power purchase cost in its
orders:
"Where a PPAs / MOUs exist, cost should be determined accordingly".

"In case of CPSUs or other generators, who are supplying power to more than one state, where
payments are governed as per generation tariffs as approved by CERC, the cost should be taken
based on CERC tariffs & the methodology adopted therein".

"Where neither PPA nor CERC Tariff or Notifications are available for any reason, projections can
be made based on the latest available rates as per invoices".

"Estimation should be made for various components separately and a reasonable level of escalation
in costs should be assumed for those elements that are expected to undergo change".
The Commission feels that the most appropriate basis for estimation of power purchase cost would be the
actual annual average cost of power from various generating / trading sources in previous FY and as per the
tariff as applicable as per the approved PPA / generation tariff order in the relevant cases including
renewable sources of power.
There is a increase in the PPC of 23.60% from FY12 TO FY13,an increase of 13.50% from FY13 to
FY14.The PPC constitute 81% of the net ARR approved in FY14 which is highest among all three FY’s.
44
PPC
16000
14000
12000
10000
8000
6000
4000
2000
0
14451.53
12728.92
10298.15
PPC
FY12
FY13
FY14
Fig-4 Trend of PPC over three years
O&M Expenses-comprises of Employees cost, Repair & Maintenance expenses and Administration &
General expenses which are analyzed under this sub-head.
Employee Expenses-Employees' cost includes cost incurred for the employees presently licensees. The cost
of working employees includes salary, dearness allowance and other allowances such as HRA, CCA, LTC,
medical reimbursement etc. While In the case of retired employees and those who would retire during the
year, the Licensee have to discharge financial liabilities towards pension, gratuity, leave encashment benefit
etc and the same has been taken into account while estimating employees cost in all three FY.
There is a continuous decrement of employee cost of 2.45% from 2011-12 to 2012-13 and 1.40% from
2012-13 to 2013-14.
R&M expenses-For maintaining the distribution system in a proper working condition Repair and
maintenance (R&M) cost is incurred by the distribution licensees. The Commission, in order to evolve a
scientific basis for calculating R&M expenditure had directed the distribution licensees to prepare R&M
norms for the equipments used in the distribution and retail supply business. As per report submitted to the
Commission, the normative expenses worked out to 1.65% of GFA. The expense of Rs 158 Crore, Rs
151Crore and Rs 184Crore are approved by the Commission in FY12, 13 & 14 respectively.
A&G expenses-The Commission believes that A&G expenses do get impacted with the general level of
prices in the economy. Thus considering the inflationary impact at 10% YOY, the Commission allows Rs.
99.58 Crore to be recovered in the ARR in FY 2011-12.The same approach is followed in FY 2012-13 also.
The Commission approves Rs 57.60 Crore as A&G expenses for FY 2013-14 for UHBVNL and Rs. 52.83
Crore for DHBVNL after accounting for 4% increase per annum over the audited expenses of FY 2011-12
in line with the MYT regulations.
The O&M expenses constitute of 10% of net ARR approved in FY 2011-12 which is highest among all
three FY’s.
45
FY
TOTAL O&M COST
2011-12
2012-13
1393.69
1405.4
2013-14
1419.79
TOTAL O&M COST
1430
1420
1419.79
1410
1405.4
TOTAL O&M
COST
1400
1393.69
1390
1380
2011-12
2012-13
2013-14
Fig-5 Trend of O&M Cost over three years
DEPRECIATION-In FY 2011-12 UHBVNL has claimed depreciation on an opening balance of GFA
which works out to 3.43% of GFA at the beginning of the year. The commission applies the same
depreciation rate 3.43%.DHBVNL has claimed depreciation on the opening balance of GFA of which works
out to an average of 5.07% of opening GFA. The rate of depreciation proposed by DHBVNL is much higher
than the depreciation rate of 2.74%(adopted by Commission) as per audited accounts for FY 2009-10.
Therefore the Commission has based its calculation for depreciation on the average rate of depreciation as
per the last available audited accounts.
In FY 2012-13 The Commission, based on the depreciation rate of 3.45% as per audited accounts for FY
2010-11, has approved depreciation on its estimation of opening balance of GFA for UHBVNL. The
Commission has based its calculation for depreciation on the average rate of depreciation (3.58%) as per the
last available audited accounts for DHBVNL.
In FY 2013-14 The Commission has revised the applicable rates of depreciation vide the MYT and the
licensees were to file the depreciation costs accordingly but have expressed their inability to do so for the
ensuing year. The Commission, therefore, allows the depreciation rates claimed by the licensees, as per
audited accounts for FY 2011-12 and the same shall be allowed to be trued up based on the audited cost as
per the revised depreciation rates.
46
The Depreciation amount increased from Rs 204 Crore in FY12 to Rs 294 Crore i.e; 44% but very small
increase from Rs294 Crore to Rs 304 Crore i.e; 3.5% in FY 14.
FY
DEPRECIATION
2011-12
204.8
2012-13
294.2
2013-14
304.15
DEPRECIATION
350
300
304.15
294.2
250
200
204.8
DEPRECIATION
150
100
50
0
2011-12
2012-13
2013-14
Fig-6 Trend of Depreciation amount over three years (Approved)
INTEREST ON WORKING CAPITAL -The Commission has allowed interest on borrowings for
working capital equivalent to one month of ARR in accordance with the orders of the Hon’ble Appellate
Tribunal for Electricity. The interest rate of 12.25% has been applied on amount of working capital in FY 12
and 12% in FY13. The Commission has allowed interest rate of 12% on borrowings for working capital in
accordance with the MYT regulations for FY 14.
INTEREST AND FINANCE CHARGES- The Commission followed the following approach to compute
interest and finance charges-:
Net Interest on capex loans ,Interest on working capital , Interest on consumer deposits and Interest on
financing regulatory gap are added together to get the net Interest expenses. Discoms has not separately
provided details of interest on consumer security deposit and Interest on financing regulatory gap therefore
the detailed approach for computing Interest and finance charges can’t be explained.
RETURN ON EQUITY-The accumulated losses of the two distribution Licensees i.e. UHBVNL and
DHBVNL have completely eroded their entire net worth.. the Commission does not consider it appropriate
to
allow
any
return
on
equity
in
the
all
three
FY’s,
47
The key components of Annual Revenue Requirement filed by petitioner and approved by HERC are as follows:
In Rs Crore
FY
ARR
COMPONENTS
PPC
O&M COST
DEPRECIATION
INTEREST &
FINANCE
CHARGES
INTEREST ON
WC
ROE
ARR
NON TARIFF &
OTHER
INCOME
NET ARR
PS
2011-12
CA
DIFF
11666.82
10298.15
1368.6
%of net
ARR
Approved
72.5
1696.39
390.6
1484.59
204.8
211.8
185.8
10.4
1.4
662.5
516.97
145.53
1467.58
457.23
18579.71
148.75
NO
14708.98
1318.8
457.23
3870.7
501.1
18502.09
501.1
14207.87
0
4294.2
Table no-5
2012-13
PS
CA
12728.92
4741.2
%of net
ARR
Approved
81.7
363.9
1405.4
294.2
285.07
69.7
9.02
1.9
3.6
539.10
736.27
-197.17 4.7
180
315
-135
1.83
1.04
557.46
423.49
24504.38
158.5
NO
15941.99
398.96
423.49
8562.4
2790.5
541.5
25941.8
261.24
NO
17404.7
2529.27
541.5
85371
1.5
367
24594.59
363.14
15578.85
3.86
9015.7
227.50
26255.8
227.48
17177.2
.02
9078.58
17470.19
1690.471
DIFF
2013-14
PS
CA
1.01
DIFF
19046
14451.53
4594.47
%of net
ARR
Approved
84.1
1669.5
309.6
1419.8
304.15
249.71
5.45
8.2
1.77
Diff in amount of ARR Components filed by Petioner and approved by the Commission
48
REASON FOR DIFFERENCE (filed vs approval)
1) Interest on Working Capital-The Petitioner has proposed huge amount of working capital but
Commission has not approved such huge amount and as a result interest on WC (approved by
Commission) is small figure as compare to proposed amount. The approach for computing amount of
working capital is not given in the Tariff order
In FY 2013-14 UHBVNL has not furnished the details of Interest on WC.
2) Interest and Finance Charges- In FY 2011-12 DHBVNL has not furnished the data of Interest on
financing Regulatory Gap. In FY 2012-13 Both Discoms has not filed any data of Interest on
financing Regulatory Gap. In FY 2013-14 Both Discoms have proposed high interest capitalized and
commission reject it.
3) O&M Cost-While working out expenditure under employee cost, the Commission has not allowed
expenditure on account of new recruitments as proposed by the distribution licensees for all three
FY.
HIGHLIGHTS OF THE ORDER
FY 2011-12
 Increase in sales in 2011-12 in case of UHBVNL 13% and 15% by DHBVNL.
 Commission has revise the Tariff in Independent Hoarding/Decorative Lightning category from Rs
5.95/KwH to Rs 6.50/Kw
 The Commission allow the Distribution companies to take borrowings from approved institutions to
the extent required but not exceeding the uncovered revenue deficit as estimated by the Commission
FY 2012-13
 For DS consumers’ commission has reduced MM (Rs70 to Rs50 per month per KW of connected
load.
 Commission has introduced a separate category of Tariff for existing NDS consumers with load
above 50KW up to 70KW.
 Commission has revised the tariff for the public water, lift irrigation, MITC & street light supply
consumers with cost causation principle
49
FY 2013-14
 DHBVNL have not submitted any Tariff proposal to bridge the revenue deficit at the current Tariff
of DS consumers.
 Commission has considered discom proposal and allows a recovery of about 45% of regulatory
asset and Balance amount shall be recovered in the next two years.
50
PUNJAB
INTRODUCTION
The Punjab State Electricity Board (PSEB) was a statutory body formed on 1-2-1959 under the
Electricity Supply Act.1948. Subsequently with the re-organization of the erstwhile State of Punjab under
the Punjab Re-organization Act 1966 this form came into existence w.e.f. 1st May, 1967. Starting with the
modest installed capacity of 62 MW, the PSEB grew up by leaps and bounds with generating capacity 6841
MW as on 31-3-2009 from all sources, including share from Central Sector Projects. The Board's gross
generation during the year2008-09 was 38880 Million Units. PSEB operated its own Generation Power
Plants and also got power as its share from BBMB. The PSEB also constructed and maintained its
Transmission and Distribution system for providing efficient services to the various categoriesof electricity
consumers in the state.
Punjab State Power Corporation Limited (PSPCL) is the electricity generating company of the
Government of Punjab state in India.
PSPCL has submitted that it is one of the „Successor Entities‟ of the erstwhile Board duly constituted under
the Companies Act, 1956, on 16.04.2010 after unbundling of the Board by Government of Punjab vide
notification no.1/9/08-EB(PR)/196 dated 16.04.2010, under the “Punjab Power Sector Reforms Transfer
Scheme” (Transfer Scheme).
. The consumer’s category-wise energy sales Approved by Commission shown below:
Consumer Category
Domestic
Non Residential
Small Power
Medium Supply
Large Supply
Public Lighting
Bulk Supply
Railway Traction
Total Metered Sales
AP Consumption
Common Pool
Outside State Sale
Total Sales
Sales Approved(MU’s)
% of the Total Sales
2011-12
2012-13
2013-14
2011-12
2012-13 2013-14
25.09
27.37
26.77
8954
9642
10452
7.35
8.05
8.24
2623
2838
3218
2.34
2.52
2.48
835
891
972
4.91
5.15
5
1755
1815
1953
26.92
22.30
25.50
9607
7856
9957
0.38
0.38
0.36
137
135
143
1.51
1.56
1.59
539
552
623
0.50
0.52
0.36
181
184
143
68.76
67.89
70.34
24531
23913
27461
30.39
31.23
28.74
10843
11003
11221
0.84
0.86
0.77
302
305
304
0
0
0
0
0
53
100
100
100
35676
35221
39039
Table no-6 Consumer Category wise Sales Approved by the PSERC
51
The Approaches followed by the Commission to determine the key components of ARR are explained in
detailed manner as below:
POWER PURCHASE COST-For PPC of Central Generating Stations the Commission notes that the
Terms and Conditions of Tariff Regulations issued by CERC in January 2009 are applicable for all Central
Generating Stations from April 1, 2009 onwards. However, CERC is yet to issue Tariff Orders for individual
Central Generating Stations. All the Central Generating Stations are provisionally raising the bills at the
tariff approved by CERC for FY 2008-09. In this Order, therefore, the Commission has decided to consider
fixed charges as per bills for September, 2010. These fixed charges will be reviewed in the subsequent
Orders of the Commission once the CERC issues Tariff Orders for the Central Generating Stations based on
the new Tariff Regulations.
In FY 2012-13 The Commission has decided to consider fixed charges as per respective Tariff Orders
issued by the CERC, and in cases where Tariff Order has not been issued, fixed charges have been taken as
per bills for September 2011, and where bills for September 2011 are also not available, fixed charges have
been taken as projected by the PSPCL in the ARR. The variable charges have been considered as per bills
for September 2011, and where bills for September 2011 are not available, variable charges as projected by
PSPCL in the ARR for FY 2012-13 have been considered by the Commission.
In FY 2013-14 The Commission has decided to consider fixed charges as per respective Tariff Orders
issued by CERC, and in cases where Tariff Order has not been issued, fixed charges have been taken as per
bills for September 2012, and where bills for September 2012 are also not available, fixed charges have been
taken as projected by PSPCL in the ARR. The variable charges have been considered as per bills for
September 2012, and where bills for September 2012 are not available, variable charges as projected by
PSPCL in the ARR for FY 2013-14 have been considered by the Commission.
Trend of PPC over three years shown below-
PPC
10000
8000
6000
7818.98
5751.26
5717.04
PPC
4000
2000
0
FY12
FY13
FY14
Fig 7 Trend of PPC over three years
52
O&M Expenses-Comprises of Employee cost, R&M expenses and A&G expenses which are explained
below:
Employee Cost- The provisions of the PSERC Tariff Regulations provide for determination of
Employee cost in two parts:

