4 - kulmani biswal - tariff detrmination generation and transmission (case study)

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Forum of Regulators

Department of Industrial and Management Engineering

Indian Institute of Technology Kanpur

3rd Capacity Building Programme for Officers of Electricity Regulatory Commissions

23 – 28 August, 2010

Tariff Determination : Generation and Transmission

(Case Study)

Kulamani BiswalChief (Finance), CERC

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Functions of the Regulators

• Regulations framing • Licensing• Tariff setting• Regulate

– Transmission and Distribution of Electricity– Power purchase by Discoms

• Dispute resolution• Levy of fees• Promote renewables• Specify Grid code• Specify and enforce standards

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Investors Expectation

• Regulators to ensure:– Return on Capital employed– Return of Capital Employed– Reimbursement prudent operating Expenses– Reward to efficient performer– Reduction in Regulatory Uncertainties

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Consumer Interest –What does it mean?

• In my view:– Access to Electricity– Availability of Electricity– Assured Quality of Electricity– Attentive to Services– Affordable Price

Regulators to strike a balance between the interest of Consumers and Investors

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Role of Regulators in setting tariff

Regulators to ensure:• Transparent Procedure• Balance the conflicting interest• Reasonableness of the Rate

base• Recovery of the Capital

invested along with reasonable return

• Normative O & M expenses • Good performance is

incentivised

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Tariff Determination-Legal Aspects

• Chapter –VII comprising Sec-61 to Sec-66 of the Electricity act, 2003 deals with Tariff matters

• Appropriate Commission to determine the tariff subject to the provisions of the Act

• Appropriate Commission to make Tariff Regulations

• The aggrieved parties can prefer appeal before ATE against the Orders of the commission

• Similarly, ATE Orders are appealable before the Supreme Court

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the Electricity Act, 2003

• Section 61: Commission to specify the terms & conditions of Tariff and shall be guided by:Ø Principles and methodology

specified by CERCØ Commercial PrinciplesØ Ensure efficiency, economy and

competitionØ Balance the interest of

consumers and investors Ø Rewarding efficiency in

performanceØ Multi-year tariff principlesØ Tariff to reflect cost of supplyØ Encouraging co-generation and

Non-conventional sources of energy

Ø The National Electricity Policy and Tariff Policy issued by GOI

utilities consumers

commission

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Provisions of the Electricity Act, 2003

• Section 62: Commission to determine the tariff for:Ø Supply of electricity by a generating company to a

distribution licenseeØ Transmission of electricityØ Wheeling of electricityØ Retail sale of electricity

Provision of parallel distribution license in the sameArea

• Section 63: appropriate commission shall adopt the tariff determined through transparent process of bidding

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Provisions of the Electricity Act, 2003

ü Section 64 deals with the procedure for tariff orderØ Application shall be made to the appropriate

commission with such fee as may be prescribedØ Orders shall have to be issued within 120 days of the

date of receipt of the applicationØ Copies of the orders shall be sent to appropriate

Govt., the authority and the licensees within 7 daysØ A tariff order unless amended or revoked shall be in

force for such period as may be specified in the tariff order.

ü Section 65 deals with the provision of subsidy by the state Govt.

ü Section 66 deals with the provision of development of market for electricity trading

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Benchmarking

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Benchmarking

• Benchmark what?– Capital cost– Norms of operation

• Plant availability• SHR• Auxiliary consumption, etc.

– O&M norms – Financial norms

• D/E ratio• Rate of RoE• Interest rate, etc.

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Benchmarking• Benchmarking criteria:

– To be based on:• Actual • Industry/ national/ international standards• Resources (technology/investment/motivation)

pumped in– Measurable – Achievable– Controllable – Accountable – Rewardable

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Target should be achievable

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Unrealistic Target may lead to System Collapse

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Benchmarking• Tariff Regn, 2009: “7(2) The capital cost admitted by the Commission after

prudence check shall form the basis for determination of tariff:Provided that in case of the thermal generating station and the transmission system, prudence check of capital cost may be carried out based on the benchmark norms to be specified by the Commission from time to time:”

• Commission initiated the process in June 2008:– Phase-I: Concept & Mathematical Model: Approved– Phase-II:

• Data base creation• Model preparation• Model validation• Consultation: public comments, public hearing• Final Benchmark Norms

– Status:• Trasnsmission:

– Lines:– Substations : Approved vide Commission’s order dated 16.6.2010

• Thermal Generation: Under testing & validation in progress

HighlightsOf

2009-14 Regulation

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Highlights: 2009-14 Regulation

• Tariff fixation procedure rationalizedØNo provisional tariff ØUpfront tariff fixationØNo additional capitalization after cut-off date on new

assets for thermal power stationØNo AADØNo separate calculation of IncentiveØNo separate calculation of Income TaxØRepayment linked to depreciationØBenchmark norms for prudence check of capital cost of

thermal generating station and transmission systemØCapacity Index concept for hydro stations has been

dispensed with.

