System Operators’ Course

CERC Terms & Conditions of Tariff 2009-14

Background

• Till March 2001, Tariff of ISGS was fixed by GoI through a notification.

• First Tariff regulations issued by CERC on 31-03-01 for the control period April’2001-March’2004

• Tariff regulations for April2004-March 2009 issued in March 2004

• Tariff regulations for April2009-March 2014 issued in Jan 2009

What are Terms and Conditions of Tariff?

• Rules for determining the Tariff of ISGS and Transmission licensees.

• Applicable to – a) Generating Stations supplying to more than

one beneficiary (Thermal, Hydro, CCGT) – (NTPC, NLC, NHPC, DVC, NEEPCO)

• b) Inter State Transmission System

• Tariff of Nuclear power stations is fixed by DAE.

Some Imp Definitions and terminology • Control Period : Period for which tariff is specified (April 2009-

March 2014)• MYT : Multi Year Tariff: The tariff spread over useful life of the

equipment• Beneficiary : Person purchasing power from the ISGS• Cut off date :Last day of FY after 2 years from the CoD. • Date of Commercial Operation: date from which Tariff recovery

starts • ‘Infirm power’ : Power injected before CoD. • ‘Inter-State generating station’ or ‘ISGS’ : Gen Stns supplying

power to more than one state.• ‘Useful life’: Life of the system from CoD used for computing

Depreciation and determination of Tariff norms.• ( Coal/Gas based/ Substation=25 yrs, Hydro/Line 35 yrs)• ‘Design energy' means the quantum of energy which can be

generated in a 90% dependable year with 95% installed capacity of the hydro generating station;

Steps in Tariff and Collection

Apply for Tariff fixation (6 months before)

Tariff fixation Bench mark norms

of Project Cost

Billing by the ISGS/ ISTS

Filing of AddCap+ deferred Liabilities +actual Expenditure

Accounting in REA

Truing up by CERC

CoD

Cut off Date Audited Costs

Adjustment of Excess or Deficit collection

Audited Costs

Interest RatesBeneficiaries

Audited Costs

High lightsRegulation 39Income from UI, Incentive & non-core business –Not a pass through

Regulation 26 (ii)BMin Boiler efficiency, Max. Design unit Heat Rate etc. are defined for different type of boilers and coals defined for new Thermal Gen stations to discourage procurement of inefficient Boilers.

Project Exp.

IDC

FERV

Initial Spares

AddlCap

Rehab &Resettle (hydro)

RGGYY (hydro)

Asstetsnot in Use

Profit in Sale ofInfirm power

Debt:Equity Ratio

Capital Cost

Loan Equity

Total Project Cost considered for Tariff fixation

Rs.

Tariff

Capacity Charges

Energy Charges

Interest on Loan

Return on Equity

Depreciation

O&M expenses

Maint. Spares

Normative Seconday Oil Cost

Primary Fuel

Lime Stone (if

applicable)

Components of Tariff

R&M Allowence

Equity Return EquityRate of RoE

Loan Interest on LoanRate of Interest

Loan +EquityDepreciationRate of

Depreciation

Type/Size of Unit/ / Tr. system

O&M ExpNormative O&M Exp

Normative % Spares Maint. spares

O&M Exp

Working Capital Interest on Working CapitalInterest rates

Sec Oil Seondary Oil rate Sec. Oil rates

O&M Exp

Cost of 1.5* month primary fuel Stock

O&M Exp for 1 month

Cost of 2 months Sec oil Stock

2 months receivables

Cost of Maint. Spares (as a % of O&M ch.)

Working Capital

Interest rates

Interest on Working Capital

* 2 months for non-pit head stns.

Time Lines in Tariff PeriodP

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Dep

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2 ye

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2-4 years

2-3 months 10-12 yrs

2-3 months

2+ years

Project schedule to determine addl. RoE

Control Period 1

Control Period 2

Control Period 4

Control Period 5

Eligibility for R&M

Tariff after Renovation and Modernisation

Construction Period

Bench marking Model for Generating Stations

Benchmarking by CERC

Fuel /TechnologyGreen Field/ ExisitngSize of UnitNo. of UnitsEvacuation Voltage Level

Fuel LinkagePlant Location (Pit Head/ Non Pit Head)Month/Year of AwardBoiler Configuration

Bill of Quantities

• Boiler Efficiency• Steam Generator • Turbine Generator Island• Turbine Heat Rate• Fuel Oil Handling & Storage system• Coal Handling System• Chimney• Ash Handling System• C & I Package• Civil Works• Cooling Tower• Switchyard Package• Initial Spares• Mode of Unloading Fuel Oil

