ABT a complete report and a case study

Availability Based
tariff
Presented By:
WASEEM HASHMAT
DY.SUPDT (CHP-O)

Outline of Presentation
• Old Tariff Methodology
• Chronological Sequence of Implementation of ABT
• CERC Tariff regulations
• Concept of ABT
• How the mechanism work with scheduling
• Components of Fixed cost
• Computation of Energy Charge -Thermal
• Advantage of ABT

OLD TARIFFOLD TARIFF
SINGLE PART TARIFF :
 A system of single-part tariff was in vogue in India for pricing of
thermal power prior to 1992.
 The single-part tariff for a station was calculated so as to cover
both the fixed cost as well as the variable (energy) cost at a certain
(normative) generation level.
 A sort of incentive and disincentive was inherent in the single-part
tariff.
 This had induced maximization of generation all the time (in peak
load as well as off-peak hours).
 Led to sharp difference between CGs & SEBs on who should back
down.

OLD TARIFFOLD TARIFF
TWO PART TARIFF :
It has two parts:
1. Fixed Charges
2. Variable charges
Fixed charges include
1. Return on equity
2. O&M charges
3. Interest on loans
4. Interest on working capital
5. Depreciation.
6. Taxes and Duties
Variable Charges i.e. cost of fuel, varies directly with level of generation, consists of
1. Primary fuel (Coal/Gas)
2. Secondary fuel - Oil

 K P Rao Tariff did not encourage grid discipline
 Low frequency during peak hours
 High frequency during off-peak hours
 Rapid changes in frequency and fluctuating voltages
 Reasons
 Conflicting commercial interest in the tariff structure-
SEBs/CGS
 Lack of generating capacity and transmission systems
Two Part Tariff ……..Two Part Tariff ……..DrawbacksDrawbacks

Chronological Sequence of Implementation of ABT
1990 : K. P. Rao Committee – Proposed Two – Part Tariff
structure consisting of Fixed and Variable charges
1993-94 : A structured study by M/s ECC, USA, funded by ADB,
sponsored by World Bank as a covenant of loans to POWERGRID
→ Availability Based Tariff (ABT)
1995-98 : NTF / RTFs, formed for ABT implementation.
NTF/RTF-National/Regional task force
1999 : Matter transferred to CERC : Hearings etc.
2000 : CERC Order, but stayed due to petitions
2001-02 : Problems of regional grid operation continued
: Many intractable commercial disputes also arose
2002-03 : ABT implemented successfully. ADB-Asian development bank

GEN. TARIFF DETERMINATION PROCERDUREGEN. TARIFF DETERMINATION PROCERDURE
Tariff Regulations issued by CERC
Petition to CERC prepared in line
with the Regulations
Financial Details Operational Details
Serve a Copy of application
on each beneficiary
SUBMIT THE APPLICATION TO CERC WITH
• Proof of Dispatch of Application to beneficiaries
• Address of Website hosting the Application
•Application fee draft
Post the application
on Website
Publish Notice in at least two daily newspaper, one in
English & other Vernacular Language within 7 days
Tariff Policy Issued by GOI taken as Guidelines by CERC

CERC Tariff Regulations
Terms and Conditions of Tariff
for three year period
Effective from
1.4.2001 to 31.3.2004.
CERC Notification
dated 26
March,2001,CERC
Regulation-2001.
CERC Notification
dated 21 September,
2001
(First Amendment).
CERC Notification
dated 08 July, 2002,
(First Amendment).
CERC Notification
dated 01 May, 2003
(First Amendment).
Several petitions filed by NTPC during the period 2001-2004Several petitions filed by NTPC during the period 2001-2004
E.g. Petition number-E.g. Petition number- R P 82/2001 in 2/99R P 82/2001 in 2/99
Petition for removing difficulties faced during ABT implementation .Petition for removing difficulties faced during ABT implementation .

CERC Tariff Regulations
CERC-(Terms & Conditions of Tariff)
FY 2004-09
On 26th
March 2004
Petition number-Petition number- I.A. No. 49/2008157/2004
Approval of tariff in respect of Singrauli Super Thermal Power Station (2000 MW) forApproval of tariff in respect of Singrauli Super Thermal Power Station (2000 MW) for
the period from 1.4.2004 to 31.3.2009.the period from 1.4.2004 to 31.3.2009.
CERC-(Terms & Conditions of Tariff)
FY 2009-14
On 19th
January 2009
Petition number-Petition number- Petition No. 225/2009
Approval of tariff in respect of Singrauli Super Thermal Power Station (2000 MW) forApproval of tariff in respect of Singrauli Super Thermal Power Station (2000 MW) for
the period from 1.4.2009 to 31.3.2014.the period from 1.4.2009 to 31.3.2014.

