electricity pricing and generation tariff - sks_badarpur

7/31/2019 Electricity Pricing and Generation Tariff - SKS_Badarpur

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ELECTRICITY PRICING

ANDGENERATION TARIFF

By-S. K. SharmaDGM(Commercial)

NTPC


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Principles of Pricing

Correct pricing signal to investors and consumers

Stable and predictable over the tariff period avoid

tariff shocks

Protect interest of consumer and investors risk Incentive for efficiency improvement and promoting

rational use of electricity

Consider socio-economic need of the country to

ensure supply and services even to low income group

Tariff determination to be transparent and simple

Encourage market determination of prices


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Objectives

Promote competition, efficiency in the economy

Reliable and quality of power supply

Adequate supply to meet the demand Optimum generation on merit order basis

Adequate transmission network to facilitate power flow

to different parts of the country

Promote supply with the environmental norms

Sound commercial practices


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Options for Electricity Pricing

Rate of Return (ROR) / Cost of Service Regulation

Performance Based Regulation (PBR)

Hybrid Sliding Scale Method

(RPIX) Price / Revenue Cap Regulation

Long Run Marginal Cost (LRMC)

Competitive Bidding

Price Determination by Market Mechanism


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Rate of Return/Cost of Service Regulation

This is a cost plus pricing strategy.

It is based on determination of allowable capital cost

and a fair rate of return.

Variable cost is on actuals based on the data of the testyear.

Advantages

It is a familiar traditional approach. Provides steady predictable return to utilities for

reinvestment


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Limitations

Investor has a tendency to over invest as capital cost formsbasis for earning return.

It is a backward looking approachcontinue to pay based

on historic cost even if the investment has become

unproductive.

Pricing is independent on future price signals.

No incentive to utility to reduce cost or improve efficiency

as reduction in cost is pass through to consumers.

As this is based on cost of service, pricing is normally

reviewed and fixed on yearly basis, resulting in frequent

tariff variations.

Rate of Return / Cost of Service Regulation contd..


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Performance Based Price Regulation

(PBR) This is based on set of performance targets both

financial and operational. Pricing is based on financial

parameters like-

capital cost;

debt:equity ratio;

rate of return; and

variable cost

are based on normative operating parameters such as heat rate,auxiliary power consumption, plant load factor (PLF) etc. forgeneration tariff.


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Advantages

Provides incentive to utility to perform efficiently as

efficiency gains are retained by the utility.

Norms are fixed for a tariff period of 4-5 years avoiding

frequent tariff revisions.

Limitations

Difficulty in benchmarking of performance data.

In order to maximise gains, utility tends to sacrifice qualityof service.

In case norms are liberal, consumers pay more and in case

norms are stringent / not achievable investor may end up

in losing.

Performance Based Regulation (PBR) contd..


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Hybrid Sliding Scale

This combines features of both Rate of Return (ROR)and Performance Based Regulation (PBR).

Cost related to financial aspects are normally based on

actuals and those related to operating parameters are

based on norms.

This mode of regulation is normally used for transition

from ROR to PBR.


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(RPIX) Price/Revenue Cap Regulation

It imposes a price cap for the tariff period

The price cap can be only to the extent of retail priceinflation (RPI) after accounting for pre-defined efficiencygains.

Formula for Regulation : Pn = P-1 {1+(RPI-X)} + Z

Where,

Pn = Price cap for the current year

P-1= Average price for the previous yearRPI = Retail Price Index in %age

X = Impact of efficiency gain in %age

Z = External changes not related to inflation or productivity such asGovt. taxes, levies, duties etc.


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Advantages : Utility has flexibility to incur cost and retain efficiency

improvement measures, upgradation etc. as long asthese are within the price cap.

Choice and technology and fuels is left to the utility. Benefits of the efficiency gains are shared by the utility

and the consumer.

Limitations :

Difficulty in assuming productivity / efficiency gainfactor.

Appropriateness of RPI indices for power sector.

(RPIX) Price/Revenue Cap Regulation contd..


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Long Run Marginal Cost (LRMC) Method

LRMC is based on future cost of power which takesinto account additional investment required for

capacity addition and projected fuel cost.

LRMC pricing is based on

Estimation of future expansion plan for a period of

20-25 years

Estimation of capital cost for the capacity addition

Future demand and supply projections

Impact of technological developments on cost of

capital and requirement of power


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Advantages : Correct price signal to consumer regarding cost of

power being consumed.

Provides sufficient investable funds for future capacity

addition

Promote economic generation

Tariff not based on historical cost but more guided

towards market requirements. Old investment can be leveraged for generation of

resources for capacity addition.

Long Run Marginal Cost (LRMC) Method contd..


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Limitations :

Number of assumptions like future capacity addition

requirement, projected cost, cost of capital etc.

