Discussion Paper 06.3 · Uttar Pradesh Electricity Regulatory Commission Discussion Paper on UPERC (Terms and Conditions of Generation Tariff) Regulations for 2014-19 4 1. Introduction

Discussion Paper on UPERC (Terms and Conditions of Generation Tariff) Regulations for 2014-19

March 2014

Table of Contents

Table of contents

1. Introduction 4

2. MYT Overview 6

3. Financial Principles 9

4. Operational Norms 21

Appendix A. - Comparison of UPERC regulations with CERC Tariff Regulations, 2014 27

Appendix B. - Performance of existing generating stations in the state during last 5 years 36

Uttar Pradesh Electricity Regulatory Commission

Discussion Paper on UPERC (Terms and Conditions of Generation Tariff) Regulations for 2014-19 3

List of Abbreviations

Abbreviation Full form

MW Megawatt

PPA Power Purchase Agreement

GDP Gross Domestic Product

ABT Availability Based Tariff

ROE Return on Equity

O&M Operation and Maintenance

R&M Renovation and Modernization

COD Commercial Operation Date

SCOD Scheduled Commercial Operation Date

ICB International Competitive Bidding

PAT Perform Achieve Trade

IDC Interest during Construction

AAD Advance Against Depreciation

GFA Gross Fixed Asset

NFA Net Fixed Asset

ROI Return on Investment

PLR Prime Lending Rate

WACC Weighted Average Cost of Capital

IWC Interest on Working Capital

GSHR Gross Station Heat Rate

GCV Gross Calorific Value

PLF Plant Load Factor

GoI Government of India

CEA Central Electricity Authority

CERC Central Electricity Regulatory Commission

FOR Forum of Regulators

NAPAF Normative Annual Plant Availability Factor

MYT Multi Year Tariff

PBR Performance based regulations



1. Introduction

Legal and regulatory framework

The Uttar Pradesh Electricity Regulatory Commission (the Commission) has been vested with the functions

under the Section 86 of the Electricity Act, 2003 (the Act) to determine the tariff for generation, supply,

transmission and wheeling of electricity, wholesale, bulk or retail, as the case maybe, within the State. Section

61 of the Act requires the Commission to be guided by the multi year tariff principles while specifying the terms

and conditions for determination of tariff.

“The Appropriate Commission shall, subject to the provisions of this Act, specify the terms and

conditions for the determination of tariff, and in doing so, shall be guided by the following, namely:-

a. The principles and methodologies specified by the Central Commission for

determination of the tariff applicable to generating companies and transmission

licensees;

b. The generation, transmission, distribution and supply of electricity are conducted on

commercial principles;

c. The factors which would encourage competition, efficiency, economical use of the

resources, good performance and optimum investments;

d. Safeguarding of consumers' interest and at the same time, recovery of the cost of

electricity in a reasonable manner;

e. The principles rewarding efficiency in performance;

f. Multi year tariff principles;

g. That the tariff progressively reflects the cost of supply of electricity and also reduces

cross-subsidies in the manner specified by the Appropriate Commission;

h. The promotion of co-generation and generation of electricity from renewable sources

of energy;

i. The National Electricity Policy and tariff policy"

Further, Section 181(2) (zd) of the Act empowers the State Commission to make regulations on the Terms and

Conditions for the determination of tariff under section 61. Section 61(i) of the Act provides that while

specifying the terms and conditions of tariff, the Commission shall be guided by the National Electricity Policy

and Tariff Policy.

UPERC Generation Tariff Regulations

The Commission after enactment of Electricity Act, 2003, issued the Uttar Pradesh Electricity Regulatory

Commission (Terms and Conditions of Generation Tariff) Regulations, 2004 which remained in force for a

period of 3 years from its date of notification on 7th June 2005. The Commission then issued Uttar Pradesh

Electricity Regulatory Commission (Terms and Conditions of Generation Tariff) (First Amendment)

Regulations, 2007 which remained in force from 1st April, 2008 to 31st March 2009. The Uttar Pradesh

Electricity Regulatory Commission (Terms and Conditions of Generation Tariff) Regulations, 2009 (“UPERC

Generation Tariff Regulations, 2009”) came into force with effect from 1st April, 2009 and shall remain in force



up to 31st March, 2014. The UPERC Generation Tariff Regulations, 2009 were amended through the Uttar

Pradesh Electricity Regulatory Commission (Terms and Conditions of Generation Tariff) (First Amendment)

Regulations, 2012 vide notification dated 20th March 2012.

Need for review of Generation Tariff Regulations

In accordance with powers vested with the Commission under the Act and the aforesaid regulations the

Commission has been determining the tariff of the various generating stations covered within its jurisdiction via

a consultative process. The Commission during the control period 2009-14 has noticed areas of improvement

which can be revisited afresh in the existing framework to arrive at a framework which is more reflective of the

current scenario of the sector. Section 61 of the Act further provides that State Electricity Regulatory

Commissions shall be guided by the principles and methodologies specified by the Central Electricity

Regulatory Commission (CERC) for determination of tariff applicable to generating companies. The Central

Commission has published Terms and Conditions of Tariff Regulations for the tariff period 2014-19 (“CERC

Tariff Regulations, 2014”) in February 2014. Thus for the tariff period 2014-19, the existing tariff norms may

have to be reviewed by keeping in view the developments in the sector during the ongoing tariff period, current

and perceived challenges in the power sector and the principles adopted by CERC in fixation of tariff for the

next tariff period 2014-19.

The objective of publication of this discussion paper is to solicit views of all the concerned stakeholders in the

state of Uttar Pradesh on the approach that the Commission plans to adopt with regard to different aspects of

tariff setting during next control period (2014-19). The paper expects to generate a debate amongst the

stakeholders on the various aspect of the tariff framework. This involvement of various stakeholders provides

the element of transparency to the exercise and increases stakeholder participation. The Commission seeks to

enrich its approach and information base through the suggestions received from public.

This discussion paper is divided into 4 sections:

1. SECTION 1: Introduction 2. SECTION 2: MYT Principles 3. SECTION 3: Financial Principles 4. SECTION 4: Operating Norms

The APPENDIX to this discussion paper provides

a. A comparison of the terms and conditions for generation tariff specified by CERC in CERC Tariff Regulations, 2014 and the principles adopted by the Commission in UPERC Generation Tariff Regulations, 2009

b. Performance of the existing generating stations in the state of Uttar Pradesh during the past 5 years



2. MYT Overview

General principles

This discussion paper outlines the framework of Multi Year Tariff (MYT) Principles as the guiding light towards

arriving at Regulations for determination of tariff for the next control period (2014-19). The Commission

through the MYT Regulations aims to meet the following objectives:

• Provide Regulatory Certainty to the investors and consumers by promoting transparency, consistency and predictability of regulatory approaches thereby minimizing perceptions of regulatory risk.

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

• Provide incentivisation framework to reward performance, promote efficiency and competition.

• Address risk sharing mechanism between utility and consumers based on controllable and uncontrollable factors.

Control period

Control Period means a multi-year period fixed by the Commission from time to time typically 3 to 5 years, for

which the principles for determination of ARR shall be fixed. Clause 5.3 (h)(1) of the Tariff Policy stipulates:

"Section 61 of the Act states that the Appropriate Commission, for determining the terms and

conditions for the determination of tariff, shall be guided inter-alia, by multi-year tariff principles.

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

framework should feature a five-year control period. The initial control period may however be of 3

year duration for transmission and distribution if deemed necessary by the Regulatory Commission

on account of data uncertainties and other practical considerations. In cases of lack of reliable data,

the Appropriate Commission may state assumptions in MYT for first control period and a fresh

control period may be started as and when more reliable data becomes available."

The Control Period can be staggered for generation segments of the power sector in Uttar Pradesh, ensuring a

more focused review at the end of Control Period. The proposed option is that for the generation segment the

control period may be kept for a period of 5 years from FY 2014-15 to FY 2018-19.

Multi Year Tariff principles provide a certainty and clarity to the Generating Companies, consumers and other

stakeholders in the state regarding the various principles governing the process of tariff determination in the

state of Uttar Pradesh. It also details out the methodology to be adopted by the Commission in determining the

tariffs of various entities and acts as a roadmap for the planning and growth of the sector in the state.

Performance based regulations

The Commission in line with the objectives of safeguarding consumer interest and to ensure recovery of cost of

electricity in a reasonable manner, adopted the performance based regulation (PBR approach) in previous tariff

periods which essentially takes a long term view of the performance of the Generation Companies. In a regime

following the PBR approach an efficiently operating system leads to higher profits for the Generating

Companies while any poor performance on their part leads to lower profits. FOR Report on “MYT framework

and Distribution Margin” mentions in the context of cost plus vis-à-vis performance based regulations

"6.1.1 Annual revision of performance norms and tariff might not be desirable. During the first

control period, which should not be more than three years, the opening levels of performance

parameters should be specified as close to the actual level of performance as possible and a trajectory



of improvement of norms to desired level be provided with an incentive and disincentive mechanism

to share efficiency gains with consumers."

Under the Availability Based Tariff (ABT), two part tariff structure (fixed + variable cost) is being followed for

generation tariff with incentive and disincentive mechanism. Recovery of fixed charges is based on the

availability of plant while the recovery of variable charges is linked to operational parameters like normative

Gross Station Heat Rate (GSHR), auxiliary consumption etc. The fixed charges have five components namely

Return on Equity (ROE), Interest on Loan, Depreciation, Operation & Maintenance cost, and Interest on

Working Capital. There are incentive/ disincentives built in for over/under achievement of target availability

and normative parameters.

It is important that the basic premise of the performance based approach i.e. improvement in operational

efficiency where good performance should lead to higher profits, while poor performance should lead to lower

profits is kept in mind. Thus under the PBR mechanism the Generating Companies' bottom-lines depends on

how efficiently they plan and operate their systems. At the same time an equitable approach needs to be

adopted towards tariff determination keeping in mind the growth of the sector and the challenges being faced

by the sector.

Financial Norms

The current approach in tariff setting follows a hybrid approach where it is a mix of performance based cost of

service approach by considering actual cost for cost of debt and normative parameters as specified in the

regulations for components like return on equity, operation and maintenance expenses and interest on working

capital. The capital cost of project including interest during construction and financing charges, any gain or loss

on account of foreign exchange rate variation, capitalized initial spares and additional capital expenditure etc.

have been admitted after prudence check.

The normative parameters are expected to induce operational and financial efficiency. While continuing with

the hybrid approach, tariff regulations for the control period 2014-19 may also provide more weightage for

normative parameters to induce efficiency during operation as well as in development phase.

