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TRANSMISSION LOADING
RELIEF IN DEREGULATED
POWER SYSTEMS
Dr. P.S.SUBRAMANYAM
PROFESSOR, DEPT. OF E.E.E.
VIGNANA BHARATHI INSTITUTE
OF TECHNOLOGY
HYDERABAD-501301, INDIA
&
Dr. Chava Sunil Kumar
REFERENCES:
EXCERTS FROM
1. TRANSMISSION LOADING RELIEF
IN DEREGULATED POWER SYSTEMS
Ph.D. Thesis of
Dr. Chava Sunil Kumar
Electrical & Electronics Engineering
Under the Guidance of
Supervisor
Dr. P S Subramanyam
Professor, EEE Department
VBIT, Ghatkesar, R.R Dist.
Co- Supervisor
Dr. J. Amarnath
Professor, EEE Department
JNTUH, Kukatpally
2. Market Power Evaluation in Power
Systems with Congestion
Tom Overbye, George Gross, Peter Sauer
Department of Electrical and Computer Engineering
University of Illinois at Urbana-Champaign
Urbana, IL
Mark Laufenberg, Jamie Weber
PowerWorld Corporation
Urbana, IL

AIMS AND OBJECTIVES OF TLR IN DPS
To calculate the spot price, and carryout profit analysis of the
power system under deregulated environment making use of the
existing LP method of OPF at different loads.
To find contingency ranking based on MVA loading of the
transmission lines and to find ATC with contingencies.
To define a secured transactional space, to perform the
transactions between seller and buyer by use of updating ATC
instead of off-line ATC.
WHAT IS REGULATION?
Regulation means government has set down
laws and rules that puts limits on
and
define how a particular industry or company
should operate.
WHAT IS DEREGULATION?
Deregulation is re-structuring of the rules
and economic incentives that government
setup to control and drive the electric
supply industry.
DEREGULATED POWER MARKET
Electric deregulation is the process of changing rules and
regulations that control the electric industry to provide
customers the choice of electricity suppliers who are either
retailers or traders by allowing competition.
Market power is antithesis of competition
ability of a particular group of sellers to maintain prices
above competitive levels
Market power can sometimes lead to decreased prices in the
long run
Accompanying higher prices can result in a quickening of
the entry of new players and technological innovation
WHY DEREGULATION?
ENCOURAGE PRIVATIZATION
INCREASE COMPETITION
INCREASE EFFICIENT POWER GENERATION
INCREASE EFFICIENT TRANSMISSION
INCREASE EFFICIENT DISTRIBUTION
RESTRUCTURE INDIAN POWER NETWORK
PUBLIC AND PRIVATE SECTOR COORDINATION
REDUCE POWER COST

DEREGULATED SET UP

DISTRIBUTION
COMPANY-1
GENERATION
COMPANY-1
GOVT.
GENERATION
COMPANY-2
OWNED
TRANSMISSION
DISTRIBUTION
COMPANY-2
COMPANY
GENERATION
COMPANY-3
DISTRIBUTION
COMPANY-3
INDEPENDENT POWER
REGULATOR 8051.in
SYMPTOMS OF MARKET POWER
Economic theory tells us that in a market with
perfect competition, prices should be equal to the
marginal cost to supply the product

Therefore prices above marginal cost can
indicate market power

MARKET POWER ANALYSIS

identify relevant product/services

identify relevant geographic market
 evaluate market concentration
MARKET POWER WITH TRANSMISSION
CONSTRAINTS
Market size can be limited by physical ability to delivery
electricity
Whenever physical or operational constraints become active,
system is said to be in state of congestion
 Congestion arises through number of mechanisms
 transmission line/transformer thermal limits
 bus voltage limits voltage, transient or
oscillatory stability

CHALLENGES AND IMPLEMENTATION ISSUES POST
ELECTRICITY ACT 2003 :
REGULATORY, POLICY & TECHNICAL SOLUTIONS
Deregulation is a re-structuring of the rules and
economic incentives that government setup to control
and drive the electric supply industry.
It is known in different names
 Re-regulated market
 Open Power Market
 Competitive power market
 Vertically unbundled power system
 Open access
 Power system restructuring( Privatization and
Reforms)
FORCES BEHIND DEREGULATION
High tariffs and over staffing
 Global economic crisis
 Regulatory failure
 Political and ideological changes
 Managerial inefficiency
 Lack of public resources for the future development
 Technological advancement
 Rise of environmentalism
 Pressure of Financial institutions
 Rise in public awareness

C om p etin g G en erators
A n cilla ry S erv ices
B id
NGC
D isp a tch
P ow er E xch an ge (P X )
S y stem O p erator
(S O )
S ell
M o n ito r
D istrib u tors
F o reca st
C o n tro l
T ran sm ission F acilities
EFFECT OF HAVING D.P.S.M.
Regulated Power System ~Deregulated Power System Market
 Vertically integrated => vertically unbundled
 Regulated cost-based ==> Unregulated price-based
 Monopoly ==> Competition
 Service
==> Commodity
 Consumer ==> Customer
 Privilege
==> Choice
 Engineers
==> Engineer +
Lawyer/Manager +
Finance Consultant
HORIZONTAL MARKET POWER
Market power can sometimes lead to decreased prices in
the long run
 Accompanying higher prices can result in a quickening
of the entry of new players and technological innovation
 Some market power abuses are actually self-inflicted by
consumers by their reluctance to respond to favorable prices
offered by new vendors in deregulated markets

SYMPTOMS OF MARKET POWER
Economic theory tells us that in a market
with perfect competition, prices should be
equal to the marginal cost to supply the
product
 Therefore prices above marginal cost
can indicate market power

MARKET POWER ANALYSIS
Market power analysis requires 3 steps

identify relevant product/services

identify relevant geographic market

evaluate market concentration
RELEVANT PRODUCT
FERC (Federal Regulatory Commission)defines at least
three distinct products

non-firm energy
short-term capacity (firm energy)
long-term capacity
Emphasis is shifting to short-term energy markets
 Presentation considers short-term
 Challenge in electricity markets is “Demand varies
over time”

RELEVANT GEOGRAPHIC MARKET
Most difficult step in electricity market due to impact
of transmission system


Size of market is dependent on
 Competitive prices of generators
 Impacts of charges from transporting energy in
transmission network

Physical/operational characteristics of
transmission network
STRATEGIC MARKET POWER
Characteristic that congestion can limit market size allows
possibility that generator portfolio owner may unilaterally
dispatch generator to deliberately induce congestion
this results in market power
allows charging of higher prices
Ability to induce congestion depends on generator portfolio
and transmission system loading
PORTFOLIO FLOW CONTROL
A portfolio of N generators may be redespatched to
unilaterally control the flow on a particular line, i, by an
amount
N
 Pi  max
s
k 1
N
ik
 Pgk
such that
 P
gk
 0
k 1
where Sik is sensitivity of line i MW flow to change in
generation at bus k
PORTFOLIO FLOW CONTROL-CONTD.
Once a line is congested, any generators with a
Power Transfer Distribution Factor(PTDF) to a
particular load pocket that would increase loading
on the congested line are prevented from selling to
that market and termed Blocked Generators.

