abt_pres.__23.02.08

Generation Tariff -ABT.

In this presentation

� Evolution of Tariff in India

� Tariff provisions in Electricity Act 2003

� Availability based Tariff

� Tariff Regulations

Tariff Could be

�Market Driven

�Soap, Real estate, Automobiles etc.

�Cost Plus

�Electricity,Petroleum, Fertilizer, Railways etc.

Issues in Determination of Electricity Tariff

� Highly perishable commodity

� Infrastructure requirement

� Highly capital intensive

Objectives for Tariff determination

�Recovery of prudent costs of generation transmission and distribution of electricity and allowance of a fair return to energy company

�Promote competition, efficiency and economy including provision of incentives for operation at minimum costs

�Protect the right of the consumers to reasonably priced and quality power

�Protection of the environment and promotion of conditions for improvement in the ecological sphere

�Encouraging customers to implement energy efficiency measures

�Ensure universal supply including supply to rural areas and supply to poor

Power Generation Business in Electricity Sector

� Pre-NTPC Players� BBMB

� Nuclear Power

� Neyveli Lignite

� Badarpur TPS

� Post NTPC� Amendment in Electricity Supply Act 1948, to

include Generation Business

� Enabled new entities in Power Production, like NTPC, NHPC, NPC and a host of IPPs

Evolution of Bulk Electricity Tariff in India

� Single Part Tariff:

� Both Fixed Charges and Variable Charges realized in one

part as energy charge.

� Existed before NTPC

� Initially adopted for NTPC

� Causes Over / Under charging

� Distorts Economic Dispatch (Merit Order Operation)

� Resentment by customers

� Under drawal accrues monetary benefit to beneficiaries:

Unhealthy competition to prevent / reduce drawals

� Need to change to avoid the above was felt.


� Conventional Two Part Tariff: � Fixed Charges and Variable Charges computed

separately � Fixed Charges compensate for the cost of capacity,

including investment cost

� Variable Charges compensates for cost of energy

� Fixed Charges booked against Maximum Demand (or Contracted Demand) in Rs/kW

� Variable Charges realized against energy consumed, in Rs/KWh

� Provides the correct market perception.


� K P Rao Tariff (1992)

� A pseudo Two Part Tariff

� Fixed Charges and Variable Charges computed separately

� Both Fixed Charges and Variable Charges booked and realized in one part against energy drawn during the billing period.

� Causes no Over / Under charging

� Promotes incorrect market perception

� Continued to Distort Economic Dispatch

� Resentment by customers

� Under drawal accrues monetary benefit to beneficiaries: Unhealthy competition to prevent / reduce drawals

Laid down fairly sound costing principles


� ECC (Energy Control Consultants, Fairfax, USA) Report: � GoI appointed ECC to study and recommend Bulk Power and Transmission Tariff for

India as K P Rao tariff was soon resented by customers

� Report submitted in 1994; Accepted by GoI in 1995

� Implementation delayed till 2003, due to dispute on principles as well as structure

� NTF & RTF (National and Regional Task Forces) debated implementation modalities of ECC recommendations � Several sub groups were formed, some recommendations of ECC were modified and

final implementation was agreed by 1998-99.

� Electricity Regulatory Commissions formed in 1998; tariff setting role transferred from Government of India to CERC� ABT order issued by CERC for ISGS, along with Inter-system exchange Tariff in 1999;

stipulated mock trial to begin

� ABT finally implemented progressively from 2003

Evolution of Bulk Electricity Tariff in India� ABT as Implemented (Generation)

� A true two part tariff with supplementary adjustment for Net Exchange deviations from schedule

� Fixed cost recovered against Capacity made available; Full recovery at pre-set EAF

� Energy Charges recovered against requisitioned (scheduled, ex-bus) energy at normatively computed rates

� Actual Energy Generation (AG, measured ex-bus) would be different from scheduled and the deviations positive or negative settled at a price linked to system sufficiency, in that time slice.