Operational Norms

The operational norms and the methodology to determine such norms should reflect the optimum level of

efficiency during next tariff period.

Process to be followed in the MYT regime

Process to be followed in the beginning of the control period

The MYT framework shall inter alia consist of the parameters within the control of Generation Companies. The

MYT framework shall be finalised considering all the parameters duly specifying targets for these parameters

under the control of the Generation Companies. Some of the critical parameters in the business of Generation

of electricity are as follows:

• Norms of operation and cost of fuel – This is a significant cost component for the Generation Company and depends both on how efficiently fuel is utilized in the generating station and the price of fuel used by the station, the latter being generally beyond the control of the Company.

• Operating Costs – O&M Expenses are considered to be within the control of company, and it is expected to run its operations in an efficient manner with suitable allocation of costs between different heads, based on its individual requirements.



These above mentioned features of a generation company's business provide a useful basis for shaping the MYT

principles. The ARR and tariff for a generation company would be determined for each year of the Control

Period at the beginning of the Control Period, keeping in view the following:

• Based on a detailed examination of the Generation Companies' filings and taking into account the

suggestions and views expressed in public hearings, ARR for Generation Companies, as applicable for the Control Period, shall be determined.

• The targets shall be set for items that are deemed as “controllable” which include operating and maintenance expenditure, financing costs including depreciation pertaining to capital investments for all Generation Companies.

• Any financial loss or gain arising from the performance falling short of the targets in these controllable items may be shared in a pre specified ratio between the Generating Companies and the beneficiaries.

• The Generation Companies shall not bear the burden of items that are considered beyond their control or “uncontrollable”, and the consequent financial gain or loss shall be adjusted in the annual revenue requirement.

• Adequate investments in the business for asset creation, loss reduction, quality improvements and working capital shall be ensured, and the Generation Companies shall be compensated for it.

Process during the Control Period

The Generation Companies shall submit the actual capital expenditure incurred, capitalisation and the

performance of the generating stations during the year to the Commission at the end of each year of the Control

Period. The adjustment in tariff on account of actual capital investment vis-à-vis approved capital investment

may be carried out during the control period and at the end of Control Period.

Process at the end of Control Period

The Commission shall review the effectiveness of the implementation of the MYT principles and the success in

achieving the intended objectives. The Commission shall then seek to suitably modify the procedures and the

methodologies used for the next Control Period, based on the experience of the existing Control Period. The

Commission shall also conduct a comprehensive review and take into account, amongst other things, the sector

reality, consumer and other stakeholder expectations and Generation Companies' requirements at that point in

time.



3. Financial Principles

Capital cost

Power projects are capital intensive in nature and to promote growth in the sector it is important that the

regulators provide for an environment where investors are provided good returns on their investment. Capital

cost is one of the most important components for determination of tariff, and hence returns, available to a

generation company. The capital cost approved by the Commission forms the rate base for determination of

return on investment. Capital cost also includes interest during construction, financing charges and foreign

exchange rate variation up to the date of commercial operation of the project.

During the control period 2004-09, capital cost was determined by CERC based on the actual cost as per the

balance sheet of the regulated entities. For the control period 2009-14, CERC switched over to the methodology

of determination of capital cost based on the projected capital expenditure. In the UPERC Generation Tariff

Regulations, 2009, the Commission prescribed that a provisional tariff in advance of the anticipated date of

completion of a project may be allowed based on the capital expenditure actually incurred up to the date of

making of the application. This enabled the generating companies to file their tariff application prior to

commissioning of the project. The capital cost for the purpose of determination of final tariff is the actual

expenditure incurred by the generation company as on date of commercial operation (COD) duly certified by its

Auditors and after prudence check by the Commission.

For projects which were commissioned prior to the tariff control period, the capital cost admitted by the

Commission during that tariff period is considered and any additional capitalization during the tariff control

period is only allowed after due diligence. Areas for improvement in existing approach for determination of

capital cost include following:

Capital cost for new power plants

1. It has been observed in many cases across the country that the projected capital cost on actual COD has changed drastically owing to numerous reasons such as deferment in commissioning of projects, non placement of orders due to limited vendor responses etc. It was noticed that the objective of faster disposal of petitions by doing away with provisional tariff got defeated due to considerable variations in projected capital cost vis-à-vis actual capital cost as on COD. The Commission also observed that in general more than 90% expenditure on capital cost occurs in the initial years of the project commissioning stage.

2. Efficiency during construction phase is key towards avoiding delays in project commissioning which directly impacts the capital cost and hence the approved tariff for the project. As a result of any delay the capital cost would increase as a result of an increased cost on account of interest during construction (IDC), escalation in prices and increase in establishment charges.

It is important that all the stakeholders realise the importance of bringing in efficiency during construction phase and a provision may be made for normative IDC. The Central Commission in its CERC Tariff Regulations, 2014 has already taken a step in this regard and has introduced the concept of “Scheduled Commercial Operation Date” (SCOD).

The treatment of expenditure on account of delays after the SCOD is attributed to controllable and uncontrollable factors. As per the CERC Tariff Regulations, 2014, the “controllable factors” shall include the following:

• Variations in capital expenditure on account of time and/or cost overruns on account of land acquisition issues;



• Efficiency in the implementation of the project not involving approved change in scope of such project, change in statutory levies or force majeure events; and

• Delay in execution of the project on account of contractor, supplier or agency of the generating company.

The “uncontrollable factors” shall include the following:

• Force Majeure events, such as acts of war, fire, natural calamities, etc.; and

• Change in law.

The Central Commission through its CERC Tariff Regulations, 2014 has emphasized that there is a need to ensure that any delays as a result of controllable parameters are not passed onto the beneficiaries. The Central Commission has also stated that in case of non-commissioning of a generating station on the SCOD, the generating company shall bear the IDC or transmission charges if the transmission system is declared under commercial operation by the Commission.

3. In the area of project execution to ensure competitiveness of prices there is a need for introducing mandatory International Competitive Bidding (ICB) for main plant packages/ major packages and competitive bidding for remaining packages to ensure competitiveness of prices. In case of a single bidder, it would be difficult to consider the discovered cost as efficient cost due to lack of competition.

4. The commissioning of the generating stations and their commercial operation, is declared after successful completion of the trial operation/run. It is being felt that there is a need to specify a methodology of trial operation for generating station as in some cases, non availability of evacuation system has delayed the trial operation and commissioning of the plants.

There is also an issue of the mismatch between the commercial operation of a generating station and the associated transmission systems which needs to be addressed as it has an impact on the COD as well as IDC of the generating station. For the benefit of the consumers no additional impact of time overrun or cost overrun should ideally be allowed on account of non-commissioning of the generating station or associated transmission system by scheduled COD, as the same should be recovered through Indemnification Agreement between the generating company and the transmission licensee

5. The benchmark capital cost, as notified by the Central Commission, for coal based thermal generation is being used as a guiding parameter for allowing capital cost during 2009-14 period. The benchmark capital cost may be used as normative capital cost to induce efficiency in procurement of plant & machinery and timely development of project. The benchmark capital cost needs periodical review as it varies over a period of time due to escalation in prices, technological improvement and market competition etc.

Additional capitalisation/ de-capitalisation

1. Any addition at the fag end of the project life has a significant impact on its tariff as also the depreciation will have to be considered in the balance life of the plant. Any such expenditure is only justified if it results in a reasonable extension of the project life. Thus such a situation warrants a relook at the current useful life so that any investment during the fag end is justified.

2. Also there is a need to address the additional expenditure incurred by the generators to meet targets mandated under the Perform, Achieve & Trade (PAT) scheme.

3. The UPERC Generation Tariff Regulations, 2009 also provide for compensation allowance for the coal based stations depending upon years of operation for meeting any expenditure of capital nature. The efficacy of continuation of the same needs to be reviewed. Also there needs to be a discussion amongst the stakeholders on the necessity for extending a similar allowance to hydro projects in Uttar Pradesh.



Key discussion points

Renovation & Modernisation

There is shortage of power generation capacity in the country which makes it necessary to improve the current

generation supply and its reliability. Renovation and modernization schemes increase the generation capacity

of existing stations. Thus these schemes of current generating stations should be encouraged in public interest

and supported with recovery of cost incurred for improvement in plant load factor, reduction in fuel cost and

extension in useful life of the plant.

The Commission in UPERC Generation Tariff Regulations, 2009 made a separate provision for making

application by the generating company for meeting expenditure on renovation & modernisation (R&M) for the

purpose of extension of useful life of the generating station or a unit thereof along with a Detailed Project

Report giving complete scope, justification, cost-benefit analysis, estimated life extension from a reference date,

financial package, phasing of expenditure, schedule of completion, reference price level, estimated completion

cost including foreign exchange component, if any, record of consultation with beneficiaries and any other

information considered to be relevant by the generating company. The Commission has noticed that the R&M

proposals of the state generating companies were made without any clear cost benefit analysis or estimates of

extension in life of generating stations.

Servicing of R&M expenditure towards the fag end is an issue given the impact on depreciation schedule and

tariff to beneficiaries. There may, therefore, be a need to specify a period over which any R&M expenditure with

In view of the above, the stakeholders may furnish their comments and suggestions on the following:

a. Should provisional tariff for new power plants be computed based on projected capital expenditure or should tariff be approved on the basis of actual capital expenditure incurred by the Generating Companies as per their audited balance sheet upto the time of filing of the petition?

b. Is there a need to relook at the existing provision based on experience of considerable delays resulting into higher IDC on actual basis? Should IDC for equity infusion above desired level be allowed till the date of capitalization (COD) along with actual IDC in case of allowance of time over run or should such IDC be capped up to scheduled construction time period decided upfront?

c. Whether to make ICB mandatory for the procurement of main plant packages/ major packages and competitive bidding for the other packages to ensure competitiveness of prices?

d. Suggestions/comments on the existing methodology followed for the trial operation of generating station. Furnish alternative methodologies followed by State generating stations, Central generating stations and others, if any. Suggestions on addressing the issue of trial operation and commissioning of the project when a generating station is ready but cannot be operated due to non availability of load or evacuation system.

e. Suggestions on the treatment of various controllable and uncontrollable factors for arriving at their subsequent impact on the capital expenditure of the project and the sharing of gains and losses on account of these factors.

f. Suggestions to deal with capital expenditures made by generator to achieve targets of the efficiency improvement under the Perform, Achieve & Trade (PAT) scheme. Comments on type of expenditure to be considered as necessary for successful operation and efficient operation in case of hydro projects.

g. Suggestions/comments are invited on aspects to be covered in truing up of capital cost.



or without life extension or any additional capital expenditure at the fag end of useful life be provided to be

serviced over a period of 15-20 years.

