availability based tariff. highlights of cerc order dated 4.1.2000 on abt 1. order applicable to...

AVAILABILITY BASED TARIFF

HIGHLIGHTS OF CERC ORDER DATED 4.1.2000 ON ABT

1. ORDER APPLICABLE TO J&K ALSO.

4. ABT WAS TO BE IMPLEMENTED IN ALL THE REGIONS AS UNDER :

SREB 1.4.2000EREB 1.6.2000NREB 1.8.2000WREB 1.10.2000

3. ABT NOT APPLICABLE TO BBMB AND CHUKHA PROJECTS.

2. THE ORDER WAS MAINLY ON NTPC STATIONS..

Session outline

- Concept of electricity pricing- Tariff component- Two part tariff structure

- Concept of ABT - ABT tariff structure- What next ?

PRINCIPAL CONCEPT OF TARIFF SETTING

Rate of Return (ROR)/ Cost of Service

• Requires determination of– Allowable costs

– Rate base which represents the historic cost of the assets employed.

– Accumulated depreciation

– Rate of return on the rate base

Advantages

– Traditional approach and familiar to utilities, users and regulatory agencies

– Simple, unambiguous and fair.

– Provides predictable, steady returns to the utilities and hence conducive for further investments.


Disadvantages– Tendency to over invest for higher return to the

investor.

– Since the net return is fixed and any reduction in costs or increase in revenue is passed through

to consumer, there is little motivation to reduce the cost and make efficiency gains.

– Inflexibility of tariffs over the tariff period and the time lag for tariff revision


A cost plus electricity pricing mechanism

RR = [RB X RoR] + ED + EO&M + TWhere:

RR = the total annual revenue requirement of the utility

RB = the rate base (required investment) of the utility

RoR = the allowed rate of return (debt and equity) on investment.

ED = annual depreciation expense

EO&M = annual operation & maintenance (O&M) expense

T = annual taxes paid by the utility

b) Performance Based Regulation (PBR)

•In this method the utilities are given–A set of operational performance criteria

–A set of financial performance criteria

–Targets are set using time series data, trends of system costs and operational performance.

–Over achievement can increase return while under achievement will decrease the same

b) Performance Based Regulation (PBR)

•Advantages–More stable tariffs

–More predictable regulatory environment

•Disadvantage

•Unearned gains can boost the returns.

c) Retail Price Inflation (RPI) - X

•This method–Imposes a price cap

–Can be crossed only to the extent of retail price inflation

–X factor indicates the decrease in tariff on account of operational deficiencies.

–Inflation would allow for price changes due to uncontrollable costs.

–Determination of X factor done on actual costs and efficiencies of a range of power stations and transmission lines.

Competitive Bidding

•This is basically a market-based approach and hence requires less transaction cost relative to other methods of tariff determination.

Tariff Structure

Flat Rate- single part (p/kWh) -prior to 1991

Two part Tariff ( K.P.Rao) - 1991 to till dateFixed ChargesVariable Charges

Availability Based -2001/ 2004Capacity chargeEnergy chargeUnscheduled interchange

Tariff Structure - Two part tariff

Worldly most accepted structureIt has inbuilt efficiencyCapacity charge component based upon the customer capacity utilization.Energy charge to cover the cost of energyIt encourage economic dispatch and the financing of generation resourcesIt improves the optimization of consumption patterns.

Two part tariffComponents of Fixed Charges

• Return on Equity– capital cost for tariff is the cost as approved by

CEA– Debt equity ratio 70:30 for investments

approved after March 1992– ROE - 16% allowed

• Interest on Loan capital– weighted average of the interest rate applicable

on the outstanding project loans

• Depreciation– Notified by the GoI– 7.84 % Coal based , 8.24% Gas based

• O&M ExpensesNormative– 2.5 % of the current capital cost– or 2% of current capital cost + Insurance total

not exceeding 3%



• Interest on working capital– Rate of interest is the current cash credit interest

charged by the bankers– Working capital Norms

• Two months receivables• spares for 1- year• Coal stock- 15days/1 month for pit-head/others• Oil Stock for 1 month• Fuel expenses and O& M expenses for 1 month

• Taxes on income



• Normative and based on operational performance

• The Norms– Plant Load factor

• 4500 Hours /kW/year during stabilisation period and 6000 hours/kW/year there after ( corresponds to a PLF of 68.49%)

