This document proposes a new methodology for optimizing power plant operations to maximize revenue under India's availability-based tariff structure. It discusses how focusing only on maximizing positive unscheduled interchange (UI) charges can sometimes reduce profits, and proposes calculating the marginal gain or loss from deviations based on UI rates, power exchange prices, and fuel costs. A case study compares the profits and losses from over-injection versus under-injection in different time blocks. The goal is to incentivize optimal scheduling and control actions based on comprehensive financial impacts.

1. A new approach to Scheduling & Deviation (UI) Management
– Optimizing Operations for Maximum Gain
BK Sahoo*,RD Katre**,Ashish Bahety ***,Vishal laddha****
*EVP, **AVP, ****Manager, ****Dy. Manager
Jindal Power Limited, Tamnar.
ABSTRACT: Presently we have Availability Based Tariff (ABT) structure for the generating
stations regulated by CERC. The ABT is in vogue since 2001. The power plants have fixed and
variable costs. The fixed cost elements are interest on loan, return on equity, depreciation, O&M
expenses and interest on working capital. The variable cost comprises of the fuel cost, i.e., coal,
gas and oil in case of thermal plants. In the Availability Tariff mechanism, the fixed and variable
cost components are treated separately. The payment of fixed cost to the generating company is
linked to availability of the plant, that is, its capability to deliver MWs on a day-to-day basis. The
total amount payable to the generating company over a year towards the fixed cost depends on
the average availability (MW delivering capability) of the plant over the year. This is the first
component of Availability Tariff, and is termed ‘capacity charge’. The second component of
Availability Tariff is the ‘energy charge’, which comprises of the variable cost (i.e., fuel cost) of
the power plant for generating energy as per the given schedule for the day. The ABT provides
for payment of fixed costs linked to a normative availability of generating units which is under
control of the generating company. On the other hand, the energy charges are payable by the
beneficiaries of the station depending upon the level of the dispatch sought by them based on the
merit order of the generating stations. The third most important component is Unscheduled
Interchange charge, Presently, the “quantum of UI” in Rs during a 15-minute time block, and
cumulative values during a specified time period like a day, month, or year are being captured in
a stand-alone mode for MIS purpose and monitored. In case the UI value turns out to be +ve, this
is being perceived as good, while in case of –ve values, the same is considered as bad operations
resulting in loss of revenue. Accordingly, the efforts can many a times be concentrated towards
maximizing +ve UI and minimizing –ve UI at all times & at all cost, which may at times result in
reduction of net profit by possible reduction of revenue from scheduled generation and/or
inflating cost incurred for +ve UI generation, as illustrated below. It may also be noted that the
Regulatory intent (i.e., through changes in DSM/UI Regulations & Grid Code etc.) all through-
out has been to shift the volume transacted through UI to scheduled transactions & the trend for
past few years show a continuous reduction in UI as a % of short term power from 39% in 2009-
10 to 21% in 2013-14. Also, in our view a new Integrated Approach needs to be adopted for
looking at the UI Management along with Generation Scheduling in our daily operations, so that
revenues are really maximized while simultaneously complying with Regulatory requirement &
in line with prudent utility practice. This is with a view of optimizing operation to gain
maximum benefit
INDRODUCTION: India has a huge power shortage (unmet electricity demand), which is
retarding the nation’s progress. Hence, we need to work simultaneously on all fronts to
increase the availability of power and stabilization of grid. The mechanism of Unscheduled
Interchange (U.I.), if properly deployed, can help in bringing more power into the electricity grids

2. and stabilizing grid, enabling the utilities to meet additional consumer load, both short-term and
long-term, and significantly reduce the quantum of load-shedding.
UI has generally been known as the third component of the so-called Availability Based Tariff
(ABT), which was introduced in India at the regional level in 2002-03. Many have perceived UI
only as a disciplining mechanism, whereas it is actually a multi-purpose tool for tackling many of
the pressing problems of system operation. This paper seeks to describe the various possible
applications of UI on stand - alone basis, which can help enhance the availability of power
PEAK POWER: Most Indians are sweltering through power cuts for several hours a day. The
majority of power cuts are due to peak power shortages. Currently estimated at 10% on an all-
India basis, peak power shortages have become a constant feature of our power supply. The
average peak power shortage during the 11th Five-Year Plan (2007-2012) was 9%. With
increasing urbanization, peak deficits are expected to increase to 12-20% by 2017. Perhaps the
root cause is that India has focused almost exclusively on building base load power generation
capacity, primarily coal-fired or nuclear stations. These plants are designed to operate 24x7 for
maximum efficiency especially in a rapidly growing and urbanizing country like India.
Unfortunately, with the focus on base load, critical factors like power purchase norms for
discoms, metering and billing infrastructure, UI mechanism etc

