Section 10 Congestion and Marginal Losses
Congestion and Marginal
Losses
The Locational Marginal Price (LMP) is the incremental
price of energy at a bus. The LMP at a bus is made
up of three components: the system marginal price or
energy component (SMP), the marginal loss component
of LMP (MLMP), and the congestion component of LMP
(CLMP).1
SMP, MLMP and CLMP are a product of the least cost,
security constrained dispatch of system resources
to meet system load. SMP is the incremental cost of
energy, given the current dispatch, ignoring losses
and congestion. Losses refer to energy lost to physical
resistance in the transmission network as power is
moved from generation to load. Marginal losses are
the incremental change in system losses caused by
changes in load and generation. Congestion occurs
when available, least-cost energy cannot be delivered to
all load because transmission facilities are not adequate
to deliver that energy and higher cost units in the
constrained area must be dispatched to meet that load.2
The result is that the price of energy in the constrained
area is higher than in the unconstrained area.
Congestion is neither good nor bad but is a direct
measure of the extent to which there are multiple
marginal generating units dispatched to serve load as a
result of transmission constraints.
The energy, marginal losses and congestion metrics must
be interpreted carefully. The term total congestion refers
to what is actually net congestion, which is calculated as
net implicit congestion costs plus net explicit congestion
costs plus net inadvertent congestion charges. The
net implicit congestion costs are the load congestion
payments less generation congestion credits. This
section refers to total energy costs and total marginal
loss costs in the same way. As with congestion, total
energy costs are more precisely termed net energy costs
1 On January 1, 2012, PJM integrated the Duke Energy Ohio/Kentucky (DEOK) Control Zone. On June
1, 2011, PJM integrated the American Transmission Systems, Inc. (ATSI) Control Zone. The metrics
reported in this section treat DEOK as part of MISO for the first hour of January 2012 and as part
of PJM for the second hour of January through December 2012. ATSI is treated as part of MISO
for the period from January 2011 through May 31, 2011 and as part of PJM for the period from
June 1, 2011 through December 31,2012.
2 This is referred to as dispatching units out of economic merit order. Economic merit order is the
order of all generator offers from lowest to highest cost. Congestion occurs when loadings on
transmission facilities mean the next unit in merit order cannot be used and a higher cost unit
must be used in its place. Dispatch within the constrained area follows merit order for the units
available to relieve the constraint.
© 2013 Monitoring Analytics, LLC
and total marginal loss costs are more precisely termed
net marginal loss costs.
The components of LMP are the basis for calculating
participant and location specific congestion and
marginal losses.3
Overview
Marginal Loss Cost
Before June 1, 2007, the PJM economic dispatch and
LMP models did not include marginal losses. Losses
were treated as a static component of load, and the
physical nature and location of power system losses
were ignored. The PJM Tariff required implementation
of marginal losses when required technical systems
became available. On June 1, 2007, PJM began including
marginal losses in economic dispatch and LMP models.4
The primary benefit of a marginal loss calculation is that
it more accurately models the physical reality of power
system losses, which permits increased efficiency and
more optimal asset utilization. Marginal loss modeling
creates a separate marginal loss price for every location
on the power grid. This marginal loss price (MLMP) is a
component of LMP that is charged to load and credited
to generation.
Total marginal loss costs equal net implicit marginal
loss costs plus net explicit marginal loss costs plus net
inadvertent loss charges. Net implicit marginal loss costs
equal load loss payments minus generation loss credits.
Net explicit marginal loss costs are the net marginal loss
costs associated with point-to-point energy transactions.
Net inadvertent loss charges are the losses associated
with the hourly difference between the net actual energy
flow and the net scheduled energy flow into or out of
the PJM control area.5 Unlike the other categories of
marginal loss accounting, inadvertent loss charges
are common costs not directly attributable to specific
participants. Inadvertent loss charges are distributed
to load on a load ratio basis. Each of these categories
of marginal loss costs is comprised of day-ahead and
balancing marginal loss costs.
3 The total marginal loss and congestion results were calculated as of March 2, 2013, and are
subject to change, based on continued PJM billing updates.
4 For additional information, see OATT Section 3.4.
5 OA. Schedule 1 (PJM Interchange Energy Market) §3.7
2012 State of the Market Report for PJM 293
2012 State of the Market Report for PJM
Marginal loss costs can be positive or negative with
respect to the reference bus. If an increase in load at a
bus would decrease losses, the marginal loss component
of LMP of that bus will be negative. If an increase
in generation at a bus would result in an increase in
losses, the marginal loss component of that bus will be
negative. If an increase of load at a bus would increase
losses, the marginal loss component of LMP at that bus
will be positive. If an increase in generation at a bus
results in a decrease of system losses, then the marginal
loss component of LMP at that bus will be positive.
Day-ahead marginal loss costs are based on day-ahead
MWh priced at the marginal loss price component of
LMP. Balancing marginal loss costs are based on the
load or generation deviations between the Day-Ahead
and Real-Time Energy Markets priced at the marginal
loss price component of LMP in the Real-Time Energy
Market. If a participant has real-time generation or load
that is greater than its day-ahead generation or load
then the deviation will be positive. If there is a positive
load deviation at a bus where the real-time LMP has
a positive marginal loss component, positive balancing
marginal loss costs will result. Similarly, if there is a
positive load deviation at a bus where real-time LMP
has a negative marginal loss component, negative
balancing marginal loss costs will result. If a participant
has real-time generation or load that is less than its
day-ahead generation or load then the deviation will
be negative. If there is a negative load deviation at a
bus where real-time LMP has a positive marginal loss
component, negative balancing marginal loss costs will
result. Similarly, if there is a negative load deviation at
a bus where real-time LMP has a negative marginal loss
component, positive balancing marginal loss costs will
result.
Marginal loss credits or loss surplus is the remaining
loss amount from collection of marginal losses, after
accounting for total energy costs and net residual
market adjustments, that is paid back in full to load and
exports on a load ratio basis.
•Total
Marginal Loss Costs. Total marginal loss
costs in 2012 decreased by $397.9 million or 28.8
percent from 2011, from $1,379.6 million to $981.7
million. Day-ahead net marginal loss costs in 2012
decreased by $426.8 million or 29.8 percent from
2011, from $1,430.5 million to $1,003.8 million.
294
Section 10 Congestion and Marginal Losses
Balancing net marginal loss costs increased in 2012
by $28.9 million or 56.7 percent from 2011, from
-$51.0 million to -$22.1 million.6
•Monthly
Total Marginal Loss Costs. Significant
monthly fluctuations in total marginal loss costs
were the result of changes in load and energy import
levels, and changes in the dispatch of generation.
Monthly total marginal loss costs in 2012 ranged
from $51.0 million in April to $143.4 million in
July.
•Marginal Loss Credits. Marginal
Loss Credits are
calculated as total energy costs (net energy costs
minus net energy credits plus net inadvertent
energy charges) plus total marginal loss costs (net
marginal loss costs minus net marginal loss credits
plus net explicit loss costs plus net inadvertent
loss charges) plus net residual market adjustments.
Marginal loss credit or loss surplus is the remaining
loss amount from overcollection of marginal losses,
after accounting for total net energy costs and net
residual market adjustments that is paid back in
full to load and exports on a load ratio basis.7,8 The
marginal loss credits decreased in 2012 by $200.0
million or 34.1 percent from 2011, from $586.8
million to $386.7 million.
•Zonal
Total Marginal Loss Costs. In 2012, zonal
total marginal loss costs ranged from $2.1 million
in RECO to $205.9 million in AEP. Compared to
2011, 2012 had a decrease in total marginal loss
costs across the PJM control zones, except the ATSI
control zone, which had an increase.9
Congestion Cost
Total congestion costs equal net implicit congestion
costs plus net explicit congestion costs plus net
inadvertent congestion charges. Net implicit congestion
costs equal load congestion payments minus generation
6 Total marginal loss costs in PJM in 2012 also changed due to the addition of the DEOK Control
Zone, which accounted for $3.2 million or 0.3 percent of the total marginal loss costs. The ATSI
Control Zone had an increase in total marginal loss cost in 2012 because it became part of PJM
on June 1, 2011, which left the first five months of 2011 out of the 2011 total marginal loss cost
for ATSI.
7 See PJM. “Manual 28: Operating Agreement Accounting,” Revision 56 (October 1, 2012). Note that
the over collection is not calculated by subtracting the prior calculation of average losses from
the calculated total marginal losses.
8 Net residual market adjustments are common costs, not directly attributable to specific
participants, that are deducted from total marginal loss credits before marginal loss credits are
distributed on a load weighted ratio basis. Net residual market adjustments consist of the Known
Day-Ahead Error Value (KDAEV), day-ahead loss MW congestion value and balancing loss MW
congestion value. KDAEV are costs associated with MW imbalances created by discontinuities in,
and adjustments to, the day-ahead market solution. The day-ahead and balancing loss congestion
values are congestion costs associated with loss related MW.
9 See the 2012 State of the Market Report for PJM, Volume II, Appendix G, “Congestion and
Marginal Losses,” at “Zonal Marginal Loss Costs.”
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
congestion credits. Net explicit congestion costs are
the net congestion costs associated with point-topoint energy transactions. Net inadvertent congestion
charges are the congestion costs associated with hourly
difference between the net actual energy flow and
the net scheduled energy flow into or out of the PJM
control area in that hour. Unlike the other categories
of congestion cost accounting, inadvertent congestion
charges are common costs not directly attributable to
specific participants. Inadvertent congestion charges
are distributed to load on a load ratio basis. Each of
these categories of congestion costs is comprised of dayahead and balancing congestion costs.
Congestion charges can be both positive and negative.
When a constraint binds, the price effects of that
constraint vary. The system marginal price (SMP) is
uniform for all areas, while the congestion components
of Locational Marginal Price (LMP) will either be positive
or negative in a specific area, meaning that actual LMPs
are above or below the SMP.10
Day-ahead congestion charges and credits are based
on MWh and LMP in the Day-Ahead Energy Market.
Balancing congestion charges and credits are based on
load or generation deviations between the Day-Ahead
and Real-Time Energy Markets and LMP in the RealTime Energy Market. If a participant has real-time
generation or load that is greater than its day-ahead
generation or load then the deviation will be positive.
If there is a positive load deviation at a bus where realtime LMP has a positive congestion component, positive
balancing congestion costs will result. Similarly, if there
is a positive load deviation at a bus where real-time
LMP has a negative congestion component, negative
balancing congestion costs will result. If a participant
has real-time generation or load that is less than its
day-ahead generation or load then the deviation will
be negative. If there is a negative load deviation at a
bus where real-time LMP has a positive congestion
component, negative balancing congestion costs will
result. Similarly, if there is a negative load deviation
at a bus where real-time LMP has a positive congestion
component, negative balancing congestion costs will
result.
10 The SMP is the price at the distributed load reference bus.
© 2013 Monitoring Analytics, LLC
•Total Congestion. Total congestion costs decreased
by $470.0 million or 47.0 percent, from $999.0
million in 2011 to $529.0 million in 2012.11 Dayahead congestion costs decreased by $465.1 million
or 37.4 percent, from $1,245.0 million in 2011 to
$779.9 million in 2012. Balancing congestion costs
decreased by $4.9 million or 2.0 percent from
-$246.0 million in 2011 to -$250.9 million in 2012.
•Monthly
Congestion.
Significant
monthly
fluctuations in congestion costs were the result of
changes in load and energy import levels, changes
in the dispatch of generation and variations in
congestion frequency on constraints affecting large
portions of PJM load. Monthly congestion costs in
2012 ranged from $24.9 million in October to $73.1
million in July.
•Geographic
Differences in CLMP. Differences in
CPLM among eastern, southern and western control
zones in PJM was primarily a result of congestion
on the AP South interface, the Graceton – Raphael
Road line, the Woodstock flowgate (reciprocally
coordinated between PJM and MISO), West
Interface, and the Bedington – Black Oak interface.
(Table 10‑27)
•Congested
Facilities.
Congestion
frequency
continued to be significantly higher in the DayAhead Market than in the Real-Time Market in
2012.12 Day-ahead congestion frequency increased
by 60.3 percent from 155,670 congestion event
hours in 2011 to 249,572 congestion event hours
in 2012. Day-ahead, congestion-event hours
decreased on internal PJM interfaces but increased
on transmission lines, transformers and reciprocally
coordinated flowgates between PJM and the MISO.
Real-time congestion frequency decreased by 7.1
percent from 22,513 congestion event hours in
2011 to 20,917 congestion event hours in 2012.
Real-time, congestion-event hours decreased on
the internal PJM interfaces and transformers, but
increased on transmission lines and reciprocally
coordinated flowgates between PJM and MISO.