Likewise affected loads are prevented from
buying from the “blocked” generators.

MARKET RULES

NGC works as ISO+PX
(National Grid Company= Independent System Operator +
Power exchange)
48 half-hourly market.
 NGC uses GOAL (generation ordering and loading)
program to determine the merit order of dispatching
generation and reserve capacity.
 Generators must submit the bids by 10.00 AM one day
ahead of operation.
 The “System Marginal Price” (SMP) is the price quoted by
the most expensive generator which is accepted for dispatch
during each half-hourly time slot when transmission constraints
are ignored – simple unconstrained dispatch.

LOSS OF LOAD PROBABILITY

LOLP is calculated by a program based on
Forecasted demand (& its variance)
 Disappearance ratio (probability that a genset
was available at some point in 8-days become
unavailable by the 9th day)
 Genset capacity available for last 8 days,

LOLP is extremely sensitive to the level of capacity
relative to demand.
 Capacity payments have been heavily criticized.
 VOLL (value of lost load) was set by Govt.
( 2/kWh in 1990 rose to 16.50).

Pool purchase price
VALUE OF LOST LOAD
This additional expense is passed on to consumers.
On the other hand, some uneconomic generators who
are not selected in the day-ahead market but are
called upon to generate due to transmission constraints
or other reasons, are paid their 'bid' price, which is
higher than the prevailing PPP. This is, effectively, a
payment for out of merit generator operation.
 Constrained-off costs, out of merit payments and
several additional expenses such as transmission fixed
charges, transmission losses, start up costs, and
ancillary services charges are passed on to consumers
in the uplift

POOL SELLING PRICE
The customer side of the market is simpler: all energy is
purchased at the pool selling price (PSP). All of the extra costs
of energy above the PPP are simply lumped together in “uplift”
and spread over all kWh taken by customers through the
calculation of a single half-hourly consumer price, the PSP.
Pool Selling Price(PSP) =Pool Purchase Price(PPP)+uplift
Problems
Pool rules
Market power
Metering
Customer choice
Price volatility

CAPACITY PAYMENTS
If marginal stations cannot cover their costs, then they will
tend to shutdown, thus reducing the margin of capacity.
 Every MW of capacity which is declared available in a
half-hour receives a capacity payment for that 1/2 hour,
whether or not it is scheduled to generate.
 The probability that demand will exceed capacity (“Loss of
Load probability”, or LOLP) is calculated by comparing
expected demand with the capacity expected to be available.

PPP = SMP+CC (= LOLP*(VOLL-SMP))
CC = LOLP*(VOLL-bid) if not generating
NETWORK CONGESTION
When producer and consumer of electric
energy desires to produce and consume
energy in the amount that would cause
transmission system to operate beyond its
transfer limit , the system is said to be
congested.
CONGESTION IN NETWORKS-CONTD.
Need to introduce several definitions
concerning network power transfers
source: set of buses increasing their injection
of power into network
sink: set of buses decreasing their injection
of power into network
direction: source/sink pair
Power transfer is then associated with a
particular direction
CONGESTION IN NETWORKS-CONTD.
To understand impact of congestion in networks,
need to consider two interrelated issues
 power transfer in a particular direction may
impact line flows in large portion of system
• this impact is commonly defined as the
power transfer distribution factor (PTDF)
 once a line is congested, any new power
transfers with a PTDF on the congested line
above 5% can not take place
Nine Bus, Nine Area Example
400.0
MW
400.0
A
MW
300.0
B
250.0
Pie charts
show
percentage
loading
on lines
MW
D
MW
C
F
G
250.0
MW
250.0
150.0
MW
MW
39%
I
H
200.0
MW
50.0
MW
Each area contains one bus/one 500 MVA generator.
Each line has 200 MVA limits. HHI = 1089
E
Figure
shows
base case
flows
Nine bus example - Area I buying










Table : Line G to F PTDF Values
Seller to Buyer
A to I
B to I
29%
C to I
D to I
E to I
-1%
F to I
-20%
G to I
H to I
PTDF for Line G to F
35%
400.0 MW
A
400.0 MW
B
D
250.0 MW
11%
5%
C
F
G
250.0 MW
41%
21%
300.0 MW
H
200.0 MW
250.0 MW
150.0 MW
39%
I
50.0 MW
E
Nine Bus Example
400.0
MW
400.0
A
MW
300.0
B
250.0
If the line from G to
F were congested,
then area I could only buy
from areas E, F or I.
MW
D
MW
C
F
G
250.0
MW
250.0
150.0
MW
MW
E
39%
I
H
200.0
MW
50.0
MW
When congestion is present, area I load only has possibility of
buying from three suppliers. If we assume each supplier has 1/3
of the potential market, resultant HHI is 3333.
PTDF IMPLICATIONS ON MARKET POWER
 Once congestion is present on line, any
power transfer with Power Transfer Distribution
Factor(PTDF) above 5% on congested line, in
direction such that line loading would be
increased, is not allowed
Congestion on a single line can constrain
many different directions
THREE METHODS TO TACKLE
TRANSMISSION CONGESTION
Price Area congestion management employed in Nordic
pool (Norway, Sweden, Denmark and Finland).

Available Transfer capability (ATC) based congestion
management system employed in US.

Optimal Power Flow (OPF) based congestion
management system employed in UK.