 It is a performance-based tariff for the supply of electricity by generators
owned and controlled by the central government.
 It is also a new system of scheduling and despatch, which requires both
generators and beneficiaries to commit to day-ahead schedules.
System of rewards and penalties to enforce day ahead pre-committed
schedules
(though variations are permitted if notified One and one half hours in advance).
It has three parts:
 Fixed charge (FC) payable every month by each beneficiary to the
generator for making capacity available for use. The FC is not the same for
each beneficiary.
It varies with the share of a beneficiary in a generators capacity. The FC,
payable by each beneficiary, will also vary with the level of availability
achieved by a generator.
Concept of ABT

 Energy charge (variable charge) (defined as per the prevailing
operational cost norms) per kwh of energy supplied as per a pre-
committed schedule of supply drawn upon a daily basis.
 Charge for Unscheduled Interchange (UI charge) for the supply
and consumption of energy in variation from the pre-committed daily
schedule.
This charge varies inversely with the system frequency prevailing at
the time of supply/consumption.
 Settlement period of 15 minutes.
 Applicability - Central Stations and drawal from the grid by
beneficiaries
Concept of ABT

How the mechanism work
*ISGS-Interstategeneratingstations*ISGS-Interstategeneratingstations

TIME TABLE FOR EXCHANGE OF INFORMATION
IN RESPECT OF SCHEDULING
By 10.00 hrs. ISGSs shall advise NRLDC the Station-wise MW and MWh
capabilities
By 1100 Hrs. NRLDC shall advise the States / Beneficiaries the Station wise
MW & MWh entitlements.
By 1500 hrs. SLDCs/ Beneficiaries shall communicate the Station-wise
requisitions and details of bilateral exchanges to NRLDC.
By 1700 hrs. NRLDC shall convey the ex-power plant despatch schedule to
each ISGS and net drawal schedule to each State /
Beneficiary. The details of unrequisitioned surpluses shall
also be intimated.
By 2200 hrs.* ISGSs / States / Beneficiaries shall inform the modifications,
if any, for incorporating in the final schedule
By 2300 hrs. NRLDC shall issue the final despatch and drawal schedule for
the next day.
* Since issuing the final despatch and drawal schedule is a critical activity
and considerable time is involved in its preparation and carrying out requisite
moderation, if any, it has been agreed to complete this activity by 2100 hrs.

 The CGs/ISGS declare their expected output capacity for the next day
to RLDC by 9 am referred as DC in MWs
 RLDC break-up the DC as per beneficiaries plant-wise share and
convey their entitlement to their SLDCs by 10 am.
 SLDCs sent back their requisition and drawal schedule by 3 pm.
 RLDC aggregates these requisitions and determines dispatch schedule
(Schedule generation) for CGs and drawal schedule for beneficiaries.
duly incorporating any bilateral agreement and adjusting for transmission losses.
 Schedule are then issued by RLDC to all concerned and become
operational datum by 5 pm

 During contingencies, the CGs can revise their DC and beneficiaries can
prospectively revise requisition and schedule will be revised by RLDC.
 The schedules are also used for determination of the amounts payable as
energy charges.
 Each day starting from 00.00 Hrs will be divided into 96 time blocks of
15 minutes intervals.
 Deviations from schedules are determined in 15-minute time blocks
through special metering.
These deviations are priced depending on frequency.
 As frequency, AG and SG can vary ,so average of these for 15 minutes
with be final figure for calculation.