Facilities were constrained in the Day-Ahead Market
more frequently than in the Real-Time Market. In
11 The total zonal congestion numbers were calculated as of March 2, 2013 and are, based on
continued PJM billing updates, subject to change.
12 In order to have a consistent metric for real-time and day-ahead congestion frequency, real-time
congestion frequency is measured using the convention that an hour is constrained if any of its
component five-minute intervals is constrained.
2012 State of the Market Report for PJM 295
2012 State of the Market Report for PJM
2012, for only 3.2 percent of Day-Ahead Market
facility constrained hours were the same facilities
also constrained in the Real-Time Market. In 2012,
for 38.3 percent of Real-Time Market facility
constrained hours, the same facilities were also
constrained in the Day-Ahead Market.
The AP South Interface was the largest contributor
to congestion costs in 2012. With $68.5 million in
total congestion costs, it accounted for 16.1 percent
of the total PJM congestion costs in 2012. The top
five constraints in terms of congestion costs together
contributed $177.0 million, or 41.6 percent, of the
total PJM congestion costs in 2012. The top five
constraints were the AP South interface, the West
interface, the Bedington - Black Oak interface, the
Woodstock flowgate (a reciprocally coordinated
flowgate between PJM and MISO) and the Graceton
- Raphael Road line.
•Zonal Congestion.
ComEd was the most congested
zone in 2012. ComEd had -$334.2 million in total
load costs, -$521.6 million in total generation
credits and -$16.4 million in explicit congestion,
resulting in $171.0 million in net congestion costs,
reflecting significant local congestion between local
generation and load, despite being on the upstream
side of system wide congestion patterns. The Nelson
- Cordova transmission line, Woodstock flowgate,
Rantoul - Rantoul Jct flowgate, Oak Grove –
Galesburg flowgate and the Prairie State - W Mt.
Vernon flowgate contributed $81.0 million, or 47.4
percent of the total ComEd Control Zone congestion
costs.
13
14
The AEP Control Zone was the second most
congested zone in PJM in 2012, with $104.2
million. The Monticello - East Winamac flowgate
contributed $12.4 million or 11.9 percent of the
total AEP Control Zone congestion cost in 2012.
The Dominion Control Zone was the third most
congested zone in PJM in 2012, with a cost of $63.3
million.
•Ownership. In 2012, financial companies as a group
were net recipients of congestion credits, and
13 Tables reporting zonal congestion have been moved from this section of the report to Appendix
G. See the 2012 State of the Market Report for PJM, Volume II, Appendix G, “Congestion and
Marginal Losses.”
14 The total zonal congestion numbers were calculated as of March 2, 2013 and are, based on
continued PJM billing updates, subject to change. As of March 2, 2013, the total zonal congestion
related numbers presented here differed from the March 2, 2013 PJM totals by $0.10 Million, a
discrepancy of 0.02 percent (.00019).
296
Section 10 Congestion and Marginal Losses
physical companies were net payers of congestion
charges. In 2012, financial companies received
$83.1 million in net congestion credits, a decrease
of $91.6 million or 52.4 percent compared to 2011.
In 2012, physical companies paid $612.1 million in
net congestion charges, a decrease of $561.5 million
or 47.8 percent compared to 2011.
Conclusion
Marginal losses are the costs of incremental power
losses which result from the geographic distribution of
generation and load and the physical characteristics of
the transmission system interconnecting generation and
load. When calculating marginal losses, load is charged
and generation is credited for the power losses to the
system. Marginal loss costs have been decreasing since
2010, due to decreases in LMP and decreases in fuel
costs. Total marginal loss costs decreased in 2012 by
$397.9 million or 28.8 percent from 2011, from $1,379.6
million to $981.7 million.
Marginal loss credits are distributed to load and exports.
Marginal loss credits decreased in 2012 by $200.0
million or 34.1 percent from 2011, from $586.8 million
to $386.7 million.
Congestion reflects the underlying characteristics of
the power system, including the nature and capability
of transmission facilities, the offers and geographic
distribution of generation facilities and the geographic
distribution of load. Total congestion costs decreased by
$470.0 million or 47.0 percent, from $999.0 million in
2011 to $529.0 million in 2012. Congestion costs were
significantly higher in the Day-Ahead Market than in
the Real-Time Market. Congestion frequency was also
significantly higher in the Day-Ahead Market than in
the Real-Time Market.
ARRs and FTRs served as an effective, but not total,
offset against congestion. ARR and FTR revenues offset
88.8 percent of the total congestion costs in the DayAhead Energy Market and the balancing energy market
within PJM for the 2011 to 2012 planning period. In the
first seven months of the 2012 to 2013 planning period,
total ARR and FTR revenues offset 82.1 percent of the
congestion costs. FTRs were paid at 80.6 percent of the
target allocation level for the 2011 to 2012 planning
period, and at 74.9 percent of the target allocation level
for the first seven months of the 2012 to 2013 planning
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
period.15 Revenue adequacy, measured relative to target
allocations for a planning period is not final until the
end of the period.
Locational Marginal Price (LMP)
Components
As of June 1, 2007, PJM changed from a single node
reference bus to a distributed load reference bus. While
there is no effect on the total LMP, the components of
LMP change with a shift in the reference bus. With a
distributed load reference bus, the energy component
is now a load-weighted system price. There are no
congestion or losses included in the load weighted
reference bus price, unlike the case with a single node
reference bus.
LMP at a bus reflects the incremental price of energy
at that bus. LMP at any bus is made up of three
components: the system marginal price (SMP), marginal
loss component of LMP (MLMP), and congestion
component of LMP (CLMP).
SMP, MLMP and CLMP are a product of the least cost,
security constrained dispatch of system resources
to meet system load. SMP is the incremental cost of
energy, given the current dispatch, ignoring incremental
considerations of losses and transmission constraints.
Losses refer to energy lost to physical resistance in the
transmission and distribution network as power is moved
from generation to load. The greater the resistance of
the system to flows of energy from generation to loads,
the greater the losses of the system and the greater the
proportion of energy needed to meet a given level of
load. Marginal losses are the incremental change in
system power losses caused by changes in the system
load and generation patterns.16 The first derivative
of total losses with respect to the power flow equals
marginal losses. Congestion cost reflects the incremental
cost of relieving transmission constraints while
maintaining system power balance. Congestion occurs
when available, least-cost energy cannot be delivered to
all loads because transmission facilities are not adequate
to deliver that energy. When the least-cost available
energy cannot be delivered to load in a transmission15 See the 2012 State of the Market Report for PJM Section 12, “Financial Transmission and Auction
Revenue Rights,” at Table 12-23, “Monthly FTR accounting summary (Dollars (Millions)): Planning
periods 2011 to 2012 and 2012 to 2013”
16 For additional information, see the MMU Technical Reference for PJM Markets, at “Marginal
Losses.”
© 2013 Monitoring Analytics, LLC
constrained area, higher cost units in the constrained
area must be dispatched to meet that load.17 The result
is that the price of energy in the constrained area is
higher than in the unconstrained area because of the
combination of transmission limitations and the cost of
local generation.
Table 10‑1 shows the PJM real-time, load-weighted
average LMP components for the years 2009 to 2012.
The load-weighted average real-time LMP decreased
$10.71 or 23.3 percent from $45.94 in 2011 to $35.23 in
2012. The load-weighted average congestion component
decreased $0.01 or 26.9 percent from $0.05 in 2011
to $0.04 in 2012. The load-weighted average loss
component decreased $0.01 or 26.9 percent from $0.02
in 2011 to $0.01 in 2012. The load-weighted average
energy component decreased $10.69 or 23.3 percent
from $45.87 in 2011 to $35.18 in 2012.
Table 10‑1 PJM real-time, load-weighted average LMP
components (Dollars per MWh): 2009 through 2012
Year
2009
2010
2011
2012
Real-Time
LMP
$39.05
$48.35
$45.94
$35.23
Energy
Component
$38.97
$48.23
$45.87
$35.18
Congestion
Component
$0.05
$0.08
$0.05
$0.04
Loss
Component
$0.03
$0.04
$0.02
$0.01
In the Real-Time Energy Market, the distributed load
reference bus is weighted by system estimates of the load
in real time. At the time the LMP is determined in the
Real-Time Energy Market, the energy component equals
the system load-weighted price. However, real-time busspecific loads are adjusted, after the fact, according to
updated information from meters. This meter adjusted
load is accounting load that is used in settlements and
forms the basis of the reported PJM load weighted prices.
This after the fact adjustment means that the Real-Time
Energy Market energy component of LMP (SMP) and the
PJM real-time load-weighted LMP are not equal. The
difference between the real-time energy component of
LMP and the PJM-wide real-time load-weighted LMP
is due to the difference between estimated and meter
corrected loads used to weight the load-weighted
reference bus and the load-weighted LMP.
17 This is referred to as dispatching units out of economic merit order. Economic merit order is the
order of all generator offers from lowest to highest cost. Congestion occurs when loadings on
transmission facilities mean the next unit in merit order cannot be used and a higher cost unit
must be used in its place.
2012 State of the Market Report for PJM 297
2012 State of the Market Report for PJM
Table 10‑2 shows the PJM day-ahead, load-weighted
average LMP components for 2009 through 2012.
The load-weighted average day-ahead LMP decreased
$10.64 or 23.5 percent from $45.19 in 2011 to $34.55 in
2012. The load-weighted average congestion component
increased $0.17 or 276.8 percent from -$0.06 in 2011
to $0.11 in 2012. The load-weighted average loss
component increased $0.14 or 90.7 percent from -$0.15
in 2011 to -$0.01 in 2012. The load-weighted average
energy component decreased $10.94 or 24.1 percent from
$45.40 in 2011 to $34.46 in 2012. In terms of proportion
of day-ahead LMP, the congestion and loss components
both increased, while the energy component became a
smaller proportion in 2012.
Table 10‑2 PJM day-ahead, load-weighted average LMP
components (Dollars per MWh): 2009 through 2012
Year
2009
2010
2011
2012
Day-Ahead
LMP
$38.82
$47.65
$45.19
$34.55
Energy
Component
$38.96
$47.67
$45.40
$34.46
Congestion
Component
($0.04)
$0.05
($0.06)
$0.11
Loss
Component
($0.09)
($0.07)
($0.15)
($0.01)
In the Day-Ahead Energy Market, the distributed load
reference bus is weighted by fixed-demand bids only and
the day-ahead energy component is, therefore, a system
fixed demand weighted price. The day-ahead weighted
system price calculation uses all types of demand,
including fixed, price-sensitive and decrement bids. In
the Real-Time Energy Market, the energy component
equals the system load-weighted price. However, in
the Day-Ahead Energy Market the day-ahead energy
component of LMP and the PJM day-ahead loadweighted LMP are not equal. The difference between the
day-ahead energy component of LMP and the PJM dayahead load-weighted LMP is due to the difference in
the types of demand used to weight the load-weighted
reference bus and the load-weighted LMP.
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Section 10 Congestion and Marginal Losses
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
Zonal Components
The real-time components of LMP for each PJM control zone are presented in Table 10‑3 for 2011 and 2012. The dayahead components of LMP for each control zone are presented in Table 10‑4 for years 2011 and 2012.
