DPR on Regulations

8/8/2019 DPR on Regulations

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INTRODUCTION

Power is a critical infrastructure for economic development and for improving standard of living.

To attain high economic growth and high standards of living, the availability of adequatequantity and quality of power at affordable prices must be maintained. It is difficult to managethe demand and supply of power as installing power generation, transmission and distribution

facilities is a complex and time consuming process.

In spite of many power projects in operation, there is still demand supply gap prevailing as totalinstalled capacity is 1,52,000 MW (Approx.) which is almost 22% less than the present demand.

Government of India has planned to provide power for all by 2012. The expected requirement for2012 is 2,30,000 MW, which means in the 11

thfive year plan the capacity, has to be increased by

78,000 MW (Approx.).

Indian power sector had been plagued with inefficiency for a long time and hence had been

falling short of set targets in the previous plans. State Electricity boards had been facing lossesand were on the verge of bankruptcy demanding vital changes in the regulatory framework. Thetariff structure was differentiated on the basis of consumer categories with cross subsidies posing

more burdens on commercial and industrial users at the expense of agricultural sector.

Power sector was facing high Transmission and Distribution (T&D) Losses to the tune of 40%

and actions to check power theft were not stringent. There was a complete lack of a rational tariffstructure and revenue realization was inefficient. Since, complete control for supply of power

was in hands of SEBs, hence there was no competition in the sector leading to monopolisticmarket.

In the year 1991, Indian Power sector was opened up for Independent Power Producers (IPP) as

a step towards reforming the sector.

Along with it, unbundling of SEBs and privatization was brought into the sector in order toincrease competition in the Power sector.

In the year 1998, came the Electricity Regulatory act which paved the way for setting up of

Central Electricity Regulatory Commission (CERC) and State Electricity RegulatoryCommissions (SERCs).

In Indias constitution, electricity is a shared responsibility between the centre and states. Almostall the states have initiated structural and regulatory reforms in the power sector. About 22 of the

29 states have established electricity regulatory commissions empowered to regulate tariffs andestablish performance parameters.

As a step ahead to reform Indian Power sector, Electricity Act 2003 has created a new paradigm

for the development of Power sector. It has ended the monopoly of State Electricity Boardsestablished through Electricity (Supply) Act, 1948 and has created a new competitive framework

making the sector more consumer friendly by creation of independent Electricity Regulatorycommissions at the State and Centre Level as well.


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While the centre-led Electricity Act laid out the vision for a deregulated power sector, states havethe charge of implementing the restructuring process.

Electricity Act 2003 has cleared the path for setting up of captive power plants, open access intransmission, allowed private investment in transmission through licensing and made provision

for more than one distribution licensee in the same area.

Electricity Act 2003 empowered the Central Electricity Regulatory Commission (CERC) toregulate the terms and conditions for the determination of tariff of Central Sector Generating

Stations (CSGC) and also the transmission tariff for Interstate transmission of electricity.

At present the tariffs are based on the cost plus mechanism which is determined on the basis of parameters set by the regulators. These parameters compose of Fixed or capacity charges and

Energy or variable charges component.

Elements of Fixed charges include depreciation, interest on loan, return on equity, interest on

working capital and Operation &Maintenance expenses whereas energy charges cover mainlythe fuel charges. Energy charges are paid on the basis of scheduled generation according to fuel

consumption and fixed charges are paid on the basis of generators availability.

Scheduled generation from a generator is determined by (national, regional, and state) loaddispatch centers, based on projected demand and generators declared capacity for the day.

Incentives were also provided to the generators on the basis of Plant load factor in order to

ensure as much generation as possible. The PLF norm was set between 62.8% and 68.5% fordifferent power plants in 1992 and an incentive of 0.01 Rs./kWh was provided for every 1%

increase in PLF. But this norm was not in accordance with the load and demand conditions of thegrid whereas it put emphasis on increasing the generation of power plants. Hence in order to

avoid the grid indiscipline and grid fluctuations, CERC introduced a new incentive scheme based

on availability in 2002 and termed it as Availability Based Tariff (ABT) for Central SectorGeneration Companies. According to ABT, if a generator deviates from its scheduled generation,it allows an Unscheduled Interchange (UI) charge depending upon system frequency at that time

and whether excess/reduced generation is harmful or beneficial to the grid.

Thus, the present generation tariff consists of mainly four parts as:

i. Fixed or capacity charges based on availabilityii. Energy charges based on scheduled generation (in case of thermal power plants)

iii. UI charges, if any (based on load demand)iv. PLF incentive, if any (based on performance of a plant)

In case of hydro stations, there is no fuel component and the AFC is notionally divided intocapacity charge and variable charge.

Recovery of capacity charges in case of hydro stations is linked with the availability of waterwhereas variable charges are determined according to the average of least variable costs ofcentral thermal generating stations in the region.


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Hence it is entrusted with CERC to make regulations regarding tariff determination so that thereis equal risk sharing between generators and beneficiaries and generators can recover their costs

of generation which comprises of Annual Fixed Costs and Variable Costs.

After the enactment of the Electricity Act 2003, the CERC had released the tariff regulations for

the period 2004-09. Now after the expiry of the tariff period for these regulations on March 31,2009, the CERC has issued new tariff regulations for the next regulatory period 2009-14. The

new regulations have been made to make the system more efficient by making the tariffavailability based so that the grid discipline is maintained. Also, parameters to determine the

Annual Fixed Charges (AFC) are revised and decided so as to make the tariff structure morerational.

In the given project have been discussed the key changes that are brought in the CERC Terms

and Conditions for Tariff determination for the period 2009-14 as compared to those for theperiod 2004-09 and impact of these changes on the power generators and utilities.