Variable ChargesVariable Charges

– Sp.Oil Consumption• 5 ml/ kwh for 1st year after commercial operation and

3.5 ml/kwh there after

– Heat Rate• 2600kcal/kwh for 1st year after commercial operation

and 2500kcal/kwh there after( 40kcal/kwh reduced for electrically driven BFPs)


– Aux. Power consumption• For 200MW units - 9.5% for 1st year after commercial

operation and 9% there after (additional 0.5% with cooling towers)

• For 500MW units(steam driven BFPs) - 8.5 % for 1st year after commercial operation and 8.0 % there after(additional 0.5% with cooling towers)

• For 500MW units(elec. driven BFPs) - 9.5 % for 1st year after commercial operation and 9.0 % there after(additional 0.5% with cooling towers)


• Norms for gas based power stations– Heat rate

• 3150 kcal/kwh for open cycle operation and 2100 kcal/kwh for combined cycle operation on GCV basis

– Aux. Power Consumption• 1% for open cycle and 3% for combined cycle


• Variable cost calculated thus would be subject to fuel price adjustment


Variable Charges

• Fuel price adjustment.

-On price variation of fuel.

-On quality variation of fuel.

FPA =

10*Hc/(100-AC)*{[Pcm/Kcm - Pcs/Kcs] +10*Ho/(100-AC) [Pom/Kom - Pos/Kos]}

Pcm / Pcs = Price of coal PSL/ Base tariff.

Kcm / Kcs = GCV of coal PSL/ Base tariff

Pom / Pos = Price of oil PSL/ Base tariff

Kom / Kos = GCV of oil PSL/ Base tariff

AVAILABILITY BASED TARIFF

BACKGROUND

•Two Part Tariff had no mechanism to impose

-Grid discipline.

-Market Competition

-Breaking monopoly

•1994 - M/s ECC engaged by GOI for further rationalisation.

•Formation of NTF and RTF

•M/s ECC report»Market Mechanism

»Recommendation for ABT

CONCEPT

•Performance criteria shifted from PLF to Availability.

•Introducing the concept of Re-trading

•Introduction of Frequency linked component

•Introduction of Merit order despatch

TERMINOLOGYAvailability' in relation to a thermal generating station for any period means the average of the daily average declared capacities (DCs) for all the days during that period expressed as a percentage of the installed capacity of the generating station minus normative auxiliary consumption in MW, and shall be computed in accordance with the following formula:

N

Availability = 10000 x Σ DCi / { N x IC x (100-AUXn) }%

i=1

where,

IC = Installed Capacity of the generating station in MW,

DCi = Average declared capacity for the ith day of the period in MW,

N = Number of days during the period, and

AUXn = Normative Auxiliary Energy Consumption as a percentage of gross

generation;

TERMINOLOGY

‘Declared Capacity’ or ‘DC' means the capability of the generating station to deliver ex-bus electricity in MW declared by such generating station in relation to any period of the day or whole of the day, duly taking into account the availability of fuel;

TERMINOLOGYPlant Load Factor' or 'PLF' for a given period, means the total sent out energy corresponding to scheduled generation during the period, expressed as a percentage of sent out energy corresponding to installed capacity in that period and shall be computed in accordance with the following formula:

N

PLF = 10000 x Σ SGi / {N x IC x (100-AUXn) }%

i=1

where,

IC = Installed Capacity of the generating station in MW,

SGi = Scheduled Generation in MW for the ith time block of the period,

N = Number of time blocks during the period, and

AUXn = Normative Auxiliary Energy Consumption as a percentage of gross generation;

TERMINOLOGYUnscheduled Interchange (UI) Charges:

(1) Variation between actual generation or actual drawal and scheduled generation or scheduled drawal shall be accounted for through Unscheduled Interchange (UI) Charges. UI for a generating station shall be equal to its actual generation minus its scheduled generation. UI for a beneficiary shall be equal to its total actual drawal minus its total scheduled drawal. UI shall be worked out for each 15 minute time block. Charges for all UI transactions shall be based on average frequency of the time block and the following rates shall apply with effect from 1.4.2004 :

CAPACITY CHARGE

Capacity charge will be related to ‘availability’ of the generating station and the percentage capacity allocated to the state. ‘Availability’ for this purpose means the readiness of the generating station to deliver ex-bus output expressed as a percentage of its rated ex-bus output capability.