Table 10‑3 Zonal and PJM real-time, load-weighted average LMP components (Dollars per MWh): 2011 and 2012
AECO
AEP
AP
ATSI
BGE
ComEd
DAY
DEOK
DLCO
Dominion
DPL
JCPL
Met-Ed
PECO
PENELEC
Pepco
PPL
PSEG
RECO
PJM
Real-Time LMP
$53.11
$40.92
$45.49
$42.09
$54.27
$36.20
$41.78
NA
$41.31
$50.59
$52.20
$53.48
$49.51
$50.83
$45.12
$51.84
$49.31
$52.68
$49.66
$45.94
2011
Energy
Component
$46.83
$45.26
$45.56
$44.59
$46.40
$45.77
$45.94
NA
$45.73
$46.45
$46.54
$47.22
$45.82
$46.16
$44.98
$46.47
$45.57
$46.36
$47.48
$45.87
Congestion
Component Loss Component
$3.92
$2.37
($2.91)
($1.43)
$0.06
($0.13)
($2.32)
($0.18)
$5.74
$2.14
($6.93)
($2.64)
($3.40)
($0.75)
NA
NA
($2.98)
($1.45)
$3.54
$0.60
$3.05
$2.60
$3.88
$2.37
$2.87
$0.82
$3.05
$1.62
($0.25)
$0.38
$4.17
$1.20
$2.99
$0.75
$3.96
$2.35
$0.02
$2.16
$0.05
$0.02
Real-Time LMP
$37.55
$33.15
$34.86
$34.42
$40.03
$31.76
$34.25
$32.67
$33.53
$37.28
$39.53
$37.34
$36.30
$36.78
$35.10
$39.08
$35.44
$37.48
$37.80
$35.23
2012
Energy
Component
$35.86
$34.73
$34.91
$34.99
$35.44
$35.39
$35.14
$35.16
$35.05
$35.45
$35.53
$35.92
$35.11
$35.27
$34.66
$35.47
$34.92
$35.38
$36.09
$35.18
Congestion
Component Loss Component
$0.23
$1.46
($0.75)
($0.83)
$0.04
($0.09)
($0.78)
$0.21
$2.99
$1.59
($2.05)
($1.58)
($0.95)
$0.05
($0.87)
($1.62)
($0.47)
($1.05)
$1.48
$0.35
$2.31
$1.68
$0.09
$1.33
$0.67
$0.53
$0.61
$0.89
($0.12)
$0.56
$2.68
$0.93
$0.00
$0.52
$0.71
$1.39
$0.42
$1.29
$0.04
$0.01
Table 10‑4 Zonal and PJM day-ahead, load-weighted average LMP components (Dollars per MWh): 2011 and 2012
AECO
AEP
AP
ATSI
BGE
ComEd
DAY
DEOK
DLCO
Dominion
DPL
JCPL
Met-Ed
PECO
PENELEC
Pepco
PPL
PSEG
RECO
PJM
Day-Ahead LMP
$53.09
$41.12
$45.10
$41.89
$53.21
$35.72
$41.54
NA
$40.98
$49.78
$52.62
$52.22
$48.62
$51.11
$44.35
$51.03
$48.69
$52.23
$49.96
$45.19
© 2013 Monitoring Analytics, LLC
2011
Energy
Component
$46.58
$45.12
$45.08
$44.76
$46.11
$45.16
$45.64
NA
$45.35
$46.13
$46.24
$46.47
$45.08
$45.66
$44.35
$45.49
$45.23
$45.96
$46.39
$45.40
Congestion
Component Loss Component
$3.78
$2.74
($2.39)
($1.61)
$0.10
($0.09)
($1.83)
($1.04)
$4.57
$2.53
($6.17)
($3.28)
($3.21)
($0.89)
NA
NA
($2.94)
($1.43)
$2.97
$0.68
$3.40
$2.97
$3.08
$2.67
$2.74
$0.80
$3.43
$2.01
($0.25)
$0.24
$3.90
$1.64
$2.79
$0.67
$3.53
$2.75
$1.48
$2.10
($0.06)
($0.15)
Day-Ahead LMP
$37.36
$32.71
$34.29
$33.55
$39.55
$30.72
$33.76
$32.18
$33.05
$36.56
$38.91
$37.03
$35.44
$36.40
$34.69
$38.26
$34.82
$37.25
$36.91
$34.55
2012
Energy
Component
$35.08
$34.19
$34.26
$34.32
$34.85
$34.60
$34.58
$34.45
$34.42
$34.76
$34.94
$35.10
$34.29
$34.62
$33.95
$34.58
$34.22
$34.81
$35.20
$34.46
Congestion
Component Loss Component
$0.66
$1.62
($0.51)
($0.97)
$0.09
($0.06)
($0.69)
($0.08)
$2.76
$1.93
($1.98)
($1.90)
($0.65)
($0.16)
($0.49)
($1.79)
($0.30)
($1.07)
$1.31
$0.48
$1.86
$2.11
$0.47
$1.47
$0.50
$0.65
$0.72
$1.06
$0.12
$0.62
$2.39
$1.29
$0.12
$0.48
$0.79
$1.65
$0.34
$1.36
$0.11
($0.01)
2012 State of the Market Report for PJM 299
2012 State of the Market Report for PJM
Energy Costs
Energy Accounting
The energy component of LMP is the system reference
bus LMP, also called the system marginal price (SMP).
The energy cost is based on the day-ahead and real-time
energy components of LMP (SMP). Total energy costs,
analogous to total congestion costs, are equal to the net
of the load energy payments minus generation energy
credits, plus explicit energy costs, plus inadvertent
energy charges, incurred in both the Day-Ahead Energy
Market and the balancing energy market. Total energy
costs can by more accurately thought of as net energy
costs.
Ignoring interchange, total generation MWh must be
greater than total load MWh in every hour in order to
provide for losses. Since the hourly integrated energy
component of LMP is the same for every bus in every
hour, the net energy costs are negative (ignoring net
interchange), with generation credits greater than load
payments in every hour.
•Day-Ahead Load Energy Payments. Day-ahead, load
energy payments are calculated for all cleared
demand, decrement bids and Day-Ahead Energy
Market sale transactions. (Decrement bids and
energy sales are equivalent to demand.) Dayahead, load energy payments are calculated using
MW and the load bus energy component of LMP
(energy LMP), the decrement bid energy LMP or the
energy LMP at the source of the sale transaction, as
applicable.
•Day-Ahead Generation Energy Credits. Day-ahead,
generation energy credits are calculated for all
cleared generation and increment offers and DayAhead Energy Market purchase transactions.
(Increment offers and energy purchases are
equivalent to generation.) Day-ahead, generation
energy credits are calculated using MW and the
generator bus energy LMP, the increment offer
energy LMP or the energy LMP at the sink of the
purchase transaction, as applicable.
•Balancing Load Energy Payments. Balancing, load
energy payments are calculated for all deviations
between a PJM member’s real-time load and
energy sale transactions and their day-ahead
cleared demand, decrement bids and energy sale
transactions. Balancing, load energy payments are
300
Section 10 Congestion and Marginal Losses
calculated using MW deviations and the real-time
energy LMP for each bus where a deviation exists.
•Balancing
Generation Energy Credits. Balancing,
generation energy credits are calculated for all
deviations between a PJM member’s real-time
generation and energy purchase transactions and
the day-ahead cleared generation, increment offers
and energy purchase transactions. Balancing,
generation energy credits are calculated using MW
deviations and the real-time energy LMP for each
bus where a deviation exists.
•Explicit Energy Costs. Explicit energy costs are the
net energy costs associated with point-to-point
energy transactions. These costs equal the product
of the transacted MW and energy LMP differences
between sources (origins) and sinks (destinations)
in the Day-Ahead Energy Market. Balancing energy
market explicit energy costs equal the product of the
differences between the real-time and day-ahead
transacted MW and the differences between the
real-time energy LMP at the transactions’ sources
and sinks. The explicit energy costs will sum to zero
because the LMP (SMP) at the transactions’ sources
and sinks will be the same for each transaction.
•Inadvertent
Energy Charges. Inadvertent energy
charges are the net energy charges resulting from
the differences between the net actual energy flow
and the net scheduled energy flow into or out of
the PJM control area each hour. This inadvertent
interchange of energy may be positive or negative,
where positive interchange typically results in
a charge while negative interchange typically
results in a credit. Inadvertent energy charges are
common costs, not directly attributable to specific
participants, which are distributed on a load ratio
basis.18
Total Energy Costs
Table 10‑5 shows total energy, loss and congestion
component costs and total PJM billing, for each year
from 2009 through 2012. The total energy, loss and
congestion component costs appear low compared to
total PJM billing because these totals are actually net
energy, loss and congestion costs.
18 OA. Schedule 1 (PJM Interchange Energy Market) §3.7.
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
Table 10‑5 Total PJM costs by component (Dollars
(Millions)): 2009 through 201219
Table 10‑6 Total PJM energy costs by category (Dollars
(Millions)): 2009 through 2012
Component Costs (Millions)
2009
2010
2011
2012
Energy
Costs
($629)
($798)
($794)
($593)
Loss
Costs
$1,268
$1,635
$1,380
$982
Congestion
Costs
$719
$1,424
$998
$529
Total
Costs
$1,358
$2,261
$1,584
$926
Total
PJM Billing
$26,550
$34,771
$35,887
$29,181
Total Costs
Percent of PJM
Billing
5.1%
6.5%
4.4%
3.2%
2009
2010
2011
2012
Load
Payments
$42,535.2
$53,101.5
$47,658.9
$37,471.4
Energy Costs (Millions)
Generation
Explicit Inadvertent
Credits
Costs
Charges
$43,165.7
$0.0
$1.7
$53,886.9
$0.0
($12.6)
$48,480.9
$0.0
$28.3
$38,073.5
$0.0
$9.1
Total
($628.8)
($797.9)
($793.7)
($593.0)
Energy costs for 2009 through 2012 are shown in Table
10‑6 and Table 10‑7. Table 10‑6 shows PJM energy
costs by category for 2009 through 2012 and Table 10‑7
shows PJM energy costs by market category for 2009
through 2012. These energy costs are the actual total
energy costs rather than the net energy costs in Table
10‑5.
Table 10‑7 Total PJM energy costs by market category
(Dollars (Millions)): 2009 through 2012
2009
2010
2011
2012
Load
Payments
$42,683.8
$53,164.9
$48,144.9
$37,641.2
Day Ahead
Generation
Explicit
Credits
Costs
$43,351.2
$0.0
$53,979.1
$0.0
$48,880.0
$0.0
$38,251.1
$0.0
Total
($667.4)
($814.1)
($735.2)
($609.9)
Energy Costs (Millions)
Balancing
Load Generation
Explicit
Payments
Credits
Costs
($148.5)
($185.5)
$0.0
($63.4)
($92.2)
$0.0
($485.9)
($399.1)
$0.0
($169.8)
($177.6)
$0.0
Total
$36.9
$28.8
($86.8)
$7.8
Inadvertent
Charges
$1.7
($12.6)
$28.3
$9.1
Grand
Total
($628.8)
($797.9)
($793.7)
($593.0)
Monthly Energy Costs
Table 10‑8 shows a monthly summary of energy costs
by type for 2011 and 2012.
Table 10‑8 Monthly energy costs by type (Dollars
(Millions)): 2011 and 2012
Energy Costs (Millions)
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total
Day-Ahead
Total
($90.3)
($61.1)
($52.4)
($49.9)
($54.8)
($82.1)
($110.0)
($66.9)
($55.0)
($42.7)
($30.2)
($39.7)
($735.2)
2011
Balancing
Inadvertent
Total
Charges
($5.2)
$2.1
($2.4)
$2.3
($5.4)
$2.4
($0.3)
$2.5
($0.2)
$2.9
($3.2)
$1.1
($16.8)
$6.7
($16.4)
$5.0
($5.5)
$1.5
($5.9)
$0.3
($14.6)
$0.8
($11.0)
$0.6
($86.8)
$28.3
Grand
Total
($93.3)
($61.2)
($55.4)
($47.7)
($52.1)
($84.2)
($120.1)
($78.2)
($59.0)
($48.3)
($44.0)
($50.1)
($793.7)
Day-Ahead
Total
($48.5)
($36.0)
($30.1)
($30.7)
($39.4)
($57.1)
($84.0)
($60.3)
($43.6)
($42.2)
($65.2)
($72.7)
($609.9)
2012
Balancing
Inadvertent
Total
Charges
($10.1)
$2.5
($9.9)
$2.4
($8.6)
$1.9
($2.8)
$0.7
$0.1
($0.3)
$4.0
$0.0
$3.0
$0.6
$2.6
$0.3
$1.1
($0.2)
$1.6
$0.2
$7.8
$1.1
$19.0
($0.1)
$7.8
$9.1
Grand
Total
($56.1)
($43.5)
($36.8)
($32.8)
($39.6)
($53.1)
($80.4)
($57.4)
($42.8)
($40.5)
($56.2)
($53.8)
($593.0)
19 The Energy Costs, Loss Costs and Congestion Costs include net inadvertent charges.
© 2013 Monitoring Analytics, LLC
2012 State of the Market Report for PJM 301
2012 State of the Market Report for PJM
Marginal Losses
Marginal Loss Accounting
PJM calculates marginal loss costs for each PJM member.
•Day-Ahead
Load Loss Payments. Day-ahead,
load loss payments are calculated for all cleared
demand, decrement bids and Day-Ahead Energy
Market sale transactions. Day-ahead, load loss
payments are calculated using MW and the load
bus loss component of LMP (MLMP), the decrement
bid MLMP or the MLMP at the source of the sale
transaction, as applicable.
•Day-Ahead
Generation Loss Credits. Day-ahead,
generation loss credits are calculated for all cleared
generation and increment offers and Day-Ahead
Energy Market purchase transactions. Day-ahead,
generation loss credits are calculated using MW
and the generator bus MLMP, the increment offer
MLMP or the MLMP at the sink of the purchase
transaction, as applicable.