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PURPOSE OF THE STUDY

The Central Electricity Regulatory Commission, established under the Electricity Regulatory

Commissions Act, 1998, and deemed to be the Central Commission for the purpose of theElectricity Act, 2003, that came into effect from 10 June 2003, is bestowed with the jurisdiction

for regulation of tariff of the generating companies owned or controlled by the CentralGovernment, and other generating companies having a composite scheme of generation and sale

in more than one State, regulating the inter-State transmission of energy and determination oftariff of the transmission utilities. The commission has specified the terms and conditions of tariff

for the period 1.4.2004 to 31.3.2009, under the provisions of Section 61 of the Act, in addition toperforming other functions conferred upon it.


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QUALITATIVE ANALYSIS OF THE CERC REGULATIONS 2004 AND CERC

REGULATIONS 2009 AND THEIR IMPACT ON TARIFF DETERMINATION:

To analyze the impact of new CERC Regulations 2009 on the Tariff, all the componentsaffecting the tariff as per both the earlier and new Regulations were compared and an analysis of

their impact on the annual fixed charges payable to the generator in the form of tariff was done.

The components of Annual Fixed Charges used to compute the Capacity Charges are as follows:

y Return on equityy Interest on Loan Capitaly Depreciationy Operation & Maintenance Expensesy Interest on Working capital

COMPONENTS OF ANNUAL FIXED COST: All the components of Annual Fixed Cost

have been analyzed to study the impact of change of Regulations from CERC Regulations 2004to CERC Regulations 2009 as follows:

RETURN ON EQUITY:

To determine the return on equity first the amount of equity employed by the generator is

determined. As per the Regulations of CERC the prescribed debt-equity ratio is 70:30.

The Regulations state that in case the share of equity is more than that of 30% than the amount of

equity used for determination of tariff remains limited to 30% and the rest of the equity is takenas normative loan.

Also, in case share of equity is less than 30% then the actual debt equity ratio is used for thedetermination of tariff.


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As per 2004 Regulations:

After determination of the equity base as above return on equity is calculated at 14% per annum

post tax.


Return on equity is computed on pre tax basis at the base rate of 15.5%

Projects commissioned after 01/04/09, if completed within the time line additional return of

0.5% is allowed otherwise not.

Rate of return on equity is computed by grossing up the base rate with the normal tax rate asgiven below:

Rate of return on equity = base rate/ (1-t)

Where- t is the applicable tax rate.

Impact:

y As the rate of return on equity as per 2009 Regulations (15.5% pretax) is more than thatas per 2004 Regulations (14% post tax), hence the amount of return on equity has also

increased which leads to the increased profitability of the generator.

y As return on equity makes a component of the annual fixed charges, it has a direct impacton the tariff determination. Increase in ROE means increased AFC, which in turn means

increased tariff resulting into more burdens on the beneficiaries.

y As per the new Regulations, ROE has become now pre-tax, for which the base rate of15.5% is grossed up through the applicable tax rate for the company. This, in turn,

translates into nearly 23.5% post-tax return on the equity as against 14%, previously. This

benefit of tax has been provided to the project developer to promote more investmentsinto the sector.

y According to new Regulations, generators have not to bear the burden of income tax onthe unscheduled interchange (UI) earning, incentive earning and efficiency gains of the

projects.

INTEREST ON LOAN CAPITAL:

After determination of loan capital as per the specified debt-equity ratio, interest on loan capitalis calculated taking the loan capital as gross normative loan.

The steps for determining the interest on loan capital are same for both the Regulation periods

2004 and 2009.

The gross normative loan comprises of opening gross loan, additional capitalization and FERV.


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Net loan is computed by subtracting cumulative repayment from gross loan. The opening netloan and the closing net loan are used to compute the average net loan on which the weighted

average rate of interest is employed to determine the interest on loan.

Repayment of the loan is equal to the Depreciation allowed from the first year of commercial

operation of the project.

In case of swapping of loan, the generating company is required to try to refinance the loan.


It states that the loan should be refinanced as long as it results in net benefit to the beneficiaries.

The costs associated are borne by the beneficiaries and the benefits are also passed on to the

beneficiaries completely.


Costs associated with the refinancing of loan are borne by the beneficiaries and the net savingsare shared between the beneficiary and the generating company in the ratio of 2:1.

Impact:

y If the generating company could avail loan at a lesser rate of interest on loan repayment,so that the beneficiaries could benefit from it in the form of lesser tariff to be paid, then

the efforts should be made to do so.

y Earlier the complete benefit had to be passed on to the beneficiaries and the generatingcompany was not able to make any profit but under the changed Regulations in 2009, the

net savings have to be divided into the beneficiaries and the generating company in theratio of 2:1, made on account of refinancing of loan.

DEPRECIATION:

Depreciation is calculated on the historical cost of the assets based on straight line method overthe useful life of assets.

Depreciation is allowed up to maximum of 90% of the capital cost of the assets and 10% is the

salvage value.

Land is not a depreciable asset; hence its cost is excluded from capital cost for the purpose of

computing depreciable value of assets.


On repayment of entire loan, the remaining depreciable value is spread over the balance usefullife of the asset.


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Advance Against Depreciation (AAD): loan repayment amount subject to a ceiling of 1/10th

ofloan amount minus Depreciation.

AAD is permitted only if the cumulative repayment exceeds the cumulative Depreciation up to aparticular year.

AAD is restricted up to the extent of difference between the cumulative repayment andcumulative Depreciation.


The remaining depreciable value as on 31st

march of the year closing after 12 years period from

date of commissioning (COD) is spread over the balance useful life of the assets.

Advance against Depreciation is not taken into account in to the new CERC Regulations.

Impact:

y As per the new Regulations of CERC for tariff determination, the concept of AAD hasbeen removed while the Depreciation rate has been increased at the same time.

y Earlier the Depreciation rate for hydro projects was 2.57% with 35 years of project lifeand Depreciation on 90% of the capital cost.

y Now as per the 2009 Regulations the Depreciation rate for the assets of the project hasbeen increased up to 5.28% for hydro projects.

y It has a marginal impact on the tariff for the project as the removal of advance againstDepreciation (AAD) while computing remaining depreciable value is compensated with

the increase in the rate of Depreciation.