An alternative provision was also made in the UPERC Generation Tariff Regulations, 2009 in the form of

special allowance to be allowed in lieu of R&M for coal based thermal power stations. This provision enabled

generating companies to meet the requirement of expenses including R&M on completion of 25 years of useful

life to a unit /station without any need for seeking for resetting of capital base. The Central Commission in the

CERC Tariff Regulations, 2014 has increased the compensation allowance to Rs 7.5 lakhs/MW (for FY 2014-15).

Key discussion point

Depreciation

Depreciation is a major component of annual fixed cost. The concept of depreciation and the associated rate has

been a subject of debate. There have been suggestions of linking depreciation to creation of a reserve fund for

replacement of assets versus the linking of depreciation to cash flow for repayment of loans taken by the

generation company. It is accepted in regulatory regime that the depreciation represents service to capital

subscribed and is normally considered a cash flow available for repayment of loan. The clause 5(c) of the Tariff

Policy stipulates that

"The Central Commission may notify the rates of depreciation in respect of generation and

transmission assets. The depreciation rates so notified would also be applicable for distribution with

appropriate modification as may be evolved by the Forum of Regulators."

The rates of depreciation so notified would be applicable for the purpose of tariffs as well as

accounting.

There should be no need for any advance against depreciation.

Benefit of reduced tariff after the assets have been fully depreciated should remain available to the

consumers. "

The Para 5.8.2 of the National Electricity Policy, provides that

“depreciation reserve is created so as to fully meet the debt service obligation.”

This regulatory meaning of depreciation has gained precedence in tariff setting approach. Accordingly, the

Central Commission, in CERC Tariff Regulations, 2009, prescribed that there should be enough cash flow

available to the generating companies to meet the repayment obligations during first 12 years of operation,

which is the average tenure of loans available to power generation companies. The depreciation rates were set at

an average rate of 5.28% accordingly. The provision of Advance Against Depreciation (AAD) was dispensed with

in line with Tariff Policy, 2006 and fair life got delinked at least for first 12 years of operation, while setting the

depreciation rates.

In the previous tariff periods, the Commission has been allowing depreciation at an average rate of 3.60% for

thermal power plants and 2.57% for hydro power plants along with the provision of Advance Against

Depreciation (AAD) for meeting repayment obligations of the generators. Thus the key areas of discussion

regarding depreciation are as follows:

In light of this discussion, comments/suggestion are solicited on whether there is a need to address the above issues & review the provision relating to Renovation & Modernisation and Special allowance to make it more responsive to the requirement of generating stations?



1. Whether, in line with the approach followed by CERC, the depreciation rates should be linked with debt

service obligation of the generators considering a repayment period of 12 years or should the existing

practice of allowing a lower depreciation rate along with AAD be continued.

2. While combining assets or units, the treatment of weighted average life may have a mismatch in respect

of completion of 12 years of each individual units or assets. Similarly, there will be a mismatch at the

end of completion of useful life of combined units vis-à-vis individual units. Since useful life is linked

with depreciation after 12 years, there will be a consequential impact on recovery of depreciation. In

view of point (2), the need for re-assessment of useful life for treatment of additions during fag end of

life has been recognized. The re-assessment of useful life is also been supported by Accounting

Standard-6. It is perceived that extension by way of re-assessment of useful life will provide certainty to

distribution licensee for getting supply beyond useful life and consumers will be benefited by availing

supply of electricity at lower cost.

3. The treatment of depreciation on account of additional capital expenditure at the fag end of life and

also the Special allowance approved in lieu of renovation and modernisation as the same have

consequential impact on the tariff due to recovery of depreciation over balance useful life.

Similarly, the additional capital expenditure after allowing the Special allowance has an impact on

recovery of depreciation. As more assets of regulated entities are approaching towards completion of

useful life, this issue requires attention. The need is felt that pre-specified useful life could be revised

and extended after re-assessment of useful life for spread of balance depreciation.

Key issues for discussion

In view of the above discussion the stakeholders may furnish their comments and suggestions on

the following:

a. Should the Commission allow depreciation rates as prescribed by CERC and the concept of

AAD be dispensed with?

b. Whether the treatment of weighted average useful life in case of combination, due to gradual

commissioning of units, shall continue or alternatives if any ?. Can additional expenditure

during fag end of life be considered for the re-assessment of useful life? Can additional

expenditure after Renovation and modernization (or special allowance) be restricted to

limited items/equipments? Can a regulatory method be derived wherein life gets reassessed at

the start of every tariff period or every additional capital expenditure through a provision in

the same way it is prescribed in accounting standard?

c. In case of re-assessment of useful life, can depreciation be charged over the balance life of the

assets along with the original written down value up to 90% value OR add cap and original

amount depreciate over revised/reassessed useful life of asset. ?



Net Fixed Asset v/s Gross Fixed Asset Approach

The Gross Fixed Assets approach creates internal resources for capacity replacement/addition through return

on equity base of 30% (normative equity) even though the assets are written off up to 10% (salvage value). The

interest on loan is computed duly taking into account the loan repayment equivalent to the depreciation and

considering weighted average rate of interest calculated on the basis of the actual loan portfolio at the beginning

of each year applicable to the project. Under the Net Fixed Assets approach the entire capital base including

debt and equity is depreciated. The return on equity available to the Generation Company is only allowed upto

the time the equity investment has not been recovered through the depreciation allowed to the generator.

Key points for discussion

Debt/Equity Ratio

Debt: Equity ratio is the most important factor for the promoters as it has an impact on return on investment.

The financing pattern which is usually allowed on normative basis as 70:30 (debt: equity). The provision 5.3(b)

of the tariff policy stipulates that

"For financing of future capital cost of projects, a Debt: Equity ratio of 70:30 should be adopted.

Promoters would be free to have higher quantum of equity investments. The equity in excess of this

norm should be treated as loans advanced at the weighted average rate of interest and for a weighted

average tenor of the long term debt component of the project after ascertaining the reasonableness of

the interest rates and taking into account the effect of debt restructuring done, if any. In case of equity

below the normative level, the actual equity would be used for determination of Return on Equity in

tariff computations."


The suggestions of stakeholders are invited on whether there is a need to revisit the existing approach

for debt: equity ratio or to continue with the existing composition?

The comments of stakeholders are invited on following issues :

a. Should the Commission follow the NFA model where NFA is arrived at by deducting the

accumulated depreciation from the Gross Capital Cost admitted for tariff purposes ?

b. Or should the Commission follow a modified GFA approach where gross capital may be divided

in the ratio of loans and equity and the loan amount may be reduced to the extent of depreciation

accrued. Once the loan amount is fully repaid and reduced to zero, further depreciation would be

allowed to reduce the equity component.



Return on Equity (RoE)

To provide returns on investments made by Generating Companies and to incentivise capacity addition in the

sector providing a sound return on equity is important. In this context, the Tariff Policy stipulates:

"a) Return on Investment

Balance needs to be maintained between the interests of consumers and the need for investments

while laying down rate of return. Return should attract investments at par with, if not in preference

to, other sectors so that the electricity sector is able to create adequate capacity. The rate of return

should be such that it allows generation of reasonable surplus for growth of the sector."

The following aspects can be taken into account while specifying Return on Equity (ROE):

1. It is noticed that power market has grown up substantially after enactment of the Electricity Act, 2003

hence; the risk premium to be built in ROE would then be further discounted. The cost plus tariff

regime would protect regulated entity from market risk as it is pass through in regulated regime. The

discounting of risk premium for arriving at the norm for ROE could be justified in cost plus regime.

While taking a view on risk premium for specifying the level of ROE, it is important to look at the

project risks and market risks involved in cost plus regime.

2. CERC in its Explanatory Memorandum to the draft CERC Tariff Regulations, 2014 has deliberated

upon the use of scientific models for determining return on equity and has stated that it does not favour

the calculation of RoE by use of scientific models at present. The Commission has stated in the

Explanatory Memorandum as under:

"The rate of return on equity can be fixed by using scientific models like dividend growth model,

price/earning ratio, capital asset pricing model, risk premium model, etc. However, the

limitation of using any of these scientific models is the availability of sufficient volume of

historical data. Thus, scientific method of determining cost of equity is still not practicable, as

adequate number of entities operating in the power sector have not entered the primary market

for providing a decent representative sample of the companies operating in the power sector.

Accordingly the Commission does not favour determination of the cost of equity using any of the

scientific models."

3. Further, the Central Commission in its CERC Tariff Regulations, 2014, has proposed to continue with

the existing base rate of return on equity of 15.50% with the additional 0.5% return on equity for timely

completion of projects. It is noted that the Commission had allowed ROE at a base rate of 15.50% in

UPERC Generation Tariff Regulations, 2009 for entire tariff period in line with the ROE provided by

CERC in its CERC Tariff Regulations, 2009.

4. It is to be noted that the Commission in UPERC Generation Tariff Regulations, 2009 had allowed tax

on actual basis limited to tax on return on equity while the Central Commission in CERC Tariff

Regulations, 2014, has continued with the pre-tax approach for calculation of RoE.

5. The Central Commission in the CERC Tariff Regulations, 2014 has also incorporated a provision of

reduction of 1% in the rate of return on equity in case generation station declares COD without

commissioning of RGMO/FGMO, data telemetry and communication system to respective load

dispatch centre, and protection system.



In view of above, fresh look is required on following issues on which comments/suggestions of

stakeholders are solicited:

a. Can we continue the existing method of working out cost of debt by considering weighted

average rate of interest, calculated on the basis of actual loan, actual interest rate and

scheduled loan repayment, or switchover to normative cost of debt calculated on the basis of

present debt market condition? What should be the criteria for working out normative cost of

debt?

b. How can we address the variation of cost of debt among different rating Companies? Can

allowable cost of debt be linked to a benchmark yield on comparable bonds or Government

securities? Can ceiling be specified linking with benchmark yield? Any other alternatives.


Cost of Debt

In UPERC Generation Tariff Regulations, 2009 interest on loan is pass through and is computed by considering

weighted average rate of interest on the basis of actual loan, actual interest rate and scheduled loan repayment.

The recent development of financial market/ debt market contemplates changes in following area:

1. As of now, debt market is gradually structuring and foreign debt market is becoming accessible to the

Indian companies. The rising cost of domestic borrowing as seen presently could lead to an increase in

demand for External Commercial Borrowings (ECBs) amongst Indian Companies; however, there are

several constraints like limit on borrowing, shorter tenures of up to 5 years, high hedging costs,

exposure to foreign exchange risks etc. Keeping in view of the limitation on ECBs, the existing

mechanism of encouraging developer for reduction of cost of debt through swapping, hedging is to be

examined.