•Balancing Load Loss Payments. Balancing, load loss
payments are calculated for all deviations between
a PJM member’s real-time load and energy sale
transactions and their day-ahead cleared demand,
decrement bids and energy sale transactions.
Balancing, load loss payments are calculated using
MW deviations and the real-time MLMP for each
bus where a deviation exists.
•Balancing
Generation Loss Credits. Balancing,
generation loss credits are calculated for all
deviations between a PJM member’s real-time
generation and energy purchase transactions and
the day-ahead cleared generation, increment offers
and energy purchase transactions. Balancing,
generation loss credits are calculated using MW
deviations and the real-time MLMP for each bus
where a deviation exists.
•Explicit Loss Costs. Explicit loss costs are the net
loss costs associated with point-to-point energy
transactions. These costs equal the product of the
transacted MW and MLMP differences between
sources (origins) and sinks (destinations) in the
Day-Ahead Energy Market. Balancing energy
market explicit loss costs equal the product of the
differences between the real-time and day-ahead
transacted MWs and the differences between the
real-time MLMP at the transactions’ sources and
sinks.
•Inadvertent Loss Charges. Inadvertent loss charges
are the net loss charges resulting from the
differences between the net actual energy flow and
the net scheduled energy flow into or out of the PJM
control area each hour. This inadvertent interchange
of energy may be positive or negative, where
positive interchange typically results in a charge
while negative interchange typically results in a
credit. Inadvertent loss charges are common costs,
not directly attributable to specific participants, that
are distributed on a load ratio basis.20
Total marginal loss costs, analogous to total congestion
costs, are equal to the net of the load loss payments
minus generation loss credits, plus explicit loss costs,
plus inadvertent loss charges, incurred in both the DayAhead Energy Market and the balancing energy market.
Total marginal loss costs can by more accurately thought
of as net marginal loss costs.
Marginal loss costs can be both positive and negative and
consequently load payments and generation credits can
also be both positive and negative. The loss component
of LMP is calculated with respect to the system marginal
price (SMP). An increase in generation at a bus that
results in an increase in losses will cause the marginal
loss component of that bus to be negative. If the increase
in generation at the bus results in a decrease of system
losses, then the marginal loss component is positive.
Monthly marginal loss costs in 2012 ranged from $51.0
million in April to $143.4 million in July.
Marginal loss credits decreased in 2012 by $200.0
million or 34.1 percent from 2011, from $586.8 million
to $386.7 million.
Total Marginal Loss Costs
Table 10‑9 shows the total marginal loss component
costs for 2009 through 2012. The yearly total loss
component costs appear low compared to total PJM
billing because these totals are actually net loss costs.
20 OA. Schedule 1 (PJM Interchange Energy Market) §3.7
302
Section 10 Congestion and Marginal Losses
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
Table 10‑9 Total PJM Marginal Loss Component Costs
(Dollars (Millions)): 2009 through 201221
2009
2010
2011
2012
Loss
Costs
$1,268
$1,635
$1,380
$982
Percent
Change
NA
29.0%
(15.6%)
(28.8%)
Total
PJM Billing
$26,550
$34,771
$35,887
$29,181
Percent of
PJM Billing
4.8%
4.7%
3.8%
3.4%
Total marginal loss costs for 2009 through 2012 are
shown in Table 10‑10 and Table 10‑11. Table 10‑10
shows PJM total marginal loss costs by category for 2009
through 2012. Table 10‑11 shows PJM total marginal
loss costs by market category for 2009 through 2012.
Table 10‑10 Total PJM marginal loss costs by category
(Dollars (Millions)): 2009 through 2012
2009
2010
2011
2012
Load
Payments
($78.4)
($122.3)
($174.0)
($11.1)
Marginal Loss Costs (Millions)
Generation
Explicit Inadvertent
Credits
Costs
Charges
($1,314.2)
$32.0
($0.0)
($1,707.0)
$50.2
($0.0)
($1,551.9)
$1.6
$0.0
($1,036.8)
($44.0)
$0.0
Monthly Marginal Loss Costs
Table 10‑12 shows a monthly summary of marginal loss
costs by type for 2011 and 2012.
Marginal Loss Costs and Loss Credits
Marginal loss credits (loss surplus) are calculated by
adding the total energy costs, the total marginal loss
costs and net residual market adjustments. The total
energy costs are equal to the net implicit energy costs
(load energy payments less generation energy credits)
plus net explicit energy costs plus net inadvertent
energy charges. Total marginal loss costs are equal to
the net implicit marginal loss costs (load loss payments
less generation loss credits) plus net explicit loss costs
plus net inadvertent loss charges.
Total
$1,267.7
$1,634.8
$1,379.6
$981.7
Table 10‑11 Total PJM marginal loss costs by market
category (Dollars (Millions)): 2009 through 2012
2009
2010
2011
2012
Load
Payments
($84.7)
($146.3)
($215.4)
($43.0)
Day Ahead
Generation
Explicit
Credits
Costs
($1,311.7)
$65.4
($1,716.1)
$95.8
($1,592.1)
$53.8
($1,060.3)
($13.4)
Marginal Loss Costs (Millions)
Balancing
Load Generation
Total
Payments
Credits
$1,292.3
$6.4
($2.5)
$1,665.6
$23.9
$9.1
$1,430.5
$41.4
$40.2
$1,003.8
$32.0
$23.4
Explicit
Costs
($33.5)
($45.6)
($52.2)
($30.6)
Total
($24.6)
($30.8)
($51.0)
($22.1)
Inadvertent
Charges
($0.0)
($0.0)
$0.0
$0.0
Grand
Total
$1,267.7
$1,634.8
$1,379.6
$981.7
Table 10‑12 Monthly marginal loss costs by type
(Dollars (Millions)): 2011 and 2012
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total
Day-Ahead
Total
$188.5
$121.8
$108.8
$84.8
$94.3
$129.9
$217.4
$137.9
$107.7
$85.7
$76.0
$77.8
$1,430.5
Marginal Loss Costs (Millions)
2011
Balancing
Inadvertent
Grand
Day-Ahead
Total
Charges
Total
Total
($2.9)
$0.0
$185.7
$100.6
($1.8)
$0.0
$119.9
$80.4
($4.8)
$0.0
$104.0
$67.1
($5.6)
$0.0
$79.2
$55.4
($7.0)
$0.0
$87.3
$69.6
($4.5)
$0.0
$125.4
$93.3
($3.7)
$0.0
$213.7
$141.8
($3.5)
$0.0
$134.5
$96.1
($4.7)
$0.0
$102.9
$71.7
($3.6)
$0.0
$82.0
$65.9
($1.7)
$0.0
$74.3
$83.0
($7.1)
$0.0
$70.6
$78.8
($51.0)
$0.0
$1,379.6
$1,003.8
2012
Balancing
Inadvertent
Total
Charges
($5.4)
$0.0
($3.1)
$0.0
($5.2)
$0.0
($4.4)
$0.0
($2.5)
($0.0)
($0.8)
$0.0
$1.6
$0.0
$2.4
$0.0
($0.9)
($0.0)
($1.7)
$0.0
($0.6)
$0.0
($1.3)
$0.0
($22.1)
$0.0
Grand
Total
$95.2
$77.2
$61.9
$51.0
$67.1
$92.5
$143.4
$98.5
$70.8
$64.1
$82.5
$77.5
$981.7
21 Calculated values shown in Section 10, “Congestion and Marginal Losses,” are based on
unrounded, underlying data and may differ from calculations based on the rounded values in the
tables.
© 2013 Monitoring Analytics, LLC
2012 State of the Market Report for PJM 303
2012 State of the Market Report for PJM
Ignoring interchange, total generation MWh must be
greater than total load MWh in any hour in order to
provide for losses. Since the hourly integrated energy
component of LMP is the same for every bus within
every hour, the net energy bill is negative (ignoring net
interchange), with more generation credits than load
payments in every hour. Total energy costs plus total
marginal loss costs plus net residual market adjustments
equal marginal loss credits which are distributed to load
and exports as marginal loss credits.
Table 10‑13 shows the total energy costs, the total
marginal loss costs collected, the net residual market
adjustments and total marginal loss credits redistributed
for 2009 through 2012.
Table 10‑13 Marginal loss credits (Dollars (Millions)):
2009 through 201222
2009
2010
2011
2012
Loss Credit Accounting (Millions)
Total Total Marginal
Net Residual
Energy Costs
Loss Costs
Adjustments
($628.8)
$1,267.7
$0.8
($797.9)
$1,634.8
($0.5)
($793.7)
$1,379.6
$0.9
($593.0)
$981.7
($2.0)
Loss Credits
$639.7
$836.4
$586.8
$386.7
Congestion
Congestion Accounting
Transmission congestion occurs in the Day-Ahead and
Real-Time Energy Market.23 Total congestion costs
are equal to the net implicit congestion costs plus net
explicit congestion costs plus net inadvertent congestion
charges, incurred in both the Day-Ahead Energy Market
and the balancing energy market.
In the analysis of total congestion costs, load congestion
payments are netted against generation congestion
credits on an hourly basis, by billing organization, and
then summed for the given period.24
Load Congestion Payments and Generation Congestion
Credits are calculated for both the Day-Ahead and
Balancing Energy Markets.
22 The net residual market adjustments included in the table are comprised of the known day-ahead
error value minus the sum of the day-ahead loss MW congestion value, balancing loss MW
congestion value and measurement error caused by missing data.
23 When the term congestion charges is used in documents by PJM’s Market Settlement Operations,
it has the same meaning as the term congestion costs as used here.
24 This analysis does not treat affiliated billing organizations as a single organization. Thus, the
generation congestion credits from one organization will not offset the load payments of its
affiliate. This may overstate or understate the actual load payments or generation credits of an
organization’s parent company.
304
Section 10 Congestion and Marginal Losses
•Day-Ahead Load Congestion Payments. Day-ahead
load congestion payments are calculated for all
cleared demand, decrement bids and Day-Ahead
Energy Market sale transactions. Day-ahead load
congestion payments are calculated using MW and
the load bus CLMP, the decrement bid CLMP or
the CLMP at the source of the sale transaction, as
applicable.
•Day-Ahead
Generation Congestion Credits. Dayahead generation congestion credits are calculated
for all cleared generation, increment offers and
Day-Ahead Energy Market purchase transactions.
Day-ahead generation congestion credits are
calculated using MW and the generator bus CLMP,
the increment offer’s CLMP or the CLMP at the sink
of the purchase transaction, as applicable.
•Balancing
Load Congestion Payments. Balancing
load congestion payments are calculated for all
deviations between a PJM member’s real-time load
and energy sale transactions and their day-ahead
cleared demand, decrement bids and energy sale
transactions. Balancing load congestion payments
are calculated using MW deviations and the realtime CLMP for each bus where a deviation exists.
•Balancing Generation Congestion Credits. Balancing
generation congestion credits are calculated for
all deviations between a PJM member’s real-time
generation and energy purchase transactions
and the day-ahead cleared generation, increment
offers and energy purchase transactions. Balancing
generation congestion credits are calculated using
MW deviations and the real-time CLMP for each
bus where a deviation exists.
•Explicit Congestion Costs. Explicit congestion costs
are the net congestion costs associated with pointto-point energy transactions. These costs equal the
product of the transacted MW and CLMP differences
between sources (origins) and sinks (destinations) in
the Day-Ahead Energy Market. Balancing energy
market explicit congestion costs equal the product
of the deviations between the real-time and dayahead transacted MWs and the differences between
the real- time CLMP at the transactions’ sources and
sinks.
•Inadvertent
Congestion Charges. Inadvertent
congestion charges are congestion charges resulting
from the differences between the net actual energy
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
flow and the net scheduled energy flow into or out
of the PJM control area each hour. This inadvertent
interchange of energy may be positive or negative,
where positive interchange typically results in a
charge while negative interchange typically results
in a credit. Inadvertent congestion charges are
common costs, not directly attributable to specific
participants, that are distributed on a load ratio
basis.25
The congestion costs associated with specific constraints
are the sum of the total day-ahead and balancing
congestion costs associated with those constraints.
The congestion costs in each zone are the sum of the
congestion costs associated with each constraint that
affects prices in the zone. The network nature of the
transmission system means that congestion costs in a
zone are frequently the result of constrained facilities
located outside that zone.