INTEREST ON WORKING CAPITAL (IoWC):

There are three main components of Working capital, two of which are considered to be same for

both the Regulations period. These are:

1. Operations and Maintenance expenses for one month2. Receivables equivalent to two months of fixed cost

The third component maintenance spares has different valuations in the two Regulations.

As per 2004 Regulations: Maintenance spares @1% of the historical cost escalated @6% per

annum from the COD.

As per 2009 Regulations: Maintenance spares @15% of the O&M expenses.

Rate of interest on Working capital is the short term Prime Lending Rate (PLR) of State Bank ofIndia.


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COMPONENTS 2004-09 2009-14 IMPACT

1. Maintenance Spares 1.5% ofhistorical cost

escalated @6%per annum

15% of O&Mcost

Negative

2. Sales Receivables 2 Months 2 Months No Impact

3. O&M Expenses 1 Month 1 Month No Impact

Impact:

Impact of the change in the calculation method of maintenance spares has no any major impact

on the interest on Working capital and IoWC recovered under the new Regulations is as earlieron the short term Prime Lending Rate (PLR) of State Bank of India.

OPERATION AND MAINTENANCE EXPENSES:


For existing hydro generating stations in operation for 5 years or more in 2003-04, actual O&Mexpenses for the years 1998-99 to 2002-03, excluding abnormal expenses formed the basis of

O&M expenses. The average of the normalized O&M expenses for 1998-99 to 2002-03 wasescalated @4% per annum to arrive at O&M expenses for 2003-04 which was further escalated

@4% per annum to arrive at O&M expenses for subsequent years.

For hydro generating stations not in existence for 5 years, O&M expenses were fixed at 1.5% of

the capital cost and escalated @4% per annum from the subsequent years to reach O&Mexpenses for 2003-04 and then again were escalated @4% per annum to arrive at O&M expensesfor subsequent years.

For hydro generating stations commissioned on or after 1.4.2004, the base O&M expenses werefixed @1.5% of actual capital cost which will be escalated @4% per annum for subsequent

years.


For existing hydro generating stations in operation for 5 years or more, actual O&M expenses forthe years 2003-04 to 2007-08, excluding abnormal expenses form the basis of O&M expenses.

The average of the normalized O&M expenses for 2003-04 to 2007-08 is escalated @5.17% perannum to arrive at O&M expenses for 2007-08 which is further escalated @5.72% per annum to

arrive at O&M expenses for subsequent years.

For hydro generating stations not in existence for 5 years, O&M expenses are fixed at 2% of the

capital cost (excluding cost of R&R works) and escalated @5.17% per annum from thesubsequent years to reach O&M expenses for 2007-08 and then again are escalated @5.72% per

annum to arrive at O&M expenses for the year 2009-10.


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For hydro generating stations having COD on or after 1.4.2009, the base O&M expenses arefixed @2% of actual capital cost (excluding cost of R&R works) which is escalated @5.72% per

annum for subsequent years.

O&M expenses for 2009-10 are further rationalized considering 50% increase in employee cost

on account of pay revision of the employees of PSUs.

Impact:

y For the plants commissioned on or after 1.4.2009, 2% of the project cost (excluding R&Rexpenses) will form the base O&M expense which will be escalated @5.72% per annum.

Hence the new Regulations provide for better coverage of O&M expenses as the earlierRegulations allowed an O&M cost of only 1.5% of capital cost escalated @4% per

annum.

y In the new CERC Regulations rationalization of tariff has been done on account ofincrease in employee cost due to pay revision by increasing the O&M expenses by 50%to form the base for the next years in the tariff period.

COMPONENTS OF ANNUAL FIXED CHARGES/ CAPACITY CHARGES:

COMPONENTS 2004-09 2009-14 IMPACT

1. Return on Equity 14% 15.5% Positive

2. Interest on Loan Capital On actual loan

capital

On actual loan

capital

Marginal

Positive

3. Depreciation 2.57%+ AAD 5.28% MarginalNegative

4. Interest on Working capital On NormativeWorking capital

On NormativeWorking capital

No impact

5. Operation & MaintenanceExpenses

Based onnormative

parameters

Based onnormative

parameters

Positive


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COMPUTATION AND PAYMENT OF CAPACITY CHARGE AND ENERGY CHARGE

FOR HYDRO GENERATING STATIONS:


Capacity Charges were based upon the annual fixed cost and primary energy charges.

Capacity Charges = Annual fixed cost Primary energy charges

Primary energy charges were dependent upon saleable primary energy and primary energy rate.

Primary energy rate was deemed to be equal to the lowest variable charges of the central sectorthermal power generating stations of the concerned region.

Primary energy charges = saleable primary energy x primary energy rate

Incentives were not inclusive in the methodology to calculate Capacity Charges but were

provided for separately on the basis of capacity index (declared capacity expressed as % ofmaximum available capacity) of the generating station.

Incentive = 0.65 x Annual Fixed Charges x (CIA-CIN)/100

Where CIA is the Capacity Index Achieved and CIN is the Normative Capacity Index.


The Capacity Charges as per the new Regulations are inclusive of incentives and are dependent

on the plant availability factor.

Capacity Charges for a month =

Annual fixed cost x 0.5 x (no. of days in a month/no. of days in a year) (Plant availability factor

for a month/Normative annual plant availability factor)

And the energy charges are computed after adjusting for Free Energy for Home State (FEHS)and auxiliary consumption of the plant.

Energy charges =

Energy charge rate x scheduled energy for the month x (adjusted for FEHS)/100

Where, Energy charge rate =

Annual fixed cost x 0.5 x 10/ Design Energy (adjusted for auxiliary consumption and FEHS)

The energy charges are capped at 80 paisa/kWh as per the new Regulations.