Generating StationGenerating Station
1000 MW1000 MW
Coal fired
Three beneficiaries A,B & C
RLDC
DC-900 MW (ex-bus) for next day
State-
A
(30%)
270 MW
SLDC-A
10 am
State-
B
(30%)
270 MW
State-
C
(40%)
360 MW
10 am
10 am
9 am
3 pm 3 pm
3 pm
The Daily Scheduling process
SLDC-
B
SLDC-
C

Suppose requisition received from SLDC to RLDC ( by 3 pm)
A- Fully requisition of their share -270 MW (24 hrs)
B- Fully requisition of their share -270 MW (24 hrs)
C- Requisition 360 MW during day but 200 MW during night
 Now RLDC issue dispatch schedule to both generating stations as
well as beneficiaries by 5 pm.
and would be effective from following midnight (unless modified in the
intervening hours) and will be called Scheduled generation.
 A, B and C shall pay capacity (Fixed) charge for whole day
corresponding to plant availability of 900 MW.
(generating station will get fixed cost corresponds to 900MW)
 Energy charge payment by three states corresponds to:
[270x24MWh ,270x 24 MWh and (360x16 + 200x8) MWh]
Hence, energy charge payment will be made for scheduled generation.

The Daily Scheduling process
Forced Outage:
RLDC To Revise The Schedules Based On Revised Declared
Capability As Advised By The Generator.
The revised schedules to become effective from the 4th time- block
Planned Outage Or Asked By Beneficiaries:
The Revised Schedules / Declared Capability To Become Effective
From The 6th Time-block.
RLDC, on its own, can revise the schedules in the interest of better
system operation.

Merit Order Scheduling
 Beneficiaries to pay the capacity charges as per entitlement.
 Energy charges on schedule generation and not on actual generation.
 Comparison of own generation with UI rate based on variable charge.
 Low UI At High Frequencies Encourage Backing down By Costly
Units And Over Drawl By Beneficiaries.
 High UI Rate At Low Frequencies Encourage Maximum Generation
By All And Curtailment Of Over Drawl.

How the beneficiaries share the payment
 Beneficiaries pay the fixed cost in proportion to their share in
respective plant.
 Payment of fixed cost dependent on Declared capacity (DC) of the
plant for the day.
 Variable cost paid by beneficiaries would be the fuel cost for energy
scheduled to be supplied to them.( Schedule of generation as sent by
RLDC).
 If beneficiaries draw more power than scheduled to be supplied, he
has to pay excess drawal at the rate dependent on system condition.
 If beneficiaries draw less power he gets paid back for energy not
drawn dependent on system condition.

 The actual energy supplied by generating station may differ from
what was scheduled.
 This deviation from the schedule technically termed as Unscheduled
Interchange (UI).
 The generating station receive or pay back for excess or shortfall of
the scheduled generation, supplied at a rate dependent on frequency
at that time.
 The relationship between UI rate and grid frequency, for the
interconnected system is specified by CERC.
 Latest UI regulation by CERC is effective from 03/05/2010.
(First amendment of principal UI regulation-2009)
Deviation from schedule

Deviation from schedule
 Most recent UI regulation which was supposed to be effective
from 2nd
April 2012 is on hold due to petition.
(Second amendment of principal UI regulation)
 Below 50.2 Hz and upto 49.7 Hz, linear in 0.02 Hz step,
at the rate 15.5 paise / kWh.
 Below 49.7 Hz and upto 49.5 Hz, linear in 0.02 Hz step,
at the rate 47.0 paise /kWh.
 Below 49.50 Hz at the rate 873.00 paise /kWh.
 UI rate is zero above frequency 50.2 Hz and the break even
frequency was considered 50.06 Hz

Additional UI for over drawal:
 Below 49.5 Hz to 49.2 Hz@40% of the UI Charges at
49.5 Hz of Rs. 8.73/kWh.
 Below 49.2 Hz @100% of the UI Charges at 49.5 Hz of
Rs. 8.73/kWh
Additional UI for Under Injection:
Below 49.5 Hz & up to 49.2 Hz, Additional UI is 20% of the
Unscheduled Interchange Charge of 873.0 Paise/kWh
(corresponding to the grid frequency of below 49.5 Hz)
Below 49.2 Hz, Additional UI is 40 % of Unscheduled Interchange
Charge of 873.0 Paise/kWh
Additional UI

UI Price Vector
08/06/13 28CERC

New UI Regulation
UI charge when Actual Generation is in
excess of 105 % of Declared Capacity in
a Time Block or in excess of 101 % of
average Declared Capacity over a day
corresponding to grid frequency interval
of below 49.70 Hz and not below 49.68
Hz i.e. 403 paisa/kWh.
Earlier it was zero.

New UI Regulation
Under injection of electricity by a
generating station during a time block shall
not exceed 12% of scheduled injection
when frequency is below 49.7 Hz and 3%
on daily aggregate basis for all time blocks
when frequency is below 49.7 Hz.