ENERGY CHARGE

Energy charges shall be worked out on the basis of a paise per kwh rate on ex-bus energy scheduled to be sent out from the generating station as per the following formula

Energy charges = Rate of energy charges

(paise/kwh) x Scheduled Generation (ex-bus MWh)

UNSCHEDULED INTERCHANGE (U I) :

Variation in actual generation / drawal with respect to scheduled generation / drawal shall be accounted for through Unscheduled Interchange (UI).

UI for generating station shall be equal to its total actual generation minus its scheduled generation.

UI for beneficiary shall be equal to its total actual drawal minus its total scheduled drawal.

UNSCHEDULED INTERCHANGE (UI) :

UI shall be worked out for each 15 minute time block.

Charges for all UI transactions shall be based on average frequency of the time block.

UI rates shall be frequency dependent and uniform throughout the country.

1000

900

800

700

600

500

400

300

200

100

0

0 2 4 6 8 10 12 14 16 18 20 22 24

Forecast ex-bus capability of Power Plant

Hours

MW

Net Injection Schedule

SEB - A's Requisition

SEB - A's Entitlement - (40% )

SCHEDULING

TARIFF COMPONENTComponents of Tariff:

(1) Tariff for sale of electricity from a thermal power generating station shall comprise of two parts, namely, the recovery of annual capacity (fixed) charges and energy (variable) charges.

(2) The annual capacity (fixed) charges shall consist of:

(a) Interest on loan capital;

(b) Depreciation, including Advance Against Depreciation;

(c) Return on equity;

(d) Operation and maintenance expenses; and

(e) Interest on working capital.

(3) The energy (variable) charges shall cover fuel cost.

Existing Tariff Availability Based Tariff

Based on K.P.Rao Committee Report

Based on E.C.C Report

Two Part Tariff

I. Fixed Charges

II. Variable Charges

Three Part Tariff

I. Capacity Charges

II. Energy Charges

III. U.I.Charges

Fixed charges recovery proportional to Drawal.It thus becomes single part tariff

Capacity charges recovery proportional to Entitlement / Allocation of Capacity Share

F.C. fully recovered at 62.78% PLF including deemed generation

C.C.fully recovered at T.A. of 80% as declared by the Generating Company.

TARIFF COMPARISON


The fuel risk is generally passed on to the beneficiaries.

The fuel risk is with NTPC.

The Rate of Return shall be 16%

The Rate of Return at 16% is protected.

Interest on Loan is at actuals & passed on to the beneficiaries.

Same to continue.

Depreciation shall be as under

Coal based = 7.84%

Gas based = 8.24%

To be charged from the beginning of the next financial year

Depreciation shall be as under

Coal based = 3.6%

Gas based = 6.0%

To be charged from the same financial year on pro rata basis.

TARIFF COMPARISON

Existing Tariff Availability Based TariffThe O&M Charges are 2.5% of current capital cost escalated @10% per annum.

The base level of O&M shall be average of actual O&M expenses in the last five years (1995-96 to 1999-2000 )escalated twice @10% to bring it to 1999 – 2000 level.

Escalation in O&M cost to be provided on the basis of a weighted price index of CPI (40%) and WPI (60%).

Base O&M to be escalated at the rate of 6% per annum for the tariff period.

TARIFF COMPARISON

Existing Tariff Availability Based TariffIn case actual escalation is within 20% of this, it shall be absorbed by the utility. Deviation beyond 20% will be adjusted for which petition will have to be filled.

All Tax on income including incentive is pass through.

Same shall continue.Tax on the other income streams accruing to the company shall not be pass through.

Tax Escrow account to be opened by each beneficiaries.

Tax to be billed on regional basis so that beneficiaries paying higher cost of new stations are also provided advantage of tax holiday.

TARIFF COMPARISON

Existing Tariff Availability Based TariffInterest on working capital includes

Existing practice to continue.

TARIFF COMPARISON

a) Fuel cost for one month and fuel stock of 15 days for pit head stations & 30 days stock for non pit head stations calculated on normative PLF basis. b) 60 days stock of Secondary fuel oil calculated on normative PLF basis. c) Operation & Maintenance expenses (Cash) for one month.