Terminal benefits including BBMB share on actual basis.

Increase in other employee expenses limited to average increase in Wholesale Price Index.
Regulation 28(8) also provides for consideration of any exceptional increase in employee cost on account
of pay revision.
.The employee cost is increasing year by year. There is a increment of 14.5% from FY12 to FY13 and
13.6% from FY13 to FY14.
R&M expenses- The Commission has been approving the R&M expenses in accordance with the provisions
of Regulation 28 (8) of PSERC Tariff Regulations by adjusting the base R&M expenses in proportion to the
increase in WPI. The Commission approved Rs 595 Crore in FY14 which is 54% more as compare to FY14.
A&G expenses- The Commission has been approving the A&G expenses in accordance with provisions of
the amended Regulation 28 (2)(b) of PSERC Tariff Regulations by adjusting the base A&G expenses in
proportion to the increase in WPI. The Commission approved Rs 87.9 Crore, Rs 101.4 Crore and Rs 136.8
Crore in FY12, 13 and FY14 respectively. There is a increase of 15% and 34.8% in last two years.
FY
TOTAL O&M COST
2011-12
3381.15
2012-13
3899.88
2013-14
4530.13
TOTAL O&M COST
5000
4530.13
4000
3000
3899.88
3381.15
TOTAL O&M COST
2000
1000
0
2011-12
2012-13
2013-14
Fig 8 Trend of O&M Cost over three years
DEPRECIATION- The Commission has applied the average percentage rates of depreciation (net) for FY
2011-12, which are derived from the audited accounts of FY 2009-10. The Commission apply 3.72%
53
depreciation rate on the asset value as on 1 April 2012 for FY 2012-13 and dep. comes out to be Rs 290
Crore. Same approach is followed in FY 2013-14 and dep. comes out to be Rs 307 Crore.
FY
DEPRECIATION
2011-12
405.29
2012-13
290.10
2013-14
307.18
DEPRECIATION
450
400
350
300
250
200
150
100
50
0
405.29
290.1
307.18
DEPRECIATION
2011-12
2012-13
2013-14
Fig 9 Trend of Depreciation amount over three years
INTEREST ON WORKING CAPITAL- The Commission has determined the working capital
requirement of Rs. 1,866.23 Crore, as per PSERC Tariff Regulations. By applying the State Bank Advance
Rate of 11.75% as on April 01, 2010, the interest thereon works out to Rs. 219.28 Crore for FY 2011-12.
The Commission has determined the Working Capital requirement of Rs. 2023.77 Crore as per PSERC
Tariff Regulations. By applying the State Bank Advance Rate of 13% as on April 1, 2011, the interest
thereon is worked out to be Rs 263 Crore for FY 2012-13. The Commission has determined the Working
Capital requirement of ₹3540.91 Crore as per PSERC Tariff Regulations. By applying an average rate of
11.24% per annum payable by PSPCL to the financial institutions for short term and mid-term loans as
considered in the Review for FY 2012-13, the interest on working capital is worked out to be Rs 397 Crore.
INTEREST AND FINANCE CHARGES-There are various components which constitute the net Interest
and Finance Charges are as follows:

Interest on Institutional loans

Interest on GOP

Interest on GPF

Lease rentals

Interest to consumers

Interest on WC Loans

Discount to consumers for advance payment
54

Finance charges for loans

Less:capatilalization

Net Interest and Finance charges
The Interest and Finance charges are Rs 1066 Crore, Rs 1580 Crore and Rs 1767 Crore for FY 12,13
and 14 respectively.
RETURN ON EQUITY- The Commission observes that at present, PSPCL has not been able to show
requisite improvement in the critical parameters like employee cost. Thus, the Commission retains the ROE
rate @ 14% and works out the ROE at Rs. 366.47 Crore on the total equity of Rs. 2,617.61 Crore in FY
2011-12. The Commission allows ROE @ 15.5% on equity of Rs. 2617.61 Crore which works out to Rs.
405.73 Crore in FY2012-13. The Commission considers it appropriate to allow RoE of Rs 942.62 Crore @
15.5% on the equity of Rs 6081.43 Crore in FY 2013-14.
55
The key components of Annual Revenue Requirement filed by petitioner and approved by PSERC are as follows:
In Rs Crore
FY
ARR
COMPONENTS
PPC
O&M COST
DEPRECIATION
INTEREST &
FINANCE
CHARGES
INTEREST ON
WC
ROE
ARR*
NON TARIFF &
OTHER
INCOME
NET ARR
PS
2011-12
CA
2012-13
DIFF
6349.74
4164.44
NOT
GIVEN
5751.26
3381.15
598.48
783.29
2236.27
1066.86
1169.4
938.47
598.86
18950.40
219.28
366.47
15504.1
719.19
232.39
3446.2
502.77
18447.62
579.11
14925
-76.34
3522.6
405.29
%of net
ARR
Approved
38.5
22.6
PS
CA
DIFF
7207.38
4508.32
NOT
GIVEN
5717.04
3899.39
7.14
2571.68
1580.35
991.33
1.46
2.45
1358.45
607.55
20415.5
263.09
405.73
17035.85
1095.36
201.82
3379.68
700.07
19715.5
1068.72
15967.13
-368.65
3748.33
2.71
1490.34
608.93
%of net
ARR
Approved
35.8
24.4
PS
2013-14
CA
DIFF
8680.57
4884.8
NOT
GIVEN
7818.98
4530.13
9.9
2656.86
1767.18
1.6
2.5
1356.19
1411.50
23589.60
397.99
958.2
942.45
469.05
21592.45 1997.15
906.36
22683.24
779.57
20812.98
290.10
1.8
861.59
354.67
%of net
ARR
Approved
37.5
21.7
307.18
1.5
889.68
8.5
1.9
4.5
126.79
1870.26
* It includes Fuel cost
Table no-7 Diff in amount of ARR Components filed by Petioner and approved by the Commission
56
REASON FOR DIFFERENCE (filed vs approval)
1) Depreciation- PSPCL has projected depreciation charges which included Generation , transmission
and Distribution.PSPCL has not projected depreciation of Distribution separately but Commission
approved separately of each function.
2) Interest on Working Capital-For all 3 FY’s PSPCL has not projected its working capital on the basis
of norms as per PSERC Tariff Regulations but Commission has determined the working capital
requirement as per PSERC Tariff Regulations which creates a difference in the amount of interest.
HIGHLIGHTS OF THE ORDER
FY 2011-12
 DS/NRS/LS consumer catered at 400 volts against specified voltage of 11 kV is levied surcharge at
the rate of 15%.
 DS/NRS/BS/LS consumers catered at 33/66 kV against specified voltage of 132/220 kV be levied
surcharge at the rate of 5%.
 SC and non SC BPL, Domestic consumers with connected load up to 1000 watts will be given
100units of free power per month in view of Govt subsidy.
FY 2012-13
 Levy of 10 paisa/unit on prorate basis, on continuous process industries, shall commence with effect
from November 01, 2012.
 The remaining Regulatory Asset of Rs 1325.75 along with carrying cost is now considering for
amortization in this tariff order.
FY 2013-14
 Commission approves an increase of 50% of the existing Peak Load Exemption Charges.
 Rebate of 25 paisa/unit to all consumers getting supply at 220/132 Kv.
 Commission approves proposal of PSPCL for introduction of TOD for six months (oct-march) of
the year.
57
BIHAR
INTRODUCTION
The Bihar State Electricity Board (hereinafter referred to as erstwhile BSEB) was constituted
under section 5 of Electricity (Supply) Act, 1948 on 1st April, 1958. It was a deemed licensee in terms of
Section 14 of the Electricity Act, 2003. Bihar State Electricity Board was engaged in the business of
generation, transmission and distribution of electricity in the State of Bihar. In terms of Section 172 of the
Act, the Board constituted under the repealed laws is to be deemed as the State Transmission Utility and a
licensee under the provisions of the Act for a period of one year from 10th June, 2003 i.e. the appointed date.
Subsequently it has been mutually agreed by the Central Government and the Government of Bihar to
authorize the Board to continue to function as a State Transmission Utility and Licensee.
The Government of Bihar unbundled and restructured the Bihar State Electricity Board with effect from
1st November, 2012. The Generation, Transmission and Distribution Businesses of the erstwhile Bihar State
Electricity Board are transferred to four successor companies. The four successor companies are listed
below:
Generation:
Bihar State Power Generation Company Limited
Transmission: Bihar State Power Transmission Company Limited
Distribution: (i) North Bihar Power Distribution Company Limited
(ii) South Bihar Power Distribution Company Limited
Bihar State Power (Holding) Company Limited (BSPHCL), a holding company is responsible for purchase
of electricity from various sources and supply of electricity to Distribution companies and other activities
including trading of electricity.
58
Appropriate estimation of category wise energy sales is essential to arrive at the quantum of power to be purchased and the likely revenue by sale of energy
which shows its importance. The consumer’s category-wise energy sales Approved by Commission shown below:
Category
2011-12
Category
MU’s
Kutir Jyoti
263
D.S-I
886
D.S-II
1424
D.S Total
2012-13
Category
MU’s
Category
2013-14
MU’s
2012-13
Kutir Jyoti
MU’s
Rural
365
Kutir Jyoti (R)
456
Urban
67
2573
Kutir Jyoti (U)
1
Sub total
432
NDS-I
29
D.S-I
1048
Domestic Services
NDS-II
575
D.S-II
1425
Domestic-I
689
NDS-III
7
D.S-III
1
Domestic-II
1867
NDS Total
610
D.S Total
2474
Domestic-III
1
Irrigation IAS
398
NDS-I
22
Sub total
2557
Irrigation total
398
NDS-II
582
Non Domestic Service
LT Industrial L.T.I.S-I
204
NDS-III
18
Non Domestic-I
19
LT Industrial L.T.I.S-II
73
NDS Total
622
Non Domestic-II
870
LT Industrial total
277
IAS-I
272
Non Domestic-III
3
PWW
143
IAS-II
317
Sub total
892
Street Light-I(Metered)
4
LT Industrial L.T.I.S-I
197
Industrial(LT)Services
Street Light-I(Unmetered)
34
LT Industrial L.T.I.S-II
127
LTIS-I
172
Street Light Total
38
PWW
160
LTIS-II
116
H.T.S-I
962
Street Light-I(Metered)
7
Sub total
288
H.T.S-II
289
Street Light-II(Unmetered)
33
H.T.S-III
110
Street Light-III
2
Streetlight-I
8
H.T.S.S
930
Street Light Total
42
Streetlight-II
45
HT Total
2291
H.T.S-I
967
Sub total
53
R.T.S-25Kv/132Kv
496
H.T.S-II
426
PWW
57
Street Light(Public lighting)
59
BSEB Total
6828
H.T.S-III
221
Irrigation & Agriculture Service
H.T.S.S
447
IAS-I
336
RTS
785
LT Total
4810
BSEB Total
7512
HT Consumers
HT industrial
HTS-I
747
HTS-II
219
HTS-III
193
HTSS
523
Sub Total
1682
Railway Trac.
551
Total HT
2233
Nepal
550
Grand Total
7593
Table no-8 Consumer Category wise Sales Approved by the BERC
60
The Approaches followed by the Commission to determine the key components of ARR are explained in
detailed manner as below:
POWER PURCHASE COST- Commission determined the ppc for FY 12 by using the information of cost
data of FY 11 provided by BSEB. The PPC of FY14 has been determined by the Commission, considered
for NTPC stations, 5% increase per annum over the actual rates of April to September 2012, to cover likely
increase in the cost of coal and transportation charges. NHPC has revised power purchase price of Rangit
HPS, and it has built in bills claimed from April to September 2012. The Commission has also considered
5% increase in power purchase from Tala and Chukka projects in Bhutan. For the power purchased from