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• New features introducedØTariff fixation on the basis of projected capital cost and

additional capital expenditureØSecondary fuel oil consumption to be a part of AFCØTruing up of capital costØPrudence check of capital cost on the basis of

benchmarked norms for thermal and transmission projectsØIDC, financing charges and FERV during construction

period on the equity considered as normative loanØSpecial provision for capital cost of hydro projectsØProvision for R&M for life extension and ‘Special

Allowance’ for thermal generating projectsØPre-tax rate of return on EquityØLand for reservoir in case of hydro projects to be

depreciable asset

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• New features introduced (Contd.)ØSharing net benefits on re-financing of loan and savings

on account of secondary fuel oil consumption.ØSpecial additional O&M norms for thermal projects more

than 10 yrs lifeØNorms of heat rate linked to designed heat rate with a

margin of 6.5%ØDe-scaling factor for O&M norms of thermal projects to

take care of economy of scaleØSharing hydrological risks in hydro projectsØInducement to hedging of foreign loansØNorms for new technologies (such as supercritical)ØSharing CDM benefitsØIncentive linked to Plant Availability Factor and AFCØSpecial provisions for DVC

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• Other major proposalsØ15.5% base rate for pre-tax rate of ROEØAdditional 0.5% base rate for pre-tax rate of ROE for

timely completion of projectsØNew rate of depreciation averaging to approximately

5.28%ØTightened norms of operationØReasonable compensation for pay hikes factored into

O&M Norms ØAuditors to include auditors appointed under section 224

& 233B of the Companies Act, 1956 and any other law for time being in force.ØUndischarged liabilities not to form a part of the capital

cost

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Vetting of hydro capital cost

• The Tariff Regulations, 2009 provided that:“the Commission may issue guidelines for vetting of capital cost of hydro-electric projects by an independent agency or expert and in that event the capital cost as vetted by such agency or expert may be considered by the Commission while determining the tariff of hydro generating station” (Third proviso to clause(2) of Regulation 7 ).

• The Commission has issued “the guidelines for vetting of capital cost of hydro electric projects by Designated Independent Agencies/Experts” vide its order No. L-1/50/2010-CERC dated 2nd August 2010.

• Three Independent agencies have been appointed by the Commission

Application for

tariff DETRMINATION

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Application for tariff: 2004-09 Regulation

ØApplication for tariff determination shall be made as per the appendix-I attached to the notificationØProjects coming after 1.4.2004 can apply for

provisional tariff with the expenditure as on date of application.ØFresh application can be made for final tariff

based on actual expenditure incurred and capitalized after COD duly audited and certified by the statutory auditors.ØRecovery of income tax and FERV shall be done

directly without making any application before the Commission.

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Application for tariff: 2009-14 Regulation

• Application:ØApplication for completed or projected to be completed

within 6 months from the date of applicationØNo provisional tariffØTariff for capital expenditure and additional capital

expenditure actually incurred or projected to be incurred during the tariff period

• Truing up of capital cost (including ACE)ØUtilities to apply before 31.10.2014ØTo be done along with the tariff for next tariff periodØUtilities can approach for one more time prior to 2013-

14ØUnder-/over-recovered tariff to be recovered/refunded

with a simple interest at the rate equal to short-term PLR of SBI as on 1st April of respective year in 6 equal monthly installments starting within 3 months from the date of order

Tariff determination

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Elements of Tariff : 2004-09 Regulation

ØFixed Cost: Annual Fixed Charges∗ Return on Equity∗ Interest on Loan∗ Depreciation & Advance Against Depreciation∗ Interest on Working Capital∗ Operation & Maintenance Expenses

ØVariable Cost: Energy Charges

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Elements of Tariff: 2009-14 Regulation

ØFixed Cost: Annual Fixed Chargesv No AADvNew element:vCost of normative secondary fuel oil consumption vSpecial Allowance and Separate Compensation