Congestion costs can be both positive and negative and
consequently load payments and generation credits can
be both positive and negative. The CLMP is calculated
with respect to the system reference bus LMP, also called
the system marginal price (SMP). When a transmission
constraint occurs, the resulting CLMP is positive on
one side of the constraint and negative on the other
side of the constraint and the corresponding congestion
costs are positive or negative. For each transmission
constraint, the CLMP reflects the cost of a constraint
at a pricing node and is equal to the product of the
constraint shadow price and the distribution factor at
the respective pricing node. The total CLMP at a pricing
node is the sum of all constraint contributions to LMP
and is equal to the difference between the actual LMP
that results from transmission constraints, excluding
losses, and the SMP. If an area experiences lower
prices because of a constraint, the CLMP in that area is
negative.26
The congestion metric requires careful review when
considering the significance of congestion. The net
congestion bill is calculated by subtracting generating
congestion credits from load congestion payments.
The logic is that congestion payments by load are
offset by congestion revenues to generation, for the
25 OA. Schedule 1 (PJM Interchange Energy Market) §3.7
26 For an example of the congestion accounting methods used in this section, see MMU Technical
Reference for PJM Markets, at “FTRs and ARRs.”
© 2013 Monitoring Analytics, LLC
area analyzed. Whether the net congestion bill is an
appropriate measure of congestion for load depends
on who pays the load congestion payments and who
receives the generation congestion credits. The net
congestion bill is an appropriate measure of congestion
for a utility that charges load congestion payments to
load and credits generation congestion credits to load.
The net congestion bill is not an appropriate measure
of congestion in situations where load pays the load
congestion payments but does not receive the generation
credits as an offset.
Net congestion, which includes both load congestion
payments and generation congestion credits, is not
a good measure of the congestion costs paid by load
from the perspective of the wholesale market.27 While
total congestion costs represent the overall charge or
credit to a zone, the components of congestion costs
measure the extent to which load or generation bear
total congestion costs. Load congestion payments, when
positive, measure the total congestion cost to load in
an area. Load congestion payments, when negative,
measure the total congestion credit to load in an area.
Negative load congestion payments result when load is
on the lower priced side of a constraint or constraints.
For example, congestion across the AP South interface
means lower prices in western control zones and higher
prices in eastern and southern control zones. Load in
western control zones will benefit from lower prices and
receive a congestion credit (negative load congestion
payment). Load in the eastern and southern control
zones will incur a congestion charge (positive load
congestion payment). The reverse is true for generation
congestion credits. Generation congestion credits,
when positive, measure the total congestion credit to
generation in an area. Generation congestion credits,
when negative, measure the total congestion cost to
generation in an area. Negative generation congestion
credits are a cost in the sense that revenues to generators
in the area are lower, by the amount of the congestion
cost, than they would have been if they had been paid
LMP without a congestion component, the total of
system marginal price and the loss component. Negative
generation congestion credits result when generation is
on the lower priced side of a constraint or constraints.
For example, congestion across the AP South interface
27 The actual congestion payments by retail customers are a function of retail ratemaking policies
and may or may not reflect an offset for congestion credits.
2012 State of the Market Report for PJM 305
2012 State of the Market Report for PJM
means lower prices in the western control zones and
higher prices in the eastern and southern control zones.
Generation in the western control zones will receive
lower prices and incur a congestion charge (negative
generation congestion credit). Generation in the eastern
and southern control zones will receive higher prices
and receive a congestion credit (positive generation
congestion credit).
As an example, total congestion costs in PJM 2012 were
$529.0 million, which was comprised of load congestion
payments of $138.5 million, generation credits of
-$444.0 million and explicit congestion of -$53.5
million (Table 10‑15).
Total congestion costs in Table 10‑15 include congestion
costs associated with PJM facilities and those associated
with reciprocal, coordinated flowgates in the MISO.29
Table 10‑16 shows the 2012 congestion costs by category.
The 2012 PJM total congestion costs were comprised of
$138.5 million in load congestion payments, -$444.0
million in generation congestion credits, and -$53.5
million in explicit congestion costs.
Table 10‑15 Total PJM congestion costs by category
(Dollars (Millions)): 2011 to 2012
2011
2012
Total Congestion
Load
Payments
$112.2
$138.5
Congestion Costs (Millions)
Generation
Explicit Inadvertent
Credits
Costs
Charges
($1,009.9)
($123.1)
$0.0
($444.0)
($53.5)
$0.0
Total
$999.0
$529.0
Table 10‑14 shows total congestion for 2008 to 2012.28
Table 10‑14 Total PJM congestion (Dollars (Millions)):
2008 to 2012
Congestion Costs (Millions)
Congestion
Total PJM Percent of PJM
Cost Percent Change
Billing
Billing
$2,051.8
NA
$34,306.0
6.0%
$719.0
(65.0%)
$26,550.0
2.7%
$1,423.3
98.0%
$34,771.0
4.1%
$999.0
(29.8%)
$35,887.0
2.8%
$529.0
(47.0%)
$29,181.0
1.8%
2008
2009
2010
2011
2012
Figure 10‑1 shows PJM monthly congestion for 2008
through 2012.
Figure 10‑1 PJM monthly congestion (Dollars
(Millions)): 2008 to 2012
$400
2008
2009
$350
2010
2011
2012
Congestion (Millions)
$300
$250
$200
$150
$100
$50
$0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
28 Congestion charges for 2010 reflect an updated calculation compared to the results in the 2010
State of the Market Report for PJM.
306
Section 10 Congestion and Marginal Losses
29 See “Joint Operating Agreement Between the Midwest Independent Transmission System
Operator, Inc. and PJM Interconnection, L.L.C.” (December 11, 2008) Section 6.1 <http://pjm.com/
documents/agreements/~/media/documents/agreements/joa-complete.ashx> (Accessed March 13,
2012).
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
Table 10‑16 Total PJM congestion costs by market category (Dollars (Millions)): 2011 to 2012
2011
2012
Load
Payments
$36.2
$135.5
Day Ahead
Generation
Explicit
Credits
Costs
($1,141.8)
$66.9
($512.5)
$131.9
Congestion Costs (Millions)
Balancing
Load Generation
Explicit
Total
Payments
Credits
Costs
$1,245.0
$75.9
$131.9
($190.0)
$779.9
$3.0
$68.5
($185.4)
Total
($246.0)
($250.9)
Inadvertent
Charges
$0.0
$0.0
Grand
Total
$999.0
$529.0
Monthly Congestion
Table 10‑17 shows that during 2012, monthly congestion costs ranged from $24.9 million to $73.1 million. Table
10‑18 shows the congestion costs during 2011. Monthly congestion costs in 2012 were lower than in 2011.
Table 10‑17 Monthly PJM congestion costs (Dollars (Millions)): 2012
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total
Load
Payments
$4.0
$9.1
$10.4
$11.7
$13.4
$14.0
$13.9
$23.9
$12.8
$2.6
$10.3
$9.5
$135.5
Day Ahead
Generation
Explicit
Credits
Costs
($53.1)
$9.3
($38.3)
$7.4
($38.5)
$10.9
($43.7)
$16.5
($37.2)
$16.7
($50.9)
$4.7
($67.6)
$9.5
($30.0)
$6.9
($44.0)
$4.9
($38.1)
$13.7
($40.5)
$15.7
($30.5)
$15.8
($512.5)
$131.9
Total
$66.3
$54.8
$59.8
$72.0
$67.2
$69.6
$91.0
$60.8
$61.8
$54.4
$66.4
$55.8
$779.9
Congestion Costs (Millions)
Balancing
Load Generation
Explicit
Payments
Credits
Costs
$1.0
$5.7
($15.4)
($3.7)
$2.7
($12.8)
($1.6)
$3.7
($13.8)
($3.2)
$5.2
($28.7)
$0.5
($2.6)
($21.2)
$5.4
$8.3
($9.8)
$3.3
$7.3
($13.9)
$5.9
$6.9
($9.6)
($3.9)
$6.9
($12.3)
($3.1)
$7.8
($18.7)
$2.1
$9.3
($12.7)
$0.3
$7.3
($16.4)
$3.0
$68.5
($185.4)
Total
($20.0)
($19.2)
($19.1)
($37.1)
($18.2)
($12.7)
($17.9)
($10.6)
($23.1)
($29.6)
($19.9)
($23.4)
($250.9)
Inadvertent
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
Grand
Total
$46.3
$35.5
$40.7
$34.9
$49.1
$56.8
$73.1
$50.2
$38.7
$24.9
$46.5
$32.4
$529.0
Total
($14.8)
($18.0)
($14.6)
($28.8)
($29.3)
($26.4)
($20.6)
($11.9)
($23.9)
($19.4)
($19.2)
($19.1)
($246.0)
Inadvertent
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
Grand
Total
$241.6
$74.5
$43.9
$39.2
$35.0
$135.9
$173.8
$63.1
$67.9
$38.6
$38.1
$47.4
$999.0
Table 10‑18 Monthly PJM congestion costs (Dollars (Millions)): 2011
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total
Load
Payments
$27.0
$14.0
($2.5)
$5.0
$14.3
$1.8
$3.8
$4.7
$0.0
($8.7)
($12.6)
($10.6)
$36.2
Day Ahead
Generation
Explicit
Credits
Costs
($228.4)
$0.9
($77.5)
$1.0
($58.8)
$2.2
($56.5)
$6.6
($41.5)
$8.6
($154.0)
$6.4
($184.1)
$6.5
($63.7)
$6.6
($84.9)
$6.9
($59.7)
$6.9
($64.6)
$5.3
($68.1)
$9.0
($1,141.8)
$66.9
Total
$256.4
$92.5
$58.4
$68.0
$64.3
$162.3
$194.4
$75.0
$91.9
$58.0
$57.3
$66.5
$1,245.0
Congestion Costs (Millions)
Balancing
Load Generation
Explicit
Payments
Credits
Costs
$21.1
$15.6
($20.3)
$5.6
$12.8
($10.9)
$0.2
$4.7
($10.0)
$1.4
$6.4
($23.7)
$3.0
$7.4
($24.9)
$13.1
$22.4
($17.1)
$21.2
$21.6
($20.2)
($0.4)
$1.8
($9.7)
$8.8
$21.2
($11.5)
$2.1
$6.2
($15.2)
($0.6)
$6.8
($11.8)
$0.5
$5.0
($14.6)
$75.9
$131.9
($190.0)
Congested Facilities
A congestion event exists when a unit or units must be dispatched out of merit order to control the impact of a
contingency on a monitored facility or to control an actual overload. A congestion-event hour exists when a specific
facility is constrained for one or more five-minute intervals within an hour. A congestion-event hour differs from
a constrained hour, which is any hour during which one or more facilities are congested. Thus, if two facilities are
constrained during an hour, the result is two congestion-event hours and one constrained hour. Constraints are
often simultaneous, so the number of congestion-event hours likely exceeds the number of constrained hours and
© 2013 Monitoring Analytics, LLC
2012 State of the Market Report for PJM 307
2012 State of the Market Report for PJM
the number of congestion-event hours likely exceeds the
number of hours within a year.
In order to have a consistent metric for real-time and
day-ahead congestion frequency, real-time congestion
frequency is measured using the convention that an
hour is constrained if any of its component five-minute
intervals is constrained. This is also consistent with the
way in which PJM reports real-time congestion. In 2012,
there were 249,572 day-ahead, congestion-event hours
compared to 155,670 day-ahead, congestion-event
hours in 2011. In 2012, there were 20,917 real-time,
congestion-event hours compared to 22,513 real-time,
congestion-event hours in 2011.
During 2012, for only 3.2 percent of Day-Ahead Market
facility constrained hours were the same facilities also
constrained in the Real-Time Market. During 2012, for
38.3 percent of Real-Time Market facility constrained
hours, the same facilities were also constrained in the
Day-Ahead Market.
The AP South interface was the largest contributor
to congestion costs in 2012. With $68.5 million in
total congestion costs, it accounted for 16.1 percent
of the total PJM congestion costs in 2012. The top
five constraints in terms of congestion costs together
contributed $177.0 million, or 41.6 percent, of the total
PJM congestion costs in 2012. The top five constraints
were the AP South interface, Graceton – Raphael Road
transmission line, Woodstock flowgate, Bedington Black Oak interface and West interface.
reciprocally coordinated flowgates between PJM and
MISO and transformers and decreased on PJM interfaces
and transmission lines in 2012 compared to 2011.
Table 10‑19 provides congestion-event hour subtotals
and congestion cost subtotals comparing the 2012
results by facility type: line, transformer, interface,
flowgate and unclassified facilities.30,31 For comparison,
this information is presented in Table 10‑20 for 2011.32
Table 10‑21 and Table 10‑22 compare day-ahead and
real-time congestion event hours. Among the hours for
which a facility is constrained in the Day-Ahead Market,
the number of hours during which the facility is also
constrained in the Real-Time Market are presented in
Table 10‑21. In 2012, there were 249,572 congestion
event hours in the Day-Ahead Market. Among those,
only 8,098 (3.2 percent) were also constrained in the
Real-Time Market. In 2011, among the 155,670 dayahead congestion event hours, only 8,976 (5.8 percent)
were binding in the Real-Time Market.33
Among the hours for which a facility is constrained
in the Real-Time Market, the number of hours during
which the facility is also constrained in the Day-Ahead
Market are presented in Table 10‑22. In 2012, there were
20,917 congestion event hours in the Real-Time Market.