2. It is being felt that allowable cost of debt may be linked to a benchmark yield on comparable bonds or

normative debt for achieving financial efficiency. The possibility of normative cost of debt or

benchmarking of debt is to be examined. Alternately, the ceiling for cost of debt may also require to be

examined as the cost of debt varies depending upon credit rating and financial condition of project

developer.


The suggestions/comments of stakeholders are invited on

a. Comments are invited on issues relating to the return on equity to be allowed to generating stations in the state during the next control period.

b. Should the Commission follow the approach of the Central Commission where storage type generating stations including pumped storage hydro stations and run of river generating station with pondage are provided an additional return of 1%.

c. Is there a need to deliberate the inclusion of the provision of reducing return on equity by 1% in case the generating station declares COD without commissioning of RGMO/FGMO, data telemetry and communication system to respective load dispatch centre



Truing Up

The Commission presently allows for a truing up of capital expenditure along with the tariff petition filed for the

next tariff period. The Central Commission in the CERC Tariff Regulations, 2014 stated that it shall carry out

truing up of tariff of generating station based on the performance of the station on following controllable

parameters:

1. Gross Station Heat Rate

2. Secondary Fuel Oil Consumption

3. Auxiliary Energy Consumption

4. Re-financing of Loan

The net gain as a result of the controllable parameters will be calculated as per the following formula

Net Gain = (ECRN – ECRA) x Scheduled Generation

where ECRN – Normative Energy Charge Rate computed on the basis of norms specified for Gross Station Heat

Rate, Auxiliary Consumption and Secondary Fuel Oil Consumption.

ECRA – Actual Energy Charge Rate computed on the basis of actual SHR, Auxiliary Consumption and

Secondary Fuel Oil Consumption for the month.

The Central Commission has stated that the financial gains to a generating company on account of controllable

parameters shall be shared between generating company and the beneficiaries, in the ratio of 60:40.


Interest on Working Capital (IWC)

The working capital is separately specified by Commission for coal-fired thermal generating station, open-cycle

/combined cycle gas generating stations and hydro generating stations. The working capital is determined

based on fuel stock, inventory of maintenance spares, operation and maintenance cost and receivables

depending on type of thermal generating station and hydro projects.

The following areas are identified for discussion/consideration by stakeholders:

1. Stock of fuel considered for working capital in respect of various type of generating stations requires

fresh deliberations. The actual fuel stock is required to be examined while determining working capital

or some benchmark need to be fixed. The Central Commission has allowed fuel stock of 15 days for pit

head generating stations and 30 days for non pit head generating stations corresponding to the

normative annual plant availability factor.

a. Whether the existing principle of only truing up the capital expenditure should be continued or is there a need to take a relook at the current methodology and also allow truing up on account of change in performance parameters? Should there be a mechanism for truing up of O&M expenses?

b. Additionally what should be the frequency for truing up of controllable factors? Also suggestions are invited on the methodology for sharing of gains/losses on account of truing up with the beneficiaries?



2. The resources created from return and depreciation are used as internal resources for capacity addition

programmes and hence, is not available for meeting working capital requirements. This position led to

conclusion that the short-term funding has to be obtained from banking institutions for which interest

liability has to be borne by the regulated entity.

Therefore, IWC based on the cash credit was followed during previous tariff period. It was observed

that tariff recoverable includes returns and depreciation which are not cash expenses, and the

additional recoveries would provide enough funds to meet the working capital requirements for

operation.

3. In respect of working capital allowed for maintenance spares, it is to be examined from the view point

that O&M expenses also covers maintenance spares expenditure. It is to be deliberated whether the 15%

maintenance spares should be made as part of working capital or O&M expenses in the existing

methodology.


Tariff for co-generating stations using coal for

generation during off peak season

The Commission had via UPERC (Terms and Conditions of Tariff) (First Amendment) Regulation, 2012

provided for a methodology for tariff determination in respect of 50% generation of co-generating plants

generating electricity via coal during off - season supplying to the state distribution companies. The tariff

determined was on the basis of actual cost incurred by the co generating stations via separate orders and as per

the terms and conditions of their supply agreements. The Commission has observed that during fag end of the

current control period none of the co-generating plants have made use of this provision.


Operation and Maintenance Cost

The Commission has notified normative cost of O&M for thermal and hydro generating stations in the UPERC

Generation Tariff Regulations, 2009. The expansion of capacity and use of latest technology is expected to

reduce O&M cost. However O&M expenses of generating stations have increased significantly owing to the high

The following issues have emerged for considerations on which stakeholders comments/suggestions

are solicited:

a. Whether amount and stock of fuel oil/O&M expenses/maintenance spares/receivables specified in

the existing regulations should continue or, any change is required? Whether O&M expenses should

form a part of the working capital as per the existing methodology?

b. In this regard it is to be deliberated whether the Depreciation and Return of equity should be

considered as part of annual fixed costs while working out two months receivable for working

capital as no working capital is required to fund the depreciation and return on equity.

Commission wishes to invite comments from stakeholders on whether there is a need for continuing this

provision in the next control period.



inflationary trends in the economy. These factors call for the review of normative O&M cost. The Commission

feels that there is a need to engage in a debate on the norms for O&M from the following angles:

1. The fixed escalation rate does not capture the variation due to unexpected expenses on account of wage

revision, increase of water charges etc. Does the approach involving the use of a fixed escalation rate,

for arriving year on year O&M cost require any change.

2. In respect of generation by hydro, although each hydro plant is different based on the location, type of

plant, mode of operation, siltation, hydrological aspects, there is still a need for bringing cost of O&M of

a hydro station on normative basis as in case of thermal station. In this context, the existing

methodology of allowing O&M as a percentage of capital cost in new hydro stations and based on the

previous year's actual O&M expenses for existing stations needs to be reviewed.


Stabilisation period

The Commission in UPERC Generation Tariff Regulations, 2009 in relation to a unit identified the stabilisation

period as a) 180 days from the COD for a coal based generating station b) 90 days from the COD for a gas based

generating station. In the Uttar Pradesh Electricity Regulatory Commission (Terms and Conditions of

Generation Tariff) (First Amendment) Regulations, 2012 the Commission has not provided for norms for GSHR

during stabilization period for all units except 200/210/250/300 MW and 500 MW units. Also, CEA in its

advice to the Central Commission on "Norms of operation for the tariff period 2009-14" had stated that:

"The present norms provide for stabilization period of 180 days for coal/lignite fired units. As the

commissioning procedures have been significantly improved and very high PLF are being sought by

the utilities to be demonstrated during the trial operation by the suppliers, there appears to be no

need of such a stabilization period. Further, the CERC tariff notification of 2004 also stipulated that

the stabilization period and relaxed norms applicable during the stabilization period shall cease to

apply from 1.4.2006. In view of the above the provision of stabilization period existing in the present

norms may be withdrawn and the usual norms be made applicable from the date of commissioning

(completion of trial operation) of the unit."

In view of the above, the stakeholders may furnish their comments and suggestions on the following:

a. Comments on adequacy of the existing O&M norms with regard to the O&M requirement and

resultant cash flows. Whether to review the existing O&M norms?

b. Comments on the requirement of mid-term review of normative O&M cost. How to deal with

variations in O&M cost during the tariff period? Is there a need for introduction of truing up after

specifying normative parameters?

c. Efficacy of the method of determining O&M cost based on the percentage of Capital Expenditure for

new hydro projects. Alternatives to develop O&M Cost norms for the Hydro generating stations?

Should O&M expenses for new hydro power stations be graded with the size of the power stations

i.e. the level of O&M expenses allowed/ MW be different for power stations of lower and higher

capacities.

d. Treatment of income from other business and other income like interest on deposits, advances etc.

while arriving at the O&M cost? Suggestion on treatment of license fees, taxes and duties.




Comments/suggestions are invited from stakeholders regarding the need for stabilisation period in view

of the CEA's advice and provisions of CERC Tariff Regulations 2014.



4. Operational Norms

Approach for Operational Norms

The target value for various operational parameters namely Availability, Plant Load Factor (PLF), Gross Station

Heat Rate, Auxiliary Consumption, Specific Fuel Oil Consumption etc. are specified by the Commission in its

tariff regulations. The Tariff Policy, 2006 has set a principle for specifying operational norms. Clause 5.3 (f) of

the Tariff Policy stipulates that:

"Suitable performance norms of operations together with incentives and disincentives would need be

evolved along with appropriate arrangement for sharing the gains of efficient operations with the

consumers. Except for the cases referred to in para 5.3 (h)(2), the operating parameters in tariffs

should be at “normative levels” only and not at “lower of normative and actuals”. This is essential to

encourage better operating performance. The norms should be efficient, relatable to past

performance, capable of achievement and progressively reflecting increased efficiencies and may also

take into consideration the latest technological advancements, fuel, vintage of equipments, nature of

operations, level of service to be provided to consumers etc. Continued and proven inefficiency must

be controlled and penalized.

The Central Commission would, in consultation with the Central Electricity Authority, notify

operating norms from time to time for generation and transmission. The SERC would adopt these

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

SERCs may fix relaxed norms suitably and draw a transition path over the time for achieving the

norms notified by the Central Commission"

In line with the principle stated in the Tariff Policy the Commission had taken cue from recommendations of

the Central Commission while specifying norms for Generating Stations for the previous control period. In

addition the norms of operation for the existing power stations also were based on historical data analysis and

consideration of efficiencies, technological advantage, vintage etc.

Operational Norms for thermal power generating

stations

Gross Station Heat Rate

Along with the price and gross calorific value (GCV) of the fuel, Gross Station Heat rate (SHR) has an important

impact on computation of energy charges. In the UPERC Generation Tariff Regulations, 2009-14 norms for

GSHR were prescribed for existing power plants based on performance of the plants during 2004-05 to 2007-

08. Norms for GSHR for new power stations were prescribed in line with the norms approved by the Central

Commission. The actual performance of the stations vis-à-vis the prescribed norm is given in Appendix B.


The following issues have emerged for which comments are sought from the different stakeholders

a. Whether the existing norms of gross station heat rate are required to be strengthened? Alternative

methodology for arriving at revised norms, if any, and present level of station heat rate based on

the technological improvement that may also be specified.

b. What are the important criteria to be considered while specifying norms for gross station heat rate?



Secondary Fuel Oil Consumption

The existing norm for the Secondary Fuel Oil Consumption is 1.0 ml/kWh for coal based projects commissioned

on or after 1.4.09 and 2.0 ml/kWh for projects commissioned before 1.4.09. This is in addition to the relaxed

norms specified for some generating stations. The actual performance of the stations vis-à-vis the prescribed

norm is given in Appendix B.