Impact:

y Earlier the Capacity Charges had been computed on the basis of plant load factor takinginto account the capacity index but in new Regulations focus is on the recovery of

Capacity Charges based on the plant availability factor.


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y Earlier the beneficiary had to pay the AFC irrespective of the actual power generationdue to variation in availability of water. Also the generators were paid incentives on the

basis of capacity index varying from 85% to 90%.

y Also the secondary energy charges were also to be paid to the generators for extrageneration in case of excess water availability.

Hence earlier, the generators were profiting from the secondary energy charges whereas

beneficiaries had to pay for the AFC even if the plant was generating less power on account oflesser water availability.

So the AFC were divided into two components:

1. Capacity Charges2. Energy charges

After division of AFC, the benefits and losses arising due to variation in availability of water will

be shared as follows:

y If, Actual generation = design energy, then complete recovery of AFC from beneficiaryy If, Actual generation > Design energy, partial sharing of benefits of secondary energy

with beneficiaries

y If, Actual generation < Design energy, partial sharing of losses on account of lowergeneration by generator

Earlier for the energy generated above the Design Energy charges was paid by the beneficiary at

the lowest variable cost of the central sector TPS in the region.

y Under the new norms, emphasis has been imparted to the Normative Annual PlantAvailability Factor (NAPAF) to meet the peak load requirements through hydro powergenerating stations.

y As the plant availability factor is defined as,PAF = Declared capacity/ Installed capacity (adjusted for auxiliary consumption)

y According to the new methodology to compute Capacity Charges, if the actual PAF isgreater than that of NAPAF, the generating company will be eligible for incentives.

Hence a benefit of the new Regulations for computing Capacity Charges based on PAF ratherthan CI is that for achieving higher PAF the generator will have to operate for at least 3 hours a

day close to installed capacity rather than operating at a steady load in order to get incentives.

But in case of lesser availability of water the generator will not be able to operate at peaking load

for 3 hours a day and hence resulting in lower recovery of fixed charges.

NORMS OF OPERATION FOR RECOVERY OF AFC:


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PARAMETER FOR

RECOVERY OF AFC

2004-09 2009-14

CAPACITY INDEX NPAF

1. Purely Run-of-River (RoR)

Stations

90% NPAF based on actual

hydrological data forpast 5 years

2. Storage type station or RoRwith pondage

85% -do-

AUXILIARY ENERGY CONSUMP

TION:

2004-09 2009-14

Surface Hydro

Generating Station

With rotating exciters 0.2% 0.7%

With static exciters 0.5% 1%

Underground HydroGenerating Station

With rotating exciters 0.4% 0.9%

With static exciters 0.7% 1.2%

AUX has clearly been increased for the regulatory period 2009-14 from that of 2004-09 whichwill finally lead to lesser energy available to the beneficiaries.

REBATE:

A rebate of 2% is allowed for payment of bills through letter of credit on presentation. There hasnot been any change in the Regulations of the earlier regulatory period to that of latest.

LATE PAYMENT SURCHARGE:

Earlier a late payment surcharge at the rate of 1.25% per month was levied by the generatingcompany for delay in payment of bills beyond 1 month which is now extended to 2 months.


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CALCULATION OF CAPACITY CHARGE AND ENERGY CHARGE FOR

BAIRASIUL HYDROELECTRIC PROJECT: A CASE STUDY BASED ON A

COMPARATIVE ANALYSIS OF CERC REGULATIONS 2004 AND 2009:

Capital cost:

The commission decided the capital cost for the purpose of tariff period 2004-09 as Rs.18112.37

lakh after considering the additional capitalization less the assets not in use of Rs.246.07 lakhand also considering the Foreign Exchange Rate Variation (FERV) of Rs.0.30 lakh.

(Rs. In Lakhs)

Capital Cost admitted as on 31.3.2001 17866.00

Additional Capitalization as approved for the years 2001-04, deducting

Assets not in use

246.07

FERV admitted for the tariff period 2001-04 0.30

Opening Capital Cost as on 1.4.2004 for the tariff period 2004-09 18112.37

Debt-Equity Ratio :

(Rs. In Lakhs) (%)

Debt 10327.37 57.02

Equity 7785 42.98

Total 18112.37 100.00

Components of Tariff:

The tariff for supply of electricity from a hydro generating station comprises of:

1. Capacity Charges and2. Energy charges,

These charges are used for the recovery of Annual Fixed Cost.


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Now compute the components of AFC based on the CERC Regulations 2004 and CERC

Regulations 2009 taking the tariff order of Bairasiul Hydroelectric Project for the tariff period of2004-09 as the base for computation and then compare the variation arising out of the difference

in Regulations.

1. RETURN ON EQUITY: Given Equity capital is Rs.7785 lakhs


At the rate of return on equity 14% (post tax)

RoE = Rs. 1089.90 lakhs


Base rate to compute return on equity is set at 15.5% (pre-tax).

Adjusting the rate of return according to the prevailing tax rate (33.99% MAT), as per thefollowing formula,

Rate of return on equity = Base rate/ (1-t)

Where, t- tax rate

Adjusted Rate of RoE = 15.5/ (1-0.3399) = 23.48%

Then, RoE = 23.48% of Rs. 7785 lakh

= Rs. 1828 lakh

Impact:

The return on equity has increased by applying the new Regulations which will help the

generator to cover its cost of capital more efficiently.

Since by new Regulations, tax on UI charges and incentives has not to be paid by the generator,it has also helped in increasing the Return on equity.

2. INTEREST ON LOAN CAPITAL: Given Loan capital is Rs.10327.37 lakh. Themethodology to compute Interest on loan capital as per 2004 Regulations and 2009 Regulations

is same.


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The only difference arises in case of refinancing of loan, for which 2004 Regulations passed onall the benefit to the beneficiaries (In efforts to refinance the loan, if the loan is acquired at a rate

lesser than the weighted average rate of interest then the benefit arising out of it will be entirely passed on to the beneficiary) but 2009 Regulations have divided the benefit of refinancing

among beneficiaries and generator in the ratio of 2:1.