Total Unit cost

Source: CERC Explanatory Memorandum ( 8th Dec.’09)

Indeces for Steel, Cement, LabourGenerous set of assumptions

Distance of Water Source (River)Calorific Value

Ash Content Moisture Content in Coal

Developed as per National Tariff policy, for facilitatting prudence checks in line with Clause 7(2) of the TCT regulations

Bench marking Model for Transmission lines

Benchmarking by CERC

Voltage classNo. of circuitsConductor typeNo. of ConductorsInsulator type

Line lengthWind zones & Terrain No. of Towers Types of TerrainsNo. of River crossings

Bill of Quantities

• Conductor length• Earthwire length• No. of insulators• Qty. of Hardware

• Tower Weights• Foundation Volume

Total cost / Cost per ckm

Source: CERC Explanatory Memorandum ( 8th Dec.’09)

Generous set of assumptions

Unit cost based on historical data and

Application of PVFormula and

indices

Plant Availability Factor

DCi = Average declared capacity (in ex-bus MW),N= No. of Days in the periodIC = Installed CapacityAux = Normative auxiliary energy consumption in percentage.

For Thermal Plants, DCi is the Max Pk hour MW schedule given by RLDC

For Hydro Plants DCi is the MW delivered for atleast 3 hours certified by RLDC

Availability Calculation of Transmission System

Availability = (100-100*NAFM)Where NAFM= Non-availability factor in per unit for the month

1) For AC system

[ Σ ( OHL x CktkmL x NSCL ) + Σ ( OHT x MVA T x 2.5 ) +Σ ( OHR x MVAR R x 4 ) ]

THM x [ Σ (Cktkml xNSCL ) + Σ (MVAT x 2.5 ) + Σ (MVARR x 4 ) ]

Where

OHL, OHT & OHR = Outage hours for Line or Transformer or Reactor Cktkm = Length of a transmission line circuit in kmNSC = Number of sub-conductors per phaseMVA = MVA rating of a transformer / ICTMVAR = MVAR rating of a bus reactor, THM = Total hours in the month

2) NAFM for each HVDC systemNAFM = [ Σ (TCR x hours) ] ÷ [ THM x RC ]• TCR = Transmission capability reduction of the system in MW• RC = Rated capacity of the system in MW.

Computation of monthly Capacity charges payable

AFC = Annual fixed cost specified for the year, in Rupees.

NAPAF = Normative annual plant availability factor in percentage

NDM = Number of days in the month

NDY = Number of days in the year

PAFM = Plant availability factor achieved during the month, in percent:

PAFY = Plant availability factor achieved during the year, in percent

For Thermal Gen. Stns. less than ten (10) years old:

Monthly capacity Charges = AFC x ( NDM / NDY ) x ( 0.5 + 0.5 x PAFM / NAPAF )

For Thermal Gen. Stns. Older than ten (10) years:

Monthly capacity Charges = AFC x ( NDM / NDY ) x ( PAFM / NAPAF )

For Hydel Plants

Monthly capacity Charges = AFC x 0.5 x NDM / NDY x ( PAFM / NAPAF )

For Transmission charges of ISTS :

Monthly transmission Charges = AFC x ( NDM / NDY ) x ( TAFM / NATAF )

Energy Charges RateAux = Normative auxiliary energy consumption in percentage.

CVPF = Gross calorific value of primary fuel as fired, in kCal per unit

CVSF = Calorific value of secondary fuel, in kCal per ml.

ECR = Energy charge rate, in Rupees per kWh sent out.

GHR = Gross station heat rate, in kCal per kWh.

LC = Normative limestone consumption in kg per kWh.

LPL = Weighted average landed price of limestone in Rupees per kg.

LPPF = Weighted average landed price of primary fuel, in Rupees per unit

SFC = Specific fuel oil consumption, in ml per kWh.

For Coal based and Lignite fired stationsECR = { (GHR – SFC x CVSF) x LPPF / CVPF + LC x LPL } x 100 / (100 – Aux)

For gas and Liquid fuel based stations

ECR = GHR x LPPF x 100 / {CVPF x (100 – Aux) }

For Hydel Plants

ECR = AFC x 0.5 x 10 / { DE x ( 100 – Aux ) x ( 100 – FEHS )}

Secondary OilRegulation 20

• Secondary fuel charges de-linked from Energy Charges and put in Fixed charges

• Sec Oil Exp.= SFC x LPSFi x NAPAF x 24 x NDY x IC x 10

• Secondary oil consumption halved to

1ml/u

• Actual Expenses based on landed cost to be adjusted at the FY end.