Allowance, wherever applicable

ØVariable Cost:v Energy Charges for thermal: cost of secondary

fuel shall not be considered.vEnergy Charges for hydro: linked to AFC with a

multiplication factor of 0.5

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Financial Parameters• The financial parameters of tariff setting

are:(1) Approach for Rate of Return (RoR)(2) Capital Cost (3) Debt/Equity Ratio(4) Return on Equity (ROE)(5) Pre-tax Vs Post-tax Return(6) Interest on Loan (IOL)(7) Depreciation(8) Interest on Working Capital (IOWC)(9) Treatment of FERV(10)Operation and Maintenance Expenses

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Approach for Rate of Return• CERC follows ROE approach in 2004-09

regulations. ØReasons for not adopting ROCE approach were:

- Lack of benchmarking for D/E mix- Volatile interest rate- Limited tenure debt market

• As per the Tariff Policy CERC may adopt either ROE or ROCE approach whichever is considered better in the interest of the consumers.

• 2009-14 Regulation:ØContinue with ROE approach

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Capital Cost• As per the 2004-09 regulations:Ø Except for NLC & Badarpur station of NTPC CERC fixes tariff based on GFA

approach i.e. Equity does not get depleted once the loans are repaid.Ø There is no benchmark for capital cost.Ø Actual expenditure incurred and capitalized, subject to actual cash outgo, is

considered for the purpose of tariff determination.Ø Initial spares subject to a ceiling specified by the commission form a part of the

capital cost.Ø IDC on actual loan and IEDC are allowed to be capitalized along with hard

cost.Ø No ROE is provided during construction.Ø Additional capital expenditure is allowed subject to prudence check

• As per Tariff Policy:Ø Appropriate Commission is to ensure that the Total Capital Cost is reasonableØ Requisite benchmarks should be evolved by the Commission

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Capital Cost : 2009-14 RegulationØProjected capital cost and additional capital expenditure

consideredØ IDC, financing charges & FERV during construction period on

the equity considered as normative loan shall be allowedØ Initial spares for transmission: given separately for lines, sub-

stations and series compensation devices & HVDC stationsØPrudence check on the basis of benchmarked norms, to be

published by the Commission, for thermal and transmission projectsØSpecial provisions for hydro projects as per tariff policyØAdditional capital expenditure on new works for thermal projects

not within the original scope of work shall not be allowed aftercut-off date (taken care of under Compensation Allowance)ØSpecial provision for R&M works, with an option for ‘Special

Allowance’, linked to escalation @ 5.72%, for thermal projects, added

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Capital Cost : 2009-14 Regulation

ØSpecial provisions for hydro projectsØDepreciation to be allowed on land for reservoir.ØDevelopers insulated from hydrological risk during the

first 10 years.ØEnhanced free power and rehabilitation cost allowed

according to new Tariff Policy, for expediting project implementation.ØAdditional capital expenditure to be allowed:ØOn account of damage caused of natural calamities (but not due

to flooding of powerhouse attributable to negligence of Genco) after adjusting for insurance proceeds.ØDue to any additional work which has become necessary for

successful and efficient plant operation.

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Capital Cost : 2009-14 Regulation

§ Special R&M provision for thermal stationØ Option-I : Special Allowance

(i) Rs.5.0 lakh/MW/year(ii) linked to escalation @ 5.72% per annum(iii) Not available to station that have already undertaken R&M and

cost was admitted by the Commission

Ø Option-II : Comprehensive R&M (i) To be approved on the basis of cost benefit analysis, efficiency

gain, etc.(ii) Capital cost for Tariff = R&M and LE expenditure after

deducting the accumulated depreciation already recovered from the original project cost

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Debt/Equity Ratio

• Present approach:Ø2004-09 Regulations stipulates a D/E ratio of

70:30 for projects after 01.04.2004.• As per Tariff Policy:ØD/E ratio of 70:30 for new projects.

• 2009-14 Regulation :ØUniform D/E ratio of 70:30 for all new projects,

additional capital expenditure and R&M worksØFor existing projects, D/E ratio, as admitted by

the Commission, to continue

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Return on Equity• 2004-09 Regulations

– Post tax ROE of 14% for entire tariff period.– Return on foreign equity to be allowed in the same currency

and to be paid in INR based on ER prevailing on the date of billing

F As stipulated by GoI in October 1991 , the norms have been: ‘RBI Bank Rate at the beginning of the year + 5%’.

• As per Tariff Policy:ØRate of RoE fixed should maintain a balance between the

interest of the consumers and the need for investments.ØRate of RoE fixed by CERC for generation and transmission

shall be followed by the SERCs.ØSERCs may adopt the rate of RoE fixed for transmission for

the distribution with suitable modification.