Existing Tariff Availability Based Tariff•d) Maintenance spares maximum of 1% of capital cost but not exceeding one years requirement less one fifth of initial spares already capitalised.

e) Receivables equivalent to two month’s average billing calculated on normative PLF basis.

Existing practice to continue.

TARIFF COMPARISON

Existing Tariff Availability Based TariffNo provision of Development Surcharge.

The generating company shall be entitled to a development surcharge of 5% on every bill for fixed charges raised by it.

The D.C.shall not be payable for plants operating exclusively within a state.

Levy of Development Surcharge shall be subject to the following conditions:-

TARIFF COMPARISON


All Tax on income including incentive is pass through.

Same shall continue.Tax on the other income streams accruing to the company shall not be pass through.

Tax Escrow account to be opened by each beneficiaries.

Tax to be billed on regional basis so that beneficiaries paying higher cost of new stations are also provided advantage of tax holiday.

TARIFF COMPARISON


50% F.C. recoverable even at Zero PLF

Proportionate recovery of C.C for Availability between 0 to 80%

Could be increased to 85 % subsequently at any time if the experience dictates such a requirement

This, However could be considered for relief after due justification for plants having operational problem.

Gross Generation & Deemed Generation is Certified by REB

Availability is determined by REB based on declared capability for each time block.

Existing Tariff Availability Based TariffFor Certification of Backing down, the capability to be determined by Unrestricted Generation during Peak Period.Backing down shall be the difference between capability and the actual generation.

No Provision for certification of Deemed Generation.

Variable Charges shall be paid on each unit of Actual Energy sent out from the station.

Energy Charges shall be paid on the Ex.Bus Schedule Energy.

Existing Tariff A.B.T

Operating Norms

1. Heat Rate

Coal Based Station

Stabilisation : 2600 Kcal/Kwh

Subsequent Period : 2500 Kcal/Kwh

(40 Kcal/Kwh shall be deducted in 500 MW units for electrically driven BFP)

Gas / Liquid Based Station

Without Nox Control With Nox Control

Open Cycle 3150 Kcal/Kwh 3190 Kcal/Kwh

Combined Cycle 2100 Kcal/Kwh 2125 Kcal/Kwh

Existing to continue

Existing Tariff A.B.T2. Auxiliary Power Consumption

Coal Based Station

WithC.T Without C.T

200 MW Series 9.5% 9.0%

500 MW Series

With TDBFP 8.0% 7.5%

With MDBFP 9.5% 9.0%

Gas / Liquid Based Station

Open Cycle 1.0%

Combined Cycle 3.0%

(During the stabilisation period, normative APC shall be reckoned at 0.5% over and above the figure specified above.)


Existing Tariff A.B.T

3. Secondary fuel Oil Consumption

Stabilisation Period 5.0 ml/Kwh

Subsequent Period 3.5 ml/ Kwh

4. Stabilisation Period Stabiliation period commencing from the date of commercial operation shall be reckoned as follows :

Coal Based / Thermal Station 180 Days

Open cycle Gas & Naptha based station 90 Days

Combined cycle gas & Naptha based station 90 Days


Existing Tariff

A.B.T

Date of Commercial Operation

Coal Based / Thermal Station < 180 days from

the date of

synchronisation.

Gas / Liquid Based Station From the date of

Synchronisation


Existing Tariff Availability Based TariffIncentive is payable @ 1 Paisa / Kwh for every 1% increase in PLF (Including deemed generation) above 68.49 % .

Incentive is payable on PLF above 77%.Only the Schedule Generation shall be taken into account for PLF.

The incentive rate shall be 50% of Fixed Cost (P/Kwh) limited to 21.5 P/Kwh upto 90% PLF.Beyond 90% this rate will be reduced to half.

Incentive billing in the ratio of Fixed Charges billed.

Incentive billing in the ratio of Energy Scheduled by beneficiaries beyond target PLF.


No provision for Unscheduled Interchange Charges.

Unscheduled Interchange Charges shall be applicable on the difference between actual generation / drawal and the schedule generation / drawal.

U.I. Shall be worked out on each 15 minute time block.

U.I. Rate be based on the average frequency of the time block.


No provision for Unscheduled Interchange Charges.

The U.I. Rates are as under.•50.5 Hz and above = Zero•49.0Hz and below = 420 P/Kwh•Between 49.0Hz & 50.5 Hz the UI rate is linear in steps of 0.02 Hz which is 4.8 Paisa

120

240

420

360

49.5 50.550.0

0

49.0

U.I RATE STRUCTURE

UI

FREQ.