COST TO THE CONGESTORS
 Such a strategy of deliberate
congestion could certainly involve
additional costs to congesters (since they
presumably would have to move away
from an economic dispatch)
 Congesters need to balance costs
versus benefits from higher prices
Nine Bus, Nine Area Example
400.0
MW
400.0
A
MW
300.0
B
250.0
Pie charts
show
percentage
loading
on lines
MW
D
MW
C
F
G
250.0
MW
250.0
150.0
MW
MW
39%
I
H
200.0
MW
50.0
MW
Each area contains one bus/one 500 MVA generator.
Each line has 200 MVA limits. HHI = 1089
E
Figure
shows
base case
flows
PTDF Values for A to I Direction
A
44%
D
B
10%
30%
C
56%
13%
10%
20%
G
35%
F
2%
E
34%
34%
32%
H
34%
Pie charts now show the percentage PTDF
value; arrows show the direction.
PTDF show
the incremental
impact on
line flows, in
this case for
a transfer from
area A to area
I.
PTDF Values for G to F Direction
A
6%
D
B
6%
18%
C
6%
12%
6%
12%
G
61%
F
19%
E
21%
H
20%
21%
Example: For 200 MW transfer from G to F, line
H to I MW flow will increase by 200*21%=42MW
Note that
for both the
A to I and
the G to F
directions
almost all
PTDFs are
above 5%
Merged Areas F and G Blocking Line
400.0
MW
400.0
A
MW
300.0
B
250.0
MW
With G-F
congestion
area I can
only buy
from FG,
or E
D
MW
C
F
G
430.0
MW
70.0
150.0
MW
21%
I
H
200.0
MW
MW
Generators F and G are deliberately
dispatched to congest line G to F
50.0
MW
E
SPOT MARKET MODEL
The participants in deregulated power market are independent power producer,
distribution company. Bids are for supplying loads because all participants in the
power system each other effect. The bids are been received by Independent
System Operator.(ISO)
The participants submit hourly offers that contain quantity and price, and they
receive dispatch instructions from the ISO.
ISO determines transaction between participants according to their bids and
power demand.
Transaction payments are defined as the product of the spot price and power
transactions for each participant.
PURPOSE OF ATC
AVAILABLE TRANSFER CAPABILIITY:
•To
deliver electric power reliably.
• To provide flexibility for changing system
conditions.
• To give the indication about the additional
amount of power transfer.
• To allow trading of electric power among
systems.
IMPORTANT DEFINITIONS
Total Transfer Capability (TTC) is defined as the
amount of electric power that can be transferred
over the interconnected transmission network in a
reliable manner under specified conditions.

Transmission Reliability Margin (TRM) is defined
as that amount of transmission transfer capability
necessary to ensure that the interconnected
transmission network is secure under a reasonable
range of uncertainties in system conditions.

DEFINITIONS



Capacity Benefit Margin (CBM) is defined as that amount of
transmission transfer capability reserved by load serving entities
to ensure access to generation from interconnected systems to
meet generation reliability requirements.
Recallability is defined as the right of a transmission provider to
interrupt all or part of a transmission service for any reason,
including economic, the transmission provider’s transmission
service tariffs or contract provisions.
Non-recallable ATC (NATC) is defined as TTC less TRM, less nonrecallable reserved transmission service (including CBM).
TOTAL TRANSFER CAPABILITY (TTC)
•
System Conditions.
•
Critical Contingencies.
•
Non-Simultaneous and Simultaneous Transfers.
•
System Limits(Thermal, Stability and Voltage).
TRANSMISSION RELIABILITY MARGIN
(TRM)
Uncertainty exists in future system topology, load
demand and power transactions

TRM is kind of a safety margin to ensure reliable
system operation as system conditions change.


TRM could be 8% or 10% of the TTC
CAPACITY BENEFIT MARGIN (CBM)
Capacity Benefit Margin (CBM) is defined as that
amount of transmission transfer capability reserved by
load serving entities to ensure access to generation from
interconnected systems to meet generation reliability
requirements.

Its use is intended only for the time of emergency
generation deficiencies.

WHAT IS AVAILABLE TRANSFER
CAPABILITY(ATC)
In broad terms, ATC is defined as the maximum
amount of additional MW transfer possible between
two parts of a power system.
OR
Mathematically, ATC is defined as the Total Transfer
Capability (TTC) less the Transmission Reliability Margin
(TRM), less the sum of existing transmission commitments
and the Capacity Benefit Margin (CBM).
ATC = TTC – TRM – “Existing TC(and CBM)”.


ATC
ADVANTAGES OF AVAILABLE TRANSFER
CAPABILITY (ATC) METHOD
ATCs produced by the calculations gives a reasonable
and dependable indication of transfer capabilities
available to the electric power market.


ATC calculations produce commercially viable results.
Regional or wide-area coordination is necessary to
develop and post information that reasonably reflects the
ATCs of the interconnected transmission network.

ASSUMPTIONS DURING A TRANSFER
CAPABILITY CALCULATION
The base case power flow of the system is feasible and corresponds to
a stable operating point.
The load and generation are changing very slowly so that the
system transient stability is not affect.
The system steady state stability is maintained with sufficient damping.
Bus voltage limits are maintained before the system loses voltage
stability.
METHODS FOR COMPUTATION OF
TRANSFER CAPABILITY
Continuation Power Flow (CPF) method
Optimal Power Flow (OPF) method.
Repeated Power Flow (RPF) method.
LIMITS TO TRANSFER CAPABILITY
Thermal Limits
Voltage Limits
Stability Limits
COTINUATION POWER FLOW
CONTINUATION POWER FLOW:
The general principle behind the continuation
power flow is simple. It employs a predictorcorrector scheme to find a solution path. It
adopts locally parameterized continuation
technique. It includes load parameter, step
length for load parameter and state variable
ALGORITHM OF OPF ANALYSIS
1.
2.
3.
4.
5.
6.
Solve the power flow.
Linearize the power system about the current power flow
solution.
Solve the linearly-constrained OPF problem to compute
the incremental change in the control variables. The LP
then determines the optimal, feasible solution for the linear
problem.
Update the control variables and resolve the power flow.
If the changes in the control variables are below a
tolerance then the solution has been reached; otherwise go
to step 2.
Finish by solving the power flow.
ALGORITHM FOR REPEATED
POWER FLOW METHOD
Establish and solve for a base case.
Select a transfer case.
Solve for the transfer case.
Increase step size if transfer is successful.
Decrease step size if transfer is unsuccessful.
Repeat the procedure until minimum step size reached.
METHODS BASED ON DISTRIBUTION
FACTORS
AC Power Transfer Distribution Factors:
Consider a bilateral transaction tp between a seller at bus m
and a buyer at bus n.
Line- l carries the part of the transacted power and is
connected between bus-i
and bus-j. For a change in real power, transaction among the
above buyer and seller by
∆tp MW, if the change in a transmission line quantity ql lis by
∆ql
A.C.Power Transfer Distribution Factors can be defined as
(ACPTDF) ql-tp = (∆ql ) / (∆tp )
METHODS BASED ON DISTRIBUTION
FACTORS-CONTD.
Voltage Distribution Factors:
Voltage Distribution Factors (VDFs) are defined as the change in the
bus voltage magnitude ‘∆Vi ‘at any bus-ito the change in the pth
transaction, say, by ‘∆tp’ between seller bus and the buyer bus.
Let the base case voltage magnitude at any bus- I be ‘Vi0’ and,
after the change due to a transaction, the new bus voltage be
‘Vi-tp’
The voltage distribution factors are defined as:
VDF i-tp = (∆Vi / ∆tp )
Where, ∆Vi = Vi-tp –Vi0
METHODS BASED ON DISTRIBUTION
FACTORS-CONTD.
ATC for base case, between bus/zone ‘m’ and bus/zone ‘n’
using the line flow limit criterion has been calculated using
ACPTDFs as
ATCmn =
min
max
0