� Time slice of 15 minutes each in use

� Average Frequency of operation in the time slice used as an index of system sufficiency

� Settlement through a pool account

� Promotes better market perception

� Encourages Economy in Dispatch

Evolution of Bulk Electricity Tariff in India� ABT as Implemented (Beneficiary)

� A true two part tariff with supplementary adjustment for Net Exchange deviations from schedule� Fixed cost recovered from customers in proportion to capacity

allocation � Energy Charges recovered against requisitioned (scheduled,

ex-bus) energy at normatively computed rates, on the respective drawal schedule

� Actual Energy Generation (AG, measured ex-bus) would be different from scheduled and the deviations positive or negativesettled at a price linked to system sufficiency, in that time slice.� Time slice of 15 minutes each in use� Average Frequency of operation in the time slice used as an

index of system sufficiency� Settlement through a UI pool account

� Promotes better market perception� Encourages Economy in Dispatch

Central Electricity Regulatory Commission

� The Central Electricity Regulatory Commission (CERC) establishedunder the Electricity Regulatory Commissions Act, 1998

� Vested with the jurisdiction inter-alia, to regulate the tariff of generating companies owned or controlled by the Central Government

� Jurisdiction with regard to tariff with effect from 15th May, 1999

� Prior to this date, the tariff jurisdiction was exercised by the Central Government by virtue of Section 43A(2) of the Electricity Supply Act, 1948

� Mandated to regulate only bulk electric power tariffs viz., the tariff of generation and transmission, and the inter state transmission ofpower

� Promoting competition, efficiency and economy, encouraging investment in the industry and safeguarding the consumer interest

� Simulate some of the possible effects of a market

Tariff determination by CERC

�Section 79 of the Electricity Act, 2003 provides that

“ The Central Commission shall discharge the following functions, namely :-

(a)To regulate the tariff of generating companies owned or controlled by the Central Government;

(b)To regulate the tariff of generating companies other than those owned or controlled by the Central Government specified in clause (a), if such generating companies enter into or otherwise have a composite scheme for generation and sale of electricity in more than one State;

(c)To regulate the inter-State transmission of electricity;

(d)To determine tariff for inter-state transmission of electricity.

(e)…….

Tariff determination by SERC

�Section 86 of the Electricity Act,2003 provides that the SERC shall –

“(1)(a) determine the tariff for generation, supply, transmission and wheeling of electricity , wholesale, bulk or retail, as the case may be, within the State:……

(b)Regulate electricity purchases and procurement process of distribution licensee …..

Role of Regulator in Cost Plus Tariff

� Actual or Norms

� Prudence Check in case of Actuals

� Fixation of Norms

Problems in grid operation

� High frequency during off-peak hours with frequency going upto 50.5 to 51.0 Hz for many hours of the day.

� Low frequency during peak load hours with frequency going to 48.0-48.5 Hz for many hours during the day.

� Rapid and wide changes in frequency in band of 1 Hz in 5 to 10 minutes for many hours every day.

� Very frequent grid disturbances causing tripping of generating stations interruption of supply to large consumers and disintegration of the regional grids.

� Least cost power not dispatched in preference of more costly power .

Resolutions

� Integrated grid operation requires the normalization of frequency across all five Regions requiring proactive load management by Beneficiaries and dispatch discipline by Generators.

� Maximization of generation during peak load hours and load curtailment equal to deficit in generation.

� Backing down of generation to match the system load reduction during off- peak hours keeping the merit order of generation in view.

Availability Based Tariff

ABT order dated January 4, 2000 of CERC

Generators and beneficiaries must declare day- ahead availability and demand based on 15-minute time blocks

Energy charges are proposed to be charged only to the extent of the scheduled drawal by the beneficiary

Unscheduled interchange of power (UI charges) are payable/receivable depending upon who has deviated from the schedule and also subject to the grid conditions at that point of time

ABT system will entitle the generating station to reimbursement of fixed cost based on the availability or declared capacity of the generating station

ABT introduces system of incentives and disincentives based on actual performance

Why ABT

� Plan as an integrated National Grid five Regional grids work at vastly varying operational parameters

� Chronic surpluses in the East and shortages in the South, have resulted in sustained functioning of these grids at frequencies which are far beyond even the normal band of 49.5 to 50.3 Hz

� Inducing grid discipline.