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Return on Equity : 2009-14 Regulation

ØPre-tax rate of ROE Ø15.5% base rate for pre-tax rate of ROEØAdditional 0.5% base rate for timely

completion of projectsØForeign equity to be converted to INR on

the date of investment.

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Pre-tax Vs Post-tax Return : 2004-09 Regulation

• 2004-09 regulations:Ø allow post-tax returnØActual income tax gets reimbursed.ØSometimes tax burden on beneficiaries becomes

heavy due to:vIncentivevEfficiency gainvNotional expenditurevIncome on UI

ØBenefit of tax holiday passed on to the beneficiaries

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Pre-tax Vs Post-tax Return :2009-14 Regulation

ØPre-tax rate of return ØBase rate to be grossed up considering normal tax

rate applicable to the company during 2008-09ØTo be trued up with the normal tax rate of respective

year applicable to the company during true up exercise

ØBenefit of tax holiday under section 80IA shall remain with the utilitiesØBeneficiaries not to bear the burden of income tax

on other earnings (like UI earning, incentive earning and efficiency gains)

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Interest on loan

• 2004-09 regulations:Ø Normative loans are serviced as per the Weighted

Average Rate of Interest (WARI) on actual loansØRepayment: Normative repayment or depreciation,

whichever is higher• As per Tariff Policy:ØEncourage structuring of debt, including tenure.Ø Incentives for savings in costs on account of subsequent

restructuring of debt.• 2009-14 Regulation :ØContinue existing methodology for calculation of IOL.ØRepayment shall be equal to the depreciation allowed.

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Depreciation : existing

• As per the 2004-09 regulations:ØValue Base for the purpose of depreciation is Historical Cost of

the assetØHistorical cost includes Additional capitalization and FERV up to

31.03.2004ØStraight Line Method over the useful life of the assetØDepreciation Rates as prescribed in Appendix II to Tariff

Regulations, 2004ØSalvage Value is 10%, Depreciation is allowed up to 90% of

historical costØOn repayment of entire loan, the remaining depreciable value

shall be spread over the balance useful life of the assetØDepreciation is chargeable from the first year of operation. In case

of operation of the asset for part of the year, depreciation shall be charged on pro rata basisØAAD is allowed subject to certain condition.

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Depreciation

• As per Tariff Policy:ØDepreciation Rates be notified by CERC

- Notified rates shall be applicable for the purpose of tariff as well as accounting

ØNo advance against depreciation (AAD) would be allowedØBenefit of reduced tariff would be available to consumers

after the asset is fully depreciatedØSERC to follow the rate as prescribed by CERC with or

without modification as evolved by FoR

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Depreciation : 2009-14 Regulation

• 2009-14 Regulation :ØValue Base for the purpose of depreciation is capital cost

admitted by the CommissionØNew schedule of depreciation rate averaging to

approximately 5.28% (Appendix-III)ØLand for reservoir in case of hydro projects to be a

depreciable assetØSpread over after 12 yearsØNo advance against depreciation (AAD)

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Interest on Working Capital : existing

• 2004-09 regulations– IOWC is allowed on the following components:

• Fuel cost– Coal/Lignite: Pit head station : 1&1/2 mo.

Non-pit head station : 2 mo.– Gas based station : 1 mo.

• Secondary fuel oil (for coal/lignite) : 2 mo.Liquid fuel stock (for gas based) : ½ mo.

• O&M Expenses : 1 mo.• Maintenance Spares: 1% of historical cost escalated @6% p.a• Receivables : 2 mo.

– Interest rate is short-term SBI PLR as on 01.04.09 or 1st April of the year of COD, whichever is later

– Current Liabilities not considered.

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Interest on Working Capital :2009-14 Regulation

• 2009-14 Regulation:– IOWC components:

• Maintenance Spares linked to O&M expensesØ Coal/Lignite based : 20% of O&MØGas/Liquid based : 30% of O&MØHydro : 15% of O&MØTransmission : 15% of O&M

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Treatment of FERV• 2004-09 regulations:ØFERV is allowed as pass through.

• Tariff Policy: ØFERV shall not be pass through.ØAppropriate cost of hedging and swapping to take care of

FERV should be allowed for debt obtained in foreign currencies.

• 2009-14 Regulation :ØCost of hedging is allowedØTo the extent hedging is not done, FERV shall be allowed

as pass through.