(
P

P
)
 ij

ij
ij  N l 



 PTDF ij , mn

ATC at base case considering voltage limit violation can be
calculated as

min


 (V i  t  V i )

i NB
ATCmn = min 


 VDF i , mn

CONTINGENCY ANALYSIS
Contingency Analysis (CA), as a part of static security
analysis, is critical in many routine power system and power
market analysis, such as ATC evaluation, security
assessment and transaction arrangement.

A typical CA has models

Single element outage (one –transmission line, one generator
outage, etc.),
Multiple element-outages (two-transmission line outage, one
–transmission line and one generator outage, etc.) and
Sequential outage (one outage after another)
CONTINGENCY ANALYSIS – CONTD.
After a contingency event, power system problems can range
from:
None: When the power system can be re-balanced after a
contingency, without overloads to any element.
Severe: When several elements such as lines and transformers
become overloaded and have risk of damage.
Critical: When the power system becomes unstable and will
quickly collapse.
METHODS OF CONTINGENCY ANALYSIS
DC load flow method of contingency analysis
Z-matrix method of contingency analysis
Voltage stability index (L-index) computation
Decoupled load flow
Fast decoupled load flow
By analyzing the effects of contingency events in
advance, problems and unstable situations can be
identified, critical configurations can be recognized,
operating constraints and limits can be applied, and
corrective actions can be planned.
TRANSMISSION LOADING RELIEF
(TLR)
Transmission Loading Relief (TLR) is a sequence of actions
taken during operations planning or during real time operation to
avoid or remedy security violations associated with the
transmission system.
Interchange transactions are typically created through the use
of Available Transfer Capability (ATC) information.
There should be a very close relationship between the need for
TLR and the accuracy and use of ATC information.
NERC TLR PROCEDURE INVOLVES
FOLLOWING “LEVELS”
Level 1: Notify reliability coordinators of potential operating security limit Violations.
Level 2: Hold transfers at present level to prevent operating security limit Violations.
Level 3a: Reallocation of Transmission Service by curtailing interchange transactions using
non-firm point-point transmission service to allow interchange transactions using
higher priority transmission service.
Level 3b: Curtail interchange transactions using Non- Firm Transmission Service
Arrangements to mitigate an operating security limit Violation.
TLR Level 4: Reconfigure Transmission.
TLR Level 5a: Reallocation of Transmission Service by curtailing interchange transactions
using Firm Point-to-Point Transmission Service on a pro rata basis to allow additional
interchange transactions using Firm Point-to-Point Transmission Service.
TLR Level 5b: Curtail interchange transactions using Firm Point-to-Point Transmission
Service to mitigate an operating security limits Violation.
TLR Level 6: Emergency Procedures.
 TLR Level 0: TLR concluded.
LIMITATIONS ON TRANSMISSION
RELIEF PROCEDURE
Computation of off-line ATC doesn’t consider the
effect of the actual transactions in/out of the region. It is
a non-simultaneous computation.
The non-peak hour operating conditions differ from
that at peak hour.
Numerical errors are present in off-line ATC because it
often neglects the influence of reactive power, uses linear
models and assumes constant distribution factors.
PROBLEMS IN TLR DUE TO THE
ABOVE LIMITATIONS
By using daily offline ATC computations can result in inaccurate
TLR decisions.
New constrained facilities can be originated when TLR procedures
are implemented.
There is a need of precise and fast coordination among all the
coordinators and participants in the operating grid since TLR is an
iterative process that changes from one level to another.
Market’s efficiency is affected due to the opens opportunities for
economic gaming of TLR procedures.
SOME OF TYPICAL MEANS OF CONTROLS TO
MITIGATE THE TRANSMISSION EMERGENCIES
Generator active power adjustment
Phase angle regulator adjustment
Interchange schedule adjustment
Generator reactive power adjustment
Transformer tap adjustment
Shunt capacitor/reactor switching or synchronous condenser
adjustment
Transmission line switching
Pumped storage generator operation
Economic load Management/Customer load shedding
Distributed generation
Transmission System Expansion
METHODS TO ALLEVIATE TLR
Sensitivity based load curtailment
Economic load management
VAR support
Re-dispatching and coordinated re-dispatching
Counter trading
HOUR-AHEAD ATC
Computation of hour-ahead ATC is same as off-line ATC and for
the next hours it operates on the planned model.
It is used in the Energy Management System (EMS) study mode.
The difficult part of hour-ahead ATC is data management and
modeling.
To accurately compute ATC, System and transaction data need to
provide.
ALGORITHM FOR HOUR-AHEAD ATC
Obtain a base system case.
Using system and bus load forecast functions, system
model modifications are also included to the loads. Update
generation settings and base flows.
For next hour case, compute the PTDFs by solving the
power flows.
Compute ATC for confirmed reservations using a
transaction analyzer which could also be used for
computations such as contingency analysis, sensitivity
analysis, interchange distribution calculations, transaction
arrangement and transmission loading relief.
TYPES OF TRANSACTIONS
In open-access electricity markets transactions
can be done in three different ways.
1. Simultaneous transactions
2. Sequential transactions: off-line ATC
3. Sequential transactions-updated ATC
RESULTS AND DISCUSSION
26-bus system
No. of
No. of
No. of
No. of
buses
: 26
lines
: 46
areas
:1
generators : 6
RESULTS OF 26-BUS SYSTEM (NR)
Gen.
No.
1
2
3
4
5
26
Gen. Gen.
MW Mvar
472 254
171
78
188
40
148
80
194 137
101
27
Min.
MW
100
50
80
50
50
50
Max. Min.
MW Mvar
500
0
200
40
300
40
150
40
200
40
120
15
Total MW generation
Total Mw load
Total Mw losses
System cost
:
:
:
:
Max.
Mvar
350
250
150
80
160
50
Cost
Cost
$/hr $/MWhr
5109
10.82
2193
12.82
2141
11.39
2031
13.72
2564
13.21
1484
14.64
1276.5 MW
1263.0 MW
13.52 MW
$16777.71 / hr
RESULTS OF 26-BUS SYSTEM (OPF)
Gen
no
1
2
3
4
5
26
Gen Gen Min
MW Mvar MW
421 260 100
170
65
50
294
40
80
130
80
50
170 142
50
92
28
50
Max Min Max
MW Mvar Mvar
500
0
350
200
40
250
300
40
150
150
40
80
200
40
160
120
15
50
Total MW generation
Total Mw load
Total Mw losses
System cost
:
:
:
:
Cost
$/hr
4429
2175
3496
1782
2236
1358
1277.0 MW
1263.0 MW
14.03 MW
$15475.24 / hr
Cost
$/MWhr
10.52
12.79
11.89
13.70
13.15
14.76
Case Scenarios