• Savings in Sec. oil consumption to be shared with Beneficiaries 50:50

DepreciationRegulation 17• Allowed up to maximum of 90% of the capital

cost and salvage value is 10%• 5.28% for 1st 12 years Balance depreciable

value spread over the balance useful life• IT eqpt.=15% ; PLCC=6.33 ; Motor

vehicles=9.5% ; AC=9.5%• Bldgs= 3.34%• Land under lease=3.34%• Temp erections=100%

• Advance Against Depreciation removed

Sample Calculation of Tariff – CERC Norms 2009-14Case Study :A Project Consisting 1 No. 400KV D/C Transmission Line of 75 km line length and 4 Nos of 400KV Bays. Capital Cost of the Project : Rs 100 CrAdopting Debt : Equity Ratio of 70 : 30 Loan (Debt) Amount : Rs 70 Cr Equity Amount : Rs 30 Cr

CALCULATION OF TARIFF for 2009-10 (For illustration purpose only) Interest on Loan : 70 x 0.095 = 6.65 Cr( IOL @ 9.5%)Return on Equity : 30 x 0.17481 = 5.24 Cr(ROE @ 17.481% {15.5%/ 16% before MAT})Depreciation : 100 x 0.0528 = 5.28 Cr(Depreciation @ 5.28% {Building : 3.34%, TL/SS : 5.28% ,PLCC : 6.33 % and balance spread over after 12 Years})O&M Expenses = 2.57 Cr4 No * 52.40 Lakh/Bay (400KV)75 Km * 0.627 Lakh/Km (400KV D/c Twin) Interest on Working Capital @ 12.25% = 0.41 Cr( WC=2 Month Receivables + 1 Month O&M + 15% O&M for spares)TOTAL TARIFF = Rs. 20.15 Cr / year

Will Tariff be paid after ‘Useful life’? Yes. Tariff is receivable by the Owner ‘Depreciation’ component will not be receivable Eligible for Renovation and Moderation Asset can be written off and new project can be constructed or

R&M can be taken up Allowance for R&M Rs.5Lac/MW/yr as Fixed Ch. R&M as a separate project

‘useful life’ in relation to a unit of a generating station and transmission system from the COD shall mean the following, namely:-

(a) Coal/Lignite based station :25 years(b) Gas/Liquid fuel based station :25 years(c) AC and DC sub-station: 25 years(d) Hydro generating station : 35 years(e) Transmission line : 35 years

Some TCT clauses relevant to System

Operation

Commercial Declaration‘Date of commercial operation’ or ‘COD’ means(a) in relation to a unit or block of the thermal generating station, the date

declared by the generating company after demonstrating the maximum continuous rating (MCR) or the installed capacity (IC) through a successful trial run after notice to the beneficiaries, from 0000 hour of which scheduling process as per the Indian Electricity Grid Code (IEGC) is fully implemented, and in relation to thegenerating station as a whole, the date of commercial operation of the last unit or block of the generating station;

(b) in relation to a unit of hydro generating station, the date declared by thegenerating company from 0000 hour of which, after notice to the beneficiaries, scheduling process in accordance with the Indian Electricity Grid Code is fully implemented, and in relation to the generating station as a whole, the date declared by the generating company after demonstrating peaking capability corresponding to installed capacity of the generating station through a successful trial run, after notice to the beneficiaries:

hydro generating station with pondage : If insufficient reservoir or pond level -demonstrate peaking capability equivalent to installed capacityrun-of-river hydro generating station - demonstrate peaking capability as and when sufficient inflow is available.

c) element of the transmission system : first day of a calendar month

Infirm power‘Infirm power’ means electricity injected into the

grid prior to the commercial operation of a unit or block of the generating station;

11. Sale of Infirm Power. Supply of infirm power shall be accounted as Unscheduled Interchange (UI) and paid for from the regional or State UI pool account at the applicable frequency-linked UI rate:

Provided that any revenue earned by the generating company from sale of infirm power after accounting for the fuel expenses shall be applied for reduction in capital cost:

Maintaining Fuel Stock18 1(a) Coal-based/lignite-fired thermal generating stations

(i) Cost of coal or lignite and limestone, if applicable, for 1½ months for pithead generating stations and two months for non-pit-head generating stations, for generation corresponding to the normative annual plant availability factor;

Open-cycle Gas Turbine/Combined Cycle thermal generating stations

Fuel cost for one month corresponding to the normative annual plant availability factor, duly taking into account mode of operation of the generating station on gas fuel and liquid fuel;

Liquid fuel stock for ½ month corresponding to the normative annual plant availability factor, and in case of use of more than one liquid fuel, cost of main liquid fuel.