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O&M Expenses : 2009-14 Regulation

• Escalation rateØ 5.17% for 2003-04 to 2007-08Ø 5.26% for 2004-05 to 2007-08Ø 5.72% from 2008-09

• Reasonable compensation for pay hikes factored into O&M Norms

• Special additional O&M norms for thermal projects more than 10 yrs life

• De-scaling factor for O&M norms of thermal projects to take care of economy of scale

• O&M for new hydro station increased from 1.5% to 2% of capital cost

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O&M Expenses : 2009-14 Regulation

• Separate Compensation AllowanceØ Introduced to meet the expenses on new assets of capital nature.Ø Shall be allowed after 10 yrs of life.Ø Shall be allowed unit wise in ‘Rs lakh / MW’Ø Norm is enhanced after a block of 5 years useful life.

• Compensation for pay hikes :O&M expenses for 2009-10 shall be further rationalized by considering-Ø Thermal: 45% increase in employees cost (35% of O&M)

Ø Hydro: 50% increase in employees cost (35% of O&M)Ø Transmission: 45% increase in employees cost (lines= 30% of O&M; AC s/s=

60% of O&M; HVDC station= 30% of O&M)

• Escalation factorØ average escalation during the last 5 years with a weightage of 60% for

WPI and 40% for CPI

Technical parameters

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Technical Parameters• The technical parameters of tariff

setting are:(1) Norms of Operation

(i) Target availability/ Normative capacity index for recovery of AFC

(ii) Target PLF for incentive(iii) Auxiliary energy consumption(iv) Transformation loss(v) Gross station heat rate(vi) Secondary fuel oil consumption(vii)Stabilisation period

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Norms of Operation: 2004-09 Regulation

ü Target Availability for Recovery of Full Capacity (Fixed) Charges –ü ThermalØ Recovery of Capacity charges below the level of Target availability

shall be on pro-rata basis.Ø At zero availability, no capacity charges are payable.Ø Thermal Power Stations : 80% ü HydroØ Purely Run-of-river power stations : 90%Ø Storage type power stations and Run of river power stations with

pondage : 85%ü TransmissionØ AC System : 98%Ø HVDC bi-pole links and HVDC back to back stations

: 95%

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Operating parameters for Thermal and Hydro generating stations and Transmission system have been prescribed in the regulations.

ü For thermal generating stations tightened ceiling norms have been prescribed for: Ø Normative Annual Plant Availability Factor (NAPAF) for recovery of fixed

charges and for incentiveØ Gross station heat rateØ Secondary fuel oil consumption, with provision for sharing of savings andØ Auxiliary Energy consumption

ü For hydro generating stations ceiling norms have been prescribed for: Ø NAPAF for recovery of fixed charges and for incentiveØ Auxiliary Energy consumption, including transformation losses

ü For transmission system ceiling norms have been prescribed for: Ø Normative Annual Transmission System Availability Factor (NATAF) for

recovery of fixed charges and for incentiveØ Auxiliary Energy consumption has been included in the normative O&M

expenses.

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ü NAPAF/NATSAF for recovery of fixed charges and for incentiveØ Recovery of Fixed Charges below or above the level of NAPAF/NATAF shall

be on pro-rata basis.Ø At zero availability no capacity charges are payable.Ø NAPAF for thermal:

Ø NAPAF for hydro: Differs for station to station from 55% to 90%

Ø NATAF for transmission: ØAC System = 98%ØHVDC bi-pole links = 92%ØHVDC back-to-back stations = 95%

Talcher / Tanda / Badarpur 82%

TPS – I / II / I(Expansion) 72% / 75% / 80%

Meija unit-I to IV/Bokaro / Chandrapura / Durgapur 82%/75% / 60% / 74%

AGBPS 72%

Lignite based using CFBC technology: First 3 yrs. From COD/thereafter

75%/80%

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Plant Availability (PAFM) – 2009-14

ØPAFM shall be computed in accordance with the following formula:

NPAFM = 10000 x Σ DCi / { N x IC x (100-AUX) }%

i = 1Where,v AUX is normative auxiliary energy consumption

including transformer lossesv DCi is the Declared capacity (ex-bus) 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

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NAPAF – 2009-14 Regulation

Ø NAPAF determination criteria :1) Storage and Pondage type plants:

i. with head variation between FRL and MDDL of up to 8%, and where plant availability is not affected by silt :90%

ii. with head variation between FRL and MDDL more than 8%, and where plant availability is not affected by silt:- Plant specific allowance to be provided in NAPAF for

reduction in MW output capability as reservoir level falls over the months

- Multiplying factor for head variation shall be applied as follows:

(Head at MDDL/Rated head) x 0.5 + 0.522) Pondage type plants where plant availability is significantly

affected by silt: 85%3) Run-of-river type plants :NAPAF to be determined plant wise,

based on 90% dependable 10-daily inflows pattern as approved in the DPR.