There are six generators in 26-bus system, two generating
companies A and B.

Company A owns generator 1, 4 and 26

Company B owns 2, 3 and 5.

Simulations are done on with varying load conditions from
50% to 100% load.

Profit ($/MWhr) = Spot Price($/MWhr) – Cost($/MWhr)

Profit ($/hr) = Profit ($/MWhr) x Gen MW
Determination of required power production of
26-bus
system
at
different
load
levels
Power in MW
Supply Curve
Demand Curve
1470
1500
1263 (100%)
1200
1263 (90%)
1000
1350
1000
947
(75%)
800
631
(50%)
500
500
0
1
1, 3
1, 2, 3
1, 2, 3, 5
Generators Numbers
1, 2, 3,
4, 5
1, 2, 3,
4, 5, 26
Generator Costs, Bids, and Profits of Company B of 100%
1
4
26
Gen
(MW)
499.95
150.00
0.0
Gen
(Mvar)
260.88
80.00
0.0
Cost
Cost
Bids Spot Price
($/hr) ($/MWhr) ($/MWhr) ($/MWhr)
5489.36
10.98
12.07
15.05
2052.5
13.68
15.05
15.05
0.0
0.0
0.0
0.0
Total Profit ($/hr)
Profits
($/hr)
2034.80
205.50
0.0
2240.30
Generator Costs, Bids, and Profits of Company B of 100%
Gen
Gen
Cost
Cost
Bids
Spot Price
(MW) (Mvar) ($/hr) ($/MWhr) ($/MWhr) ($/MWhr)
2 200.00 95.65 2580.00
12.90
14.19
15.05
3 227.98 40.00 2625.64
11.51
12.66
15.05
5 200.00 146.02 2640.00
13.20
14.52
15.05
Total Profit ($/hr)
Profits
($/hr)
430.00
807.00
370.00
1607.00
Calculation of bids, spot price and profits
 Consider the generators 1, 4 belongs to the company A.
 Generator 1 generation is 499.95 MW with cost of generation 5489.36
$/hr and Cost of generation per MWhr is 10.98 $/MWhr.
 Generator 4 generation is 150.00 MW with total cost of generation
2052.5 $/hr and Cost of generation per MWhr is 13.68 $/MWhr.
 Bids are taken as 10% higher than the cost of generation and the bids
of generators 1 and 4 are 12.07 $/MWhr and 15.05 $/MWhr.
 The spot price is taken as the highest bid i.e. 15.05 $/MWhr of
generator 4.
 Profit ($/MWhr) of generator 1 is = 15.05 – 10.98 = 4.07
Profit ($/hr) = 4.07 x 499.95 = 2034.80
Profit ($/MWhr) of generator 4 is = 15.05 – 13.68 = 1.37
Profit ($/hr) = 1.37 x 150.00 = 205.50
Total profit of Company A in ($/hr) = 2034.80 + 205.50 = 2240.30.
Generator Costs, Bids, and Profits of Company A of 90%
1
4
26
Gen
Gen
Cost
Cost
Bids
Spot Price
(MW) (Mvar) ($/hr) ($/MWhr) ($/MWhr) ($/MWhr)
500.00 248.3 5495.39
10.99
12.089
14.487
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Total Profit ($/hr)
Profits
($/hr)
1748.5
0.0
0.0
1748.5
Generator Costs, Bids, and Profits of Company B of 90%
Gen
Gen
Cost
Cost
Bids
Spot Price
(MW) (Mvar) ($/hr) ($/MWhr) ($/MWhr) ($/MWhr)
2 170.35 122.86 2179.22
12.79
14.069
14.487
3 296.35 40.00 3529.43
11.91
13.101
14.487
5 185.35 145.87 2441.05
13.17
14.487
14.487
Total Profit ($/hr)
Profits
($/hr)
289.08
763.69
244.11
1296.87
Generator Costs, Bids, and Profits of Company A of 75%
Gen
Gen
Cost
Cost
Bids
Spot Price
(MW) (Mvar) ($/hr) ($/MWhr) ($/MWhr) ($/MWhr)
1 494.46 286.50 5412.63
10.95
12.045
14.08
4
0.0
0.0
0.0
0.0
0.0
0.0
26
0.0
0.0
0.0
0.0
0.0
0.0
Total Profit ($/hr)
Profits
($/hr)
1547.65
0.0
0.0
1547.65
Generator Costs, Bids, and Profits of Company B of 75%
2
3
5
Gen
(MW)
Gen
(Mvar)
170.46
296.46
0.0
126.20
40.00
0.0
Cost
Cost
Bids
Spot Price Profits
($/hr) ($/MWhr) ($/MWhr) ($/MWhr) ($/hr)
2180.58
12.8
3530.84
11.91
0.0
0.0
Total Profit ($/hr)
14.08
13.101
0.0
14.08
14.08
0.0
218.18
643.31
0.0
861.49
Generator Costs, Bids, and Profits of Company A of 50%
Gen
Gen
Cost
Cost
Bids
Spot Price
(MW) (Mvar) ($/hr) ($/MWhr) ($/MWhr) ($/MWhr)
1 421.6 205.38 4435.47
10.52
11.572
12.617
4
0.0
0.0
0.0
0.0
0.0
0.0
26 0.0
0.0
0.0
0.0
0.0
0.0
Total Profit ($/hr)
Profits
($/hr)
884.09
0.0
0.0
884.09
Generator Costs, Bids, and Profits of Company B of 50%
2
3
5
Gen Gen
Cost
Cost
Bids
Spot Price
(MW) (Mvar) ($/hr) ($/MWhr) ($/MWhr) ($/MWhr)
0.0
0.0
0.0
0.0
0.0
0.0
217.0 40.0 2488.3
11.47
12.617
12.61
0.0
0.0
0.0
0.0
0.0
0.0
Total Profit ($/hr)
Profits
($/hr)
0.0
248.90
0.0
248.90
COMPARISON OF PROFITS OF
COMPANY A AND COMPANY B
Profits ($/hr)
MW Load
(%)
Spot Price
($/MWhr)
50
12.617
884.09
248.9
75
14.08
1547.65
861.5
90
14.487
1748.5
1296.87
100
15.05
2240.3
1607
Company A Company B
S
p
o
t
p
r
i
c
e
Variation of the spot price
with respective to load
% MW load
Comparison of the profits
of company A and B
P
r
o
f
i
t
% MW load
Variation of ATC from Bus 1 to Other Buses
Transfer
Buses
NR Method
100% Load
90% Load
75% Load
50% Load
ATC Limiting ATC Limiting ATC Limiting ATC Limiting ATC Limiting
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line
1-3
200
17-18
215
17-18
272
16-17
314
16-17
308
16-17
1-5
238
6-18
195
6-18
180
6-18
72
6-18
162
6-18
1-9
197
2-8
195
7-9
153
2-8
154
16-20
232