� Economic efficiency dictates that least cost power should be dispatched in preference to more costly power (merit order dispatch)

� Generators have a perverse financial incentive to go on generating even when there may be no demand.

� Beneficiaries were not liable for payment of the fixed cost associated with the share of capacity allocated to them.

ABT Overview

� It is a performance based tariff for supply of electricity by Interstate Generating Stations.

� It is a system of scheduling and dispatch which requires both Generators and Beneficiaries to commit to day ahead schedules.

� It is a system of rewards and penalties seeking to enforce day ahead committed schedules though variations are permitted if notified one and half hour in advance.

� The order emphasizes prompt payment of dues. Non-payment of prescribed charges will be liable for appropriate action under sections 44 and 45 of the ERC Act.

ABT

� It has three parts:� Capacity Charges - A fixed charge (FC) payable every

month by each beneficiary to the generator for making capacity available for use. The FC is not the same for each beneficiary. It varies with the share of a beneficiary in a generators capacity. The FC, payable by each beneficiary, will also vary with the level of availability achieved by a generator.

� Energy Charges - An energy charge (defined as per the prevailing operational cost norms) per kWh of energy supplied asper a pre-committed schedule of supply drawn upon a daily basis.

� UI charge - A charge for Unscheduled Interchange for the supply and consumption of energy in variation from the pre-committed daily schedule. This charge varies inversely with the system frequency prevailing at the time of supply/consumption. Hence itreflects the marginal value of energy at the time of supply.

Availability

What exactly is availability?

� ‘Availability’, for the purpose of this order, means the readiness of the generating station to deliver ex-bus output expressed as a percentage of its related ex-bus output capability as per rated capacity.

How is availability calculated?

� Availability of thermal generating station for any period shall be the percentage ratio of average SOC for all the time blocks during that period and rated Sent Out Capability of the generating station as per the following formula:

Availability

{ n }

Availability ={ Σ Σ Σ Σ SOCi + CL } x 100

{ i=1 (1-AUX/100) } h x I.C.

where,

I.C. = Installed Capacity of the station in MW

SOCi = SOC of the ith time block of the period

n = Number of time blocks during the period

AUX = Normative Auxiliary Consumption as a

percentage of gross generation.

h = Number of hours during the period = n/4

CL = Gross MWH of capacity of unit(s) kept closed on account of Generation scheduling order.

Scheduling

� To match the supply and demand on a daily basis at least one day in advance.

�i) Each day of 24 hours starting from 00.00 hours be divided into 96 time blocks of 15 minutes each.

�ii) Each generating station is to make advance declaration of its capacity for generation in terms of MWh delivery ex-bus for each time block of the next day. In addition, the total ex-bus MWh which can actually be delivered during the day will also be declared in case of hydro stations. These shall constitute the basis of generation scheduling.

�iii) While declaring the capability, the generator should ensure that the capability during peak hours is not less than that during other hours.

�iv) The Scheduling as referred to above should be in accordance with the operating procedures in force.

�v) Based on the above declaration, the regional load despatch centre shall communicate to the various beneficiaries their respective shares of the available capability.

Scheduling

� vi) After the beneficiaries give their requisition for power based on the generation schedules, the RLDC shall prepare the generation schedules and drawal schedules for each time block after taking into account technical limitations and transmission constraints.

�vii) The schedule of actual generation shall be quantified on ex-bus basis, whereas for beneficiaries, scheduled drawals shall be quantified at their respective receiving points.

�viii) For calculating the drawal schedule for beneficiaries, thetransmission losses shall be apportioned in proportion to their drawals.

