Transcript TARIFF DESIGN for GENERATING STATIONS

TARIFF DESIGN for
GENERATING STATIONS
-- Bhanu Bhushan -< [email protected] >
Feb 2011
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Basic criteria
• Reimbursement of reasonable cost of generation
and a reasonable return on investment : RoE,
IoL, Depreciation, O&M, Fuel, IWC.
• Separation of Fixed and Variable costs, to
ensure that a generating company does not
suffer a financial loss when the station is asked
to back down, to ensure that there are no
perverse incentives, and to facilitate merit-order
operation.
• Equitable sharing of the total payment between
the beneficiaries according to benefits derived
(or entitled to derive): Fixed cost α shares;
Variable cost α scheduled energy.
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• Focused incentives for improved performance,
particularly to maximize MW availability and
generation during peak-load hours, and to back
down as per merit-order during off-peak:
Fixed cost payment α plant availability;
= AFC when actual availability = NAPAF;
AFC and ECR based on judicious norms for heat
rate, auxiliary power consumption, secondary oil,
even in cost-plus tariff, but fuel cost and GCV
variations are pass-through.
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Desirables
• Generators and beneficiaries should know,
upfront, what the charges would be, and
retrospective adjustments should be avoided.
• Dispute-free implementation on long-term basis:
the scheduling process: availability declaration,
MW and energy entitlements, requisitions,
schedules, metering, deviations, U.I. accounting.
Two-part tariff for all thermal and hydro generation
is a must, whether cost-plus or market-based.
The two components have to be worked out
based on specified norms (in cost-plus) or
reached through competitive bidding process
(in market-based).
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Some salient features of the CERC (Terms &
Conditions of Tariff) Regulations, 2009, issued on
19.01.2009 and effective from 01.04.2009 for 5 years
• Plant availability norm raised from 80% to 85%.
• PLF-linked incentive withdrawn; incentive is now
an integral part of Capacity charge, which is
directly linked to plant availability.
• Secondary oil cost included in AFC.
• Infirm power paid at U.I. rate.
• If secondary oil consumption is below the norm
(1 ml/kWh now), savings shared 50:50 with
beneficiaries.
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Some of the norms / provisions
• GSHR: 2500 / 2425 kcal/kWh for 210 / 500 MW.
• Auxiliary power consumption: 8.5 / 6.0% for 210 /
500 MW; + 0.5% for IDCT.
• Transit loss for coal = 0.2 / 0.8%.
• Useful life = 25 / 35 years for thermal / hydro.
• Shares to remain constant during a month.
• FEHS for hydro = 12% + 1%.
• NAPAF for hydro, plant-specific, as per average
peaking capability, duly considering year-round
inflow variation (for R-o-R), head variation (for
storage), maintenance requirement (e.g. silt).
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• 13. Components of Tariff. (1) The tariff for
supply of electricity from a thermal generating
station shall comprise two parts, namely,
capacity charge (for recovery of annual fixed
cost consisting of the components referred to in
regulation 14) and energy charge (for recovery
of primary fuel cost and limestone cost where
applicable).
• (2) The tariff for supply of electricity from a hydro
generating station shall comprise capacity
charge and energy charge to be derived in the
manner specified in regulation 22, for recovery
of annual fixed cost (consisting of the
components referred to in regulation 14) through
the two charges.
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Annual fixed cost (AFC) of a generating station
consists of the following components –
(a) Return on equity;
(b) Interest on loan capital;
(c) Depreciation;
(d) Interest on working capital;
(e) Operation and maintenance expenses;
(f) Cost of secondary fuel oil (for coal-based and
lignite fired generating stations only);
(g) Special allowance in lieu of R&M or separate
compensation allowance, wherever applicable.
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• RoE: at a rate to provide 15.5% (post-tax).
• Equity in excess of 30% of project cost treated
as loan.
• IoL: On average notionally outstanding loan for
the year @ weighted average rate of interest.
• Annual notional loan reduction = Depreciation
charged in tariff.