Any wrong estimation in any of the parameters may

result in unaffordable tariff.

For any change in the above factors, corresponding

changes in tariff is necessary.

Long Run Marginal Cost (LRMC) Method contd..


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Competitive Bidding

Electricity pricing under competitive bidding is based on

selection of utility through market competition.

Under competitive bidding tariff based bids are invited

and utility is awarded the project based on least tariffbasis.

Tariff so arrived at is fixed for the life of the project.

For effective competitive bidding, it is necessary to laydown guidelines for the bidding and ensure

transparency in the bidding process.


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Advantages :

This method provides fixed tariff of the life of the

project and all risks associated with project cost over-

run are to be taken by the investor.

There is no need to fix financial and operating norms.

Consumer is aware about the cost he has to pay for the

life of the project and provide a stable tariff basis.

Competitive Bidding contd..


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Market Mechanism

This is dependent on the presence of large number of

suppliers and consumers in the market.

For pricing through market mechanism, it is necessary

that electricity industry has to be structured itself into the

market so that adequate freedom is available to the

consumer and purchaser for carrying out the business inthe market.

For this mechanism, it is necessary to unbundle

generation, transmission and distribution business and

create large number of players in each industry segment.

Monopoly in bulk power supply to be dispensed with.

Non-discriminatory open access in transmission and

distribution system is a pre-requisite.


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Advantages

There is no need to regulate pricing of electricity

Prices are determined by demand and supply in the

market.

Competition encourages efficiency in operation and

low cost of power

It promotes investment for capacity addition.

It provides a market situation to the consumers and

sellers avoiding monopoly in supplies.

Market Mechanism contd..


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Limitations

In energy deficit conditions prevailing in of the

countries under such mechanism, utility/seller will try

to take undue advantage and prices may increaseabnormally.

In case market is not fully developed, utilities may

manipulate the market to increase price for their gain

California crises.

Switchover to market has to be very gradual.

Market Mechanism contd..


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GENERATIONTARIFF


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Tariff Principles

Regulatory Commission to determine tariff for supply of

electricity by generating co. on long/medium term contracts.(Section 62)

No tariff fixation by regulatory commission if tariff is determinedthrough competitive bidding or where consumers, on beingallowed open access enter into agreement with generators/traders.

Consumer tariff should progressively reduce cross subsidies andmove towards actual cost of supply. (Section 61 (g))

State Government may provide subsidy in advance through thebudget for specified target groups if it requires the tariff to be

lower than that determined by the Regulatory Commission.(Section 65)

Regulatory Commissions may undertake regulation includingdetermination of multi-year tariff principles, which rewards

efficiency and is based on commercial principles. (Section 61 (e),


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DIFFERENT TARIFF PROVISIONS

0

20

40

60

80

100

120

140

160

180

0 20 40 60 80 100 120

DEEMED PLF(AVAILABILITY)

FIX

EDCHARGES

INCENTIVE

SINGLE PART

KPRAO

CERC ORDER


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Generation tariffof regional stations consists of-

Capacity charges Energy charges

UI charges

Capacity charges are recovered at 80% availability & pro-rata

recovery below 80%. For generation above 80%, PLF incentive atthe rate of 25 paise/Unit

Energy charges are based on actual fuel cost and normative

operating parameters. Energy charges are paid based on scheduled

generation.

UI charges are linked to frequency and are levied on deviations from

schedules.

Availability Based Tariff


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UI Charges

0

100

200

300

400

500

600

700800

48

.8

48

.9

49

49

.1

49

.2

49

.3

49

.4

49

.5

49

.6

49

.7

49

.8

49

.9

50

50

.1

50

.2

50

.3

50

.4

50

.5

50

.6

Freqency (Hz.)

Rate(P/Unit)


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UI Charges

Max. UI rate increased to 745 p/unit.

A band has been provided for generation above DC. (5%

above DC in any time block, restricted to 1% over a day

for payment of UI for generation above DC has been

provided)


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Capacity charges consists of

Return on equity (ROE)

Interest on Loan

Depreciation

O&M Cost

Interest on Working Capital

Generation Tariff


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Tariff Period - 5 years

Debt : Equity Ratio - 70:30 In case equity is more than 30% it shall be limited to 30%

and excess equity shall be treated as normative loan and

shall be serviced at weighted average rate of interest ofthe outstanding loan.

As per this provision, for the stations where debt:equity

ratio was 50:50, it will now be 70:30 and equity in excess

of 30% will be treated as notional loan.


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Capital Cost For existing stations

Admitted by Commission upto 31.3.2001

+ Addcap & FERV for the period 2001 - 2004.

For new stations

Actual expenditure capitalised

+ Spares @ 2.5% for coal based stations & 4% for gas basedstations & 1.5% for hydro station.

