Transcript Slide 1

CERC Terms & Conditions of
Tariff 2009-14
System Operators’ Course
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’2001March’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 2009March 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
Audited Costs
Bench mark norms
of Project Cost
CoD
Billing by the ISGS/ ISTS
Accounting in REA
Cut off Date
Filing of AddCap+ deferred Liabilities
+actual Expenditure
Audited Costs
Truing up by CERC
Beneficiaries
Adjustment of Excess or
Deficit collection
Interest Rates
High lights
Regulation 39
Income from UI, Incentive & non-core business
–Not a pass through
Regulation 26 (ii)B
Min 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.
Total Project Cost considered for Tariff fixation
Project Exp.
Asstets
not in Use
IDC
Profit in Sale
of
Infirm power
FERV
Capital
Cost
Initial Spares
Addl
Cap
Rehab &
Resettle
(hydro)
RGGYY
(hydro)
Rs.
Debt:Equity
Ratio
Loan
Equity
Components of Tariff
Tariff
Capacity
Charges
Interest on
Loan
Energy
Charges
Depreciation
O&M
expenses
Return on
Equity
R&M
Allowence
Maint.
Spares
Normative
Seconday
Oil Cost
Primary Fuel
Lime Stone
(if
applicable)
Equity
Rate of RoE
Return Equity
Loan
Rate of Interest
Interest on Loan
Loan +Equity
Rate of
Depreciation
Depreciation
Normative
O&M Exp
O&M Exp
Type/Size of Unit/ /
Tr. system
O&M Exp
Working Capital
Seondary Oil rate
Normative % Spares
Interest rates
Sec. Oil rates
Maint. spares
Interest on
Working Capital
Sec Oil
Cost of 1.5* month primary fuel
Stock
* 2 months for non-pit head stns.
O&M Exp
Cost of 2 months Sec oil Stock
Working Capital
O&M Exp for 1 month
Interest rates
Cost of Maint. Spares (as a % of
O&M ch.)
2 months receivables
Interest on Working Capital
Time Lines in Tariff Period
Project schedule to determine addl. RoE
Control
Period 1
2-3 months
Control
Period 2
Depreciation in straight Line method (12 years)
End of Loan repayment
Apply for True I Up of Tarriff
Cut-Off Date for addl . Capitalisation
CoD
2+ years
1st Trial synchronisation
Drawl of Start up power (2-3 months)
Project
Start date (2- 4 years)
Control
Period 4
Tariff after
Renovation and
Modernisation
10-12 yrs
2-3 months
2-4 years
Control
Period 5
Eligibility for R&M
End of Useful Life
Construction
Period
Bench marking Model for Generating Stations
Benchmarking by CERC
Fuel /Technology
Green Field/ Exisitng
Size of Unit
No. of Units
Evacuation Voltage Level
Fuel Linkage
Plant Location (Pit Head/ Non Pit Head)
Month/Year of Award
Boiler Configuration
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
Bill of Quantities
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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
Indeces for Steel, Cement, Labour
Generous set
of assumptions
Source: CERC Explanatory Memorandum ( 8th Dec.’09)
Bench marking Model for Transmission lines
Benchmarking by CERC
Voltage class
No. of circuits
Conductor type
No. of Conductors
Insulator type
Bill of Quantities
Line length
Wind zones & Terrain
No. of Towers
Types of Terrains
No. of River crossings
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Conductor length
Earthwire length
No. of insulators
Qty. of Hardware
Total cost / Cost per ckm
• Tower Weights
• Foundation Volume
Unit cost based
on historical data and
Application of PV
Formula and
indices
Generous set
of assumptions
Source: CERC Explanatory Memorandum ( 8th Dec.’09)
Plant Availability Factor
DCi = Average declared capacity (in ex-bus MW),
N= No. of Days in the period
IC = Installed Capacity
Aux = 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 km
NSC = Number of sub-conductors per phase
MVA = MVA rating of a transformer / ICT
MVAR = MVAR rating of a bus reactor,
THM = Total hours in the month
2) NAFM for each HVDC system
NAFM = [ 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 Rate
Aux = 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 stations
ECR = { (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 Oil
Regulation 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
Depreciation
Regulation 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 2009-14
Case 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 Cr
Adopting 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 Cr
4 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’?
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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 the
generating 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 capacity
run-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 Stock
18 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 peakload 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”.
Effect of PoC Regualtions (Sharing of
Inter state Transmission charges and losses)
Salient features of PoC Regulations
 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)
1)
2)
3)
4)
Generating Stations
SEBs/STUs
Bulk consumer directly connected with ISTS
Any designated entity representing aforementioned physically connected entity
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) ratio
Different Norms for Fixed charges specified based
on classification of
 Peaking Stations
 Other than Peaking Stations
For Thermal, Hydro and CCGT
 Norms 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 :
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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