3. NEW PARADIGM: Deregulated Electricity Supply Industry
A) Supply chain dissociated
B) Command and control regime has been replaced by contractual approach
C) Open Access in delivery network
D) Scheduled contracts settled at mutually agreed rates
E) Unscheduled interchanges settled at frequency dependent rates
EXISTING TARIFF POLICY
Availability Based Tariff consists of
A. Capacity (fixed) Charge
B. Energy (variable) Charge
C. Unscheduled Interchange (UI) Charge
1) Capacity fixed charge: Capacity Charge is a function of ex-bus MW Availability of
power for the day, declared before the day starts (for 96 time blocks)
Elements of fixed charges:
 O&M expenses
 Depreciation
 Interest on loan capital
 Interest on working capital
 Return on Equity
 Income tax recovery directly from users.

4. 2) Energy (variable) Charge - It comprises of the variable cost (i.e., fuel cost) of the power
plant for generating energy as per the given schedule for the day. It may specifically be
noted that energy charge (at the specifiedplant-specific rate) is not based on actual
generation and plant output, but on scheduled generation.
3) Unscheduled Interchange (UI) Charge- UI Charge is a function of average grid frequency in
15-minute time block and difference between actual and schedule
Total payment to generator = Capacity Charge + Energy Charge + UI Charge
UI MECHANISM:
1)UI mechanism is primarily a competitive real-time balancing mechanism
“Independent power plants can themselves monitor the frequency deviations and thus no real
time signal needs to be sent by the electric utility. This eliminates the problem of how utility
could compute and transmit the price faster than the time scale to be controlled”
Fred Schweppes & Arthur Berger –‘Real time pricing to assist in load frequency control’
A. UI rate is frequency actuated
B. Last mile connectivity to generators-Not required
2) UI mechanism is ‘self-healing’, ‘self-dealing’, ‘Zero sum game-
“A transparent, efficient spot market allows producers and consumers to deal directly
with each other with less need for middlemen and market makers, and helps new,
small, niche players compete effectively with established, large, diversified players”
Larry Ruff-‘Competition in Electricity Markets’
A. UI rate is transparent
B. Decreasing marginal return with every additional unit of deviation from schedule
acts as a counterweight
C. Settlement is weekly
3)UI mechanism tries to achieve efficiency & economy through merit-order operation
A) Sub-optimal scheduling due to forecasting errors & unit outages gets corrected in
real-time
B) Generators can conserve when UI rate is lower than their marginal cost
C) Every utility with some control over generation & load becomes a formidable player
in the UI market
TYPES OF TRANSACTIONS:
 Bilateral transactions:-A transaction for exchange of energy (MWh)between a specified
buyer and a specified seller ,directly or through a trading licensee or discovered at power
exchange through anonymous bidding ,from a specified point of injection to a specified
point of drawl for a fixed or a varying quantum of power(MW) for any time period
during a month

5.  Through IEX and PXIL:
Market Clearing Price in IEX:
In an hourly based spot market all bids and offers form one aggregate demand curve and
one aggregate supply curve for every hour. The point where the two curves intersect one
another is called Market Clearing Price. The Market Clearing Price is the clearing price
for cleared transactions in the whole market area as if no congestion at all.
UI CHARGES FOR DEVIATION: The charges for the Deviations for all the time-blocks shall
be payable for over drawl by the buyer and under-injection by the seller and receivable for
under-drawl by the buyer and over-injection by the seller and shall be worked out on the average
frequency of a time-block at the rates specified in the table below as per the methodology
0
200
400
600
800
1000
Charge for Deviations(paise/kWh
Charge for Deviations(paise/kWh

6. For the above purpose, the energy is metered in 15-minute time blocks, since frequency keeps
changing (and the UI rate with it). The metered energy is then compared with the scheduled
energy for that 15-minute time block, and the difference (+ or -) becomes the UI energy, as
illustrated in figure. The corresponding UI rate is determined by taking the average frequency for
the same 15-minute time block into account.
AN EFFORT TO BREAK THE MYTHS: All monitoring and consequent remedial control
actions should yield maximum benefits for the Company. Judging operating personnel for only
maximizing +ve UI may sometimes prompt them to slightly under-declare their available
capacity so that they may always be able to run the machine at higher real-time injection