Auxiliary Energy Consumption

The existing norms of auxiliary consumption for coal based generating stations vary from 6.0% (for unit size of

500 MW and above) to 9.0% (for 200 MW series units with steam driven boiler feed pumps and electrically

driven boiler feed pumps). The Commission had also specified relaxed norms for certain existing generating

stations. The actual performance of the stations vis-à-vis the prescribed norm is given in Appendix B.


Target Availability for recovery of full Capacity (Fixed) charges

In control period 2009-14, the target availability was kept at 85% for generating stations commissioned on or

after 1.4.09 and 80% for generating stations existing on or before 31.3.09. The Commission had also specified

relaxed norms for certain existing generating stations. The actual performance of the stations vis-à-vis the

prescribed norm is given in Appendix B.

Now with the increase of private participation, access to imported fuel by private developer and technological

improvement may have improved the availability. However, on the other hand the recent shortage of domestic

fuel has affected availability of the plants and their scheduling in case of shortage of fuel. The availability may

also be linked to availability of coal under the FSA as it may lead to a dispute amongst different parties on the

a. In view of the above, the stakeholders are requested to share their experiences to assess if there is

scope for improvement in the norms for auxiliary consumption.

b. Further, the norm for 45 MW/ 250 MW/ 660 MW units may have to be specified separately for

which suggestions/comments are invited along with authentic support data available, if any.

c. Comments on operating parameters for small capacity CFBC technology based thermal power

plants are also invited.

In view of the above, stakeholders are requested to share their experiences with the supporting data to

assess if there is a scope for revision of the existing norms of secondary fuel oil consumption.

c. The need for continuation of relaxed norms for specific stations? Changes required in the existing

norms given in UPERC Generation Tariff Regulations 2009 may be commented duly supported with

authentic data if any.

d. The need for examining the impact of use of imported coal on the gross station heat rate of

generation plants.



In view of the above, comments/suggestions are invited from the stakeholders regarding any need for

revision of the above norms.

point of availability which remained unutilized on account of fuel shortage. The existing norm for availability

may therefore needs to be revisited with fresh look. In the event of bridging gap through e-auction or imported

coal (other than fuel arrangement agreed in purchase agreement), the need of prior consent, maximum

permissible limit of blending etc. also need to be deliberated. The issues of treatment of availability and fixed

charges, if the consent is not given by beneficiaries, are to be considered in the context of normative availability

for recovery of full fixed charges.


Target Plant Load Factor for Incentive

The Commission in UPERC Generation Tariff Regulations, 2009 has specified Target Plant Load Factor for

providing incentive to generating stations for higher generation. In control period 2009-14, the target PLF was

kept at 85% for generating stations commissioned on or after 1.4.09 and 80% for generating stations existing on

or before 31.3.09. The Commission had also specified relaxed norms for certain existing generating stations.

The actual performance of the stations vis-à-vis the prescribed norm is given in Appendix B.

Transit & Handling losses

The Commission in UPERC Generation Tariff Regulations, 2009 has specified a norm of 0.2% for transit losses

in case of pit head stations and 0.8% in case of non- pithead stations in line with the norm prescribed by CERC.

The same may have to be reviewed based on the past data in this regard.

Operating Norms for hydro power generating stations

The existing operational norms for hydro power generating stations include norms for normative capacity

index, auxiliary consumption, and transformation losses. Capacity Index as a measure of plant availability was

implemented by the Commission in continuation with the approach followed by it during previous tariff

periods. The norms of auxiliary power consumption of hydro generating stations vary from 0.7% to 1.2% (based

on the technical configuration of the plants). The transformation losses from generation voltage to transmission

voltage equivalent to 0.5% of energy generated were also allowed.


Suggestion/comments of stakeholder are solicited with supporting data to review existing norms of

transit & handling losses

In view of the above, stakeholders are requested to share their experiences with the supporting data to

assess if there is a scope for revision of the existing norms.

Whether the existing norms of annual plant availability should be reviewed for thermal generating

stations? What should be the treatment of normative availability in the event of fuel shortages and of

procuring alternative fuel in case of shortage condition?



Incentive

1. The UPERC Generation Tariff Regulations, 2009 provide for incentive to all thermal power stations (except certain plants), at 25 paise per kWh for energy corresponding to scheduled generation in excess of energy corresponding to target plant load factor.

2. In case of hydro generating stations, during 2009-14 incentive was linked to the capacity charges and capacity index in accordance with the following formula:

Incentive = 0.65 x Annual Fixed Charge x (CIA – CIN)/100

(If incentive is negative, it shall be set to zero.)

Where, CIA is the Capacity Index achieved and CIN is the normative capacity index whose values are

90% for purely run of the river hydro stations and 85% for pondage/storage type hydro generating

stations.

3. In the UPERC Generation Tariff Regulations, 2009 generating companies are eligible for an incentive equivalent to reduction of interest during construction (IDC) as a result of commissioning of the plant/unit ahead of schedule. The Commission has also provided for an additional return on equity of 0.5% for in case of timely commissioning of projects in absence of any provision made in the PPA.

4. At present there is same incentive for availability during peak and off peak period. There may be need for introducing differential incentive during peak and off peak periods. On the same consideration higher incentive may be provided to storage and pondage type hydro generating station providing peaking support.


Additional Issues

Availability of Domestic Fuel

The shortage of fuel (Coal and Gas) has a potential to make existing operational capacity remaining stranded.

The Coal India Ltd. has not been able to supply committed quantity of coal as per Fuel Supply Agreement. The

uncertainty with respect to gas supply also continues. In the above circumstances, the generating stations are

Based on above, comments of stakeholders are solicited on following:

a. Should incentive of old and new stations be at same level or differentiated based on vintage?

b. Suggestions are invited on differential incentive for off peak and peak period for thermal and

hydro generating stations. Similarly, comments for differential incentive mechanism for storage

and pondage type hydro generating stations.

c. Should the incentive continue at the current levels or is there a need to take a fresh look at the

incentive available to generating stations?

d. Comments/suggestions are invited from the stakeholders on the need for abolishing additional

incentive amount equivalent to interest during construction keeping in mind the double

incentivisation that would result because of an additional 0.5% ROE.



either forced to procure fuel from spot market (in case of gas and coal) or to procure imported coal at higher

prices.

Consequential Impact

The adoption of this alternate route of procuring fuel leads to a situation in which the generating stations have

to use blended coal to overcome the shortfall in coal through Fuel Supply Agreements. The electricity

generation from blended coal may not be able to get dispatch schedule due to higher prices of imported

coal/gas leading to consequential impact on generation.

If the power plant is heavily relying on this alternative route of fuel procurement, the energy charges will

increase and may not be controllable. On the contrary, the beneficiaries may seek generating station to obtain

their consent prior to procuring costlier fuel. In case the consent is not given by beneficiaries, the generating

companies may not be able to recover capacity charges and may not be able to meet debt service obligations.

If the power plants heavily rely on imported coal, one may argue that blending ratio adopted by generator may

not be commensurate with actual shortage and generator may use higher quantity of imported coal to cover up

inefficiency in procurement of domestic or cheaper coal. It may also be argued that pass-through of actual fuel

charge as per the Tariff Regulations may not enforce the generating companies to achieve efficiency in fuel

procurement in terms of price and quality.

Another area of concern is difficulty in verification of GCV of blended coal, due to unavailability of separate

value of GCV of domestic and imported coal as received. It may therefore, be necessary to provide for payment

of energy charges based on as received GCV of domestic and imported coal.

Further, as alternative, the normative / agreed blending ratio may be decided in advance in consultation with

the beneficiaries in due consideration of technical limitation of steam generator. The blending ratio in the

domestic coal based plants varies depending upon the quality of design coal, the quality of actual coal being

received, age of plant, unit loading etc. The beneficiary may be scheduled to the availability corresponding to

the extent of normative /agreed blending ratio and the beneficiaries not desirous of blending may not be

scheduled, for the power in excess of availability of domestic coal. However, the scheduling and payment of

incentives would need to be debated.

The Central Commission in CERC Tariff Regulations, 2014 has further stated that in case of the energy charge

rate based on weighted average price of use of fuel including alternative source of fuel exceeds 30% of base

energy charge rate as approved by the Commission for that year or energy charge rate based on weighted

average price of use of fuel including alternative sources of fuel exceeds 20% of energy charge rate based on

based on weighted average fuel price for the previous month, whichever is lower shall be considered and in that

event, prior consultation with beneficiary shall be made not later than three days in advance. The Central

Commission has further stated that

" Provided further that copies of the bills and details of parameters of GCV and price of fuel i.e.

domestic coal, imported coal, e-auction coal, lignite, natural gas, RLNG, liquid fuel etc., details of

blending ratio of the imported coal with domestic coal, proportion of e-auction coal shall also be

displayed on the website of the generating company. The details should be available on its website on

monthly basis for a period of three months."




The following issues have emerged on which comments/suggestions of stakeholders are solicited:

a. Should normative or agreed blending ratio be specified for the existing plants and new plants separately in consultation with the beneficiaries? What should be the methodology to work out normative/agreed blending ratio for existing and new projects?

b. Is it necessary and practical to take prior consent of beneficiaries for blending the imported coal with domestic coal?

c. How to ensure procurement of fuel by the generator namely e-auction coal or imported coal, at reasonable and competitive prices. Should there be need to seek explanation for any variation beyond a pre-specified indexation.

d. Any other suggestions/ measures for addressing above issues.



Appendix A. - Comparison of UPERC regulations with CERC Tariff Regulations, 2014

Financial principles

Capital Cost

The comparative evaluation of different norms for capital cost between the CERC Tariff Regulations, 2014 and

the UPERC Generation Tariff Regulations, 2009 is as follows:

Norms CERC Tariff Regulations, 2014 UPERC Generation Tariff

Regulations, 2009

Interest during construction (IDC), Incidental Expenditure during Construction (IEDC)

IDC to be computed corresponding to loan from date of infusion of fund / financial closure after taking into account prudent phasing of funds up to SCOD

IEDC computed from zero date after taking into account pre operative expenses up to SCOD

Subject to prudence check by the Commission. No separate provision for IEDC.