�ix) In case of any forced outage of a unit, or in case of any transmission bottleneck, RLDC will revise the schedules. The revised schedules will become effective from the 4th time block, counting the time block in which the revision is advised by the generator, to be the 1st one.

�x) It is also permissible for the generators and the beneficiaries to revise their schedules during a day, but any such revisions shall be effective only from the 6th time block reckoned in the manner as already stated.

Scheduling

� xi) RLDC is also entitled to revise (if need be), the schedules during the day in the interest of better system operation. These revised schedules shall become effective from the 4th time block counting the time of issue of revised schedule as the 1st time block.

�xii) In the event of any grid disturbance, the schedules of bothgeneration and drawal shall be deemed to have been revised to be equal to their actual generation/drawal. The grid disturbance and its duration shall be certified by RLDC.

�xiii) The schedules issued/revised by RLDC shall be effective from designated time block, irrespective of communication success or failure.

Unscheduled Interchange

i) a generator generates more than the schedule, thereby increasing the frequency;

ii) a generator generates less than the schedule, thereby decreasing the frequency.

iii) a beneficiary overdraws power, thereby decreasing the frequency;

iv) a beneficiary underdraws power, thereby increasing the frequency.

UI to be worked out for each 15 minutes time block. The charges shall be based on the average frequency of the relevant time block.

Average Frequency of time block UI Rate (Paise/ KWh)

50.5 Hz and above 0.0 p/kWh

Above 50.48 Hz 8 p/kWh

Below 50.5 Hz and up to 49.80 Hz 8 p/kWh per 0.02 Hz step

Below 49.80 Hz and upto 49.00 Hz 18 p/kWh per 0.02 Hz step

Below 49.02 Hz 1000 p/kWh

(Rates subject to change through a separate notification from time to time)

49.0 49.8 50.5

745

210

p/kWh

Hz50.049.3 49.6

345

425

0

UI Rate Chart

0.7 Hz = 210 p/kWh

0.1 Hz = 30 p/kWh

0.02 Hz = 06 p/kWh

0.3 Hz = 135 p/kWh

0.1 Hz = 45 p/kWh

0.02 Hz = 09 p/kWh

150

585

0.5 Hz = 400 p/kWh

0.1 Hz = 80 p/kWh

0.02 Hz = 16 p/kWh

49.0 49.8 50.5

1000

280

p/kWh

Hz50.049.4 49.6

460

640

0

UI Rate Chart

0.7 Hz = 280 p/kWh

0.1 Hz = 40 p/kWh

0.02 Hz = 08 p/kWh

200

820

0.8 Hz = 720 p/kWh 0.1 Hz = 90 p/kWh 0.02 Hz = 18 p/kWh

Tariff Regulations

CERC (Terms & Conditions of tariff) Regulations 2004

� Date of notification 26th March 2004

� Effective from 1st April 2004

� Valid for a period of 5 years

� Thermal Stations

� stage-wise, unit-wise or for the whole generating station

� Transmission system

� line-wise, substation wise and system wise as the case may be and aggregated to regional tariff

Elements of Tariff

� Fixed Cost which do not vary with level of generation, consists of:

� Return on Equity

� Interest on Loans

� Depreciation

� O&M Cost

� Interest on Working Capital

� Variable Charges i.e. cost of fuel, varies directly with level of generation, consists of--

� Primary fuel (Coal/Gas)

� Secondary fuel - Oil

� Objective

�To provide fair return on the investment by the investor and forgeneration of internal resources for capacity additions.

� Rate of Return

�Section 61 of the Electricity act provides that tariff by appropriate Commission are determined on Commercial Principles taking care of consumers’ interest as well as recovery of the cost of electricity in a reasonable manner.

�For generating companies, rate of return is notified by CERC was 16% for Tariff period 2001-04 and 14% for the period 2004-09.

� Income tax is separately recoverable through tariff on Actuals.

Return on Equity

�Return on equity is computed on the equity component of capital cost of the project considering the approved debt:equity ratio.

�For the purpose of tariff, capital cost adopted is the amount capitalized on year to year basis as per audited accounts.