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NAPAF – 2009-14 Regulation

ØAn allowance may be allowed by the Commission in NAPAF determination under special circumstances i.e. abnormal silt problem or other operating conditions and known plant limitations etc.ØA further allowance of 5% may be allowed for

difficulties in N.E. RegionØ In case of a new hydro station the project

developer has the option to approach the Commission for determination of NAPAF

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NAPAF of stations in operation – 2009-14 Regulation

• Station • Type of

Plant• Plant

Capacity • NAPAF

(%)

• NHPC

• Chamera-1 • Pondage • 3X180 • 90

• Biarasiul • Pondage • 3x60 • 85

• Loktak • Storage • 3x35 • 85

• Chamera-II • Pondage • 3x100 • 90

• Rangit • Pondage • 3x20 • 85• Dhauligana • Pondage • 4x70 • 85

• Teesta-V • Pondage • 3x170 • 85

• Dulhasti • Pondage • 3x130 • 90

• Salal • ROR • 6x115 • 60

• Uri • ROR • 4x120 • 60• Tanakpur • ROR • 3x31.4 • 55

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NAPAF of stations in operation – 2009-14 Regulation

NHDCIndirasagar Storage 8x125 85

Omkareshwar Pondage 8x65 90THDCTehri Stg-1 Storage 4x250 77SJVNLNathpa Jhakri Pondage 6x250 82

NEEPCOKopli Stg-1 Storage 4x50 79Khandong Stg.-2 Storage 3x25 69Doyang Storage 3x25 73Ranganadi Pondage 3x135 85

DVCPanchet Storage 2x40 80Tilaiya Storage 2x2 80Maithon Storage 3x20 80

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1. Gross Station Heat Rate (kcal/KWH)(A) Coal Based Thermal Stations

200/210/250 MW 500 MW(sub-critical)

2500 2425 – For 500MW and above with electrically operated BFP : - 40– For combination of 200/210/250 MW sets and 500MW and above sets :

weighted average– Special norms for some specific stations.

Talcher / Tanda / Badarpur 2950/2825/2825

Bokaro / Chandrapura / Durgapur 2700/3100/2820

Coal based using CFBC technology 2550

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(B) Lignite-Fired Thermal stations Ø Above station heat rates (as at A) to be corrected using

multiplying factor as given below:ØLignite having 50% moisture multiplying factor of 1.10ØLignite having 40% moisture multiplying factor of 1.07ØLignite having 30% moisture multiplying factor of 1.04ØFor other values: to be pro-rata of above

Ø Special norms for some specific stations.

TPS – I / II 4000/2900

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Norms of Operation : 2009-14 Regulation(C) Existing Open Cycle Gas Turbine/CCGT Stations

(in Kcal/kWh)Station Combined Cycle Open Cycle

Gandhar GPS 2040 2960

Kawas GPS 2075 3010

Anta GPS 2075 3010

Dadri GPS 2075 3010

Auraiya GPS 2100 3045

Faridabad GPS 2000 2900

Kayamkulam GPS 2000 2900

Assam GPS 2400 3440

Agartala GPS 3500

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Norms of Operation : 2009-14 Regulation

(D) New Thermal Generating Stations achieving COD on or after01.04.2009 (in Kcal/kWh)ØCoal-based and lignite fired thermal stations

= 1.065 x Design Heat RateNote: shall not exceed the given maximum design unit

HR depending upon the pressure and temperature ratings of the unit.

ØGas-based/ liquid-based thermal stations= 1.06 x Design Heat Rate of the unit/block for

Natural Gas and RLNG= 1.071 x Design Heat Rate of the unit/block for

liquid fuel

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2. Secondary fuel oil consumption ml/kwh

Coal based 1.0

Lignite fired excluding CFBC technology and TPS-I

2.0

TPS-I 3.5

Lignite fired based on CFBC technology 1.25

Meija/Bokaro / Chandrapura / Durgapur 2.0/2.0 / 3.0 / 2.4

Lime stone consumption for Lignite fired station using CFBC technology (kg/kwh)

Barsinger 0.056

TPS-I(Exp) 0.046

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3. Auxiliary Energy Consumption (%)