Adani and other IPPs, the cost as provided in the PPA are considered and for power from other sources (now
and existing) the cost as claimed by BSPHCL is approved.
The PPC has increased from FY12 to FY13 by 60% which lead to the increased
ARR in FY13.
Trend of PPC over last three years shown below
PPC
6000
5571
5000
4694
4000
3000
2916
PPC
2000
1000
0
FY12
FY13
FY14
Fig 10 Trend of PPC over three years
O&M Cost-The O&M Cost comprises of Employee expenses, R&M expenses and A&G expenses which
are explained below:
Employee Cost-. The Commission in current economic situation considers escalation rate of 10%
appropriate for determining employee cost for FY2011‐12 and 9.56% for FY 2012-13.The Commission
considers the Consumer Price Index (CPI) at 8.63% per annum as on March, 2012 for determining the
employee cost for the FY 2013-14.
R&M Cost- The Commission agrees to approve higher R&M cost with an expectation that this will help
BSEB in improving operational efficiency which is same as previous year Rs 67 Crore. The Commission in
current economic situation considers escalation rate of 9.56% appropriate for determining R&M cost for
FY2012-13. An increase of 7.69% per annum for the FY 2013-14 on the actual expenses of FY 2011-12.
61
.A&G expenses-The Commission has analyzed past trend of increase in A&G cost and the present levels.
The Commission has found that growth in A&G cost over the period FY 08 to FY 10 to be around 8%.
Therefore the Commission finds the consideration of 8% escalation rate on actual cost of FY 2009‐10 to
determine A&G expenses for FY 2010‐11 & FY 2011‐12 and 9.56% for FY 2012-13.The Commission has
considered the increase in A&G at an increase of 7.69% over the 2012-13 (RE) for determining FY 14.
Total O&M Cost
FY
TOTAL O&M COST
2011-12
776
2012-13
754
2013-14
530.15
TOTAL O&M COST
1000
800
776
754
600
530.15
400
TOTAL O&M
COST
200
0
2011-12
2012-13
2013-14
Fig 11 Trend of O&M Cost over three years
DEPRECIATION-Based on approved GFA and capitalization considered during FY 2010‐11 & FY
2011‐12, the Commission approves depreciation of Rs 76 Crore for FY2011‐12. The Commission has
considered closing balance GFA as achieved in FY 2011-12 as per the annual accounts of that year. The
Commission has thereafter considered asset additions of Rs. 1810.7 Crores and by applying weighted
average rate of depreciation (same as used in FY 2010-11) on average GFA the amount comes out to be Rs
118 Crore. For FY 2013-14 Commission follow the same method with average rate of depreciation is
5.21%.
FY
DEPRECIATION
2011-12
76.20
2012-13
118.24
2013-14
77.6
62
DEPRECIATION
140
120
118.24
100
80
77.6
76.2
DEPRECIATION
60
40
20
0
2011-12
2012-13
2013-14
Fig 12 Trend of Depreciation amount over three years
INTEREST ON WORKING CAPITAL-Interest on working capital is computed on normative basis as per
BERC (Terms and conditions for determination of Tariff) Regulations, 2007. SBI PLR rate of 13% as on 1st
April, 2011 has been considered for calculation of interest for funding working requirement .However for
FY 12 &13 same rate of interest has applied and there is a huge increase in the amount of interest from Rs
75 Crore to Rs 140 Crore i.e, increase of 86%.For FY 2013-14 same procedure has followed with an interest
rate of 14.45%.
INTEREST AND FINANCE CHARGES-Based on opening GFA and capitalization approved the interest
rate of 13% has been applied and interest & finance charges(Generation ,transmission and distribution
combine) comes out to be Rs 149 Crore, Rs 191 Crore and Rs 211 Crore for FY 12,13 and 14 respectively.
RETURN ON EQUITY-Return is admissible only on equity actually deployed for the creation of
assets.Since, BSEB has not been corporatized; it does not have any equity. The Commission has considered
entire assets base funded through loan and accordingly interest has been allowed ,therefore no return is
allowed for FY2011-12 and 2012-13.After unbundling the Commission has computed the return on the
equity as per opening balance sheet as on 1st April, 2011 and there is no equity addition during FY 2011-12
and FY 2012-13, the return on equity is computed on the equity capital as on 1st April, 2011 @ of 14%
which comes out to be Rs 123 Crore for FY 2013-14.
63
The key components of Annual Revenue Requirement filed by petitioner and approved by BERC are as follows:
In Rs Crore
FY
ARR
COMPONENTS
PS
2011-12
CA
DIFF
%of net
ARR
Approved
2012-13
PS
CA
DIFF
%of net
ARR
Approved
2013-14
PS
CA
DIFF
%of net
ARR
Approved
PPC
O&M COST
DEPRECIATION
INTEREST &
FINANCE
CHARGES
INTEREST ON WC
ROE
ARR
NON TARIFF &
OTHER INCOME
NET ARR
3395
2916
479
64.2
5139
4694.6
444.38
61.9
6508
1115.07
776.13
338.94
17.1
900.5
756.03
144.47
11.5
533.14
72.93
76.20
-3.27
1.67
169.63
118.24
51.39
1.8
216
118.38
149
75.16
67
43.22
3.28
1.65
423.48
166.07
121.37
140.27
302.11
25.8
1.85
2.13
174
5296*
NO
4706*
174
590*
282
7898.13
NO
6703.6
282
1194.5
148.16
5148
168.23
4538
-20.07
610
55
7843.02
127.16
6576.4
-72.16
1266.6
5571.92
936.08
83.6
530.15
2.99
7.9
133.13
77.6
55.53
1.16
237
188
211.28
123.16
25.72
64.84
3.17
1.85
123.1
7285.6
123.1
6850.21
0
435.4
1.85
110.68
7174.9
186.50 -75.82
6663.71 511.22
*It includes fuel cost
Table no-9
Diff in amount of ARR Components filed by Petioner and approved by the Commission
64
REASON FOR DIFFERENCE (filed vs approval)
FY 2011-12
1) O&M Cost-For projecting employee cost for FY 2011‐12, BSEB has considered a further escalation
of 15% over the revised estimates of employee cost for FY 2010‐ 11 but Commission in current
economic situation considers escalation rate of 10% appropriate for determining employee cost for
FY2011‐12 Commission approved half of the A&G Expenses as proposed by the BSEB. BSEB has
proposed a substantial increase in A&G expenses for FY 2011‐12 as compared to the actual incurred
in FY 2009‐10.
2) ARR-Commission has not included Return on Equity and Interest on Working Capital but BSEB
include it during filing.
FY 2012-13
1) Interest & Finance Charges- For calculation of Interest and Finance charges for FY 2011-12 & FY
2012-13, BSEB has considered the closing balance of loans of FY 2010-11 but Commission has
considered the closing balance of loan for FY 2011-12 (as per review Order for FY 2011-12) as the
opening loan for FY 2012-13 and has computed the interest on loan for FY 2012-13.
2) Return on Equity-Commission has not approved return on equity.
FY 2013-14
1) Depreciation-The Petitioner has computed the depreciation based on closing GFA,but Commission
computed on average GFA during the year.
2) Power Purchase Cost-BSPHCL has considered the power purchase cost for the FY 2013-14 by
applying CAGR of 5 years on the trends of unit power purchase cost from FY 2008-09 to FY 201213 on the actual rates paid for power from various generating companies during April 2012 to
September, 2012. The Commission does not approve the methodology considered by BSPHCL in
arriving at the power purchase cost for the this year. For NTPC stations, the Commission has
considered 5% increase per annum over the actual rates of April to September 2012, to cover likely
increase in the cost of coal and transportation charges. NHPC has revised power purchase price of
65
Rangit HPS, and it has built in bills claimed from April to September 2012. The Commission has
also considered 5% increase in power purchase from Tala and Chukka projects in Bhutan. For the
power purchased from Adani and other IPPs, the cost as provided in the PPA are considered and for
power from other sources (now and existing) the cost as claimed by BSPHCL is approved.
HIGHLIGHTS OF THE ORDER
FY 2011-12
 Levy of Delay payment surcharge (DPS) @ 1.5% per month.
 Commission has reduced the Cross Subsidy surcharge by 50% in this Tariff order.