9-10
1-12
230
17-18
228
2-8
146
2-8
108
12-14
215
12-14
1-15
141
17-18
152
17-18
138
13-15
147
13-15
217
16-17
1-16
80
17-18
86
17-18
101
15-16
99
15-16
117
16-17
1-17
33
17-18
36
17-18
46
17-18
55
1-17
56
16-17
1-18
235
1-18
208
1-18
223
1-18
197
1-18
329
1-18
1-19
201
6-19
203
6-19
200
16-20
94
6-18
212
6-18
1-24
59
22-24
55
22-24
65
22-24
62
22-24
80
22-24
Variation of ATC from Bus 2 to Other Buses
Transfer
Buses
2-1
2-3
2-5
2-9
2-12
2-15
2-16
2-17
2-18
2-19
2-24
NR Method
100% Load
90% Load
75% Load
50% Load
ATC Limiting ATC Limiting ATC Limiting ATC Limiting ATC Limiting
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line (MW)
Line
666
1-2
672
1-2
691
1-2
670
1-2
723
1-2
251
17-18
270
17-18
333
16-17
350
2-8
378
16-17
266
6-18
218
6-18
201
6-18
81
6-18
181
6-18
193
7-9
194
7-9
139
2-8
112
2-8
232
9-10
224
2-8
208
2-8
134
2-8
105
12-14
209
12-14
156
12-15
175
12-15
135
13-15
144
13-15
230
13-15
86
17-18
90
15-16
98
15-16
96
15-16
123
15-16
34
17-18
37
17-18
47
17-18
52
16-17
54
16-17
259
1-18
229
1-18
246
1-18
217
1-18
363
16-17
204
6-19
205
6-19
189
2-8
109
6-18
246
6-18
59
22-24
54
22-24
65
22-24
62
22-24
79
22-24
Variation of ATC from Bus 3 to Other Buses
Transfer
Buses
NR Method
100% Load
90% Load
75% Load
50% Load
ATC Limiting ATC Limiting ATC Limiting ATC Limiting ATC Limiting
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line
3-1
225
3-13
182
3-13
104
3-13
94
12-14
188
12-14
3-5
206
3-13
166
3-13
95
3-13
76
12-14
152
12-15
3-9
193
3-13
157
3-13
86
12-14
62
12-14
124
12-14
3-12
183
12-14
150
3-13
69
12-14
50
12-14
100
12-14
3-15
139
13-15
124
13-15
72
3-13
76
3-13
158
3-13
3-16
84
15-16
78
15-16
77
3-13
80
3-13
106
15-16
3-17
40
17-18
42
17-18
52
16-17
44
16-17
45
16-17
3-18
185
16-17
167
16-17
99
3-13
89
12-14
155
16-17
3-19
195
6-7
160
3-13
91
3-13
69
12-14
138
12-14
3-24
57
22-24
53
22-24
63
22-24
60
22-24
78
22-24
Variation of ATC from Bus 4 to Other Buses
Transfer
Buses
NR Method
100% Load
90% Load
75% Load
50% Load
ATC Limiting ATC Limiting ATC Limiting ATC Limiting ATC Limiting
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line
4-1
216
4-12
218
4-12
386
4-12
279
6-7
342
16-17
4-3
194
4-12
195
4-12
346
4-12
357
4-12
359
12-15
4-5
196
6-7
161
6-7
205
6-7
98
6-7
144
6-7
4-9
178
10-12
162
10-12
219
7-9
218
9-10
218
9-10
4-12
162
4-12
163
4-12
289
4-12
299
4-12
313
4-12
4-15
118
12-15
133
12-15
178
13-15
190
13-15
190
12-15
4-16
92
15-16
85
15-16
92
15-16
91
15-16
116
15-16
4-17
38
17-18
40
17-18
52
17-18
47
16-17
48
16-17
4-18
214
4-12
215
4-12
240
16-17
178
6-7
206
16-17
4-19
177
10-12
162
10-12
232
6-19
149
6-7
218
6-7
4-24
56
22-24
52
22-24
62
22-24
59
22-24
76
22-24
Variation of ATC from Bus 5 to Other Buses
Transfer
Buses
NR Method
100% Load
90% Load
75% Load
50% Load
ATC Limiting ATC Limiting ATC Limiting ATC Limiting ATC Limiting
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line
5-1
106
5-6
100
5-6
110
5-6
288
5-6
275
5-6
5-3
106
5-6
100
5-6
110
5-6
288
5-6
275
5-6
5-6
106
5-6
100
5-6
110
5-6
288
5-6
275
5-6
5-9
106
5-6
100
5-6
110
5-6
232
9-10
232
9-10
5-12
106
5-6
100
5-6
110
5-6
148
12-14
275
5-6
5-15
106
5-6
100
5-6
110
5-6
165
13-15
219
16-17
5-16
85
17-18
92
17-18
104
16-17
103
15-16
118
16-17
5-17
34
17-18
37
17-18
47
17-18
55
16-17
56
16-17
5-18
106
5-6
100
5-6
110
5-6
288
5-6
275
5-6
5-19
106
5-6
100
5-6
110
5-6
237
6-19
272
6-19
5-24
63
22-24
58
22-24
69
22-24
66
22-24
85
22-24
Variation of ATC from Bus 26 to Other Buses
NR Method
100% Load
90% Load
75% Load
50% Load
Transfer
ATC Limiting ATC Limiting ATC Limiting ATC Limiting ATC Limiting
Buses
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line
(MW)
Line
26-1
82
11-26
185
11-26
181
11-26
169
11-26
175
11-26
26-3
81
11-26
183
11-26
180
11-26
168
11-26
173
11-26
26-5
76
11-26
170
11-26
168
11-26
156
11-26
162
11-26
26-6
76
11-26
170
11-26
168
11-26
156
11-26
162
11-26
26-9
80
11-26
178
11-26
175
11-26
163
11-26
169
11-26
26-12
80
11-26
179
11-26
176
11-26
128
11-26
170
11-26
26-15
81
11-26
166
12-15
147
13-15
156
13-15
171
11-26
26-16
80
11-26
94
17-18
102
15-16
100
15-16
123
16-17
26-17
34
17-18
37
17-18
47
17-18
53
16-17
55
16-17
26-18
80
11-26
179
11-26
176
11-26
164
11-26
170
11-26
26-19
76
11-26
171
11-26
168
11-26
156
11-26
162
11-26
26-24
61
22-24
56
22-24
67
22-24
64
22-24
83
22-24
ATC is varying with variation of load. This variation
of
ATC depends upon Generators in operation, Load
variation, bus voltages, Variation of line flows and line
limits.
IEEE 118-bus system
No. of
No. of
No. of
No. of
buses
lines
areas
generators
: 118
: 186
:4
: 54
IEEE 118-bus system