Declared Capability in Fuel Shortage Conditions

21(4) In case of fuel shortage in a thermal generating station, the generating company may propose to deliver a higher MW during peak-load hours by saving fuel during off-peak hours. The concerned Load Despatch Centre may then specify a pragmatic day-ahead schedule for the

generating station to optimally utilize its MW and energy capability, in consultation with the beneficiaries. DCi in such an event shall be taken to be equal to the maximum peak-hour expower plant MW schedule specified by the concerned Load Despatch Centre for that day.

Declared Capability in Fuel Shortage Conditions

Pk hours to be specified in RPC forum

DC not to be revised during Pk hours

DC can not be reduced Unless Unit trips

If unit trips, maximum possible DC to be given in other units

In such case max DC during pk hrs to be specified as DC for the day

To Check Gaming by Generator

DC can not be increased

For Hydro Stations

• DCi = Declared capacity (in ex-bus MW) for the ith day of the month which the station can deliver for at least three (3) hours, as certified by the nodal load dispatch centre after the day is over.

• (8) The concerned Load Despatch Centre shall finalise the schedules for the hydro generating stations, in consultation with the beneficiaries, for optimal utilization of all the energy declared to be available, which shall be scheduled for all beneficiaries in proportion to their respective allocations in the generating station.

Sharing of ISTS charges(1) Regional Tr. Ch of a Beneficiary

=(Agreed Pooled Assets+ Associated Tr. System+ IR link)

Total ISGS capacity

X (Wt. Avg. Entitlement from all ISGS+LTA+ MTOA)

(2) IR link sharing :

SR-WR, NR-WR, ER-NER = 50:50

NR-ER by NR, SR-ER by SR, WR-ER by WR

(3) ICT and Down Stream N/W charges by Respective Beneficiary

(4) Unpooled ATS : by respective Beneficiaries

Transmission charges in absence of a Beneficiary

Regulation 33 (7)• A new clause is added with regard

payment of Tr. Charges by the generator incase of non-identification of beneficiary for its capacity.

• “Transmission charges corresponding to any plant capacity for which a beneficiary has not been identified and contracted shall be paid by the concerned generating company”.

Notified on 15.06.2010 and shall come into force from 01.01.2011

Transmission charges for the Assets of POWERGRID shall continue to be determined by CERC

Existing methodology for Sharing of Transmission Charges is replaced (Regulation 33 of Terms & Conditions of Tariff, 2009 : Repealed )

Sharing based on Point of Connection (PoC) Tariffs based on load flow analysis

PoC are identified against all the USERS of the ISTS network known as Designated ISTS Customers (DICs)

Salient features of PoC Regulations

1) Generating Stations

2) SEBs/STUs

3) Bulk consumer directly connected with ISTS

4) Any designated entity representing aforementioned physically connected entity

Effect of PoC Regualtions (Sharing of Inter state Transmission charges and losses)

Proposed Changes in Fixed Charge Recovery

For incentivising Peak Availability • Annual Fixed charge for the peak hours • Annual Fixed charge for the off-peak hours in (1): (2.4) ratioDifferent Norms for Fixed charges specified based

on classification of Peaking Stations Other than Peaking Stations For Thermal, Hydro and CCGTNorms for Pumped Storage Hydro

Generating Stations introduced

Tariff Policy 2006 Provisions of “Tariff Policy” of Jan 2006 state:

“Even for the Public Sector Projects, tariff of all new generation and transmission projects should also be decided on the basis of competitive bidding after a period of five years or when Regulatory Commission is satisfied that the situation is ripe to introduce such competition.”

“Tariff of the projects to be developed by CTU/STU after the period of five years or when the Regulatory Commission is satisfied that the situation is right to introduce such competition would also be determined on the basis of Competitive Bidding.”

Competitive Bidding in : Power plant setup Transmission system construction

Tariff Competitive Bidding

• For Old projects, tariff will be continued to be fixed.

• For New projects awarded under Competitive Bidding, Quoted Tariff as per final award will be used got payment of charges

References :

• Terms and Conditions for Renewable Energy • RLDC fee and Charges• Statement of Objects and Reasons for Terms and

Conditions of Tariff regulations • Indian Electricity Grid Code 2010 • CERC order dt Benchmarking of Thermal projects • CERC order dt Benchmarking of Transmission projects

• CERC (Terms and Conditions for Tariff determination

from Renewable Energy Sources) Regulations, 2009. • Tariff Notification for Generating Companies – Govt. of

India