 Removal of Load factor rebate.
FY 2012-13
 Change in the nomenclature of demand based tariff category from sub category name (A) to sub
category name (B).
 Introduction of rebate for RTS tariff for availing supply at voltages higher than 132 Kv.
FY 2013-14
 BSEB is restructured on functional basis wef; 1 Nov 2012 and this petition is filled by BSPHCL on
the behalf of two distribution companies.
 Unrecovered gap is considered as Regulatory Asset to be amortized in subsequent three years.
66
ASSAM
INTRODUCTION
The Government of Assam notified Vide Memo No PEL151/2003/Pt./165 dated 10th
Dec’2004 to restructure the Assam state Electricity Board (ASEB) into five entities namely;
Assam Electricity Grid Corporation Limited (AEGCL) to carry out function as State Transmission Utility
(STU).
Assam Power Generation Corporation Limited (APGCL) to carry out function of generation of electricity
in the State of Assam.
Three Electricity Distribution Companies, namely Lower, Central and Upper Assam Distribution Company
Limited respectively to carry out functions of distribution and retail sale of electricity In the districts covered
under each company area. All companies are duly incorporated with the Registrar of Companies as per the
Companies Act. Further in exercise of power under Section 172 of the Electricity Act 2003, the State
Government authorized ASEB to continue its trading functions by periodic notification till Sept 2009. In
May 2009, as per GOA notification No PEL.41/2006/199 dated 13th May’09, in accordance with the Assam
State Reform (Transfer and merger of Distribution Functions and undertakings) scheme, 2009, CAEDCL &
UAEDCL distribution companies merged with the LAEDCL, thereby forming one distribution company for
the state.
The name of the company is changed from LAEDCL to Assam Power Distribution Company Limited
(APDCL) vide certificate of incorporation dated 23rd October 2009. The Commission notified the AERC
(Terms and Conditions for Determination of Tariff) Regulations, 2006 vide No. AERC.2005/19 dt 28th
April 2006, which was published in the Assam Gazette on 24th May, 2006. It was stated that it shall come
into force from the date of their publication in the Official Gazette of the Government of Assam.
The Assam Electricity Regulatory Commission (hereinafter referred to as the AERC or the Commission)
was established under the Electricity Regulatory Commissions Act, 1998 (14 of 1998) on February 28, 2001.
The AERC came into existence in August 2001 as a one-man Commission.
Considering the multidisciplinary requirements of the Commission, it was made a Multi Member
Commission constituting three Members (including Chairperson) from 27th January 2006. The Commission
has started functioning as Multi Member Commission on joining of two Members from 1st of February
2006. As per Assam Electricity Regulatory Commission (AERC), Terms and Conditions of Tariff
Regulations 2006, the APDCL is required to file the proposal for determination of Annual Revenue
Requirement and Tariff with the Commission.
67
The Category wise consumer Sales are given below:
SI NO
ENERGY SALES (APPROVED )
CONSUMER CATEGORY
1
2
3
4
5
6
7
8
9
Jeeban Dhara
Domestic A
Domestic B
Commercial
General Load
Public Lightning
Agricultural
Small Scale Industries-Rural
Small Scale Industries-Urban
2012-13
MU’s
298
1370
151
479
61
8
42
69
28
10
11
12
13
14
15
16
17
18
19
20
Total LT
HT Domestic
HT Commercial
PWW
Bulk supply-Govt educational Institutions
Bulk supply-others
HT small industry upto 50Kw
HT industry I 50Kw to 150Kw
HT industry II above 150Kw
Tea, coffee and rubber
Oil and Coal
HT Irrigation above 7.5HP
2506
33
304
84
60
339
25
59
832
432
92
30
Total HT
TOTAL HT+ LT
%of total sales
6.21
28.56
3.14
9.98
1.27
.01
0.87
1.43
0.58
52.25
2290
0.68
6.33
1.75
1.25
7.06
0.52
1.23
17.34
9
1.91
0.62
47.74
4796
100
Table no-10 Consumer Category wise Energy Sales approved by AERC
The Petitioner didn’t filed Revised ARR and Distribution tariff for FY 2011-12 and ARR for FY2013-14 are
not come yet therefore we can’t compared the Sales of FY 2012-13.
The Approaches followed by the Commission to determine the key components of ARR are explained in
detailed manner as below:
POWER PURCHASE COST- The average per unit rate for energy purchase from central generating
station and others during 2009-10 is adopted for arriving at power purchase costs for the FY 2012-13. For
new stations from which energy availability is projected for 2012-13, the per unit rate as given by APDCL is
considered.
Transmission Cost- The transmission costs include the costs to be paid to AEGCL for intra-state
transmission to PGCIL for regional transmission of power, and SLDC charges.
68
PGCIL Cost- are approved by CERC and to be paid by APDCL on the basis of calculation in the Regional
Energy Accounting of NERLDC
ASEB Cost- The Government of Assam has continued ASEB for the purpose of implementation of various
schemes. The normal expenditure of ASEB has been added to the power purchase cost. The expenditure is
allowed till alternate arrangements are made by the State Government.
O&M COST- include employee expenses, repair and maintenance (R&M) expenses and administrative and
general (A&G) expenses explained below:
Employee expenses- Commission takes into consideration the submission of the APDCL to consider the
impact of 6th Pay Commission recommendation and provisionally approves 30% increase in FY 2010-11
over the actual of FY 2009-10 and 8% per annum for the years 2011-12 and 2012-13.The employee
expenses comes out to be Rs 542 Crore.
R&M expenses- This is a controllable item on which the expenses have to be restricted normally about 6%
escalation per annum. In view of the vintage of the assets and the need to maintain quality of supply to the
consumers, it is considered to allow 10% increase per annum on the base expenses of previous year and this
expense comes to be Rs 32 Crore.
A&G expenses-follow the same approach as mentioned above.
FY
TOTAL O&M COST
2011-12
Not Filed Revised ARR
2012-13
587.42
2013-14
Not Come yet
DEPRECIATION- Commission has computed the depreciation based on the depreciation rates approved in
Annexure I of AERC (Terms and Conditions for determination of tariff) Regulations 2006. However
commission apply 3.74% weighted average rate of depreciation and adopted same methodology as other
SERC’s used.
FY
DEPRECIATION
2011-12
Not Filed Revised ARR
2012-13
34.38
2013-14
Not Come Yet
INTEREST ON WORKING CAPITAL- As per the AERC Regulations 2006, the Interest on working
capital shall consist of
a) O & M Expenses for one month
b) Maintenance spares at 1% of the historical cost of fixed assets.
c) Receivables equivalent to 60 days Average billing of consumers less security deposits of the consumers.
69
Rate of interest on working capital to computed at the PLR rate of SBI as on the 1st April of the financial
year
The amount of interest is Rs 50 Crore.
INTEREST AND FINANCE CHARGES-The Commission considered ASE Loans with interest rate of
10% ,ADB Loans with interest rate of 10% comes to be Rs 1.10 Crore and New Loans with an interest rate
of 10% comes out to be Rs 16.60 Crore.The Total Interest and Finance charges approved 17.70 Crore for FY
2012-13.
RETURN ON EQUITY- As per the AERC Regulations 2006 Return on Equity shall be computed on the
Equity capital Employed in the business, as per the opening balance sheet notified under transfer scheme
subject to a maximum of 30%.
The return on equity has come out Rs 22.79 Crore.
70
The key components of Annual Revenue Requirement filed by petitioner and approved by AERC are as follows:
In Rs Crore
FY
ARR
COMPONENTS
PPC
O&M COST
DEPRECIATION
INTEREST &
FINANCE CHARGES
INTEREST ON WC
ROE
ARR
NON TARIFF &
OTHER INCOME
NET ARR
2011-12