Among these, 8,011 (38.3 percent) were also constrained
in the Day-Ahead Market. In 2011, among the 22,513
real-time congestion event hours, only 8,885 (39.5
percent) were binding in the day-ahead.
Congestion by Facility Type and Voltage
In 2012, compared to 2011, day-ahead, congestionevent hours increased on the reciprocally coordinated
flowgates between PJM and MISO, transmission lines
and transformers while congestion frequency on internal
PJM interfaces decreased. Real-time, congestionevent hours increased on the reciprocally coordinated
flowgates between PJM and the MISO and transmission
lines, while congestion frequency on interfaces and
transformers decreased.
Day-ahead congestion costs increased on the reciprocally
coordinated flowgates between PJM and MISO in 2012
compared to 2011 and decreased on PJM interfaces,
transmission lines and transformers in 2012 compared
to 2011. Balancing congestion costs increased on the
308
Section 10 Congestion and Marginal Losses
30 Unclassified are congestion costs related to non-transmission facility constraints in the DayAhead Market and any unaccounted for difference between PJM billed congestion charges and
calculated congestion costs including rounding errors. Non-transmission facility constraints
include Day-Ahead Market only constraints such as constraints on virtual transactions and
constraints associated with phase-angle regulators.
31 The term flowgate refers to MISO flowgates in this section.
32 For 2008 and 2009, the load congestion payments and generation congestion credits represent
the net load congestion payments and net generation congestion credits for an organization, as
this shows the extent to which each organization’s load or generation was exposed to congestion
costs.
33 Constraints are mapped to transmission facilities. In the Day-Ahead Market, within a given hour,
a single facility may be associated with multiple constraints. In such situations, the same facility
accounts for more than one constraint-hour for a given hour in the Day-Ahead Market. Similarly
in the Real-Time Market a facility may account for more than one constraint-hour within a given
hour.
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
Table 10‑19 Congestion summary (By facility type): 2012
Congestion Costs (Millions)
Type
Flowgate
Interface
Line
Other
Transformer
Unclassified
Total
Load
Payments
($60.3)
$70.8
$78.0
$9.7
$31.1
$6.2
$135.5
Day Ahead
Generation
Explicit
Credits
Costs
($190.2)
$39.4
($68.8)
$2.9
($193.3)
$63.2
($4.3)
$2.0
($54.8)
$22.7
($1.2)
$1.7
($512.5)
$131.9
Total
$169.3
$142.5
$334.6
$16.0
$108.5
$9.1
$779.9
Load
Payments
($5.9)
$14.6
($9.0)
($0.6)
$4.4
($0.5)
$3.0
Balancing
Generation
Explicit
Credits
Costs
$10.5
($81.5)
$21.6
($3.6)
$31.4
($82.8)
$0.0
($0.9)
$3.8
($15.5)
$1.2
($1.2)
$68.5
($185.4)
Total
($97.9)
($10.6)
($123.2)
($1.6)
($14.9)
($2.8)
($250.9)
Grand
Total
$71.4
$131.9
$211.3
$14.4
$93.6
$6.3
$529.0
Event Hours
Day
Real
Ahead
Time
29,500
7,772
7,005
737
144,670
10,151
8,007
433
60,390
1,824
NA
NA
249,572
20,917
Table 10‑20 Congestion summary (By facility type): 2011
Congestion Costs (Millions)
Type
Flowgate
Interface
Line
Other
Transformer
Unclassified
Total
Load
Payments
($109.0)
$64.0
$45.6
($0.5)
$35.1
$1.1
$36.2
Day Ahead
Generation
Explicit
Credits
Costs
($212.8)
$11.0
($395.3)
($10.7)
($346.3)
$39.5
($4.7)
$0.1
($181.2)
$21.5
($1.5)
$5.4
($1,141.8)
$66.9
Total
$114.8
$448.7
$431.3
$4.3
$237.8
$8.0
$1,245.0
Load
Payments
$8.4
$37.7
$23.2
$2.2
$3.3
$1.2
$75.9
Balancing
Generation
Explicit
Credits
Costs
$22.9
($88.5)
$38.3
$7.1
$51.2
($67.1)
$4.6
($0.4)
$14.5
($39.7)
$0.3
($1.4)
$131.9
($190.0)
Total
($103.0)
$6.4
($95.1)
($2.8)
($50.9)
($0.5)
($246.0)
Grand
Total
$11.8
$455.1
$336.2
$1.5
$186.9
$7.5
$999.0
Event Hours
Day
Real
Ahead
Time
23,179
7,423
9,013
1,803
89,956
9,259
1,042
248
32,480
3,780
NA
NA
155,670
22,513
Table 10‑21 Congestion Event Hours (Day Ahead against Real Time): Calendar years 2011 to 2012
Congestion Event Hours
Type
Flowgate
Interface
Line
Other
Transformer
Total
Day Ahead
Constrained
29,500
7,005
144,670
8,007
60,390
249,572
2012
Corresponding Real
Time Constrained
3,239
369
3,496
265
729
8,098
Percent
11.0%
5.3%
2.4%
3.3%
1.2%
3.2%
2011
Day Ahead Corresponding Real
Constrained
Time Constrained
23,179
2,917
9,013
1,144
89,956
3,211
1,042
67
32,480
1,637
155,670
8,976
Percent
12.6%
12.7%
3.6%
6.4%
5.0%
5.8%
Table 10‑22 Congestion Event Hours (Real Time against Day Ahead): 2011 to 2012
Congestion Event Hours
Type
Flowgate
Interface
Line
Other
Transformer
Total
Real Time
Constrained
7,772
737
10,151
433
1,824
20,917
© 2013 Monitoring Analytics, LLC
2012
Corresponding Day
Ahead Constrained
3,320
395
3,382
229
685
8,011
Percent
42.7%
53.6%
33.3%
52.9%
37.6%
38.3%
Real Time
Constrained
7,423
1,803
9,259
248
3,780
22,513
2011
Corresponding Day
Ahead Constrained
2,922
1,143
3,150
63
1,607
8,885
Percent
39.4%
63.4%
34.0%
25.4%
42.5%
39.5%
2012 State of the Market Report for PJM 309
2012 State of the Market Report for PJM
Table 10‑23 shows congestion costs by facility voltage class for 2012. In comparison to 2011 (shown in Table 10‑24),
congestion costs decreased across 765kV, 500kV, 345kV and 230kV in 2012.
Table 10‑23 Congestion summary (By facility voltage): 2012
Congestion Costs (Millions)
Voltage (kV)
765
500
345
230
161
138
115
69
34
12
Unclassified
Total
Load
Payments
($0.2)
$75.3
($41.6)
$67.2
($14.3)
($9.1)
$24.1
$28.0
$0.0
($0.0)
$6.2
$135.5
Day Ahead
Generation
Explicit
Credits
Costs
($3.4)
$3.2
($79.3)
$5.2
($135.1)
$23.7
($72.4)
$19.8
($23.3)
$3.8
($202.1)
$69.7
($1.5)
$3.6
$5.9
$1.1
($0.0)
$0.0
($0.0)
$0.0
($1.2)
$1.7
($512.5)
$131.9
Total
$6.5
$159.9
$117.2
$159.3
$12.7
$262.7
$29.2
$23.1
$0.1
$0.0
$9.1
$779.9
Load
Payments
$0.2
$19.7
$1.6
$4.8
($1.5)
($9.0)
($0.5)
($11.8)
($0.0)
$0.0
($0.5)
$3.0
Balancing
Generation
Explicit
Credits
Costs
($0.1)
($0.1)
$25.8
($8.4)
$7.8
($35.7)
$11.0
($38.7)
$1.9
($10.2)
$15.5
($89.6)
$2.1
($1.4)
$3.3
($0.1)
$0.0
$0.0
$0.0
$0.0
$1.2
($1.2)
$68.5
($185.4)
Total
$0.1
($14.6)
($41.9)
($44.9)
($13.6)
($114.1)
($4.0)
($15.3)
$0.0
$0.0
($2.8)
($250.9)
Grand
Total
$6.6
$145.3
$75.3
$114.5
($0.9)
$148.7
$25.2
$7.9
$0.1
$0.0
$6.3
$529.0
Event Hours
Day
Real
Ahead
Time
3,412
89
12,025
1,129
34,050
3,623
35,443
4,052
3,622
1,407
130,390
8,661
18,614
901
10,531
1,053
1,470
2
15
0
NA
NA
249,572
20,917
Grand
Total
$10.6
$545.1
$95.8
$149.9
($14.7)
$160.3
$31.8
$12.7
$0.0
$0.0
$0.0
$0.0
$7.5
$999.0
Event Hours
Day
Real
Ahead
Time
1,109
183
17,936
3,691
29,923
4,559
23,752
3,540
1,760
1,152
60,087
7,691
12,193
1,109
8,872
583
11
0
2
5
7
0
18
0
9,999
9,999
155,670
22,513
Table 10‑24 Congestion summary (By facility voltage): 2011
Congestion Costs (Millions)
Voltage (kV)
765
500
345
230
161
138
115
69
35
34
14
12
Unclassified
Total
310
Load
Payments
$0.8
$100.0
($98.5)
$1.7
($13.6)
$21.2
$7.4
$16.1
$0.1
$0.0
$0.0
($0.0)
$1.1
$36.2
Day Ahead
Generation
Explicit
Credits
Costs
($9.3)
$2.3
($466.5)
($5.4)
($264.2)
$15.6
($175.8)
$12.5
($22.0)
$6.3
($173.7)
$26.1
($27.8)
$4.2
($1.1)
($0.1)
$0.0
$0.0
($0.0)
$0.0
($0.0)
$0.0
($0.0)
$0.0
($1.5)
$5.4
($1,141.8)
$66.9
Section 10 Congestion and Marginal Losses
Total
$12.4
$561.0
$181.2
$190.1
$14.6
$221.0
$39.5
$17.1
$0.0
$0.0
$0.0
$0.0
$8.0
$1,245.0
Load
Payments
$2.9
$42.4
$10.3
$18.3
($2.5)
$4.4
$1.1
($2.2)
$0.0
$0.0
$0.0
$0.0
$1.2
$75.9
Balancing
Generation
Explicit
Credits
Costs
$2.1
($2.6)
$47.2
($11.1)
$26.3
($69.4)
$21.4
($37.1)
$6.0
($20.8)
$19.0
($46.1)
$7.3
($1.5)
$2.2
$0.1
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.3
($1.4)
$131.9
($190.0)
Total
($1.8)
($15.9)
($85.5)
($40.2)
($29.3)
($60.7)
($7.7)
($4.4)
$0.0
$0.0
$0.0
$0.0
($0.5)
($246.0)
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
Constraint Duration
Table 10‑25 lists constraints in 2011 to 2012 that were most frequently in effect and Table 10‑26 shows the constraints
which experienced the largest change in congestion-event hours from 2011 to 2012.