7. compared to that scheduled thus earning continuous +ve UI. But this may not be the correct
thing to do for the following reasons:
1. Sometimes paying UI (i.e., incurring some –ve UI) through under-injection may also be
beneficial for the Company, as in the case when (say) frequency is 50.04 Hz with UI
value of Rs.0.36 per unit, while value of direct fuel cost saved by under-injection (i.e.,
not generating) may be around Rs.2.00 per unit. This is also likely to help grid frequency
management by curbing un-necessary injection during periods of high frequency, while
simultaneously saving money for the Company, although this financial benefit is not
being captured in the current way of UI monitoring alone, where any UI incurred is likely
to be viewed negatively without considering the simultaneous benefit accrued due to
saved fuel cost.
2. Further, operating persons are likely to declare a flat availability schedule, irrespective of
the variable price signal available in the Power Exchange Market during the various
periods of the day, peak vs. off-peak, day-time vs. night time etc., which may not be a
good commercial practice when a major portion of power (i.e., beyond the short-term &
long-term bilateral/PPA commitments) is sold through collective power exchange
transactions. Revenue can be maximized commensurate with a given fuel resource
constraint, by appropriate differential scheduling of generation availability based on a
reasonably forecasted power exchange price for the next day in day-ahead markets. This
will incentivize O&M to keep higher machine availability during peak hours, and even
failure to meet injection target during those hours despite best efforts may not be that
much harmful financially as the penalty (i.e., UI price) will depend on frequency at that
time, while we might have earned higher power exchange price for the energy scheduled
during those peak hours, in addition to the fuel saved for energy not generated.
3. Any conservative declaration of available generation capacity has possible likelihood of
reduced sales revenue from scheduled transactions, which may not get compensated
through unpredictable UI/DSM revenue through over-injection, thus potentially reducing
the chance of overall profit maximization for the Company through optimized operation
and simultaneously being not aligned with current regulatory norms.
4. Similarly, while any over-injection may result in +ve UI, the actual revenue gain is not
the same as the +ve UI alone, but will be moderated by the additional direct fuel cost
incurred to generate such energy.
Hence there appears to be a need for modifying our monitoring methods in order to give a fairer
picture of our operations & corresponding control action for addressing the deviations with
simultaneous correct optimization of our financial gains. These shall also be in line with Grid
Code compliance requirements relating to maintenance of frequency within tight range etc. Of
Course, the deviations at all times have to be attempted to be less than 12% of schedule or
150MW (especially for avoiding larger financial implications) with deviation signal changing at
least once in 12 continuous time blocks as specified under the Central Electricity Regulatory
Commission (CERC) DSM(UI) Regulations.
PROPOSED METHODOLOGY: In view of the above discussion, the calculation for marginal
gain or loss arising out of daily generation scheduling vis-à-vis actual generation in each 15-
minute time block is proposed to be represented in the following manner to reflect optimum
operating and/or scheduling performance to maximize revenue within available resources
without violating existing regulatory norms as specified in the CERC (Deviation Settlement

8. Mechanism and related matters) Regulations, 2014 and as calculated at Clauses 5.(1)…(iii) &
(iv), 5(2)(a), 5(2)(d), 7(1), 7(2), 7(3) & 7(4) from DSM
UI or DSM Rate = Net UI in Rs. (Including Additional Charges and/or Cap on Deviation
exceeding volume and/or frequency limits) Divided by Short/Surplus injection units
Each Time Block Marginal Gain or Loss of Revenue on the basis of Day Ahead Scheduling at
Power Exchange is equal to =>
1) If Actual Injection is more than Schedule (i.e., Surplus Injection & UI is positive (+)},
then Gain (or Loss) = Net UI Rate (Including Additional Charges and/or Cap on
Deviation) – Direct (Fuel?) Cost; or else
2) If Actual Injection is less than the Schedule (i.e., Short Injection & UI is negative (-),
then Gain (or Loss) = Power Exchange Area Price (at relevant IEX or PX) – Net UI Rate
+ Direct (Fuel?) Cost saved
The above principle is proposed to be adopted, since the sales revenue received (or receivable)
from the buyer (i.e., for bilateral or collective transaction) is based only on scheduled energy,
while actual deviations from the schedule are credited to (or paid from) the Regional Deviation
Pool Account Fund. Further, after accounting for all short-term & mid/long-term power sales
bilateral transactions, the balance residual units are scheduled/sold through power exchange
collective transactions, and these power exchange transactions are at the margins of scheduled
generation.
CASE STUDY: For One Hour (four Blocks) ,Suppose plant capacity is 600 MW, Schedule is
600MW, Variable (energy) cost-2Rs/kwh
Frequency=49.8, 50.0, 50.05Hz (Deviation Charges=variable), IEX price= 3 Rs/kwh
A) Over injection:
I II III
Over Injection
VARIABLE COST RS/MWH 2000 2000 2000
IEX/UNIT MWH 3000 3000 3000
SCHEDULE 600 600 600
FREQUENCY 50 49.8 50.05
Actual Generation 608 615 620
Deviation 8 15 20
DEVIATION CHARGES RS/MWH 1780 5948 0
UI GAIN 14240 89220 0
VARIABLE COST FOR OVER INJECTION 16000 30000 40000
TOTAL IEX COST 24000 45000 60000
Revenue Generated=(Exc. unit
Price*Gs+UI+(Cv*Dev)
22240 104220 20000
TOTAL PROFIT/LOSS FOR OVER INJECTION -1760 59220 -40000