PS
C
DIFF
A
2012-13
PS
CA
1758.37
630.69
69.90
NOT FILED REVISED ARR
AND DISTRIBUTION
45.58
TARIFF
61.38
37.76
3766.59
1256
2510.59
DIFF
1654.24
589.97
34.38
104.13
40.72
35.52
17.70
50.27
22.79
2712.56
27.88
11.11
34.97
1054.03
462.47
2250.09
793.53
260.5
%of net ARR
Approved
73.5
26.2
1.5
.78
2.2
1
2013-14
PS
CA
DIFF
NOT COME YET
Table no-11 Diff in amount of ARR Components filed by Petioner and approved by the Commission
71
REASON FOR DIFFERENCES
1) O&M Cost-Utility proposed an escalation 12% per annum considering the vintage of the assets in
R&M expenses but Commission considered only 6% escalation per annum.
2) Interest on Working Capital-The petitioner proposed a Receivable equivalent to 60 days on higher
side but Commission approved less amount.
HIGHLIGHTS OF THE ORDER
FY 2012-13
 APDCL has not filed petition for determination of revised ARR and revised Tariff for FY 2012-13.
 The commission has taken up this case on Suo Motu for determination of revised tariff for FY 201213.
 No Revision in Tariff for FY 2012-13.
72
DELHI
INTRODUCTION
Prior to the year 2001, Delhi Vidyut Board (hereinafter referred to as „DVB‟) was the sole entity handling
all functions of generation, transmission and distribution of electricity in the National Capital Territory of
Delhi (hereinafter referred to as „Delhi‟). The Government of National Capital Territory of Delhi
(hereinafter referred to as „GoNCTD‟), however, notified the Delhi Electricity Reform (Transfer Scheme)
Rules, 2001 (hereinafter referred to as „Transfer Scheme‟) on November 20, 2001 and provided for
unbundling the functions of DVB into different entities handling generation, transmission and distribution of
electricity.
The Transfer Scheme provided for unbundling of DVB and the transfer of existing distribution assets of
DVB to BRPL (formerly known as South West Delhi Distribution Company Limited) , BYPL (formerly
known as Central East Delhi Distribution Company Limited) , NDMC and TPDDL.All the Four distribution
companies shall hereinafter are collectively referred to as „DISCOMs.
BRPL-is a company incorporated under the Companies Act, 1956 and is entrusted with the business of
distribution and retail supply of electricity in the specified area of South West of Delhi in the NCT of Delhi
(as specified in the Transfer Scheme).
BYPL-is a company incorporated under the Companies Act, 1956 and is entrusted with the business of
distribution and retail supply of electricity in the specified area of Central East and East of Delhi in the NCT
of Delhi (as specified in the Transfer Scheme).
NDMC-is a Municipal Council entrusted with the distribution of electricity to the consumers in the New
Delhi area under Section 195 to 201 of the New Delhi Municipal Council Act 1994. The NDMC has the
obligations of a Licensee under the Indian Electricity Act 1910 in respect of the New Delhi Area.
TPDDL-is a company incorporated under the Companies Act, 1956 and is engaged in the business of
distribution and retail supply of electricity in the specified area of North and North West of Delhi in the
NCT of Delhi (as specified in the Transfer Scheme).
.
73
The consumerwise category Sales are shown below:
CATEGORY WISE SALES
BRPL
BYPL
TPDDL
BRPL
2011-12
Domestic
Non Domestic*
Industrial
Public Lighting
Irrigation & agriculture
Railway Traction
DMRC
Sales
MU's
5025.73
2888.58
586.5
160.38
15.29
24.27
200
Others*
Total
483.3
9384.05
Sales
MU’s
2718.64
1585.84
448.76
112.06
0.56
0
130
224.01
5219.88
BYPL
TPDDL
2012-13
Sales
MU’s
2997.96
1196.48
2064.45
96.41
15.89
61.51
190
310.25
6932.95
Sales
MU’s
5223.97
2886.46
510.64
136.4
15.16
24.77
280
544.83
9622.43
Sales
MU’s
2710.05
1627.97
429.33
114.45
0.36
0
150
211.99
5244.14
Sales
MU’s
3182.85
1302.30
2102.37
103.36
17.91
67.85
190
302.25
7268.89
BRPL
% of
total
Sales
BYPL
%of
total
Sales
TPDDL
% of
total
Sales
2011-12
53.55
30.78
6.24
1.70
0.16
0.25
2.13
5.15
100
52.08
30.38
8.59
2.14
.01
0
2.49
4.29
100
43.24
17.25
29.77
1.39
0.22
0.88
2.74
4.47
100
BRPL
%of
total
Sales
BYPL
%of
total
Sales
TPDDL
%of
total
Sales
2012-13
54.28
0.29
5.30
1.41
0.15
2.57
2.90
5.66
100
51.67
31.04
8.18
2.18
0.006
0
2.86
4.04
100
43.78
17.91
28.92
1.42
0.24
0.93
2.61
4.15
100
*Excluding DJB #Including DJB
Table no-12 Consumer Category wise Energy Sales approved by DERC
74
NDMC-have different consumer categories which are shown below:
CATEGORIES
Domestic
Single delivery point
separate delivery point upto 100 KW
Domestic power upto 100 KW
Non Domestic
upto 5 KW
more than 5 KW and less than 100 KW
Mixed Load
Supply at 11 KV (HT)
Supply on LT where supply is given from
NDMC substation
Supply on LT where applicant provides
built up space for substation
Small Industrial Power
Public Lighting
Others
DMRC
Total
Sales
MU's
258.88
94.34
145.87
18.66
254.89
50.1
204.8
726.17
514.96
3.72
%of total
Sales
7.29
11.27
1.44
3.87
15.83
39.80
.28
207.48
16.03
0.31
8.81
8.66
36
1293.72
.02
.68
.66
2.78
100
Table no-13 Consumer Category wise Energy Sales (NDMC) approved by DERC
In FY 2012-13 the Commission has replaced the two sub categories under NDLT from “Up to < 5 kW” and
“More than 5 kW and less than and up to 100 kW/108 kVA” to “Up to < 10 kW” and “More than 10 kW and
less than and up to 100 kW/108 kVA” respectively.:
CATEGORIES
Domestic
0-100 UNITS
101-200 UNITS
201-400 UNITS
ABOVE 400 UNITS
Non Domestic(Low tension)(NDLT)upto 100KW/108KVA
upto 5 KW
more than 5 KW and less than 100 KW
More than 100 KW
Supply on LT where applicant provides NDMC substation
Supply on LT where applicant provides built up space for substation
Non domestic high Tension(NDHT) Supply at 11 KV
Small Industrial Power
Sales
MU’s
239.06
26.72
45.26
73.9
93.17
422.98
42.02
177.42
203.53
3.53
200.01
536.32
0.32
%of
total
sales
19.07
2.21
3.61
5.89
7.43
33.74
3.35
14.15
16.23
0.28
15.95
42.78
0.02
75
Public Lighting
Others
DMRC
Total
14.81
9.94
30
1253.43
1.18
0.79
2.39
100
Tableno-14 Consumer Category wise Energy Sales (NDMC FY13) approved by DERC
The Approaches followed by the Commission to determine the key components of ARR are explained in
detailed manner as below:
POWER PURCHASE COST- For existing stations the Commission has projected the variable cost for
NTPC stations based on the average of the variable cost and FPA submitted by BRPL, BYPL and NDPL for
FY 2010-11 as additional information. The fixed charges for NTPC has been taken from the provisional
Tariff Orders issued by CERC. The fixed and variable cost for state generating stations has been considered
as per the Tariff Order issued by the Commission for FY 2011-12.For other existing stations Commission
approved as filed by petitioner.
For new Generating stations -In case of Maithon TPS, the Commission has considered the power purchase
cost as Rs 3.58 per unit as per information provided by the Petitioner. For NHPC hydro plants, Rs. 3.50 per
unit has been assumed for computing the power purchase cost for FY 2011-12. In case of NTPC Jhajhar
plant, Unit-II (Aravali Power Corporation Ltd.), the Commission has considered the annual fixed cost based
on the Tariff Petition filed by APCL before CERC and the variable cost as approved by the Commission for
APCL,Unit-I (under existing stations).
Other Sources- Commission has considered that there will be no requirement of power purchase for
meeting the seasonal demand in the Petitioners area of operation through intra-state purchase.
For FY 2012-13 existing stations the Commission has projected the variable cost for NTPC stations based
onthe average of the variable cost and FPA, submitted by BYPL and TPDDL for March 2012 as additional
information, and an escalation of 5% during each year. The fixed charges for NTPC stations have been taken
from the latest Tariff Orders issued by CERC up to June 15, 2012. The fixed and variable cost for state