Table 10‑25 Top 25 constraints with frequent occurrence: 2011 to 2012
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Constraint
Sporn
Oak Grove - Galesburg
Linden - VFT
Kammer
Huntingdon - Huntingdon1
Graceton - Raphael Road
Monticello - East Winamac
Breed - Wheatland
Taylor - Grenshaw
Bayway - Federal Square
Big Sandy - Grangston
AP South
Nelson - Cordova
Crete - St Johns Tap
Devon - Skokie
Bellefonte - Grangston
Prairie State - W Mt. Vernon
Howard - Shelby
Cumberland - Bush
Rantoul - Rantoul Jct
Danville - East Danville
Rockwell - Crosby
Conesville
AEP - DOM
Diversey - Clybourn
Type
Transformer
Flowgate
Line
Transformer
Line
Line
Flowgate
Flowgate
Line
Line
Line
Interface
Line
Flowgate
Line
Line
Flowgate
Line
Flowgate
Flowgate
Line
Line
Transformer
Interface
Line
Event Hours
Day Ahead
Real Time
2011
2012 Change
2011
2012 Change
972 18,619 17,647
0
0
0
1,760
3,622
1,862
1,145
1,359
214
2,616
3,847
1,231
0
0
0
1,289
3,440
2,151
69
19
(50)
558
3,421
2,863
0
0
0
1,162
2,664
1,502
415
723
308
823
2,734
1,911
241
578
337
0
2,821
2,821
215
428
213
0
3,088
3,088
0
0
0
1,146
3,034
1,888
15
48
33
740
3,066
2,326
0
0
0
4,120
2,586 (1,534)
1,013
351
(662)
606
2,643
2,037
105
288
183
3,378
2,377 (1,001)
1,120
277
(843)
0
2,627
2,627
0
0
0
50
2,603
2,553
0
0
0
234
1,483
1,249
149
1,011
862
554
2,460
1,906
0
0
0
1,612
2,053
441
215
316
101
553
2,036
1,483
188
315
127
4,632
2,234 (2,398)
323
14
(309)
571
2,212
1,641
0
0
0
1,250
2,195
945
0
0
0
1,789
2,095
306
185
61
(124)
237
2,107
1,870
2
0
(2)
Percent of Annual Hours
Day Ahead
Real Time
2011
2012 Change
2011
2012 Change
11%
212%
201%
0%
0%
0%
20%
41%
21%
13%
15%
2%
30%
44%
14%
0%
0%
0%
15%
39%
24%
1%
0%
(1%)
6%
39%
33%
0%
0%
0%
13%
30%
17%
5%
8%
3%
9%
31%
22%
3%
7%
4%
0%
32%
32%
2%
5%
2%
0%
35%
35%
0%
0%
0%
13%
35%
21%
0%
1%
0%
8%
35%
26%
0%
0%
0%
47%
29% (18%)
12%
4%
(8%)
7%
30%
23%
1%
3%
2%
39%
27% (12%)
13%
3%
(10%)
0%
30%
30%
0%
0%
0%
1%
30%
29%
0%
0%
0%
3%
17%
14%
2%
12%
10%
6%
28%
22%
0%
0%
0%
18%
23%
5%
2%
4%
1%
6%
23%
17%
2%
4%
1%
53%
25% (27%)
4%
0%
(4%)
7%
25%
19%
0%
0%
0%
14%
25%
11%
0%
0%
0%
20%
24%
3%
2%
1%
(1%)
3%
24%
21%
0%
0%
(0%)
Table 10‑26 Top 25 constraints with largest year-to-year change in occurrence: 2011 to 2012
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Constraint
Sporn
South Mahwah - Waldwick
Taylor - Grenshaw
Belmont
Breed - Wheatland
Huntingdon - Huntingdon1
Danville - East Danville
Michigan City - Laporte
Devon - Skokie
Bellefonte - Grangston
Electric Jct - Nelson
Big Sandy - Grangston
Fairview
Monticello - East Winamac
Nelson - Cordova
AP South
Cox’s Corner - Marlton
Prairie State - W Mt. Vernon
Kammer
Pinehill - Stratford
Oak Grove - Galesburg
Bunsonville - Eugene
Emilie - Falls
Bayway - Federal Square
Tanners Creek
© 2013 Monitoring Analytics, LLC
Type
Transformer
Line
Line
Transformer
Flowgate
Line
Line
Flowgate
Line
Line
Line
Line
Transformer
Flowgate
Line
Interface
Line
Flowgate
Transformer
Line
Flowgate
Flowgate
Line
Line
Transformer
Event Hours
Day Ahead
Real Time
2011
2012 Change
2011
2012 Change
972 18,619 17,647
0
0
0
5,269
210 (5,059)
494
0
(494)
0
3,088
3,088
0
0
0
4,371
1,737 (2,634)
497
60
(437)
0
2,821
2,821
215
428
213
558
3,421
2,863
0
0
0
4,632
2,234 (2,398)
323
14
(309)
2,935
873 (2,062)
632
40
(592)
0
2,627
2,627
0
0
0
50
2,603
2,553
0
0
0
2,943
636 (2,307)
158
5
(153)
740
3,066
2,326
0
0
0
2,288
0 (2,288)
0
0
0
823
2,734
1,911
241
578
337
606
2,643
2,037
105
288
183
4,120
2,586 (1,534)
1,013
351
(662)
2,625
468 (2,157)
0
0
0
234
1,483
1,249
149
1,011
862
1,289
3,440
2,151
69
19
(50)
2,367
288 (2,079)
0
0
0
1,760
3,622
1,862
1,145
1,359
214
2,444
236 (2,208)
11
148
137
2,938
902 (2,036)
11
1
(10)
1,146
3,034
1,888
15
48
33
0
1,911
1,911
0
0
0
Percent of Annual Hours
Day Ahead
Real Time
2011
2012 Change
2011
2012 Change
11%
212%
201%
0%
0%
0%
60%
2% (58%)
6%
0%
(6%)
0%
35%
35%
0%
0%
0%
50%
20% (30%)
6%
1%
(5%)
0%
32%
32%
2%
5%
2%
6%
39%
33%
0%
0%
0%
53%
25% (27%)
4%
0%
(4%)
34%
10% (24%)
7%
0%
(7%)
0%
30%
30%
0%
0%
0%
1%
30%
29%
0%
0%
0%
34%
7% (26%)
2%
0%
(2%)
8%
35%
26%
0%
0%
0%
26%
0% (26%)
0%
0%
0%
9%
31%
22%
3%
7%
4%
7%
30%
23%
1%
3%
2%
47%
29% (18%)
12%
4%
(8%)
30%
5% (25%)
0%
0%
0%
3%
17%
14%
2%
12%
10%
15%
39%
24%
1%
0%
(1%)
27%
3% (24%)
0%
0%
0%
20%
41%
21%
13%
15%
2%
28%
3% (25%)
0%
2%
2%
34%
10% (23%)
0%
0%
(0%)
13%
35%
21%
0%
1%
0%
0%
22%
22%
0%
0%
0%
2012 State of the Market Report for PJM 311
2012 State of the Market Report for PJM
Constraint Costs
Table 10‑27 and Table 10‑28 present the top constraints affecting congestion costs by facility for 2012 through 2011.
Table 10‑27 Top 25 constraints affecting PJM congestion costs (By facility): 2012
Congestion Costs (Millions)
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
312
Constraint
AP South
Graceton - Raphael Road
Woodstock
West
Bedington - Black Oak
Clover
Belvidere - Woodstock
Monticello - East Winamac
Nelson - Cordova
Loudoun - Gainsville
AEP - DOM
Northwest
Rantoul - Rantoul Jct
Hunterstown
Crete - St Johns Tap
Pleasant Valley - Belvidere
Prairie State - W Mt. Vernon
Kammer
Sporn
Harwood - Susquehanna
Unclassified
Leonia - New Milford
Breed - Wheatland
Crescent
Belmont
Type
Interface
Line
Flowgate
Interface
Interface
Transformer
Line
Flowgate
Line
Line
Interface
Other
Flowgate
Transformer
Flowgate
Line
Flowgate
Transformer
Transformer
Line
Unclassified
Line
Flowgate
Transformer
Transformer
Location
500
BGE
MISO
500
500
Dominion
ComEd
MISO
ComEd
Dominion
500
BGE
MISO
Met-Ed
MISO
ComEd
MISO
AEP
AEP
PPL
Unclassified
PSEG
MISO
DLCO
AP
Section 10 Congestion and Marginal Losses
Load
Payments
$48.3
$26.5
($7.0)
$2.5
$13.6
$9.4
($0.9)
($0.2)
($19.3)
$0.4
$8.3
$7.8
($7.3)
$3.4
($5.6)
($2.3)
($4.8)
($3.0)
($0.1)
$0.7
$6.2
$1.5
($2.8)
$0.9
$0.6
Day Ahead
Generation Explicit
Credits
Costs
($20.0)
$2.2
($7.7)
($1.1)
($30.2)
$6.8
($24.7)
($0.5)
($6.0)
$0.4
($7.5)
$6.7
($8.5)
$0.2
($19.6)
$11.5
($34.3)
$6.9
($11.0)
($1.2)
($3.9)
$0.7
($2.4)
$0.4
($13.0)
$4.3
($4.2)
$0.2
($19.2)
$0.1
($8.5)
$1.6
($10.7)
$1.9
($11.2)
($1.2)
($0.6)
$6.0
($5.4)
$0.3
($1.2)
$1.7
$1.8
$2.7
($17.9)
$0.5
($4.3)
($0.2)
($5.5)
$0.6
Total
$70.5
$33.1
$30.0
$26.7
$20.0
$23.6
$7.7
$31.0
$21.9
$10.3
$12.9
$10.6
$10.0
$7.9
$13.8
$7.8
$7.7
$7.0
$6.5
$6.4
$9.1
$2.4
$15.6
$5.1
$6.6
Load
Payments
$8.3
$1.0
$0.0
$1.6
$1.0
$0.9
($2.4)
$0.4
($0.9)
$0.6
$1.0
($0.7)
($0.2)
$0.1
$0.3
$0.1
($0.0)
($0.2)
$0.0
$0.1
($0.5)
($0.4)
$0.4
$0.2
($0.4)
Balancing
Generation Explicit
Credits
Costs
$7.6
($2.7)
($1.2)
($0.3)
$0.0
$0.0
$4.0
$0.1
$1.1
($0.7)
$0.8
($8.5)
$3.3 ($16.3)
$1.9 ($15.5)
$1.7
($7.9)
$0.9
$0.2
$4.2
($0.4)
($0.1)
($0.8)
($0.1)
($1.7)
$0.0
($0.0)
$0.9
($5.7)
$0.1
($0.8)
($0.0)
($0.7)
$0.1
$0.2
$0.0
$0.0
$0.1
$0.1
$1.2
($1.2)
$0.4
($7.2)
$0.3 ($10.1)
$0.2
($0.1)
$0.8
($0.4)
Percent of
Total PJM
Congestion
Costs
Grand
Total Total
($2.1) $68.5
$1.9 $35.0
$0.0 $30.0
($2.3) $24.4
($0.8) $19.1
($8.3) $15.2
($22.0) ($14.3)
($17.0) $14.0
($10.5) $11.3
($0.1) $10.2
($3.6)
$9.3
($1.5)
$9.1
($1.9)
$8.2
$0.0
$7.9
($6.3)
$7.5
($0.7)
$7.1
($0.7)
$7.0
($0.0)
$7.0
$0.0
$6.5
$0.1
$6.5
($2.8)
$6.3
($7.9) ($5.6)
($10.1)
$5.5
$0.0
$5.1
($1.5)
$5.0
2012
16.1%
8%
7%
6%
4%
4%
(3.4%)
3%
3%
2%
2%
2%
1.9%
2%
2%
2%
2%
2%
1.5%
2%
1%
(1%)
1%
1%
1.2%
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
Table 10‑28 Top 25 constraints affecting PJM congestion costs (By facility): 2011
Congestion Costs (Millions)
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Constraint
AP South
5004/5005 Interface
West
Belmont
AEP - DOM
Electric Jct - Nelson
Bedington - Black Oak
Crete - St Johns Tap
Clover
East
Dickerson - Quince Orchard
Oak Grove - Galesburg
Susquehanna
Graceton - Raphael Road
Wylie Ridge
East Frankfort - Crete
Brues - West Bellaire
Breed - Wheatland
Waldwick
Plymouth Meeting - Whitpain
Cloverdale
Bunsonville - Eugene
Unclassified
Pleasant Valley - Belvidere
Cloverdale - Lexington
Type
Interface
Interface
Interface
Transformer
Interface
Line
Interface
Flowgate
Transformer
Interface
Line
Flowgate
Transformer
Line
Transformer
Line
Line
Line
Transformer
Line
Transformer
Flowgate
Unclassified
Line
Line
Location
500
500
500
AP
500
ComEd
500
MISO
Dominion
500
Pepco
MISO
PPL
BGE
AP
ComEd
AEP
AEP
PSEG
PECO
AEP
MISO
Unclassified
ComEd
500
Load
Payments
$96.1
($25.2)
($19.3)
$7.7
$14.6
($10.8)
$10.9
($32.9)
$0.4
($11.5)
($9.4)
($13.6)
($2.9)
$10.9
$15.3
($10.0)
$19.8
($4.8)
($0.5)
($0.9)
$0.5
($11.5)
$1.1
($6.6)
$4.9
Day Ahead
Generation Explicit
Credits
Costs
($140.1)
($0.1)
($101.5)
($4.6)
($83.4)
($5.0)
($49.9)
($2.2)
($21.5)
$2.1
($44.4)
$7.7
($14.6)
($2.0)
($66.4)
($5.3)
($21.4)
$4.6
($31.5)
($1.2)
($28.8)
($1.7)
($22.0)
$6.3
($17.4)
($0.1)
($1.1)
($0.8)
$3.6
$1.8
($23.7)
($1.3)
$4.5
$0.7
($13.2)
$2.0
($2.3)
$2.1
($10.8)
($0.0)
($7.6)
$1.6
($19.0)
$2.1
($1.5)
$5.4
($17.6)
$1.7
($2.9)
$1.3
Total
$236.1
$71.7
$59.1
$55.5
$38.2
$41.3
$23.5
$28.2
$26.4
$18.7
$17.7
$14.6
$14.4
$11.2
$13.6
$12.4
$16.1
$10.5
$3.8
$9.9
$9.7
$9.6
$8.0
$12.7
$9.1
Balancing
Load Generation Explicit
Payments
Credits
Costs
$18.7
$16.0
$0.0
$16.1
$19.3
$7.6
$0.2
$0.1
$0.1
($3.5)
($3.2)
($1.6)
$2.0
$1.5
($0.4)
$0.4
$3.7
($7.7)
$0.2
$0.1
$0.0
$6.3
$6.7
($4.5)
$2.8
$3.4
($7.8)
$0.2
$1.3
$0.1
$4.6
$7.4
$2.7
($2.5)
$6.0 ($20.8)
$0.0
$0.0
$0.0
$0.7
($1.1)
$0.5
$2.2
$1.2
($2.5)
$0.6
$0.6
($0.6)
($2.1)
$1.8
($1.5)
$0.0
($0.0)
($0.1)
$0.1
$1.3 ($12.5)
$0.2
$0.2
($0.1)
$0.7
$0.6
($0.1)
$0.0
($0.0)
($0.0)
$1.2
$0.3
($1.4)
($0.6)
$2.1
($3.0)
$3.3
$2.1
($3.8)
Percent of
Total PJM
Congestion
Costs
Total
$2.8
$4.3
$0.3
($1.8)
$0.1
($11.0)
$0.1
($4.9)
($8.5)
($1.0)
($0.2)
($29.3)
$0.0
$2.4
($1.5)
($0.6)
($5.4)
($0.0)
($13.8)
($0.2)
($0.0)
($0.0)
($0.5)
($5.7)
($2.7)
Grand
Total
$238.9
$76.1
$59.3
$53.7
$38.3
$30.3
$23.7
$23.3
$17.9
$17.8
$17.5
($14.7)
$14.4
$13.5
$12.1
$11.8
$10.7
$10.4
($9.9)
$9.7
$9.7
$9.6
$7.5
$7.0
$6.4
2011
27%
9%
7%
6%
4%
3%
3%
3%
2%
2%
2%
(2%)
2%
2%
1%
1%
1%
1%
(1%)
1%
1%
1%
1%
1%
1%
Figure 10‑2 shows the locations of the top 10 constraints affecting PJM congestion costs in 2012.