�Equity component of the capital cost is worked out based on the approved debt:equity ratio which is 50:50 for earlier stations and 70:30 for the new projects.

�For the stations coming up after 1.4.2004, the equity allowed is30% or actual, whichever is less.

�Rate of return is applied to the equity component of the capitalcost worked out as above.

Computing Return in case of NTPC tariff

� Interest on loan is calculated based on the weighted average rate of interest and applied to the outstanding loans.

� Loans are reduced to the extent of repayment each year during the tariff period.

�No interest element is included in tariff after repayment of the entire loan.

Interest on Loan

� Objective

�Depreciation is an important element of cost and forms a part ofthe fixed cost recovery. The objective is that the recoveries through depreciation should be adequate to provide resources to the investor to replace the assets after their useful life.

� Rates of Depreciation

�There is no mention of depreciation rate in the Electricity Act,2003. So for accounts though Companies act rate are applicable, for tariff CERC has adopted the rates which were there in the E(S) 1948.

�Rates applicable for coal based stations – 3.6 % (Life 25 years)

� for gas based stations – 6 % (life 15 years)

Depreciation

� Computing Depreciation in case of NTPC Tariff

�The average depreciation rate is multiplied with capital cost for computing amount of depreciation to be charged in tariff.

�Depreciation recovery is limited to 90% of the capital cost based on plant residual value of 10%.

� Advance Against Depreciation

�In addition to depreciation , AAD is provided to service the loan obligation.

�AAD is limited to 1/12 of loan amount in 2001-04 tariff period and is limited to 1/10 of loan amount in 2004-09 Tariff period.

Depreciation

� Elements of Working Capital

�O&M expenses for one month

�Fuel expenses for one month at normative generation level

�Fuel stock - coal 15 days for pit head stations and 30 days for non- pit head stations

�Secondary fuel oil stock of 60 days

�Spares inventory for one year consumption

�Receivables – 2 months

� Funding of working capital

�By working capital margin provided in capital cost

�By short term borrowings from banks

Interest on Working capital

� Computing Interest on Working Capital in Tariff

�Total working capital required for the above elements of workingcapital is calculated.

�For the amount funded by working capital margin, weighted average rate of interest for long term loans and rate of returnsas applicable for the project are considered.

�For the balance amount of working capital, the bank cash credit rate is considered.

• VARIABLE COST

�Normative fuel cost based on norms for

�- station heat rate

�- auxiliary power consumption

�- secondary fuel oil consumption

�Provision of monthly fuel price adjustment to take care of variations in fuel price and quality.

Interest on Working capital

•Elements of O&M expenditure

� Salary & wages

� Spares and consumables for operation & maintenance of the plant

� Cost of repair and maintenance

� Administrative overheads

� Regional & corporate overheads

� Water charges

� Insurance charges

� Basis of O&M Expenditure - O&M expenses can be computed based on

� Detailed budgeting

� Past Actuals

� Normative based on industry trend

� Provisions in Tariff

� Old stations - based on the Actuals of the preceding year.

� New stations – normative at the rate of 2.5% of capital cost

� Annual escalation of 6 per cent for the tariff period

O&M Cost

� Provisions in Tariff

�Old stations –

�Coal Stations

�Less than 200 MW units :Norm based on the actuals of the preceding years.

�200MW & 500 MW units: Normative O&M Cost Coal stations

(Rs. 10.4 Lakh/MW for 2004-09)