CAPACITY
CHARGES
ENERGY
CHARGES
UI
MECHANISM
FIXED
CHARGES
+ +
VARIABLE
CHARGES BALANCE
Based on Declared
Capacity
Target avl-85%
Based on Schedule
Generation
Components of ABT
for recovery
of Annual
Fixed Costs)
for recovery of
Primary Fuel
Costs
for deviation
from the
schedule
As per frequency
linked rate

Fixed cost – These costs are permanent in nature independent
of level of production/generation.
Components of Fixed costComponents of Fixed cost ::
1. Return on Equity1. Return on Equity
2. Interest on Loan Capital2. Interest on Loan Capital
3. Depreciation3. Depreciation
4.4. Interest on Working CapitalInterest on Working Capital
5.5. Operation and Maintenance ExpensesOperation and Maintenance Expenses
New addition to AFC –New addition to AFC – Applicable for Coal Stations onlyApplicable for Coal Stations only
6.6. Cost of Secondary Fuel OilCost of Secondary Fuel Oil **
7.7. Either Compensatory Allowance for coal based stations uptoEither Compensatory Allowance for coal based stations upto
25 years of life or Special Allowance in lieu of R&M beyond25 years of life or Special Allowance in lieu of R&M beyond
25 years.25 years.**
** Included in CERC tariff regulation 2009-14Included in CERC tariff regulation 2009-14
Annual Fixed Charges

Definition of 'Return On Equity – ROEDefinition of 'Return On Equity – ROE’(RONW)’(RONW)**
The amount of net income returned as a percentage of shareholdersThe amount of net income returned as a percentage of shareholders
equity. Return on equity measures a corporation’s profitability by revealingequity. Return on equity measures a corporation’s profitability by revealing
how much profit a company generates with the money shareholders havehow much profit a company generates with the money shareholders have
invested.invested.
ROE is expressed as a percentage and calculated as:ROE is expressed as a percentage and calculated as:
Return on Equity = Net Income (PBTReturn on Equity = Net Income (PBT****)/Shareholder's Equity (Rs))/Shareholder's Equity (Rs)
Indirect method of taking profit through fixed cost.
Every generating station has certain percentage of debt (loan) and equity
i.e., 70:30 for new plant and 50:50 for existing plants, existing before
1/4/2009.(As per CERC tariff regulation 2009-14).
Certain percentage of that equity (money by shareholders) will be taken as
fixed cost (percentage will be decided by CERC).
1. Return on equity

 ROE will be used for capacity addition or giving dividend
to share holders or can be kept as reserve and surplus.
 If equity employed is less than 30%, the actual equity and
loan shall be considered for determination of return on
equity.
 Pre Tax Return to incentivise investment in sector.
 Rate of Return will be 15.5% for existing stations (CERC
Regulation 2009-14)
 Reason for increase in ROE is the Prime Lending Rate
(PLR) of the public sector banks have increased during
this period. (March 2004 10.25% -January 2009 14.00%)
Return on equity
Actual equity in excess of 30% will be treated as loanActual equity in excess of 30% will be treated as loan

 ROE will be 23.481% for the companies paying normal
tax.
This is given by formula:
Rate of pre-tax return on equity = Base rate / (1-t)
Where t is the applicable tax rate
Base rate is 15.5 %.
t = 33.99 % for company paying normal tax.
Objective
To provide fair return on the investment by
the investor and for generation of internal
resources for capacity additions.
Return on equity

Return on equity
(CoG)(CoG)
 Approval for return on equity for SSTPS for the period
2009-14 given by hearing on petition no- 225/2009
CERCtariffregulation2009-14

 Products / services which are basic need of society, used by
all sections of society irrespective of their status , infrastructure
/ basic amenities normally falls in this category . Prices/
tariffs are determined by the Govt. body / independent
regulator . During the price determination , all the costs
required to produce the product / services along with
reasonable profit ( return on capital/equity ) are considered.
Cost plus method is employed to avoid stranded cost of
redundant assets , to insulate the consumers from vide
market fluctuations, market abuse by dominant players .
Examples – Electricity, Petroleum, Fertilizer, Railways etc.
Price = Cost+ Profit
Cost Plus Price Mechanism