But in the given case, there is no refinancing of loan. Hence, Interest on loan is the only criteria

which will help in determining the Annual Fixed Charges.

As per 2004 Regulations: The Interest on loan is computed as follows:

Year 2004-05 2005-06 2006-07 2007-08 2008-09

Gross Loan-opening 10081

Additional

Capitalization 246.07FERV 0.3

Gross Normative Loan: 10327.37 10327.37 10327.37 10327.37 10327.37

Cumulative Repayment

up to previous year 7581 10327.37 10327.37 10327.37 10327.37

Net Loan-opening 2746.37 0 0 0 0

Repayment duringYear 2746.37 0 0 0 0

Net Loan-closing 0 0 0 0 0

Average Net Loan 1373.185 0 0 0 0

Weighted Average

Rate of Return on Loan 12.50% 0% 0% 0% 0%

Interest on Loan 171.6481 0 0 0 0

(All figures in Rs. Lakh)

As per 2009 Regulations: The methodology to compute Interest on loan capital as per the CERC

Regulations 2009 is same as that of CERC Regulations 2004.

So the Interest on Loan = Rs. 171.65 lakh

Impact: In the given case of Bairasiul hydroelectric project, the interest on loan as theRegulations of 2004 and 2009 is not affected and hence there is no impact on it.

Rate of interest on loan which will be recovered as a part of the tariff is not affected and is samefor the Regulations of both the tariff periods of 2004-09 and 2009-14.


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3. DEPRECIATION: For the determination of Depreciation, the gross depreciable value of theasset is computed taking 90% of the gross block after deducting from it the cost of land (land is

not a depreciable asset).

Gross depreciable value = 0.90(Rs. 18112.37 lakh-Rs. 148.22 lakh)

= Rs 16167.73 lakh

The remaining depreciable value for the year 2004-05 has been derived from the historical data

and its value has been taken from tariff order 2004-09 of Bairasiul Hydroelectric project.(Cumulative Depreciation and AAD recovered up to 31.3.2004 is Rs. 7461.39 lakh. Remaining

depreciable value as on 1.4.2004 is thus Rs. 8706.35 lakh)

The entire loan is repaid during 2005-06. Therefore, Depreciation for the years 2005-06 to 2008-

09 has been spread over the balance useful life of the generating station. The balance useful lifeof the generating station works out to be 16.1 years as on 1.4.2005.

As per 2004 Regulations: Rate of Depreciation was fixed at 2.52% and Advance against

Depreciation (AAD) was also provided for till the cumulative repayment for a particular yearexceeded the cumulative Depreciation up to that year.

AAD is computed to be Rs. 576.85 lakh as the methodology described under next sub-head.AAD is used to compute remaining depreciable value of the asset for the subsequent years by

subtracting AAD and the amount of Depreciation allowed for that year from the remainingdepreciable value of the asset of the previous year.

YearUp to 31-03-2004 2004-05 2005-06 2006-07 2007-08 2008-09

Capital cost 17866

Additional

Capitalization 246.07

FERV 0.3

Gross Block 18112.37 18112.37 18112.37 18112.37 18112.37 18112.37

Depreciation

Rate of Depreciation 2.52%

Depreciable Value(less:

cost of land) 90% 16167.74 16167.74 16167.74 16167.74 16167.74Balance Useful Life ofthe Asset 17.1 17.1 16.1 15.1 14.1 13.1

Remaining DepreciableValue 8706.35 7673.612 7196.99 6720.368 6243.746

Depreciation 455.8884 476.6218 476.6218 476.6218 476.6218



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Advance against Depreciation (AAD): Cumulative Depreciation for calculation of AAD was

worked out considering Depreciation up to the year of calculation, excluding AAD of the year ofcalculation.

Advance against Depreciation was permitted only if the cumulative repayment up to a particularyear exceeded the cumulative Depreciation up to that year.

AAD = Loan repayment amount as per Regulation subject to a ceiling of 1/10th of loan amountminus Depreciation

AAD had been calculated according to the following methodology:

Year 2004-05 2005-06 2006-07 2007-08 2008-09

1/10th of Gross Loan(s) 1032.74 1032.74 1032.74 1032.74 1032.74

Repayment of the Loan 2746.37 0 0 0 0

Minimum of the above 1032.74 0 0 0 0Depreciation during Year 455.89 476.62 476.62 476.62 476.62

(A)Difference 576.85 -476.62 -476.62 -476.62 -476.62

Cumulative Repayment of

Loan 10327.37 10327.37 10327.37 10327.37 10327.37

Cumulative

Depreciation/AdvanceAgainst Depreciation 7917.28 8970.74 9447.37 9923.99 10400.61

(B)Difference 2410.09 1356.63 880 403.38 -73.24

Advance AgainstDepreciation(Minimum of

'A' & 'B') 576.85 0 0 0 0(All figures in Rs. Lakh)

As per 2009 Regulations: The rate of Depreciation in the new Regulations has been increased to

5.28%. Also, the Advance Against Depreciation (AAD) is not taken into account whilecomputing for Depreciation.

The following methodology is employed for the calculation of Depreciation:

Year

Up to 31-03-2004 2004-05 2005-06 2006-07 2007-08 2008-09Capital cost 17866

AdditionalCapitalization 246.07

FERV 0.3

Gross Block 18112.37 18112.37 18112.37 18112.37 18112.37 18112.37

Depreciation:


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Rate ofDepreciation 5.28%

Depreciable

Value(less:cost of land) 90% 16167.74 16167.74 16167.74 16167.74 16167.74

BalanceUseful Life of

the Asset 17.1 17.1 16.1 15.1 14.1 13.1

Remaining

DepreciableValue 8706.35 7750.017 7268.649 6787.282 6305.914

Depreciation 956.3331 481.3675 481.3675 481.3675 481.3675


Impact:

Apart from the change in rate of Depreciation and the adjustment according to AAD, there is no

other major difference in the methodology to compute Depreciation.