Note: With Draft Cooling Tower: +0.5%

A. Coal based With/without Natural Draft Cooling Towers

200 MW Series 8.5

500 MW and above Series

- Electrically Driven BFPs 6.0

- Steam Driven BFPs 8.5

Talcher / Tanda / Badarpur 10.5 / 12.0 / 9.5

Bokaro / Chandrapura / Durgapur 10.25 / 11.50 / 10.50

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B. Gas basedCombined Cycle 3.0

Open Cycle 1.0

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C. Lignite fired With/without Natural Draft Cooling Towers

200 MW Series and above (+0.5%) 9.0

200 MW Series and above using CBFC technology (+1..5%)

10.0

Barsingar (using CBFC technology) 11.5

TPS-I/TPS-II/TPS-I(Exp.) 12.0/10.0/9.50

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3. Auxiliary Energy Consumption (including Transformation Losses) (%)

D. HydroSurface with- rotating excitation mounted on generator shaft 0.7

- static excitation 1.0

Underground with

- rotating excitation mounted on generator shaft 0.9

- static excitation 1.2

Commercial parameters

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Commercial Parameters• The commercial parameters of tariff

setting are:(1) Recovery of Capacity charges and Energy

charges(2) Incentives(3) Rebate(4) Late payment surcharge(5) CDM benefit(6) UI mechanism

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Energy Charges : 2009-14 Regulation

ØFor thermal stations:ØSecondary fuel oil is not a part of energy chargeØTransit & handling losses for coal:

Pit head = 0.2%Non-Pit head = 0.8%ØFor coal and lignite (Rs/kwh):ECR = ((GHR-SFCnxCVSF)xLPPF/CVPF+LCxLPL)x100/(100-AUXn))

ØFor gas and liquid fuel (Rs/kwh):ECR = GHRxLPPFx100/(CVPFx(100-AUXn))

ØMonthly Energy Charge (Rs):= ECR x Scheduled energy (ex-bus) for the month

corresponding to scheduled generation

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Hydro Tariff – 2009-14

ØThe two part tariff for supply of electricity from a hydro station shall comprise of :i) Capacity chargeii) Energy charge

ØThe recovery of fixed charges in the form of capacity & energy charges shall now be on 50: 50 basis

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Tariff Structure for Recovery

Ø 50% of the Annual Fixed Cost is collected in the form of Capacity charge on monthly basis( We may refer it as period Cost)

Ø 50% of the AFC is divided by the Design energy net off of AUX and FEHS to find out energy rate per unit

Ø Energy rate so derived is multiplied with monthly scheduled energy to find out Energy charge per month.

Ø Incentive is inbuilt in the formulae and not provided separately.

Annual Fixed Cost

Capacity Charge Energy Charge

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Capacity Charges – 2009-14

ØCapacity Charge (Inclusive of incentive) payable to a hydro generating station for a month shall be :AFCx0.5x NDM/ NDY x (PAFM/ NAPAF) where,v AFC is the annual fixed cost specified v NAPAF is Normative plant availability factor

(%)v PAFM is Plant availability factor achieved (%)v NDM & NDY are the number of days in the

month/ year

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Energy Charges : 2009-14 Regulation

ØEnergy charge is payable month wise for the total energy scheduled to be supplied for the month ex power plant to the beneficiaries, excluding free energy.ØNo secondary energy charge payableØ ECR (Rs/kwh)= AFCx0.5x10 / (DEx(100-AUXn)x(100-FEHS)

ØMonthly Energy Charge (Rs):= ECR x Scheduled energy (ex-bus) for the month

corresponding to scheduled generation x(100-FEHS)/100

Ø12% /(13% + 100 units) of ex-bus energy is given free to the home state.

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Compensation for loss in generation – 2009-14

Hydrological Risk sharing

ØShortfall scenario (Ai (actual generation in yr. i)<DE):ØDE in ECR formulae shall be:ØUp to 10 yrs (till EC recovery shortfall of previous yrs. is made

up) : DEr=Ai

ØAfter 10 yrs: DEr=A1+A2-DE

ØHigher generation scenario (Ai>DE):ØECR for excess generation shall be restricted to

80 paisa per unit(in case of shortfall, ECR shall be restricted to 80p only after EC

shortfall of previous year has been made up)

76

Transmission charge: 2009-14 Regulation

ØFor Transmission systems:ØTransmission Charge (TC) is inclusive of incentiveØTC is computed on annual basis and recoverable on

monthly basisØTC payable for a month

= AFCx(NDM/NDY)x(TAFM/NATAF)

77

Incentives: 2009-14 Regulation

ØThermal and hydro generating stationØShall form a part of recovered fixed charge and

energy chargeØLinked to Plant Availability Factor

ØTransmissionØShall form a part of recovered transmission chargeØLinked to Plant Availability Factor

78

Rebate –2009-14 Regulation

• Rebate allowable is:Ø2%: for payment of bills through letter of credit

on presentation of bills.Ø1%: for payment of bills made by a mode other

than through a letter of credit but within a period of one month of presentation of bills.