Gas Station

- Normative O&M

�New stations – normative at the rate of 2.5% of capital cost

�Annual escalation of 4 per cent for the tariff period

O&M Cost

Norms for 2001-02 to 2003-04

As approved by Govt.Debt: Equity

Based on Actuals for 1995-96 to 1999-00, with 6% escalation per

annum

O&M expenses

16%Return on Equity

Coal based- 3.6%

Gas based – 6.0%

Depreciation

Actual expenditure incurred subject to limitation of the approved cost

Capital cost

Norms for 2004-05 to 2008-09

70: 30Debt: Equity

Normative (Rs. Lakh/ MW)O&M

expenses

14%Return on Equity

Coal based- 3.6%

Gas based – 6.0%

Depreciation

Actual expenditure incurred subject to limitation of the approved cost

Capital cost

Norms for 2001-02 to 2003-04

As per GOI tariff notificationsAPC

3.5 ml/kWhSOC

Coal – 2500 kCal/kWh

Gas – 2000 kCal/kWh

Old gas stations – as per GOI tariff notifications

Heat rate

Above 77% PLFIncentive

80%Availability

Norms for 2004-05 to 2008-09

Reduced by 0.5% across the boardAPC

2.0 ml/kWhSOC

Coal – 2500 kCal/kWh – 200 MW

- 2450 kCal/kWh - 500 MW

Gas – 2000 kCal/kWh

Old gas stations – reduced by 25 kCal/ kWh

Heat rate

Above 80% PLFIncentive

80%Availability

O&M expenses for 2004-09(Coal Based Stations) (Rs. Lakh/MW)

10.9512.172008-09

10.5211.702007-08

10.1211.252006-07

9.7310.822005-06

9.3610.402004-05

500 MW & above200/210/250 MWYear

O&M expenses for 2004-09(Gas Based Stations) (Rs. Lakh/MW)

9.126.082008-09

8.775.852007-08

8.445.622006-07

8.115.412005-06

7.805.202004-05

Without warranty spares of 10 years

With warranty spares of 10 years

Year

Stabilization period

In relation to a unit, stabilization period shall be reckoned commencing from the date of commercial operation of that unit as follows, namely:

(a) Coal-based and lignite-fired generating stations- 180 days

(b) Gas turbine/combined cycle generating stations- 90 days

The stabilization period and relaxed norms applicable during thestabilization period shall cease to apply from 1.4.2006.

Other provisions

Incentive: Incentive shall be payable at a flat rate of 25.0 paise/kWh for ex-bus scheduled energy corresponding to scheduled generation in excess of ex-bus energy corresponding to target Plant Load Factor.

Rebate: For payment of bills of capacity charges and energy charges through a letter of credit on presentation, a rebate of 2% shall be allowed. If the payments are made by a mode other than through a letter of credit but within a period of one month of presentation of bills by the generating company, a rebate of 1% shall be allowed.

Late Payment Surcharge: In case the payment of bills of capacity charges and energy charges by the beneficiary (ies) is delayed beyond a period of 1 month from the date of billing, a late payment surcharge at the rate of 1.25% per month shall be

levied by the generating company.

Other provisionsDemonstration of Declared Capability: (1) The generating company may be required to demonstrate the declared capability of its generating station as and when asked by the Regional Load Despatch Centre of the region in which the generating station is situated. In the event of the generating company failing to demonstrate the declared capability, the capacity charges due to the generator shall be reduced as a measure of penalty.

(2) The quantum of penalty for the first mis-declaration for any duration/block in a day shall be the charges corresponding to two days fixed charges. For the second mis-declaration the penalty shall be equivalent to fixed charges for four days and for subsequent mis-declarations, the penalty shall be multiplied in the geometricalprogression.

(3) The operating log books of the generating station shall be available for review by the Regional Electricity Board or Regional Power Committee, as the case may be. These books shall keep record of machine operation and maintenance.

Billing & payment of Capacity Charges

Billing and payment of capacity charges on a monthly basis� Each beneficiary to pay the capacity charges in proportion to its

percentage share in Installed Capacity

� Allocated portion along with unallocated if any

� Re-allocation of Unallocated to be done by central govt.

� Beneficiaries liable to make full payment of capacity charges & energy charges corresponding to his total allocation and schedule respectively.

� RLDCs to advise all beneficiaries in the region and the other RLDCs if any capacity remains un-requisitioned during day-to-day operation,which can be traded

� Un-requisitioned capacity to be made available by the RLDCs through their respective websites.

Thank you

abt_pres.__23.02.08

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