 Interest on loan is calculated based on the weighted
average rate of interest and applied to the outstanding
loans.
 Loans are reduced to the extent of repayment each year
during the tariff period.
 No interest element is included in tariff after repayment of
the entire loan.
 To be charged from 1st year of CoD irrespective of
moratorium.
2. Interest on Loan CapitalInterest on Loan Capital
CERC tariff regulation 2009-14

Depreciation is an important element of cost and forms a part of the
fixed cost recovery. The objective is that the recoveries through
depreciation should be adequate to provide resources to the
investor to replace the assets after their useful life.
Depreciable value 90% (except land).
Depreciable life:
Thermal - 25 years for both coal and gas station
Hydro - 35 years
Rates as per latest CERC notification for coal based stations
3.6% of capital cost.
AAD (Advance against depreciation) is removed from CERC
Regulation 2009-14,hence rate of depreciation in increasing.
3. DepreciationDepreciation

 Coal Based StationsCoal Based Stations
 1.5 months fuel expenses for pit head and 2 months for1.5 months fuel expenses for pit head and 2 months for
non pit head.non pit head.
 Secondary fuel oil for 2 monthsSecondary fuel oil for 2 months
 Maintenance spares @ 20% of O&MMaintenance spares @ 20% of O&M
 Receivables for 2 monthsReceivables for 2 months
 O&M expenses for 1 monthO&M expenses for 1 month
 Cost of fuel wrt Price & GCV of preceding 3 months.Cost of fuel wrt Price & GCV of preceding 3 months.
 Rate of interest will be SBI PLR as on 1.4.2009 andRate of interest will be SBI PLR as on 1.4.2009 and
no fuel escalation will be permitted in workingno fuel escalation will be permitted in working
capital whereas rebate will be payable at currentcapital whereas rebate will be payable at current
priceprice
4. Interest on Working CapitalInterest on Working Capital

For SSTPSFor SSTPS
4. Interest on Working CapitalInterest on Working Capital
Petition No. 225/2009

5. Operation and Maintenance ExpensesOperation and Maintenance Expenses
COMPONENTS OF O&M EXPENSES
The Operation & Maintenance cost :
Expenditure incurred on the employees including gratuity, CPF, medical,
education allowances etc
+
Repair and maintenance expenses including stores and consumables,
+
Consumption of capital spares which are not a part of capital cost
+
Security expenses,
+
Administrative expenses etc. of the generating stations
+
Corporate expenses apportioned to each generating stations
+
Others (water Charge+ insurance etc)

Methodology adopted by CERC while fixing O&M Norms
 The actual O&M expenses of Central utilities for the years
2003-04 to 2007-08 are taken and then averaged.
 Then incentive & ex-gratia paid to its employees, donations,
loss in stock, prior period adjustments, claims and advances
are written off.
 Based on escalation rates for the year 2003-4 to 2007-08, the
annual escalation rate worked out as 5.72%.
 The average normalized operation and maintenance expenses
at 2007-08 price level shall be escalated at the rate of 5.72% to
arrive at the operation and maintenance expenses for year
2009-10

 Provided that operation and maintenance expenses for the year
2009-10 shall be further rationalized considering 50% increase
in employee cost on account of pay revision.
As per CERC regulation 2009-14 the O&M will be:
CERCtariffregulation2009-
14

 In addition to the normative O&M cost the regulator has also
allowed a separate compensation allowance for meeting the
expenses on new capital assets, which will be based on year of
completion of the project.

Reasons for shifting secondary oil cost to Capacity charge
 Secondary oil is required occasionally,and at a load
above about 70% it is normally not required to be fired.
Therefore, energy charge consisting of Coal as well as
oil charges does not give real situation on merit order.
 Generators are scheduled to generate as per "merit-
order.
6. Cost of Secondary Fuel OilCost of Secondary Fuel Oil

 Expenses on secondary fuel oil in Rupees shall be computed
corresponding to normative secondary fuel oil consumption
= SFC x LPSFi x NAPAF x 24 x NDY x IC x 10
Where,
SFC – Normative Specific Fuel Oil consumption in ml/kWh
LPSFi – Weighted Average Landed Price of Secondary Fuel in
Rs./ml considered initially
NAPAF – Normative Annual Plant Availability Factor in
percentage
NDY – Number of days in a year
IC - Installed Capacity in MW.
6. Cost of Secondary Fuel OilCost of Secondary Fuel Oil