Controllable and un-controllable factors for IDC and IEDC

Factors leading to cost escalation towards IDC and IEDC:

Controllable factors:

Variation in capex due to cost / time overrun on account of land acquisition issues

Efficiency in implementation of project (not involving change in scope / law)

Delay in execution of project on account of contractor, supplier or agency of Generating Company

Uncontrollable factors:

Force majeure events

Change in law

No such provision but Commission checks reasonableness of expenses

Ceiling norm of initial capital spares

4% of plant and machinery cost 1.5% of original project cost




Regulations, 2009

Revenue from sale of infirm power

Payment from for from the regional deviation settlement fund accounts in accordance with the Central Electricity Regulatory Commission (Deviation Settlement Mechanism and Related matters) Regulations, 2014. Revenue to be adjusted from capital cost after accounting for fuel cost

Thermal: The cost of infirm power shall be the energy charges calculated on the basis of cost of fuel and the norms of Gross State Heat Rate, Secondary fuel oil consumption and Aux energy consumption.

Hydro: The cost of infirm power shall be equal to the average of the lowest variable charges of central sector thermal power generating station of the Northern Region for all months of the previous year as determined by the Central Commission and half of it shall be treated as an advance made by the beneficiaries to the generating company towards meeting the expenses on the Income Tax in subsequent year(s) and the remaining shall be retained by the generator.

Depreciation

The comparative evaluation of different norms for depreciation of power plants between the CERC Tariff

Regulations, 2014 and UPERC Generation Tariff Regulations, 2009 is as follows:


Regulations, 2009

Base for depreciation

The base shall be the capital cost of the asset admitted by the Commission.

In case of multiple units in a generating station, weighted average life for the station shall be applied

The base for the purpose of depreciation shall be the historical cost of the asset as admitted by the Commission.

Rate of depreciation

As per depreciation schedule provided in Regulations an average rate of 5.28% has been allowed for all generating stations

As per depreciation schedule provided in Regulations the average rate of depreciation for hydro power plants is 2.57% and for thermal power plants is 3.60%

Advance against Depreciation

No such provision has been provided AAD allowed in addition to depreciation

Capex during fag

end

The generating company may submit details of capital expenditure during fag end (five years before useful life) of project.

The Commission based on prudence checks shall approve depreciation on capital expenditure during fag end of project

No such provision has been provided




Regulations, 2009

De-capitalization

In case of de-capitalization of assets in respect of generating station or unit thereof, the cumulative depreciation shall be adjusted by taking into account the depreciation recovered in tariff by the de-capitalized asset during its useful services..

No such provision has been provided

Return on equity

The comparative evaluation of different norms for return on equity of power plants between the CERC Tariff

Regulations, 2014 and UPERC Generation Tariff Regulations, 2009 are as follows:


Regulations, 2009

Base rate

Return on equity shall be computed at a base rate of 15.5%

Return on equity shall be computed at a base rate of 15.5%

Provision of incentive

For Projects having COD on or after 1st April, 2014, an additional return of 0.50 % shall be allowed if projects are completed within timeline

For Projects having COD on or after 1st April, 2009, an additional return of 0.50% shall be allowed if projects are completed within timeline

Provision of penalty

Projects having COD on or after 1st April, 2014, rate of return shall be reduced by 1%, if the generating station is declared commercial operation without commissioning of RGMO/FGMO, data telemetry & communication system up to LDC and protection system.

No such provisions

Income Tax

ROE shall be allowed on pre-tax basis. ROE grossed up by MAT rate or “effective” tax rate applicable to the company. The actual tax income on other income stream (i.e., income of non generation or non transmission business, as the case may be) shall not be considered for the calculation of “effective tax rate”.

Tax on the income streams of the generating company from its core business shall be recovered from beneficiaries; limited to the tax on RoE



Renovation and Modernization

The comparative evaluation of different norms for renovation and modernisation power plants between the

CERC Tariff Regulations, 2014 and UPERC Generation Tariff Regulations, 2009 are as follows:


Regulations, 2009

Renovation &

Modernization

(R&M)- Special

Allowance –

Thermal

Special Allowance @ Rs.7.5 Lakh/MW/ Year for the year 2014-15 and thereafter escalated @ 6.35% every year during the tariff period FY 2014-19.

Special Allowance @ Rs. 5 Lakh/MW/year in FY 2009-10 and thereafter escalation @ 5.72% every year during the tariff period of FY 2009-14

Interest on loan capital

The following table provides a comparative of provisions regarding interest on loan capital of generating

stations between the CERC Tariff Regulations, 2014 and UPERC Generation Tariff Regulations, 2009:


Regulations, 2009

Interest on loan capital

The rate of interest shall be the weighted average rate of interest calculated on the basis of the actual loan portfolio after accounting for interest capitalized

The rate of interest shall be the weighted average rate of interest calculated on the basis of the actual loans at the beginning of each year and shall be adjusted based on actual loan each year

Repayment of Loan

Notwithstanding any moratorium period availed by the generation company, the repayment shall be considered from the 1st year of commercial operation of the project and shall be equal to depreciation allowed for the year or part of the year

In case any moratorium period is availed of by the generation company, depreciation provided in the tariff during the years of moratorium shall be treated as repayment during those years and interest on loan shall be calculated accordingly.

Refinancing of loans – sharing of gains

The costs associated with re-financing shall be borne by the beneficiaries and the net savings shall be shared between the beneficiaries and the generating company or the transmission licensee, as the case may be, in the ratio of 2:1

The cost associated with swapping of loan shall be borne by the beneficiaries and the net savings shall be shared between beneficiaries and the generating company in the ratio of 2:1



Interest on working capital

The following table provides a comparative of provisions regarding interest on working capital of thermal

generating stations between the CERC Tariff Regulations, 2014 and UPERC Generation Tariff Regulations,

2009:


Regulations, 2009

Norms for

working capital

Working Capital shall cover:

Coal-based/lignite-fired thermal

generating stations

(i) Cost of coal for 15 days for pit-head generating

stations and 30 days for non-pit-head generating

stations corresponding to NAPAF

(ii) Cost of coal or lignite and limestone for 30

days for generation corresponding to NAPAF

(iii) Cost of secondary fuel oil for two months for

generation corresponding to NAPAF

(iv) Maintenance spares @ 20% of O&M expenses

(v) Receivables equivalent to two months of

capacity charges and energy charges for sale of

electricity calculated on the normative annual

plant availability factor, and

(vi) Operation and maintenance expenses for one month.

Gas Generating Stations

(i) Fuel cost for 30 days corresponding to the NAPAF

(ii) Liquid fuel stock for 15 days corresponding to NAPAF

(iii) Maintenance spares @ 30% of O&M expenses

(iv) Receivables equivalent to two months of capacity charge and energy charge for sale of electricity calculated on NAPAF

(v) Operation and maintenance expenses for one month.


Coal based/ fired generating stations

(i) Cost of coal for one and half months for pit-head generating stations and 2 months for non-pit head generating stations corresponding to target availability

(ii) Cost of secondary fuel oil for 2 months corresponding to target availability

(iii) O&M expenses for one month

(iv) Maintenance spare @20% of O&M charges from FY 2009-10

(v) Receivables equivalent to 2 months corresponding to target availability or actual, whichever is lower

Gas Generating Stations

(i) Fuel cost for one month corresponding to the target availability

(ii) Liquid fuel stock for ½ month

(iii) From 2009-2010, Maintenance spares @ 30% of operation and maintenance expenses

(iv) Receivables equivalent to two months or actual, whichever is lower, comprising of fixed and variable charges for sale of electricity calculated on the target availability.

(v) Operation and maintenance expenses for one month




Regulations, 2009

Rate of interest on WC

Rate of interest shall be on normative basis and shall be equal to SBI Base Rate points as on 1st April 2014 or 1st of April of the year COD

Rate of interest is shall be equal to the short –term Prime Lending Rate of State Bank of India as on 1st April 2009 or 1st of April of the year COD

The following table provides a comparative of norms of interest on working capital of hydro generating



Regulations, 2009

Norms for

working capital

Working capital shall cover:

(i) Receivables equivalent to two months of fixed cost:

(ii) Maintenance spares @ 15% of operation and maintenance expenses

(iii) Operation and maintenance expenses for one month.


(i) Operation and Maintenance expenses for one month;

(ii) Maintenance spares shall be @ 15% of O&M expenses from FY09-10

(iii) Receivables equivalent to two months of fixed charges for sale of electricity calculated on normative capacity index.

Rate of interest on WC

Rate of interest shall be on normative basis and shall be equal to SBI Base Rate points as on 1st April 2014 or 1st of April of the year COD

Rate of interest is shall be equal to the short –term Prime Lending Rate of State Bank of India as on 1st April 2009 or 1st of April of the year COD

Operation and Maintenance Expenses

The following table provides a comparative of norms of Operation and Maintenance expenses of thermal

generating stations between the CERC Tariff Regulations, 2014 and UPERC Generation Tariff Regulations,

2009:


Regulations, 2009

Norms for Operation and Maintenance Expenses

Normative base O&M expenses on per MW basis for coal and gas generation companies based on past performance of generating stations

Normative base O&M expenses on per MW basis for coal and gas generation companies based on past performance of generating stations

Compensation allowance for new assets

In case of coal-based or lignite-fired thermal stations a separate compensation allowance unit-wise shall be admissible to meet expenses on new assets of capital nature including in the nature of minor assets. The compensation in the range of

In case of coal-based thermal stations a separate compensation allowance unit-wise shall be admissible to meet expenses on new assets of capital nature including in the nature of minor assets.




Regulations, 2009

0.20-1.0 (Rs Lakh/MW/Year) for the years of operation in the range of 0-25 years

The compensation in the range of 0.15-0.65 (Rs Lakh/MW/Year) for the years of operation in the range of 0-25 years

The following table provides a comparative of norms of interest on loan capital of hydro generating stations

between the CERC Tariff Regulations, 2014 and UPERC Generation Tariff Regulations, 2009:


Regulations, 2009

Norms for new

projects

Linked to the original project cost admitted by the Commission

O&M expenses shall be fixed at 2% of the original project cost (excluding cost of rehabilitation & resettlement works) for first year of commercial operation

Linked to capital cost admitted by Commission

O&M expenses shall be fixed at 2% of the capital cost admitted by the Commission.

May be revised to 2.5% of capital cost on case to case basis

Norms for

existing plants

Normative base O&M expenses on per MW basis for hydro generation companies based on past performance of generating stations

Derived on the basis of O&M expense approved for FY 08-09, under tariff orders, escalated by 10%.

Escalation rates Fixed escalation rate of 6.64% per annum for both old and new plants.

Fixed escalation rate of 5.72% per

annum for both old and new plants.