generating stations has been considered as per the MYT Order issued by the Commission for the Control
Period. .For other existing stations Commission approved as filed by petitioner
For new Generating stations-In case of Pragati-III, the Commission has considered the power purchase rate
as Rs 4.50/kWh. For NHPC hydro plants, Rs. 4.50/kWh has been assumed for computing the power
purchase cost.
Other Sources- same as for FY2011-12.
76
PPC10870
11000
10500
10000
9251
9500
9000
PPC
8500
8000
FY12
FY13
Fig 13 Trend of PPC over last three years
O&M COST-Comprises of employee cost, R&M expenses and A&G expenses which are explained below:
Employee Cost- The Commission has determined the employee expenses of the Petitioner for the Control
Period using the methodology detailed in the MYT Regulations, 2007. As per the MYT Regulations;
“EMPn + A&Gn = (EMPn-1 + A&Gn-1)*(INDXn/ INDXn-1)”
Hence, the employee expenses for the nth year (FY 2011-12) of the Control Period (EMPn) shall be
determined using the employee expenses for the (n-1)th year (FY 2010-11) (EMPn-1) and the applicable
escalation factor.
For FY 2012-13 Commission has determined employee expenses of the Petitioner for the Control Period in
line with the formula specified in the MYT Regulations 2011 –
EMPn + A&Gn = (EMPn-1 + A&Gn-1) * (INDX);
Where,
INDX = 0.55 * CPI + 0.45 * WPI;
EMPn – Employee Costs of the Licensee for the nth year;
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.”
R&M expenses- As per the MYT Regulation, 2007, the Repairs and Maintenance (R&M) expenses of the
Petitioner for the Control Period has to be determined based on the following formula:
R&Mn = K * GFA n-1
Where,
R&Mn is Repair and Maintenance Costs of the Licensee for the nth year;
„K‟ is a constant (could be expressed in %).
77
Value of K for each year of the Control Period shall be determined by the Commission in the MYT Tariff
order based on Applicant’s filing, benchmarking, approved cost by the Commission in past and any other
factor considered appropriate by the Commission.
.
The Commission had determined the value of „K‟ for the Control Period(2007-8 to 2011-12) as 3.55% and
for next control period (2012-13-2014-15) value is 2.53%.The Commission has determined the R&M
expenses considering the opening level of GFA as approved by the Commission. The R&M expenses comes
out to be Rs 360 Crore for all Discoms in FY 2011-12 and Rs 312 Crore in FY 2012-13.
A&G Expenses-Commission has approved A&G expenses for the Control Period (FY 2007-08 to FY 201112) by considering the approved A&G Expenses of the base year (FY 2006-07) and after escalating the same
as per the revised escalation factor using the same methodology as specified in the MYT Regulations,
2007.The A&G expenses come out to be Rs 178 Crore.
For FY 2012-13 same approaches has been followed and expense come out to be Rs 219 Crore.
FY
TOTAL O&M COST
2011-12
2012-13
664.69
808.59
2013-14
Not Come yet
TOTAL O&M COST
900
808.59
800
700
664.69
600
500
TOTAL O&M COST
400
300
200
100
0
2011-12
2012-13
Fig 14 Trend of O&M Cost over three years
DEPRECIATION- The Commission has considered asset addition during FY 2011-12 and FY 2012-12 as
per the Petitioner’s submission. Based on the average of opening and closing value of assets approved, net
of Consumer Contribution Grants (average of Opening and Closing balance) during the FY 2011-12 and FY
78
2012-13 and the rates of depreciation, specified in the MYT Regulations, 2007 and MYT Regulations 2011
the depreciation comes out to be Rs 371.85 Crore and Rs 407.75 Crore respectively.
FY
2011-12
2012-13
DEPRECIATION
371.85
407.75
2013-14
Not Come yet
DEPRECIATION
420
407.75
410
400
390
380
DEPRECIATION
371.85
370
360
350
2011-12
2012-13
Fig 15 Trend of Depreciation over three years
INTEREST ON WORKING CAPITAL-The Commission considered the following components-
(a) Receivables for two months towards tariffs & charges; and
(b) Operation and Maintenance expenses for one month.
(c) Less Power Purchase Expenses for one month
The Total amount of working capital is Rs 1369 Crore and interest rate has considered 9.5% in FY 2011-12
and Rs 1417 Crore with an interest rate of 11.62% in FY 2012-12.However in the Tariff order the inerest on
WC has not given clearly.
INTEREST AND FINANCE CHARGES- Not given clearly in the Tariff order.
79
The key components of Annual Revenue Requirement filed by petitioner and approved by DERC are as follows:
In Rs Crore
FY
ARR
COMPONENTS
PPC
O&M COST
DEPRECIATION
INTEREST &
FINANCE
CHARGES
INTEREST ON
WC
ROE
ARR
NON TARIFF &
OTHER INCOME
NET ARR
PS
2011-12
CA
DIFF
11672.4
8
1621.75
452.43*
9251.47
1203.52
371.85**
NOT
CLEAR
NOT
GIVEN
74.15^
914.36
16647.8
6
208.04
16626.8
6
%of net
ARR
Approved
PS
2012-13
CA
DIFF
%of net
ARR
Approve
d
2421.01
421.23
80.58
69
9
2.7
14279.15
1803.86
410.23
10866.85
1340.67
407.75
3412.3
463.19
2.48
75.18
9.27
2.82
130.2^
847.9
-56.05^
66.46
.98
6.4
153.83
1230.75
164.82
958.77
-10.99
271.98
1.14
6.63
13423.89
3224.03
17174.21
15192.63
1981.58
145.15
62.89
193.95
298.65
-104.7
13268.74
3358.12
16980.26
14452.83
2527.43
PS
2013-14
CA
DIFF
%of net
ARR
Approved
NOT COME YET
* Including AAD ** Excluding AAD
^ Exclude interest on new loans (WC
Table no 15 Diff in amount of ARR Components filed by Petioner and approved by the Commission
80
REASON FOR DIFFERENCE (filed vs approval)
1) Depreciation-In all 2 FY’s the discoms filed the depreciation amount including AAD but
commission approved the amount excluding AAD.
2) Interest & Finance Charges-In this tariff order this component is not clearly given. It is very difficult
to segregate the amount of interest & finance charges from given information.
3)
Interest on Working Capital-It is seen that almost in all states the petitioner filed for the large
amount of working capital but Commission always reject the high amount. It is always directed by
Commission to carefully work out on WC but discoms don’t take any step in this matter.
HIGHLIGHTS OF THE ORDER
FY 2011-12
 The commission abolishes the two categories MLHT and NDLT II and creates new MDHT
Category.
 In this Order, the Commission has abolished this sub-category on the grounds that DISCOMs were
directed to install meters for all un-metered consumers (except NDMC).
 The Commission shall endeavor to cover the revenue gap approved till FY 2009-10 and unrecovered revenue gap for FY 2011-12 in the course of forthcoming MYT Period.
 The Commission did not receive any comments from the stakeholders in the NDMC area.
FY 2012-13
 The Commission, in this tariff Order has revised the slab structure of the domestic consumers.
 The Commission has decided to increase the applicable Energy charges for DMRC to meet the cost
of supply in this tariff order.
 The Commission has added DJB supply under LT also in this category.
 The commission in this tariff order has created a separate category to cover the consumption for the
advertisements and Hoardings.
.
81
CONCLUSION
The electricity Act 2003 has become the landmark in the power sector. The SERCs have played a positive
role in the after reform period. Their functions especially related to tariff fixation has brought a positive
change in the power sector. SERCs have initiated more public participation & transparencies in the
proceeding. The increased no of objections filed by consumers, NGOs & several associations proves the
increased participation. SERCs have up loaded all their proceedings, orders discussion paper on their
respective websites which are open to discussion to public.
If we want to get the clear picture of the aftermaths of restructuring & effects of regulatory governance the
overall improvement is seen in following areas in states under consideration;