 Alternatively, we may avail a ‘special allowance’ for coal based station @
Rs. 5 lakh / MW / year with annual escalation of 5.72% during 2009-14 as
compensation for meeting the R&M expenses beyond the useful life.
Compensatory Allowance for SSTPS
7. Special Allowance in lieu of R&M orSpecial Allowance in lieu of R&M or
Compensatory AllowanceCompensatory Allowance
Station for 08-09 for 09-10
Singrauli Nil 9.2
Rihand-I Nil 3.5
Rihand-II Nil 0
Unchahar-I Nil 1.5
Unchahar-II Nil 0
Unchahar-III Nil 0
Tanda Nil 1.5

Annual fixed cost of claimed by the petitioner (SSTPS) for
2009-14
Petition No.189/2009

Annual fixed cost Approved by CERC for SSTPS:
Petition No. 225/2009 Date of Order-7/8/2012
44 paisa100 % Fixed cost at 85 %
Availability

Comparison of fixed cost from 2009-12 with 2004-09
www.icra.in

Incentive:
 Incentive will be in the form of increased AFC with respect to
Availability.
 Again, this incentive will be double for Old stations w.r.t. new
stations.
– For stations > 10 years
= (AFC x NDM / NDY) x (PAFM / NAPAF)
– For stations <= 10 years
= (AFC x NDM / NDY) x 0.5 (1.0 + PAFM / NAPAF)
Case : Singrauli
 If availability is increased by 1%,then station will get extra 6.62
Cr/Yr (base is 85 %)
 Or station will get extra 37.77 paisa/Unit above 85% of
availability.

Normative Annual Plant Availability Factor (NAPAF)
 normative annual plant availability factor’ or ‘NAPAF’ in
relation to a generating station means the availability factor.
 At 85% of availability, full Fixed Charge will be recovered. If
this availability increases above 85%, then Fixed charge will
also increase.

Computation of Energy Charge -Thermal
The energy charge shall cover the primary fuel cost
(Energy charge rate in Rs./kWh) x {Scheduled energy (ex-bus) for the
month in kWh.}
Computation of Energy charges (EC)Computation of Energy charges (EC)
Energy Charge covering primary fuel cost shall be payable for totalEnergy Charge covering primary fuel cost shall be payable for total
ex-bus energy scheduled to be supplied to the beneficiary duringex-bus energy scheduled to be supplied to the beneficiary during
the calendar month, at the specified energy charge rate.the calendar month, at the specified energy charge rate.
Energy charge rate (Energy charge rate (ECECRR) in Rs. per kWh on ex-power plant basis:) in Rs. per kWh on ex-power plant basis:
For coal or lignite fired based stationsFor coal or lignite fired based stations
ECR = (GHR – SFC x CVSF) x LPPF / CVPF x 100 / (100 – AUX)}ECR = (GHR – SFC x CVSF) x LPPF / CVPF x 100 / (100 – AUX)}

Landed Cost of CoalLanded Cost of Coal
Price of coal corresponding to the grade and quality inclusivePrice of coal corresponding to the grade and quality inclusive
of royalty, taxes and duties applicable & transportation cost.of royalty, taxes and duties applicable & transportation cost.
Considering normative transit and handling losses :Considering normative transit and handling losses :
Pit head stations : 0.2% ; Non-Pit head stations : 0.8%Pit head stations : 0.2% ; Non-Pit head stations : 0.8%

www.icra.in
Energy charges for thermal power stations are linked to the normative operational
parameters as specified by the regulator
Heat rate comparison of 2004-9 and 2009-14Heat rate comparison of 2004-9 and 2009-14

The Energy Charge Rate claimed by the SSTPS and approved.
However, energy charge on month to month basis will be billed by
the petitioner as per the 2009 Tariff Regulations.
PetitionNo.225/2009

Advantages of ABT
GRID DISCIPLINE
 Adherence to the schedule
 Commercial incentives for operational discipline leads to
better load management. Backing down under high
frequency is encouraged.
FACILITATES TRADING IN CAPACITY AND ENERGY
MERIT ORDER OPERATION
ECONOMIC GENERATION
Capacity Charge and Energy Charge do not depend on actual
plant generation / drawal. No metering required for this as they
are based on off-line figures. All deviations taken care of by UI

ABT a complete report and a case study

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