Return on Equity

14% post tax Income Tax pass through on Generation Income.


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Interest on loan

On weighted average actual interest rate

Outstanding loan as on 31.3.2004

Normative repayment during 2004-09.

Interest on loan has been allowed on normative outstanding loan.

Commission has further said that during the period of moratorium,

depreciation recovery shall be considered towards loan repayment

while working out interest on loan.


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Depreciation On straight line basis

3.6% - coal based stations

6% - gas based stations

2.57% - Hydro

Advance Against Depreciation Limited to 1/10th of loan amount i.e. Dep + AAD = 7%

(maximum)


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Interest on working capital

Fuel Cost

Coal based stations - 1 month for pit head and 2 months for non-pithead corresponding to target availability.

Gas based Stations Cost of fuel for 1 month

Secondary Fuel

Coal based stations Cost of secondary fuel oil for 2 months

Gas based Stations Cost of Liquid fuel for month.

O&M expenses for 1 month

Spares 1% of historical capital cost escalated @ 6% from COD.

2 months receivables

Earlier provisions for stock of coal & oil were on normative stock or

actual whichever is lower. Now it has been provided on normative basis.


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These are now fixed on normative basis about 2.5% of

current capital cost.Coal based stations

- 200/210/250 MW - Rs.10.4 lacs/MW

- 500 MW and above - Rs. 9.36 lacs/MW

Gas based stations

- Stations with warranty spares - Rs. 5.2 lacs/MW

- Without warranty spares - Rs. 7.8 lacs/MW

Escalation

4% per year

Tanda & Talcher TPSsO&M cost provision have been

provided based on actual of last 5 years

O&M Charges


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Operating Norms

Heat Rate- 200 MW - 2500 kcal/kwh (same as earlier)

- 500 MW - 2450 kcal/kwh (reduced by 50 kcal/kwh).

In case of MDBFP Heat rate will be reduced by 40

kcal/kwh.- Gandhar / Faridabad / Kayamkulam - 2000 kcal/kwh

- Dadri / Anta / Kawas - 2075 kcal/kwh

- Auraiya - 2100 kcal/kwh

- Future gas based stations

1850 kCal/kwh for Advanced class

1950 kcal/kwh for conventional machines


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Specific Oil Consumption 2 ml / kwh (reduced from - 3.5 ml/kwh)

Auxiliary Power Consumption

Stabilisation Period 180 days allowed only upto March, 2006.

No relaxed norms for target availability have been allowed during stabilisation period.

Without cooling tower With cooling tower

200 MW 8.5 9.0

500 (TDBFP) 7.0 7.5

500 (MDBFP) 8.5 9.0

Gas Stations

Open Cycle 1.0

Combined Cycle 3.0


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Target Availability - 80%

Disincentive pro-rata of fixed charges

Incentive at flat rate of 25 paise/unit on generation above

80% scheduled PLF.

Coal Losses Landed cost of coal shall be computed considering transit

loss of-

CERC Norm- Pit Head 0.3%

- Non Pit Head 0.8%


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Other Provisions

Provision regarding actual or norm whichever is lower hasbeen deleted. It will provide efficiency gain from future

stations.

Commercial Operation Date

Earlier regulation stipulated a period of 180 days between

synchronisation of a coal unit and its commercial

operation.

This provision has been deleted. It is a welcome

change.


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Typical Example

Thermal Power Station of 1000 MW

(Capital CostRs. 4 Crs/MW)

Fixed Charges 743.89

1 Return on Equity Annexure-1 192.00

2 Interest on Loans Annexure-2 189.40

3 Depreciation Annexure-3 214.88

4 O&M Expenses Annexure-4 112.74

5 Interest on Working Capital Annexure-5 34.87

Rs./Cr.

Variable Charges Annexure-6 59.34

Ps./kWh


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Thermal Power Station of 1000 MWUnit

Capacity MW 1000

Normative Availability for Fixed cost recovery %age 80

Generation at norm Availability MUs 7008

Energy Export at norm PLF MUs 6447

Normative Heat Rate Kcal/kWh 2500

Normative Aux. Consumption %age 8Specific Oil Consumption ml/kWh 3.5

Financial Parameters :

Capital Cost Rs./Cr. 4000

Debt:Equity Ratio Ratio 70:30

Rate of Return on Equity %age 16.00Interest on Loans %age 8.5

Depreciation Rate %age 3.6

O&M expenses %age 2.50

Rate of Interest on Working Capital %age 12.0


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Return on Equity


Debt:Equity Ratio %age 70:30

Equity Rs./Cr. 1200

Return on Equity %age 16.00

Return Rs./Cr. 192

Annexure - 1

Annexure - 2


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Interest on LoansParticulars Unit Amount


Debt:Equity Ratio %age 70:30

Normative Gross Loans Rs./Cr. 2800

Net Loans Rs./Cr.

Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Average

Gross Loans 2800 2800 2600 2400 2100 1800

Repayments 200 200 300 300 200

Net Loan 2800 2600 2400 2100 1800 1600

Average Net Loan 2700 2500 2250 1950 1700 2220

Weighted Average Rate of Interest

Sources of Loans Amount Rate of Interest

US$ Rs./Cr. 1500 7

DM Rs./Cr. 200 5

SBI Newyork US$ Rs./Cr. 200 7.5HDFC Rs./Cr. 300 12

SBI Rs./Cr. 200 12.5

Uncommitted Debt Rs./Cr. 400 12.0

Weighted Rate of Interest 8.5

Interest on Loan Rs./Cr. 189.4


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Calculation of DepreciationAnnexure - 3

Particulars Unit

Capital Cost (excluding WCM) Rs./Cr. 4000

Rate of Depreciation %age 3.6

Depreciation Rs./Cr. 144

Rs./Cr.

Year-1 Year-2 Year-3 Year-4 Year-5 Average

Capital Cost 4000 4000 4000 4000 4000

Depreciation 144 144 144 144 144 --

Advance against Depreciation 93.2 93.2 93.2 93.2 93.2 --

Loan Repayment 200 200 300 300 200 --

Allowed Dep + AAD 200 200 237.2 237.2 200 214.88


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Operation and Maintenance ExpensesAnnexure - 4

Particulars Unit

Capital Cost (excluding WCM) Rs./Cr. 4000

O&M Cost %age 2.5

O&M Escalation Rate %age 6

O&M Expenses Rs./Cr. 112.74

Rs./Cr.

Year-1 Year-2 Year-3 Year-4 Year-5 Average

Capital Cost 4000

O&M Expenses 100 106 112.36 119.10 126.24 112.74


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Interest on Working CapitalAnnexure - 5

Particulars Norms Unit Amounts BasisContents:

O&M Exp. 1 Month Rs./Cr. 9.4 1/12th of O&M expenses (Annexure-4)

Spares 1 Year Rs./Cr. 45.1 40% of O&M expenses (Annexure-4)

Fuel 1 Month Rs./Cr. 31.88 Variable rate (Ann-6) 59.34ps/kWh

multiplied by {6447MUs/(12*10)}

Coal 15 days Rs./Cr. 14.83 Variable rate from Ann-6 (coal)multiplied by {6447MUs/(24*10)}

Oil 2 Months Rs./Cr. 4.43 Variable rate from Ann-6 (oil) multipliedby {6447MUs/(6*10)}

Receivables 2 Months Rs./Cr. 185 Fixed+Variable charges for two monthssupply at 80% Availability

Total WC Rs./Cr. 290.6

Interest on netWC

Rs./Cr. 34.87


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Variable Charges - Oil

Annexure - 6

Particulars Unit

Price of Oil Rs./Kl 10866.35

GCV of Oil kCal/lr 9977

Specific Oil Cons.

(Normative)

Ml/kWh 3.50

Heat Rate kCal/kWh 35

Variable Charges Ps./kWh 4.13

Total Variable Charges : 59.34 ps/kWh

Variable Charges - CoalParticulars Unit

Price of Coal Rs./MT 832.25

GCV of Coal kCal/Kg 4039

Specific Oil Cons. Kg/kWh 0.610

Heat Rate

(2500-Heat from Oil)

kCal/kWh 2465

Variable Charges Ps./kWh 55.21


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Fuel Price Adjustment Formula :

FPA = (10*Ho) * (Pom Pos) + 10*Hc * (Pcm Pcs)

(ps./kWh) (100-AC) (Kom Kos) 100-AC (Kcm Kcs)

Ho = Heat from Secondary Fuel as derived35 kCal/kWh

AC = Aux. Consumption adopted in tariff in %age 8%.

Pom = Weighted average price of Fuel Oil as per PSL at the end of Month in Rs./Kl.

Kom = Weighted average GCV of Fuel Oil on fired basis during the month in kCal/ltr.

Pos = Weighted average price of Fuel Oil as taken for initial fixation of tariff Rs./Kl

10866.35

Kos = GCV of Fuel Oil as taken for initial fixation of tariff 9977 in kCal/ltr.

Hc = Heat from Coal as derived(2500heat from Oil) in kCal/kWh.

Pcm = Weighted average price of coal as per PSL at the end of Month in Rs./MT.

Kcm = Weighted average GCV of Coal on fired basis during the Month in kCal/kg.

Pcs = Weighted average price of coal as taken for initial fixation of tariff Rs./MT

832.25

Kcs = GCV of Coal as taken for initial fixation of tariff 4039 in kCal/kg.


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electricity pricing and generation tariff - sks_badarpur

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