79

Late Payment Surcharges –2009-14 Regulation

• In case of payment of any bills (other than UI and VAR charges) by beneficiaries is delayed beyond a period of 60 days from the date of billing, late payment surcharge payable is:Ø1.25% per month.

80

CDM benefits• Provisions for sharing of CDM benefits has been

introduced.– 1st year after DOCO: 100% of the gross proceeds on

account of CDM to be retained by the project developer;

– 2nd year: share of the beneficiaries shall be 10%– Subsequent years: share of the beneficiaries shall be

progressively increased by 10% every year till it reaches 50%

81

Unscheduled Interchange (UI)• 2004-09 Regulation:Ø Variation in actual generation/ drawl and scheduled generation/ drawl shall

be accounted for through Unscheduled Interchange (UI) charges. Ø UI for the generating station shall be equal to its actual generation minus

scheduled generation.Ø UI for the beneficiary shall be equal to its actual drawl minus its scheduled

drawl.

• 2009-14 Regulation: to be dealt in a separate regulation to be specified by the CommissionØ Commission issued CERC (Unscheduled Interchange charges and related

matters) Regulations, 2009 vide Notification No.L-1(1)/2009-CERC New Delhi, the 30th March 2009

Ø This regulation has been amended vide Notification No.L-1(1)/2009-CERC New Delhi, the 28th April 2010

82

Tariff impact (Nathpa Jhakri)Recovery of AFC

Old Regn(2004-

09) New

Regn(2009-14 )

Annual design energy (MU) 6984 6984 0.00

Scheduled energy (ex-bus) 6386 6386 0.00

Normative capacity index (%)/ NAPAF (%) 85% 82% -0.03

Actual capacity index (%)/ Actual PAF (%) 96.70% 82.00% -0.15

Auxiliary Consumption (%) 0.70% 0.70% 0.00

Transformation Loss (%) 0.50% 0.50% 0.00

Free energy to home state (%) 12% 12% 0.00

0.00

Saleable design energy (MU) 6072 6072 0.00

Free energy to home state 766 766 0.00

Scheduled saleable energy (MU) 5620 5620 0.00

Energy charge Rate (Rs./kwh)-Primary 1.00 1.21 0.21 21.50%

Energy charge (Primary) - Rs crore 561.97 682.76 120.80 21.50%

Energy charge (Secondary) - Rs crore 0.00 0.00 0.00

Capacity charge 675.61 737.74 62.13 9.20%

Incentive (Rs. crore) 94.12 0.00 -94.12 -100.00%

Total amount recovered (Rs. crore) 1415.20 1420.50 5.30 0.37%

Composite rate (Rs/ kwh) 2.52 2.53 0.01 0.37%

83

Tariff impact (Nathpa Jhakri)

AFC 2004-09 Regn.

2009-14 Regn.

Difference Diff.(%)

Depreciation 19930.43 40796.30 20865.87 104.69%

Higher depreciation rate (2.29% to 5.11%). IF AAD is considered AAD plus Depreciation increased from 35018.85 to 40796.30 i.e., by 5777.45 (16.50%)

Interest on Loan 14237.26 13941.13 -296.13 -2.08% Higher repayment (Depreciation considered as repayment)

Return on Equity 55935.61 69843.60 13907.99 24.86% Increase in base rate of ROE from 14% to 15.5%; Change of approach from post-tax return to pre-tax return with grossing up by 11.33% MAT rate.

AAD 15088.42 0.00 -15088.42 -100% AAD discontinued

IoWC 3966.52 3566.95 -399.57 -10.07%

As below.

O & M Expenses 14600.00 19400.00 4800.00 32.88% Impact of employes cost provided @50% on 35% of O&M expenses.

Total 123758.24 147547.98 23789.74 19.22% As above.

I. Tax Recovered 7147.29 0.00 -7147.29 -100% Change of approach from post-tax return to pre-tax return with grossed up tax rate of 12.78% on 11.33% MAT rate.

Gross AFC 130905.54 147547.98 16642.44 12.71%

4 - kulmani biswal - tariff detrmination generation and transmission (case study)

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