To be checked with modified graph

NEW TARIFF POLICY FROM 01.04.04

About New Tariff

• Date of implementation - 01-04-2004

• Duration of tariff - 5 years

Present Tariff Vs New Tariff

Parameter Earlier Present

Target PLF for Incentive (Based on schedule Generation)

77% 80%

Present Tariff Vs New TariffParameter Earlier Present

Gross Station Heat Rate

During stabilization

- 200 /210MW

- 500 MW

2600

2600

2600

2550

Subsequent period

- 200 /210MW

- 500 MW

2500

2500

2500

2450

* Will leads to reduction in marginal contribution for 500 MW sets


Description Earlier Present

Secondary fuel oil consumption-Stabilization period (ml /kwh)- Subsequent period

5 ml

3.5

4.5 ml

2.0

•Norms may be reviewed after 2 years• Reduction in marginal contribution

Present Tariff Vs New TariffAPC

Unit size Earlier Present

(MW) With CT With out CT

With CT Without CT

200 9.5 9.0 9.0 8.5

500 with TDBFP

8.0 7.5 7.5 7.0

500 with MDBFP

9.5 9.0 9.0 8.5

* Will leads to less energy charges


• Stabilization period and relaxed norms applicable during stabilization period shall cease to apply from 01-04-2006.

What are the \norms *********************



Ceiling norms for capitalized initial spares

Reasonable 2.5% of plant & equipment cost

Return of equity

Earlier Present

CGS -16%

IPP – 16%

14%

14% (if payment security mechanism similar to central power sector utilities is provided by Govt)

16% (if no payment security mechanism similar to central power sector utilities is provided by Govt)

O&M Expenses

Earlier Present

1. Average of actual O&M expense from 95-96 to 99-00 is considered as O&M

Expense of 97-98

2. Above average value is escalated twice at 10% per annum to arrive the base year O&M expense for 99-00

Year 200 500 MW

04-05 10.4 9.36

05-06 10.82 9.73

06-07 11.25 10.12

07-08 11.70 10.52

08-09 12.70 10.95

Rs. Lakh / MW

O&M Expenses

Earlier Present

3. Base O&M expense for the year 99-00 shall be further escalated at the rate of 6% per annum to arrive at permissible O&M expense for the relevant year

Interest on working capitalDescription Earlier Present

Secondary fuel oil corresponding to target availability

Two month One month

Rate of interest Cash –credit rate prevailing at the time of tariff filing

Short term prime lending rate of SBI as on 01-04-04

Landed cost of coal

Earlier Present

Actual landed cost Landed cost after considering the normative transit and handling losses

Pit head station – 0.3%

Non pit head station – 0.8%

Incentive

Earlier Present

Upto 90% SG PLF-50 % of fixed cost /kwh subject to ceiling of 21.5 paisa / kwh

Above 90% SG PLF

- 50% of above rate

25 paisa / kwh

* Incentive will now be more particularly for old stations like Singrauli

UI Rate


Max ( 49.02 Hz and below) 420 570 p

Min (50.5 Hz and above) 0.00 0.00

Between 49.02 to 50.48

Linear in 0.02 Hz step

5.6 8.00 p

Paisa/ Kwh

Rebate


Payment of Bill through LC 2.5% 2.0%

WHAT NEXT ?

Marginal cost based pricing Methods

•Mainly two types of pricing methods–Long run marginal cost

•This is the future cost of power taking care for expansion plan and projected variable costs over 20-30 years.

–Short run marginal cost•This is the variable cost and ignores fixed cost•Time-of-tariffs are determined based on this..

•Advantages–Provide most appropriate signals to the supplier and end user regarding the true value of the power being consumed.–With backward looking X, regulatory risk enters to raise a priori expected returns.

Marginal cost based pricing Methods

•Disadvantages

–Difficulty in forecasting changes in energy demand–SRMC tariff is not stable over time.–It uses economic rather than financial concepts and so may overstate or understate the financial requirements.

Thank You

availability based tariff. highlights of cerc order dated 4.1.2000 on abt 1. order applicable to...

Documents

tariff period

tariff structure concept

abt abt tariff structure

cost of energyit

historic cost

higher return

net return

allowed rate of return