In 2004 Regulations, CERC allowed for AAD in case Depreciation rates were not sufficient to

meet the debt repayment obligation but in the 2009 Regulations concept of AAD is removed andat the same time the rate of Depreciation has been increased.

A slight increase in the amount of Depreciation has been observed as a result of change in the

rate of Depreciation which does not affect the annual fixed cost much and thus does not havemuch impact on tariff.

An increase of Rs. 500.44 lakh for the year 2004-05 and then a marginal increase of Rs. 4.75lakh for the rest of the years of tariff period have been observed.

4. OPERATION AND MAINTENANCE EXPENSES:

Since Bairasiul Hydroelectric Project was commissioned in the year 1982, hence it follows theregulations applied for plants which are in operation for more than five years which states to take

the average O&M expenses of previous five years as the base to compute the O&M expenses forthe subsequent years.

In the given case of Bairasiul Hydroelectric project, the average O&M expenses as on 2000-01have been taken as the base.

The average O&M Expenses for the year 2000-01 are reached as follows:

Year 1998-99 1999-00 2000-01 2001-02 2002-03 Average

base as on2000-01


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O&M

Expenses

2057 1980 2639 3091 3087 2570.8



To the average O&M expenses as on 2000-01, CERC Regulations 2004 fixed the escalation rateof 4% to compute O&M expenses for subsequent years:

Average O&M Expenses as on 2000-01 Rs.2570.8 lakh

Escalation Rate 4%2001-02 Rs.2673.632 lakh

2002-03 Rs.2780.577 lakh

2003-04 Rs.2891.8 lakh

Again the Regulations have fixed an escalation rate of 4% to compute the O&M expenses for the

tariff period 2004-09,

Year 2004-05 2005-06 2006-07 2007-08 2008-09

Escalation Rate 4%

O&M Expenses 3007.472 3127.771 3253.135 3382.882 3518.317(All figures in Rs. Lakh)


On the average O&M expenses as on 2000-01, CERC Regulations 2009 have fixed an escalationrate of 5.17% to compute O&M expenses for subsequent years:

Average O&M Expenses as on 2000-01 Rs.2570.8 lakhEscalation Rate 5.17%

2001-02 Rs.2703.71 lakh

2002-03 Rs.2843.492 lakh

2003-04 Rs.2990.501 lakh


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Again the Regulations have fixed an escalation rate of 5.72% to compute the O&M expenses forthe given tariff period,

Year 2004-05 2005-06 2006-07 2007-08 2008-09

Escalation Rate 5.72%

O&M Expenses 3161.557 3342.398 3533.584 3735.705 3949.387


Impact: As a result of increase in the escalation rates employed, the O&M expenses for the given

tariff period have also been covered more efficiently to provide for better recovery of theseexpenses through tariff.

O&M expenses have increased from Rs. 3007.42 lakh in 2004-05 to Rs. 3518.317 lakh in 2008-

09 for CERC Regulations 2004 whereas the same has increased from Rs. 3161.56 lakh to Rs.3949.39 lakh for CERC Regulations 2009.

5. INTEREST ON WORKING CAPITAL:

It is computed on the basis of three major components viz. Maintenance spares, Receivables andO&M expenses. The methodology to compute these factors is much the same in the two

Regulations except that of maintenance spares for which the basis has been changed in theRegulations of 2009.

The rate of interest on Working capital has been taken as the prevailing short term PrimeLending Rate (PLR) of State Bank of India (SBI) by the CERC Regulations for both the

Regulations of 2004 and 2009.

As per 2004 Regulations: The historical capital cost of Bairasiul Hydroelectric Project as on1.4.1982 was Rs. 14321 lakh.

Maintenance spares had been computed taking 1% of the historical capital cost which was then

escalated at a rate of 6% per annum.

1% of Historical Capital Cost(1982-83) Rs. 143.21 lakh


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capital


Impact: Only a marginal impact on the interest on Working capital between the two Regulations

of 2004 and 2009 has been observed as the rate of interest remains fixed to the Prime LendingRate (PLR) of State Bank of India.

ANNUAL FIXED CHARGES:


Year 2004-05 2005-06 2006-07 2007-08 2008-09

Depreciation 455.89 476.62 476.62 476.62 476.62

Interest on Loan Capital 171.65 0.00 0.00 0.00 0.00

Return on Equity 1089.90 1089.90 1089.90 1089.90 1089.90

Advance Against

Depreciation 576.85 0.00 0.00 0.00 0.00

Operations & Maintenance

Expenses 3007.47 3127.77 3252.88 3383.00 3518.32

Interest on Working capital 172.11 165.82 172.50 179.52 186.89

Total Annual Fixed Charges 5473.86 4860.11 4991.90 5129.04 5271.73



Year 2004-05 2005-06 2006-07 2007-08 2008-09

Depreciation 956.33 481.37 481.37 481.37 481.37Interest on Loan Capital 171.65 0.00 0.00 0.00 0.00

Return on Equity 1828.00 1828.00 1828.00 1828.00 1828.00

Advance Against

Depreciation 0.00 0.00 0.00 0.00 0.00

Operations & Maintenance

Expenses 3161.56 3342.40 3533.58 3735.70 3949.39

Interest on Working capital 169.13 162.97 169.79 176.97 184.51


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Total Annual Fixed Charges 6286.67 5814.73 6012.74 6222.03 6443.26


Impact:

Taking the data set of tariff order 2004-09 of Bairasiul Hydroelectric Project as a basis for

computation and comparison of Annual charges payable to the generator on the ground of twodifferent Regulations periods viz. CERC Regulations 2004 and CERC Regulations 2009, it is

observed that the New Regulations have resulted in an increase in the Annual fixed charges.

