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1
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
3
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
4
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
5
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
6
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
7
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
8
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
9
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
10
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
11
Benchmarking
12
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.
13
Benchmarking• Benchmarking criteria:
– To be based on:• Actual • Industry/ national/ international standards• Resources (technology/investment/motivation)
pumped in– Measurable – Achievable– Controllable – Accountable – Rewardable
14
Target should be achievable
15
Unrealistic Target may lead to System Collapse
16
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
18
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.
19
Highlights: 2009-14 Regulation
• 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
20
Highlights: 2009-14 Regulation
• 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
21
Highlights: 2009-14 Regulation
• 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
22
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
24
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.
25
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
27
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
28
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
29
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
30
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
31
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
32
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
33
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.
34
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
35
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
36
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.
37
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.
38
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
39
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)
40
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.
41
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.
42
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
43
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)
44
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.
45
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
46
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.
47
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
48
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
50
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
51
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%
52
Norms of Operation: 2009-14 Regulation
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.
53
Norms of Operation: 2009-14 Regulation
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%
54
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
55
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.
56
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
57
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
58
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
59
Norms of Operation: 2009-14 Regulation
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
60
Norms of Operation: 2009-14 Regulation
(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
61
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
62
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
63
Norms of Operation: 2009-14 Regulation
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
64
Norms of Operation: 2009-14 Regulation
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
65
Norms of Operation: 2009-14 Regulation
3. Auxiliary Energy Consumption (%)
B. Gas basedCombined Cycle 3.0
Open Cycle 1.0
66
Norms of Operation: 2009-14 Regulation
3. Auxiliary Energy Consumption (%)
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
67
Norms of Operation: 2009-14 Regulation
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
69
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
70
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
71
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
72
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
73
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)
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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)
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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
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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.
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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.
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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%
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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
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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%