Operational Norms

The comparative evaluation of different operating norms of thermal power plants between the CERC Tariff

Regulations, 2014 and UPERC Generation Tariff Regulations, 2009:


Regulations, 2009

Plant Availability

Coal 85%, Gas 85% (except for relaxed norm for few existing stations)

All stations existing on or before 31.03.2009: 80% All Stations commissioned on or after 01.04.2009: 85% (except for relaxed norm for few existing stations)

Plant Load Factor for incentive

Coal 85%, Gas 85% (except for relaxed norm for few existing stations)

All stations existing on or before 31.03.2009: 80% All Stations commissioned on or after 01.04.2009: 85% (except for relaxed norm for few existing stations)




Regulations, 2009

Gross Station Heat Rate

Coal

• Existing stations: 2375 kCal/kWh - 2450 kCal/kWh (few exceptions)

• New stations: 1.045 x Design Heat Rate (kCal/kWh)

Gas

• Existing stations: Station wise norms for combine cycle and open cycle mode

• New stations: 1.05 x Design Heat Rate (kCal/kWh)

Coal

• Existing stations: 2350-2500 kCal/kWh

• New stations: 2350-2500 kCal/kWh Gas

• Advanced Class Machines: 1850 (CC) kCal/kWh - 2685 (OC) kCal/kWh E/EA/EC/E2 Class Machines: 1950 (CC) kCal/kWh - 2830 (OC) (kCal/kWh

Auxiliary Consumption

Coal 200 MW series

• With cooling tower: 8.5%

• Without cooling tower: 8.5% Above 200 MW

• Steam driven boiler feed pumps: 5.25%

• Electrically driven boiler feed pumps: 7.75%

Gas

• Open Cycle: 1%

• Combined Cycle: 2.5%

Coal Below 500 MW

• With cooling tower: 9%

• Without cooling tower: 8.5% Above 500 MW

• With cooling tower: 6%-9%

• Without cooling tower: 5.5%-8.5% Gas

• Open Cycle 1%

• Combined Cycle 3%

Secondary Fuel Oil Consumption

0.5 ml/ kWh • Stations existing on or before 31.3.09: 2.0 ml/kWh

• Stations Commissioned on or after 1.4.09: 1.0 ml/kWh

Generation

Incentive

Coal/Gas Incentive for Plant Load Factor higher than Normative Plant Load Factor: Rs 0.50 / kWh per unit (generation above Normative Plant Load Factor)

Coal/Gas Incentive for Plant Load Factor higher than Normative Plant Load Factor: Rs 0.25 / kWh per unit (generation above Normative Plant Load Factor)

The following table provides a comparative evaluation of different operating norms of hydro generating


Norms CERC Tariff Regulations, 2014

UPERC Generation Tariff Regulations, 2009

Rate of secondary energy

Rate of secondary energy shall be equal to Rs 0.90/kWh

Secondary Energy Rate shall be equal to Primary Energy Rate

Availability

Availability measured by NAPAF:

Storage and Pondage type

(Head variation up to 8% & not affected by

silt): 90%

Storage and Pondage type

(Head variation more than 8%): As per DPR

approved by CEA or State Govt.

Pondage type

Availability measured by Capacity Index:

Storage type and Run-of-river power stations with pondage: 80% during 1st year of commercial operation and 85% thereafter



Norms CERC Tariff Regulations, 2014

UPERC Generation Tariff Regulations, 2009

(availability significantly affected by silt):

85%

Run of river type: Plant wise based on 10 day

design energy data moderated by past

experience where relevant

Purely Run-of-river power stations : 85% during 1st year of commercial operation and 90% thereafter

Norms for

Auxiliary

Consumption

Surface hydro generation plants

(with rotating exciter): 0.7% Surface hydro generation plants (with static excitation): 1.0% Under ground hydro generation plants (with rotating exciter): 0.9% Under ground hydro generation plants (with static excitation): 1.2%

Surface hydro generation plants

(with rotating exciter): 0.7% Surface hydro generation plants (with static excitation): 1% Under ground hydro generation plants (with rotating exciter): 0.9% Under ground hydro generation plants (with static excitation): 1.2%

Incentive Incentive payable based on availability

higher than NAPAF

Incentive payable on the basis of capacity index

higher than normative capacity index



Appendix B. - Performance of existing generating stations in the state during last 5 years

This section provides a snapshot of the performance of the existing generating stations in the state based on a

comparison between the actual operational performance vis-à-vis the targets set by the Commission in UPERC

Generation Tariff Regulations, 2009

Comparison of actual vs. target availability of existing generating stations

during FY 2009-10 to FY 2013-141

1 For FY 2013-14 the figures correspond to performance upto December 2013

72.42

65.25 63.0168.22

65.24

80 80 80 80 80

0

10

20

30

40

50

60

70

80

90

2009-10 2010-11 2011-12 2012-13 2013-14 *

Availab

ilit

y (

%)

Parichha Extension

Actual Availability Target Availability

81.08

73.55 75.25

57.19 57.99

80 80 80 80 80

0

10

20

30

40

50

60

70

80

90

2009-10 2010-11 2011-12 2012-13 2013-14 *

Avaia

lbil

ity (

%)

Anpara 'A'


79.2478.81

85 85

75

76

77

78

79

80

81

82

83

84

85

86

2012-13 2013-14 *

Avail

ab

ilit

y (

%)

Parichha Extension 2nd stage


45.00

37.71

23.3218.64

26.64

65 66 6871

75

0

10

20

30

40

50

60

70

80

2009-10 2010-11 2011-12 2012-13 2013-14 *

Avail

ab

ilit

y (

%)

Parichha




82.15

87.02

82.04

77.17

92.26

80 80 80 80 80

65

70

75

80

85

90

95

2009-10 2010-11 2011-12 2012-13 2013-14 *

Avail

ab

ilit

y (

%)

Anpara'B'


48.4353.16

43.02

26.5123.98

60 61 6366

70

0

10

20

30

40

50

60

70

80

2009-10 2010-11 2011-12 2012-13 2013-14 *

Avail

ab

ilit

y (

%)

Obra ' A'


65.50

54.7152.13

46.4340.94

65 66 67 68 70

0

10

20

30

40

50

60

70

80

2009-10 2010-11 2011-12 2012-13 2013-14 *

Availab

ilit

y (

%)

Panki


43.7239.57

30.93

39.90

21.71

55 56 5861

65

0

10

20

30

40

50

60

70

2009-10 2010-11 2011-12 2012-13 2013-14 *

Avail

ab

ilit

y (

%)

Harduaganj


49.12 47.53

79.1785 85 85

0

10

20

30

40

50

60

70

80

90

2011-12 2012-13 2013-14 *

Availab

ilit

y (

%)

Harduaganj Extn.


54.7850.8 47.78

41.38 39.94

70 71 73 7680

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

2009-10 2010-11 2011-12 2012-13 2013-14 *

Avail

ab

ilit

y (

%)

Financial Year

Availability - Obra 'B'




68.52

84.7285 85

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

2012-13 2013-14 *

Availab

ilit

y (

%)

Kundarkhi


75.88

95.18

85 85

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

100.00

2012-13 2013-14 *

Avail

ab

ilit

y (

%)

Maqsoodapur


77.81

92.38

85 85

70.00

75.00

80.00

85.00

90.00

95.00

2012-13 2013-14 *

Avail

ab

ilit

y (

%)

Barkhera


76.80

90.06

85 85

70.00

75.00

80.00

85.00

90.00

95.00

2012-13 2013-14 *

Avail

ab

ilit

y (

%)

Khamberkhera


53.70

94.91

85 85

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

100.00

2012-13 2013-14 *

Availab

ilit

y (

%)

Utraula


72

8591

96

85 85 85 85

0

20

40

60

80

100

120

2010-11 2011-12 2012-13 2013-14 *

Availab

ilit

y (

%)

Rosa




Comparison of actual vs. target plant load factor of existing generating

stations during FY 2009-10 to FY 2013-142


45

37.7

23.3118.63

26.64

60 61 6366

70

0

10

20

30

40

50

60

70

80

2009-10 2010-11 2011-12 2012-13 2013-14 *

PL

F (

%)

Parichha

Actual PLF Target PLF

81.05

78.81

85 85

75

76

77

78

79

80

81

82

83

84

85

86

2012-13 2013-14 *

PL

F (

%)



81.03

73.52 75.11

56.99 57.83

80 80 80 80 80

0

10

20

30

40

50

60

70

80

90

2009-10 2010-11 2011-12 2012-13 2013-14 *

PL

F (

%)

Anpara 'A'


72.4065.25 62.87

68.10 65.14

80 80 80 80 80

00.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

2009-10 2010-11 2011-12 2012-13 2013-14 *

PL

F (

%)

Financial Year

PLF - Parichha Extension




65.50

54.71 52.0946.42

40.94

60 61 62 63 65

0

10

20

30

40

50

60

70

2009-10 2010-11 2011-12 2012-13 2013-14 *

PL

F (

%)

Panki


49.09

66.78

16.14 16.0021.66

50 51 53 5660

0

10

20

30

40

50

60

70

80

2009-10 2010-11 2011-12 2012-13 2013-14 *

PL

F (

%)

Harduaganj


49.12 47.39

79.0385 85 85

0

10

20

30

40

50

60

70

80

90

2011-12 2012-13 2013-14 *

PL

F (%

)

Harduaganj Extn.


54.4448.96

45.5041.37 39.92

65 66 6871

75

0

10

20

30

40

50

60

70

80

2009-10 2010-11 2011-12 2012-13 2013-14 *

PL

F (

%)

Obra 'B'


40.5145.10

28.9626.51

23.98

55 5659 61

65

0

10

20

30

40

50

60

70

2009-10 2010-11 2011-12 2012-13 2013-14 *

PL

F (

%)

Obra 'A'


82.13 86.96

98.29

76.76

91.68

80 80 80 80 80

0

10

20

30

40

50

60

70

80

90

100

2009-10 2010-11 2011-12 2012-13 2013-14 *

PL

F (

%)

Anpara 'B'




66.76

84.7285 85

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

2012-13 2013-14 *

PL

F (

%)

Financial Year

Kundarkhi


51.93

79.7885 85

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

2012-13 2013-14 *

PL

F (

%)

Financial Year

Utraula


74.19

77.92

85 85

68.00

70.00

72.00

74.00

76.00

78.00

80.00

82.00

84.00

86.00

2012-13 2013-14 *

PL

F (

%)

Financial Year

Maqsoodapur


76.5177.11

85 85

72.00

74.00

76.00

78.00

80.00

82.00

84.00

86.00

2012-13 2013-14 *

PL

F (

%)

Financial Year

Barkhera


75.00 74.83

85 85

68.00

70.00

72.00

74.00

76.00

78.00

80.00

82.00

84.00

86.00

2012-13 2013-14 *

PL

F (

%)

Financial Year

Khamberkhera


60

79 76 7985 85 85 85

0

10

20

30

40

50

60

70

80

90

2010-11 2011-12 2012-13 2013-14 *

PL

F (

%)