An increase of approximately 15% to 22% has been observed in the Annual Fixed cost as per theCERC Regulations 2009 when compared with CERC Regulations 2004.


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COMPUTATION OF CAPACITY CHARGE AND ENERGY CHARGE FOR

BAIRASIUL HYDROELECTRIC PROJECT:

As per 2004 Regulations: As discussed in the qualitative analysis of the CERC Regulations,

employing the methodology to compute annual charges as given in the 2004 Regulations was asfollows:

Capacity Charges = Annual Fixed Charges-Primary Energy charge

Primary Energy charge = Saleable Primary energy x Primary Energy rate

Given for FY 2004-05, Annual Fixed Charges (AFC) = Rs. 5473.86 lakh (as computed above)

Primary Energy rate = 69.47 paisa/kWh or 0.6947 Rs. /kWh (as per the Bairasiul Hydroelectric

Project Tariff order for 2004-09)

Design Energy for an year = 77982.80 LU (as per the Bairasiul Hydroelectric Project Tariff orderfor 2004-09)

FEHS = Free Energy for Home State = 12% (defined in CERC Regulations 2004)

Saleable Primary Energy (for a month) = Scheduled Energy for a month x (1-FEHS)

= 77982.80 x (1-0.12) = 6857.66 LU

Therefore, Primary Energy charge = 6857.66 LU x 0.6947 Rs. /kWh =Rs. 4764.019 lakh

Hence, Capacity Charges = Rs. 5473.86 lakh- Rs. 4764.019 lakh = Rs. 709.84 lakh

Since the incentives were not inclusive into the Capacity Charges in 2004 Regulations, thosewere computed separately as given below,

Incentives for a month = 0.65 x AFC x (CIA-CIN)/100

Where CIA = capacity index achieved = 93% (given in Tariff order 2004-09 of Bairasiul HP)

CIN = normative capacity index = 85% (given in Tariff order 2004-09 of Bairasiul HP)

Incentives for a month = 0.65 x Rs. 5473.86 lakh x (93-85)/100 = Rs. 284.64 lakh

Incentives for a year = 12 x Rs. 284.64 lakh = Rs. 3415.69 lakh

Thus, Capacity Charges inclusive of incentives = Rs. 709.84 lakh + Rs. 3415.69 lakh

= Rs. 4125.54 lakh

As per 2004 Regulations Capacity Charges including incentives are Rs.4125.54 lakh for the year

2004-05.

Similarly Capacity charges for the rest of the years of the tariff period 2004-09 have been

computed. This calculation has been shown in the table form as follows:


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For FY 2004-05:

Units FY 2004-05

AFC lakh 5473.86

Saleable primary

energy

LU 6857.66

design energy LU given in tariff

order

7792.8 7792.8

FEHS given in tariff

order

0.12

Primary Energy

rate

Rs. given in tariff

order

0.6947

PEC lakh 4764.0192

CC lakh 709.84

CIa % given in tarifforder

93

CIn % given in tarifforder

85

Incentive lakh 284.64092

Incentive for 1 year lakh 3415.691

CC inclusive of

Incentivelakh 4125.54


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For FY 2005-06:

Units FY 2005-06

AFC Lakh 4860.11

Saleable primaryenergy

LU 6857.66

design energy LU given in tarifforder

7792.80 7792.80

FEHS given in tarifforder

0.12

Primary Energy

rate

Rs. given in tarifforder

0.6947

PEC Lakh 4764.0192

CC Lakh 96.09

Cia % given in tariff

order93

Cin % given in tariff

order85

Incentive Lakh 252.72577

Incentive for 1 year Lakh 3032.7092

CC inclusive of

IncentiveLakh

3128.80


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For FY 2006-07:

Units FY 2006-07

AFC Lakh 4991.90


LU 6857.66


7792.80 7792.80

FEHS given in tarifforder

0.12

Primary Energy

rate

Rs. given in tarifforder

0.6947

PEC Lakh 4764.0192

CC Lakh 227.88


order93

Cin % given in tarifforder

85



CC inclusive of

IncentiveLakh

3342.83


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For FY 2007-08:

Units FY 2007-08

AFC Lakh 5129.04


LU 6857.66


7792.80 7792.80


order0.12

Primary Energy

rate

Rs. given in tariff

order0.6947

PEC Lakh 4764.01918

CC Lakh 365.02

Cia % given in tarifforder

93

Cin % given in tarifforder

85



CC inclusive of

Incentivelakh

3565.54


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For FY 2008-09:

Units FY 2008-09

AFC Lakh 5271.73


LU 6857.66

design energy LU given in tariff

order7792.80 7792.80


order0.12

Primary Energy

rate

Rs. given in tariff

order0.6947

PEC Lakh 4764.01918

CC Lakh 507.71


order93

Cin % given in tariff

order85



CC inclusive ofIncentive

Lakh3797.26


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As per 2009 Regulations: The methodology to compute Capacity Charges has been changedfrom earlier by using plant availability factor instead of Plant load factor which helps in

computation of Capacity Charges inclusive of incentives as follows,

Capacity Charge for a month (inclusive of incentive) =

AFC x 0.5 x (NDM/NDY) x (PAFM/NAPAF)

Where, AFC = Rs. 6286.67 lakh (as computed above)

NDM = no. of days in a month = 30 (approx.)