Positive Trend towards reduction in distribution losses.

Increased & more focused investment

Capacity additions & system strengthening of the power systems

Localization & reduction in efficiencies.

Improved customer care.

Progress in metering, billing, & revenue collection.

Increased accountability in DISCOMs.

The SERCs tariff setting approach is well established & understood by Utilities
So a well understanding & coordination trend has established in tariff fixing. The SERCs are reviewing the
Utilities performance with the benchmarked one regularly.
The Conclusion about the ARR components in brief are given below:
In case of sale forecasting or demand estimation the historical trend method has proved to be reasonably
accurate and a well accepted method to estimate the number of consumers, the connected load and the
energy consumption where the past data is fairly accurate and the trends are well established.
Mostly SERCs have adopted merit order dispatch approach for power purchase and some followed the
method of appropriate escalation to actual cost data of previous year for determining Power Purchase Cost.
82
Prior to reforms, there were minimum efforts to scientifically assess the T&D losses that Were often masked
in unmetered (primarily agricultural) consumption. The approaches & Measures taken by SERCs are
different. There is no uniform method for measuring &
Setting targets for T&D losses.
In cost based regulation capital cost is the most important parameter. The SERCs have Carefully studied the
past assets capitalizations to approve CAPEX.
From a regulatory perspective, depreciation is considered as a small amount of the original cost of the
capital assets, built into the tariff computation every year with a view to providing the utility a source of
funding to repay installments of debt capital. The refund of capital view is mainly adopted by SERCs.
Advance against depreciation (AAD) is allowed in certain conditions like where the debt redemption
obligation is not matching with the existing depreciation allowed.
The SERCs differs on the ROCE or ROE approach The ROCE approach is consistent with the performance
based regulations. Normative CoD will not work for all companies in India.
Approved interest on loans is directly related to the loans taken into the Capital Base computations. The
loans drawn for CAPEX and interest thereon are a pass-through in the tariffs.
For the purpose of tariff fixation & identification of cross subsidy the CTS model proves to be an important
tool. The basic objective of the Commission to use the CTS with regard to tariff design in the Tariff Orders
was to build a road map to move towards cost reflective tariffs. The subsidy given by state government
limits SERC from adopting progressive Cost to Serve model. Due to subsidy SERC cannot increase tariff for
subsidized consumers like Domestic & Agricultural.
The State Government gives subsidy to fill the revenue gap for its state utilities. The main reason for giving
subsidy has political & economical background rather than the differentiation expected in electricity Act
2003, National electricity policy & National tariff Policy. The clauses & provisions itself in policy & act
looks contradictory.
In Indian power sector, the expensive peak hours with the cheap off peak hours are sold at one average
price. Electricity prices for the consumers are always been bundled- as per quantity used, but not by when
the electricity is used. TOD tariff is applied to mainly HT industrial & non industrial consumers.
83
An area of concern is that even after a decade of reform is that realistic valuation of losses is still lagging.
Indeed the improvement in feeder metering & DTC metering is significant, the large portion of unmetered
agricultural consumption still makes actual losses unknown. Somehow the estimated unmetered
consumption is masking the distribution losses.
84
RECOMMENDATIONS
PRIVATE INVESTMENT
The essential conditions for encouraging private investment in a sector are that investors should be confident
that they would get adequate returns. This crucially depends in the viability of the distribution sector. In
Electricity Act 2003 emphasis is given to increasing competition and enhancing private sector investment,
yet power sector is not completely conducive for private sector investment. Although some regulations e.g.
Multi Year Tariff and Open Access provide some certainty to investors, yet its proper implementation is
very crucial.
INDEPENDENT FUNCTIONING OF REGULATORY COMMISSIONS
Regulators have been given the key role in reforming the sector. Electricity Act 2003 gives them wide
ranging powers. The functions and powers given to regulators in electricity sector compare favorably with
the best. However, the regulators face the challenge of unfavorable initial conditions. These include the
challenge of dealing with state owned utilities, which have overwhelming presence in generation and
monopoly in distribution and transmission.
In most states these vertically integrated utilities have been unbundled and converted into corporations. But
this has not brought about any change in their management style or incentive system. They continue to
function as administrative bodies that are not responsive to economic incentives and —for them the concept
of cost does not apply. Their concept of rationality involves following procedures (particularly based on
paper work) rather than taking cost benefit based decisions. They also do not consider themselves directly
responsible to the shareholders (i.e. tax payers) nor to the consumers but only to the State Government. In
fact in a number of states the Secretary Department of Power is also the Chairperson of the Power
Corporations. Thus, the role of the government as policy maker and that of the corporation as implementing
agency is devolved in the same person. It is thus not a surprise that the accounts in most cases have not been
finalized nor was the tariff petitions filed on time. Despite the change to corporate structure, the provisions
of company law relating to prudent accounting practices and publication of quarterly accounts and
finalization of balance sheets have been given a miss. The structural reforms as envisaged by the
Government of India and enforced by States do not lead to any substantial change either of the organization
or of the administrative nature of the SEB’s.
85
TIMELINESS OF TARIFF ORDER
All SERCs should issue tariff orders in time so that tariff structure could be improved and approved tariff
could be implemented without delay.
EFFICIENT MANAGEMENT OF FUNDS
The financial institutions that have increased fund flows for generation projects as well as distribution
reform schemes like APDRP and Rajiv Gandhi Grameen Vidyutikaran Yojna have not insisted on funds
releases being conditional or following the company law provisions or principles of good governance. They
are mostly satisfied by the State Governments tendering a guarantee, despite the fact, that over the years,
such guarantees have not ensured timely payment.
LOAD FORECASTING
The sale/demand forecasting should be Time of Day (TOD) based so that peak hour demand, off peak hour
demand & the supply for the respective time can be managed in better ways. Also the methodology adopted
for forecasting should be a standard one, and should not vary through the years.
CAPITAL EXPENDITURE OR INVESTMENT
The capital work proposed by DISCOMs needs to be scrutinized by independent agencies
or consultancies so that the base line data will be corrected, the technical feasibility will be evaluated
correctly & the only useful investment will be done. Also in capital work
execution consultancy expertise needs to be utilized.
DEPRECIATION
It is necessary that all the SERCs should follow same depreciation rate to bring uniform approach for all
tariff orders & DISCOMs.
86
TOD TARIFF
The TOD tariff is based on conservation by price response. TOD tariff is applied to mainly HT industrial &
non industrial consumers. It should be given priority to extend MYT to LT industrial, commercial & high
consumption Residential consumers.However the hourly metering should be cost effective. It should be
implemented in the case of:
o The customer is large electricity user
o The customer’s price responsiveness (elasticity of demand) is high or
o The difference between the hourly prices ( due to short term & ABT ) & the
averaged price is large.
87
REFERENCES
TARIFF ORDERS
Issued by RERC,BERC, MPERC,HERC,PSERC,AERC,DERC, from FY 2011-12 to FY 2013-14.
TARIFF REGULATIONS
Issued by RERC,BERC, MPERC,HERC,PSERC,AERC,DERC, from FY 2011-12 to FY 2013-14.
WEBSITES







www.berc.co.in
www.mperc.gov.in
www.herc.gov.in
www.pserc.nic.in
www.aerc.nic.in
www.derc.gov.in
www.cerc.gov.in
REPORT
TERI, “Analysis & compilation of tariff orders”, TERI report no 2006RP23 May 2007 final report.
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