IEEE 118-bus system is composed of 54 generators with a
total installed capacity of 8190MW and the system demand is
3668MW.
The system is divided into four areas as follows. For this
analysis, the generators belong to each area is considered as
one generating company.
Area
1
2
3
4
Buses
1 – 38, 113 – 115 & 117
39 - 68
69 – 102, 116 & 118
103 - 112
Company
A
B
C
D
This analysis is discussed under different case studies as
follows
Case 1: All the generators are committed to dispatch with
100% load.
Case 2: Some of Generators with more expensive are shut
down with 100% load.
Case 3: Some more Generators with more expensive are
shut down with 75% load.
Case 4: Some more Generators with more expensive are
shut down with 50% load.
DISPATCH OF GENERATORS FOR DIFFERENT CASES
Area
1
2
3
4
Generators
1,4,6,8,10,12,15,
18,19,24,25,26,
27,31,32,34,36,
113
40,42,46,49,54,
55,56,59,61,62,
65,66
69,70,72,73,74,
76,77,80,85,87,
89,90,91,92,99,
100,116
103,104,105,107,
Generators committed to dispatch
Case1
Case 2
Case 3
Case 4
All
1,4,6,12,15,18, 12,15,18, 12,15,18,
19,26,34,36, 19, 6,34,36, 19,34,
113
113
113
All
40,42,49,54,
55,56,59,62,66
40,42,54,
55,56,59,
62,66
40,54,55,
56,59,62
All
69,76,77,87,
89,91,92,99,
116
69,77,87,
89,91,99
69,89,91
All
110,111,112
110,111,112 110,112
COMPARISON OF PROFITS OF
COMPANY A, B, C AND D
Profit $/MWhr
Spot Price
Company Company Company Company
$/MWhr
A
B
C
D
Case 1
13.06
8334.77
9516.54
8780.16
1856.27
Case 2
9.35
3465.47
3989.82
4554.97
1213.00
Case 3
8.43
2014.43
2686.84
2860.80
745.16
Case 4
11.29
3185.91
3806.74
2301.03
888.62
Variation of ATC between the Areas for
Different Cases of IEEE 118-Bus System
Transfer
Areas
1-2
1-3
1-4
2-1
2-3
2-4
3-1
3-2
3-4
4-1
4-2
4-3
Case 1
Case 2
Case 3
Case 4
ATC
(MW)
Limiting
Area/Line
ATC
(MW)
Limiting
Area/Line
ATC
(MW)
Limiting
Area/Line
ATC
(MW)
Limiting
Area/Line
706.87
127.24
101.59
454.57
127.24
101.59
454.57
706.87
101.59
247.41
247.41
127.24
Area 2
Area 3
Area 4
Area 1
Area 3
Area 4
Area 1
Area 2
Area 4
Area 4
Area 4
Area 3
67.46
67.46
67.46
232.45
232.45
175.00
542.54
704.52
175
0.00
0.00
0.00
Area 1
Area 1
Area 1
Area 2
Area 2
Area 4
Area 1
65-68
Area 4
Area 4
Area 4
Area 4
236.40
236.40
110.87
288.61
291.71
110.87
288.61
625.29
110.87
64.13
64.13
64.13
Area 1
Area 1
Area 4
Area 1
Area 2
Area 4
Area 1
Area 2
Area 4
Area 4
Area 4
Area 4
49.27
49.27
49.27
133.71
133.71
72.78
225.73
261.44
72.78
27.22
27.22
27.22
Area 1
Area 1
Area 1
Area 2
Area 2
Area 4
Area 1
Area 3
Area 4
Area 4
Area 4
Area 4
Example Case for Transmission Loading Relief
7-bus system
7-bus Case, ATC Data
Transfer
Areas
Transfer
Buses
A-B
1-6
2-6
4-6
1-7
2-7
4-7
6-7
A-C
B-C
ATC
(MW)
54
265
281
56
106
152
111
Limiting
Line
1-2
2-6
2-6
1-2
2-5
4-5
6-7
Sequential ATC data
Transactions
Direction 1-6:
Direction 2-6:
Direction 4-6:
50MW
200MW
200MW
Transfer
t0
Overload
1-2:
22%
2-6:
95%
t1
t2
t3
Area
Bus
ATC
(MW)
Limit
Line
ATC
(MW)
Limit
Line
ATC
(MW)
Limit
Line
ATC
(MW)
Limit
Line
A-B
1-6
2-6
4-6
1-7
2-7
4-7
6-7
54
265
281
56
106
152
111
1-2
2-6
2-6
1-2
2-5
4-5
6-7
4
265
281
56
106
152
111
1-2
2-6
2-6
1-2
2-5
4-5
6-7
4
65
281
56
106
152
111
1-2
2-6
2-6
1-2
2-5
4-5
6-7
4
65
81
56
106
152
111
1-2
2-6
2-6
1-2
2-5
4-5
6-7
A-C
B-C
Sequential transactions- update ATC
t0
Transfer
Area Bus
A-B 1-6
t1
ATC Limit ATC
(MW) Line (MW)
t2
Limit
Line
t4
t3
ATC Limit ATC Limit ATC Limit
(MW) Line (MW) Line (MW) Line
54
1-2
4
1-2
9
1-2
4
1-2
54
1-2
2-6 265
2-6
220
2-6
25
2-6
13
2-6
59
2-6
4-6 281
2-6
28
1-2
26
2-6
14
2-6
62
2-6
56
1-2
6
1-2
9
1-2
5
1-2
56
1-2
2-7 106
2-5
98
2-5
54
2-5
34
2-6
63
2-5
4-7 152
4-5
34
1-2
57
1-2
30
1-2
90
2-5
6-7
123
6-7
68
2-5
69
2-5
79
2-5
A-C 1-7
B-C 6-7
111
Secure Transactional Space
T3(4-6)
281
t0
26
t1
220
265
T2(2-6)
54
T1(1-6)
26-bus System
Transactions
Direction 1-18:200MW
Direction 2-12:150MW
Direction 4-9:150MW
1-18
7-9
Overload
7%
8%
4-12
8%
Sequential transactions-update ATC for 26-Bus System
t0
t1
t2
t3
t4
Trans
fer
ATC Limit ATC Limit ATC Limit ATC Limit ATC Limit
Bus
(MW) Line (MW) Line (MW) Line (MW) Line (MW) Line
1-18
231
1-18
31
1-18
5
1-18
1
1-18
205
1-18
1-12
240
2-8
74
1-18
15
1-18
3
1-18
165
2-8
2-12
220
2-8
99
1-18
19
1-18
4
1-18
151
2-8
3-9
113
3-13
93
3-13
40
1-18
7
1-18
86
3-13
4-9
175 12-10 162 10-12 146
1-18
46
1-18
95
7-9
4-18
190 16-17
42
1-18
9
1-18
2
1-18
112
4-12
26-18 130
5-6
47
1-18
10
1-18
2
1-18
83
11-26
Secure Transactional Space for transactions of
26-bus System
T3 (4-9)
175
t0
220
T2 (2-12)
t1
160
t2
200
231
T1 (1-18)
80
99
145
IEEE 118- Bus System
Transactions
Overload
Direction 25-59 :700MW
8-5
Direction 100-45 :700MW
68-81 31%
Direction 80-11
80-81 31%
:700MW
24%
Sequential transactions-update ATC for
IEEE 118-Bus System
Transfer
Area
A-B
A-C
B-A
B-C
C-A
C-B
ATC
Bus
(MW)
25-59
765
26-62
841
12-77
794
26-90
836
54-11
861
65-27
842
54-77
697
65-82
580
80-11
801
92-32
910
87-54
300
100-45 808
t0
t1
Limit
Line
64-65
64-65
65-68
65-68
38-65
38-65
65-68
65-68
65-68
65-68
86-87
86-87
ATC
(MW)
068
352
862
909
835
816
758
630
739
835
300
700
t2
Limit
Line
64-65
64-65
65-68
65-68
38-65
38-65
65-68
65-68
65-68
65-68
86-87
65-68
ATC
(MW)
065
335
965
1000
770
754
848
705
90
358
300
327
t3
Limit
Line
64-65
64-65
65-68
89-90
38-65
38-65
54-56
65-68
81-80
81-80
86-87
81-80
ATC
(MW)
060
246
1048
1007
665
650
864
673
89
100
93
77
Limit
Line
64-65
64-65
65-68
89-90
38-65
38-65
68-69
68-69
81-80
81-80
81-80
81-80
Secure Transactional Space for transactions of
118-bus System
T3 (100-45)
808
700
t1
t1
t2
700
650
739
8011
T2 (80-11)
768
T1 (25-59)
Conclusions