• Depreciation: @ 5.28% for 12 years, & balance
spread over the remaining life.
• O&M: @ Rs 18.2 / 13.0 lakh per MW for 210 /
500 MW thermal units in 2009-10, with 5.72%
escalation; 2% for new hydro.
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• IWC: Working capital comprises of
(i) coal stock for 1.5 / 2 months,
(ii) secondary oil for 2 months,
(iii) maintenance spares @ 20% of O&M,
(iv) O&M for 1 month,
(v) receivables for 2 months.
Interest rate = short-term PLR of SBI.
• Monthly billing, payable in 2 months; 2.0%
rebate for immediate payment through LC,
1.25% per month surcharge for delay.
• FERV or hedging cost is recoverable from
beneficiaries.
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Capacity charge (inclusive of incentive) payable to a
thermal generating station for a calendar month:
(a) Generating stations in commercial operation for
less than ten (10) years:
AFC x ( NDM / NDY ) x ( 0.5 + 0.5 x PAFM / NAPAF )
Provided that in case the plant availability factor
achieved during a financial year (PAFY) is less than
70%, the total capacity charge for the year shall be
restricted to
AFC x ( 0.5 + 35 / NAPAF ) x ( PAFY / 70 ).
(b) For generating stations in commercial operation for
ten (10) years or more:
AFC x ( NDM / NDY ) x ( PAFM / NAPAF ).
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PAFM or PAFY
= 10000 x Σ DCi / { N x IC x ( 100 - AUX ) } %
In case of fuel shortage, the generating company
may propose to deliver a higher MW during
peak-load hours by saving fuel during off-peak
hours. Then, DCi = the maximum peak-hour expower plant MW schedule specified by the
concerned Load Despatch Centre for that day.
ECR = { (GHR – SFC x CVSF) x LPPF / CVPF +
LC x LPL } x 100 / (100 – AUX).
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Application of ABT to Hydro plants
Hydro plants have no variable cost, and therefore
can not have an energy charge rate based on
variable cost.
Total annual fixed cost is notionally being divided
in two equal parts for recovery as capacity charge
and energy charge respectively.
This is done to attach values to peaking capability
and energy produced, both being equally
important.
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• Capacity charge payable for a calendar month
= AFC x 0.5 x ( NDM / NDY ) x ( PAFM / NAPAF ),
where, PAFM = 10000 x average DC / { IC x
( 100 – AUX ) } %
• Energy charge payable for a calendar month =
ECR x Scheduled energy x ( 100 – FEHS ) / 100,
where ECR = AFC x 0.5 x 10 / { DE x ( 100 – AUX )
x ( 100 – FEHS ) }
• Energy charge rate for energy in excess of DE
limited to 80 p/kWh (for checking windfall gain).
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Example:
IC = 400 MW, DE = 2000,000 MWh, AUX = 1%,
NAPAF = 85%, AFC = Rs 300 crore,
FEHS = 12%, NDM = 30, NDY = 365,
PAFM = 90%, Month’s load factor = 50%.
ECR = 3000,000,000 x 0.5 / ( 2000,000 x 0.99 x
0.88 ) = Rs 861 per MWh = 86.1 p/kWh.
Capacity charge for the month = 3000,000,000 x
0.5 x ( 30 / 365 ) x ( 90 / 85 ) = Rs 130,539,880.
Scheduled energy for the month = 128,304 MWh
Energy charge for the month = 861 x 128,304 x 88
/ 100 = Rs 97,213,371.
Total average rate = 115.6 + 86.1 = 201.7 p/kWh.
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Safe-guards against revenue loss due to
persisting lean inflow
• In first ten years: if A1 < DE, ECR for next year
shall be calculated assuming DE = A1, till
energy charge short fall has been made up.
Normal ECR thereafter.
• After 10 years, if A1 < DE, ECR for the third year
shall be calculated assuming DE = ( A1 + A2 –
DE ), subject to a minimum of A1 and maximum
of DE, on rolling basis.
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