Financial Year

Rosa




Comparison of actual vs. target gross station heat rate for existing generating



30633099

3259

3388

311731003070

30403010

2980

2700

2800

2900

3000

3100

3200

3300

3400

3500

2009-10 2010-11 2011-12 2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/kW

h)

Parichha

Actual Gross Station Heat Rate

Target Gross Station Heat Rate

2642

2460

2500 2500

2350

2400

2450

2500

2550

2600

2650

2700

2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/

kW

h)




2374

2231

2390

2286

2204

2500 2500 2500 2500 2500

2050

2100

2150

2200

2250

2300

2350

2400

2450

2500

2550

2009-10 2010-11 2011-12 2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/

kW

h)

Anpara 'A'



2976

2758

29162999

2660

2500 2500 2500 2500 2500

2200230024002500260027002800290030003100

2009-10 2010-11 2011-12 2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/

kW

h)

Financial Year

Parichha Extension





3195

3111 3124

2945

2892

3000 29902972

2950 2940

2700

2750

2800

2850

2900

2950

3000

3050

3100

3150

3200

3250

2009-10 2010-11 2011-12 2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/kW

h))

Obra 'A'



3138

2787 2700 2609 25372636

2900 2890 2880 2870

0

500

1000

1500

2000

2500

3000

3500

2009-10 2010-11 2011-12 2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kcal/kW

h)

Obra 'B'



3320 3243 3335 3381 3409

2678

3100 3070 3040 3010

0

500

1000

1500

2000

2500

3000

3500

4000

2009-10 2010-11 2011-12 2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kcal/

kW

h)

Panki



2289

22632280 2274 2274

2450 2450 2450 2450 2450

2150

2200

2250

2300

2350

2400

2450

2500

2009-10 2010-11 2011-12 2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/

kW

h)

Anpara 'B'



3486 3436

24632500 2500 2500

0

500

1000

1500

2000

2500

3000

3500

4000

2011-12 2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kcal/

kW

h)

Harduaganj Extn.



4119

4706 4561 4645

3675

26783100 3070 3040 3010

0500

100015002000250030003500400045005000

2009-10 2010-11 2011-12 2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/

kW

h)

Financial Year

Harduaganj





30793106

2900 2900

2750

2800

2850

2900

2950

3000

3050

3100

3150

2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/kW

h)

Kundarkhi



3198

3107

2900 2900

2750

2800

2850

2900

2950

3000

3050

3100

3150

3200

3250

2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/kW

h)

Utraula



30793093

2900 2900

2800

2850

2900

2950

3000

3050

3100

3150

2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/

kW

h)

Maqsoodapur



30773091

2900 2900

2800

2850

2900

2950

3000

3050

3100

3150

2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/

kW

h)

Barkhera



31043134

2900 2900

2750

2800

2850

2900

2950

3000

3050

3100

3150

3200

2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/

kW

h)

Khamberkhera



2480

2597

2574

2520

2500 2500 2500 2500

2420

2440

2460

2480

2500

2520

2540

2560

2580

2600

2620

2010-11 2011-12 2012-13 2013-14 *

Gro

ss S

tati

on

Heat

Rate

(kC

al/

kW

h)

Rosa





Comparison of actual vs. target auxiliary consumption for existing generating



16.9117.96

21.7120.19

17.821

11.5 11.3 11.1 10.9 10.7

0

5

10

15

20

25

2009-10 2010-11 2011-12 2012-13 2013-14 *Au

xilia

ry E

nerg

y C

on

su

mp

tio

n(%

)

Parichha

Actual Auxiliary Energy Consumption

Target Auxiliary Energy Consumption

9.88 10.06 9.9110.81 10.783

8.5 8.5 8.5 8.5 8.5

0.00

2.00

4.00

6.00

8.00

10.00

12.00

2009-10 2010-11 2011-12 2012-13 2013-14 *

Au

xilia

ry E

nerg

y C

on

su

mp

tio

n (%

)

Anpara 'A'



10.65 10.95 10.529.2

10.689

9 9 9 9

0.00

2.00

4.00

6.00

8.00

10.00

12.00

2009-10 2010-11 2011-12 2012-13 2013-14 *

Au

xil

iary

En

erg

y C

on

su

mp

tio

n(%

)

Financial Year

Parichha Extension



9.69

9.425

9 9

8.60

8.80

9.00

9.20

9.40

9.60

9.80

2012-13 2013-14 *

Au

xil

iary

En

erg

y C

on

su

mp

tio

n (

%)






15.69 15.1816.24 16.71

11.57211 10.8 10.6 10.2 10

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

2009-10 2010-11 2011-12 2012-13 2013-14 *

Au

xil

iary

En

erg

y C

on

su

mp

tio

n (

%)

Obra 'A'



14.9615.97

14.1 14.76

20.525

11.5 11.3 11.1 10.9 10.5

0.00

5.00

10.00

15.00

20.00

25.00

2009-10 2010-11 2011-12 2012-13 2013-14 *

Au

xil

iary

En

erg

y C

on

su

mp

tio

n (

%)

Harduaganj



12.1912.85

10.619.93 10.08510.5 10.3 10.1 9.9 9.7

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

2009-10 2010-11 2011-12 2012-13 2013-14 *

Au

xilia

ry E

nerg

y C

on

su

mp

tio

n (

%)

Obra 'B'



7.667.51

7.42

8.14

7.638

7 7 7 7 7

6.40

6.60

6.80

7.00

7.20

7.40

7.60

7.80

8.00

8.20

8.40

2009-10 2010-11 2011-12 2012-13 2013-14 *

Au

xil

iary

En

erg

y C

on

su

mp

tio

n (

%)

Anpara 'B'



10.02

11.05

9.0079 9 9

0.00

2.00

4.00

6.00

8.00

10.00

12.00

2011-12 2012-13 2013-14 *

Au

xilia

ry E

nerg

y C

on

su

mp

tio

n (

%)

Harduaganj Extn.



13.6712.24

13.68 13.86

11 10.8 10.6 10.2 9.8

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

2009-10 2010-11 2011-12 2012-13 2013-14 *

Au

xil

iary

En

erg

y C

on

su

mp

tio

n (

%)

Panki





11.72

11.12

11 11

10.60

10.80

11.00

11.20

11.40

11.60

11.80

2012-13 2013-14 *

Au

xil

iary

En

erg

y C

on

su

mp

tio

n (

%)

Kundarkhi



12.28

11.1811 11

10.00

10.50

11.00

11.50

12.00

12.50

2012-13 2013-14 *

Au

xilia

ry E

nerg

y C

on

su

mp

tio

n (

%)

Utraula



11.78

11.45

11 11

10.60

10.80

11.00

11.20

11.40

11.60

11.80

12.00

2012-13 2013-14 *

Au

xil

iary

En

erg

y C

on

su

mp

tio

n (

%)

Maqsoodapur



11.78

11.38

11 11

10.60

10.80

11.00

11.20

11.40

11.60

11.80

12.00

2012-13 2013-14 *

Au

xilia

ry E

nerg

y C

on

su

mp

tio

n (%

)

Barkhera



11

9 9 99 9 9 9

0

2

4

6

8

10

12

2010-11 2011-12 2012-13 2013-14 *

Au

xilia

ry E

nerg

y C

on

su

mp

tio

n (

%)

Rosa



11.65

11.17

11 11

10.60

10.80

11.00

11.20

11.40

11.60

11.80

2012-13 2013-14 *

Au

xilia

ry E

nerg

y C

on

su

mp

tio

n (%

)

Khamberkhera





11.97

9.1

3.01

5.65 6.007

3 2.9 2.8 2.7 2.6

0

2

4

6

8

10

12

14

2009-10 2010-11 2011-12 2012-13 2013-14 *

Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Parichha

Actual Secondary Fuel Oil Consumption

Target Secondary Fuel Oil Consumption

1.611.32

2.06

2.86

2.532

2 2 2 2 2

0

1

1

2

2

3

3

4

2009-10 2010-11 2011-12 2012-13 2013-14 *Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Anpara 'A'



Comparison of actual vs. target secondary fuel oil consumption for existing

generating stations during FY 2009-10 to FY 2013-145


4.27

5.27

1.351.76

3.491

2 2 2 2 2

0.00

1.00

2.00

3.00

4.00

5.00

6.00

2009-10 2010-11 2011-12 2012-13 2013-14 *

Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Financial Year

Parichha Extension



2.95

3.462

1 1

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

2012-13 2013-14 *

Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Financial Year






0.31 0.260.46

0.57

0.309

2 2 2 2 2

0

1

1

2

2

3

2009-10 2010-11 2011-12 2012-13 2013-14 *Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/kW

h)

Anpara 'B'



9.39

8.34

3.66

5.364.839

4 3.8 3.6 3.4 3.2

0

1

2

3

4

5

6

7

8

9

10

2009-10 2010-11 2011-12 2012-13 2013-14 *S

eco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Obra 'A'



3.42

4.63

2.322.1

2.8562.5 2.4 2.3 2.2 2.1

0

1

1

2

2

3

3

4

4

5

5

2009-10 2010-11 2011-12 2012-13 2013-14 *Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Obra 'B'



3.62 3.78

2.77

5.926.51

2.5 2.4 2.3 2.2 2.1

0

1

2

3

4

5

6

7

2009-10 2010-11 2011-12 2012-13 2013-14 *Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Panki



9.77

21.7

2.43

9.23 10.157

4.5 4.3 4.1 3.9 3.7

0

5

10

15

20

25

2009-10 2010-11 2011-12 2012-13 2013-14 *S

eco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Harduaganj



4.075

11.04

4.689

1 1 1

0

2

4

6

8

10

12

2011-12 2012-13 2013-14 *Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Harduaganj Extn.





1.65

1.0001 1

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

2012-13 2013-14 *

Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Financial Year

Khamberkhera



1.78

1.001 1

0.000.200.400.600.801.001.201.401.601.802.00

2012-13 2013-14 *

Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Financial Year

Kundarkhi



1.79

1.001 1

0.000.200.400.600.801.001.201.401.601.802.00

2012-13 2013-14 *

Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Financial Year

Utraula



1.71

1.0001 1

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

2012-13 2013-14 *

Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Financial Year

Barkhera



1.72

1.0001 1

0.000.200.400.600.801.001.201.401.601.802.00

2012-13 2013-14 *

Seco

nd

ary

Fu

el O

il C

on

su

mp

tio

n

(ml/

kW

h)

Financial Year

Maqsoodapur



Documents

Discussion Paper 06.3 · Uttar Pradesh Electricity Regulatory Commission Discussion Paper on UPERC (Terms and Conditions of Generation Tariff) Regulations for 2014-19 4 1. Introduction