Proper scheduling of generators using OPF
Minimize the total system losses
 Increase the generator efficiencies



Optimal power flow can provide the social welfare maximizing
solutions by supplying uninterrupted power to the
manufacturing industries which can increase the profit margin
by higher production.
OPF results can provide power system operator with flexible
solution and can be considered in generation dispatching
schedule to reflect more practical situations with less control
number guaranteeing the voltage security level.
Contd.


A continuous assessment of the ATC of the transmission
system under varying system conditions is carried out. This is
used to identify new projects to add transmission capacity to
the network, and it also initiated to develop remedial action
schemes for system operators to enforce transmission limits in
accordance with good utility practice.
The off -line studies can also be used to prepare look up tables
and would become most important in case of failure of State
Estimator (SE) to converge. Further the offline studies would
also help user to select user defined contingencies for the
online application such as Real Time Contingency Analysis
(RTCA).
Contd.




In this thesis, transactions are performed using simultaneous,
sequential-offline and sequential-update ATC methods, and the
results shows the sequential transactions with updated ATC is
ideal.
By calculating hour-ahead ATC minimizes implementation of
TLR procedures.
The above results are more useful for Power Trading
Corporation of India Ltd. (PTC)
These case studies are much useful for Energy Management
System (EMS), and online environment of deregulated power
system to perform the transactions between buyer and seller for
APGENCO, APTRANSCO, and APDISCOMs.
CONTACT :
Dr.P.S.SUBRAMANYAM :
[email protected]
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