NDY = no. of days in a year = 365

PAFM = Plant availability factor for a month = 93% (average of operational data given in FinalREA report of NRPC as on March 2009)

NAPAF = Normative Annual Plant Availability Factor = 85 % (for a hydro power plant)

Therefore, CC for a month = Rs. 6286.67 lakh x 0.5 x (30/365) x (93/85) = Rs. 282.67 lakh

CC for a year = 12 x Rs. 282.67 lakh = Rs. 3392.07 lakh

Also, Energy charge = Energy Charge rate x Scheduled energy for a month x (100-FEHS)/100

And Energy Charge rate = AFC x 0.5 x 10 / {DE x (100-AUX) x (100-FEHS)}

Where, DE = Design Energy = 779.28 MU or 779280 MWh (given in the Tariff order 2004-09

of Bairasiul HP)

AUX = Auxiliary consumption = 1% (approx.) (CERC Regulations)

FEHS = Free Energy for Home State = 12% (approx.) (CERC Regulations)

Scheduled energy for a month = 387 LU (Operational data given in Final REA report of NRPC

as on March 2009)

Hence, Energy Charge rate = Rs. 6286.67 lakh x 0.5 x 10 / {779280 x (100-1) x (100-12)}

= Rs. 0.46299 / kWh

And Energy charge = Rs. 0.46299 / kWh x 387 LU x (100-12)/100 = Rs. 157.68 for a month

Energy charge for an year = 12 x Rs. 157.68 = Rs. 1892.14 lakh

Total Capacity Charge inclusive of incentives = Rs. 3392.07 lakh + Rs. 1892.14 lakh

= Rs. 5284.21 lakh

As per 2009 Regulations, total Capacity Charges including incentives are Rs. 5284.21 lakh for

the FY 2004-05.


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Similarly Capacity charges for the rest of the years of the tariff period have been computed,which are summarized as below the table form:

For FY 2004-05:

Units FY 2004-05

AFC Lakh 6286.67

NDM Days 30

NDY Days 365

PAFM % 93

NAPAF % 85

AUX % 1

FEHS % 12

DE MWh 779280

SE LU 387

CC Lakh 282.672

CC for 1 year Lakh 3392.0659

Numerator Lakh 31433.347 3143334699

Denominator 6789087360

ECR Rs./kWh 0.462

Energy charge(for 1month)

Lakh157.67

Energy charge for 1

year

Lakh1892.14

Total Capacitycharge inclusive of

incentive

Lakh

5284.21


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For FY 2005-06:

Units FY 2005-06

AFC Lakh 5814.73

NDM Days 30

NDY Days 365

PAFM % 93

NAPAF % 85

AUX % 1

FEHS % 12

DE MWh 779280

SE LU 387

CC Lakh 261.452


Numerator Lakh 29073.659 2907365996


ECR Rs./kWh 0.428


Lakh145.841

Energy charge for 1year

Lakh1750.10

Total Capacity chargeinclusive of incentive

Lakh

4887.53


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For FY 2006-07:

Units FY 2006-07

AFC Lakh 6012.74

NDM Days 30

NDY Days 365

PAFM % 93

NAPAF % 85

AUX % 1

FEHS % 12

DE MWh 779280

SE LU 387

CC Lakh 270.355


Numerator Lakh 30063.692 3006369273


ECR Rs./kWh 0.4428


Lakh150.808


Lakh1809.69


Lakh5053.95


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For FY 2007-08:

Units FY 2007-08

AFC Lakh 6222.03

NDM Days 30

NDY Days 365

PAFM % 93

NAPAF % 85

AUX % 1

FEHS % 12

DE MWh 779280

SE LU 387

CC Lakh 279.765


Numerator Lakh 31110.173 3111017345


ECR Rs./kWh 0.458


Lakh156.057


Lakh1872.69


Lakh

5229.88


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For FY 2008-09:

Units FY 2008-09

AFC Lakh 6443.26

NDM Days 30

NDY Days 365

PAFM % 93

NAPAF % 85

AUX % 1

FEHS % 12

DE MWh 779280

SE LU 387

CC Lakh 289.713


Numerator Lakh 32216.299 3221629945


ECR Rs./kWh 0.4745


Lakh161.606


Lakh1939.27

Total Capacitycharge inclusive of

incentive

Lakh

5415.83


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DIFFERENCE IN THE ANNUAL CHARGES AS PER CERC REGULATIONS 2004

AND CERC REGULATIONS 2009:

The number of units is taken as equal to the Design Energy i.e. 6789.09 LU, after adjustment forfree energy for home state (FEHS) and auxiliary consumption (AUX),

Design Energy = 7792.8 LU

No. of units = Design Energy x (1-AUX) x (1-FEHS) LU =7792.8 x (1-.01) x (1-.12) = 6789.09

LU

Then we calculate the Capacity Charges per unit for the CERC Regulations for 2004 and 2009 as

follows:

As perCERCRegulations 2004:

Year Capacity Charges (Rs. lakh)

no. of units(LU)

Capacity Charges per

unit

2004-05 4125.54 6789.09 0.60772005-06 3128.80 6789.09 0.4609

2006-07 3342.83 6789.09 0.4924

2007-08 3565.54 6789.09 0.5252

2008-09 3797.26 6789.09 0.5593

As perCERCRegulations 2009:

Year Capacity Charges (Rs. Lakh) no. of units(LU) Capacity Charges per

unit

2004-05 5284.21 6789.09 0.77832005-06 4887.53 6789.09 0.7199

2006-07 5053.96 6789.09 0.7444

2007-08 5229.88 6789.09 0.7703

2008-09 5415.83 6789.09 0.7977


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Difference in Annual charges for the CERC Regulations 2004 and 2009: According to theabove analysis the difference between the Capacity Charges per unit of energy calculated with

the help of CERC Regulations 2004 and 2009 is observed which shows that there is an increasein the Generation Tariff as per CERC Regulations 2009 when compared to CERC Regulations

2004.

Year Difference of Capacity Charges(Rs Lakh)

difference in Capacity Charges per unit(Rs/unit)

2004-05 1158.67 0.1707

2005-06 1758.73 0.2591

2006-07 1711.13 0.2520

2007-08 1664.34 0.2451

2008-09 1618.57 0.2384

There is an approximate increase of 30% to 50% in the Capacity Charges per unit after

implementation of CERC Regulations 2009 in place of CERC Regulations 2004.

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