9. Variable cost(Cv) i.e.fuel costwill be consideredas negative as fuel is consumed in generation
of extra power
B) Under injection:
VARIABLE COST RS/MWH 2000 2000 2000
IEX/UNIT MWH 3000 3000 3000
SCHEDULE 600 600 600
FREQUENCY 50 49.8 50.05
Actual Generation 592 585 580
Deviation -8 -15 -20
DEVIATION CHARGES RS/MWH 1780 5948 0
UI GAIN -14240 -89220 0
VARIABLE COST FOR OVER INJECTION 16000 30000 40000
TOTAL IEX COST 24000 30000 15000
Revenue Generated 25760 -29220 55000
Gain 1760 -59220 40000
Variable cost (Cv) i.e. fuel cost will be considered as positive as fuel is saved in generation of
extra power
Comparison Chart for profit and loss between over injection and under injection for same data
means-frequency, mw, IEX cost, variable cost
-40000
-30000
-20000
-10000
0
10000
20000
30000
40000
50000
60000
1 2 3
50 49.8 50.058 15 20
-1760
59220
-40000
FREQUENCY(HZ)
Deviation(Over
Injection)(MWH)
TOTAL PROFIT/LOSS FOR OVER
INJECTION(Rs)

10. Conclusion: There would be fallout of the above. Depending on its variable cost, each
generating unit would have a threshold frequency, i.e., the frequency at which the UI rate equals
the variable cost of the generating unit. The output of the generating unit should be maximized as
long as the grid frequency is below the threshold frequency, irrespective of the schedule given
out by the RLDC / SLDC for the unit. And the unit should be backed down when grid frequency
climbs up and exceeds the above threshold frequency, as shown in figure. For a pit-head
generating station having an ex - power plant variable cost of 90 paise/kWh, the threshold
frequency, with the present UI rate – frequency relationship, shall be 50.2 Hz. For a load-centre
thermal plant with a variable cost (ex - power plant) of 180 paise/kWh, the threshold frequency
would be 49.9 Hz, as illustrated, and so on.
This would lead to a frequency - based dispatch of generating stations (typically as shown in
figure ), which can be given out by the SLDCs as the dispatch guideline or instructions for their
generating stations. The underlying approach is that the frequency would be allowed to float, and
there would be no attempt to operate the grid at a frequency very close to 50.0 Hz. Also, while
the schedules would serve as the commercial datum, the entities would be free to deviate from
the schedules, to achieve real region - wide merit - order in generation, in an autonomous,
decentralized and very cost – effective manner
-60000
-50000
-40000
-30000
-20000
-10000
0
10000
20000
30000
40000
1 2 3 4
50 49.8 50.05
-8 -15 -20
1760
-59220
40000
FREQUENCY(HZ)
Deviation(Over Injection)(MWH)
TOTAL PROFIT/LOSS FOR UNDER
INJECTION(Rs)

11. By this way of presentation or case study, while the UI is positive (over injection) for one hour
but here marginal loss, and for UI negative (under injection) getting marginal gain, as
summarized in the above table. It may be pertinent to note that while UI is –ve for some
block/day, there have been actual gains to the Company, and vice-versa examples can also be
seen for many time blocks.
ANNEXURE:
1. Online DSM webpage:( In PDF format attached w ith sheet)
http://www.cercind.gov.in/2014/regulation/noti132.pdf
2. http://www.iexindia.com/
3) http://posoco.in/attachments/article/227/01UI_Charges_30.03.2009.pdf
REFERENCES:
1) How to maximize profit from sale of surplus power-IPPAI
2) CENTRAL ELECTRICITY REGULATORY COMMISSION- Coram : Dr. Pramod Deo,
Chairperson,Shri S.Jayaraman, Member,Shri V. S. Verma Member
Shri M. Deena Dayalan, Member
3) Electricity Tariff & Duty and Average Rates of Electricity Supply in India -
March'2014
4) Electricity Tariff and Duty and Average Rates of Electricity Supply in India -
March,2010
5) OVERCOMING POWER SHORTAGE THROUGH U.I.- Bhanu Bhushan