Figure 10‑2 Location of the top 10 constraints affecting PJM congestion costs: 201234
34 The term flowgate refers to MISO reciprocal coordinated flowgates in this section.
© 2013 Monitoring Analytics, LLC
2012 State of the Market Report for PJM 313
2012 State of the Market Report for PJM
Congestion-Event Summary for MISO Flowgates
PJM and MISO have a joint operating agreement (JOA) which defines a coordinated methodology for congestion
management. This agreement establishes reciprocal, coordinated flowgates in the combined footprint whose operating
limits are respected by the operators of both organizations.35 A flowgate is a facility or group of facilities that may
act as constraint points on the regional system.36 PJM models these coordinated flowgates and controls for them in
its security-constrained, economic dispatch. Table 10‑29 and Table 10‑30 show the MISO flowgates which PJM and/
or MISO took dispatch action to control during 2012 and 2011 respectively, and which had the greatest congestion
cost impact on PJM. Total congestion costs are the sum of the day-ahead and balancing congestion cost components.
Total congestion costs associated with a given constraint may be positive or negative in value. The top congestion
cost impacts for MISO flowgates affecting PJM and MISO dispatch are presented by constraint, in descending order
of the absolute value of total congestion costs. Among MISO flowgates in 2012, the Woodstock flowgate made the
most significant contribution to positive congestion while the Rising flowgate made the most significant contribution
to negative congestion.
Table 10‑29 Top congestion cost impacts from MISO flowgates affecting PJM dispatch (By facility): 2012
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Constraint
Woodstock
Monticello - East Winamac
Rantoul - Rantoul Jct
Crete - St Johns Tap
Prairie State - W Mt. Vernon
Breed - Wheatland
Rising
Rantoul Jct - Sidney
Benton Harbor - Palisades
Miami Fort - Hebron
Palisades - Roosevelt
Cumberland - Bush
Brokaw
Beaver Channel - Albany
Edwards - Kewanee
Michigan City - Maple
Beaver Channel - Albany
Pana North
Dunes Acres - Michigan City
Bush - Lafayette
Load
Payments
($7.0)
($0.2)
($7.3)
($5.6)
($4.8)
($2.8)
($3.1)
$0.0
($0.6)
($1.8)
($0.9)
($1.2)
$0.0
$0.0
($0.2)
($1.0)
($6.0)
$0.0
($0.2)
$0.0
Congestion Costs (Millions)
Day Ahead
Balancing
Generation Explicit
Load Generation Explicit
Credits
Costs Total Payments
Credits
Costs
($30.2)
$6.8 $30.0
$0.0
$0.0
$0.0
($19.6)
$11.5 $31.0
$0.4
$1.9
($15.5)
($13.0)
$4.3 $10.0
($0.2)
($0.1)
($1.7)
($19.2)
$0.1 $13.8
$0.3
$0.9
($5.7)
($10.7)
$1.9 $7.7
($0.0)
($0.0)
($0.7)
($17.9)
$0.5 $15.6
$0.4
$0.3
($10.1)
($3.2)
$2.3 $2.4
($1.2)
$0.8
($5.4)
$0.0
$0.0 $0.0
$0.1
$0.4
($4.0)
($5.5)
($0.8) $4.1
$0.1
$0.3
($0.2)
($5.7)
($0.2) $3.7
($0.1)
($0.0)
$0.1
($5.6)
($0.6) $4.1
$0.1
$0.3
($0.2)
($5.5)
$6.2 $10.5
$0.4
$1.2
($11.1)
$0.0
$0.0 $0.0
($0.0)
$0.1
($1.1)
$0.0
$0.0 $0.0
($0.7)
$0.2
($0.2)
($0.9)
$0.5 $1.2
$0.0
($0.1)
($0.3)
($0.7)
$0.5 $0.2
($0.4)
($0.1)
($0.8)
($17.0)
($0.1) $11.0
($4.8)
($0.4)
($5.7)
$0.0
$0.0 $0.0
$0.0
$0.0
($0.8)
($0.3)
$0.1 $0.2
($0.2)
($0.0)
($0.7)
$0.0
$0.0 $0.0
$0.0
$0.1
($0.6)
Total
$0.0
($17.0)
($1.9)
($6.3)
($0.7)
($10.1)
($7.4)
($4.3)
($0.4)
$0.0
($0.4)
($11.8)
($1.2)
($1.1)
($0.2)
($1.1)
($10.2)
($0.8)
($0.9)
($0.7)
Grand
Total
$30.0
$14.0
$8.2
$7.5
$7.0
$5.5
($5.0)
($4.3)
$3.8
$3.7
$3.7
($1.3)
($1.2)
($1.1)
$1.0
($0.9)
$0.8
($0.8)
($0.7)
($0.7)
Event Hours
Day
Real
Ahead
Time
1,073
0
2,734
578
2,036
315
2,377
277
1,483
1,011
2,821
428
408
363
0
331
840
71
1,053
76
855
209
2,053
316
0
81
0
36
314
68
73
51
1,256
460
0
20
180
23
0
296
35 See “Joint Operating Agreement Between the Midwest Independent Transmission System Operator, Inc. and PJM Interconnection, L.L.C.” (December 11, 2008) <http://pjm.com/documents/agreements/~/media/
documents/agreements/joa-complete.ashx> (Accessed March 13, 2013).
36 See “Joint Operating Agreement Between the Midwest Independent Transmission System Operator, Inc. and PJM Interconnection, L.L.C.” (December 11, 2008), Section 2.2.24 <http://pjm.com/documents/
agreements/~/media/documents/agreements/joa-complete.ashx> (Accessed March 13, 2013).
314
Section 10 Congestion and Marginal Losses
© 2013 Monitoring Analytics, LLC
Section 10 Congestion and Marginal Losses
Table 10‑30 Top congestion cost impacts from MISO flowgates affecting PJM dispatch (By facility): 2011
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Constraint
Crete - St Johns Tap
Oak Grove - Galesburg
Bunsonville - Eugene
Pleasant Prairie - Zion
Lakeview - Pleasant Prairie
Burnham - Munster
Stillwell
Michigan City - Laporte
Breed - Wheatland
Cook - Palisades
Rantoul - Rantoul Jct
Benton Harbor - Palisades
St John - Liberty Park
Nucor - Whitestown
Temporary Monticello - E Wiinamac
Eugene - Bunsonville
Cumberland - Bush
Rising
Green Acres - St John
Rantoul Jct - Sidney
Load
Payments
($32.9)
($13.6)
($11.5)
($1.1)
($0.1)
($10.9)
($0.0)
($10.4)
$0.0
($1.3)
($3.2)
($0.2)
($1.8)
$0.0
$0.0
$0.0
($1.0)
($5.2)
$0.0
($1.0)
Day Ahead
Generation Explicit
Credits
Costs
($66.4)
($5.3)
($22.0)
$6.3
($19.0)
$2.1
($1.6)
$0.7
($0.2)
$0.2
($19.0)
($3.0)
($0.4)
($0.1)
($16.4)
$3.0
$0.0
$0.0
($5.2)
$0.3
($5.5)
$0.6
($1.0)
$0.2
($6.0)
$0.6
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
($5.8)
$2.1
($8.1)
($0.1)
$0.0
$0.0
($2.0)
$0.1
Congestion Costs (Millions)
Balancing
Load Generation Explicit
Total Payments
Credits
Costs
$28.2
$6.3
$6.7
($4.5)
$14.6
($2.5)
$6.0 ($20.8)
$9.6
$0.0
($0.0)
($0.0)
$1.2
($0.1)
($0.5)
($7.9)
$0.3
($0.3)
($0.1)
($5.7)
$5.1
$0.0
$0.0
$0.0
$0.3
($0.3)
$1.3
($3.6)
$9.0
($1.7)
($1.3)
($3.8)
$0.0
$0.4
$0.3
($4.4)
$4.1
$0.0
$0.0
($0.2)
$3.0
$0.1
$0.0
($0.5)
$1.0
$0.8
$1.2
($2.8)
$4.8
$0.6
$1.0
($2.2)
$0.0
$0.2
$0.5
($1.8)
$0.0
($0.0)
$0.5
($1.2)
$0.0
$0.1
$0.1
($1.7)
$6.9
$0.2
$0.9
($4.6)
$2.8
$0.0
$1.1
($3.3)
$0.0
$0.6
$1.4
($0.7)
$1.1
$0.5
$0.0
($0.2)
Total
($4.9)
($29.3)
($0.0)
($7.5)
($5.8)
$0.0
($5.2)
($4.2)
($4.2)
($0.2)
($0.4)
($3.2)
($2.6)
($2.1)
($1.7)
($1.6)
($5.3)
($4.4)
($1.5)
$0.3
Grand
Total
$23.3
($14.7)
$9.6
($6.3)
($5.6)
$5.1
($4.9)
$4.8
($4.2)
$3.9
$2.6
($2.2)
$2.2
($2.1)
($1.7)
($1.6)
$1.6
($1.6)
($1.5)
$1.3
Event Hours
Day
Real
Ahead
Time
3,378
1,120
1,760
1,145
2,444
11
336
210
24
302
1,152
0
93
88
2,935
632
0
215
481
9
553
188
67
132
334
161
0
56
0
69
0
107
1,612
215
947
175
0
147
62
113
Congestion-Event Summary for the 500 kV System
Constraints on the 500 kV system generally have a regional impact. Table 10‑31 and Table 10‑32 show the 500 kV
constraints impacting congestion costs in PJM for 2012 and 2011 respectively. Total congestion costs are the sum of
the day-ahead and balancing congestion cost components. Total congestion costs associated with a given constraint
may be positive or negative in value. The 500 kV constraints impacting congestion costs in PJM are presented by
constraint, in descending order of the absolute value of total congestion costs.
Table 10‑31 Regional constraints summary (By facility): 2012
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Constraint
AP South
West
Bedington - Black Oak
AEP - DOM
East
5004/5005 Interface
Doubs - Mount Storm
Conemaugh - Hunterstown
Central
Cloverdale - Lexington
Nagel
Kammer
Mount Storm - Pruntytown
Branchburg - Elroy
Burches Hill - Chalk Point
Type
Location
Interface
500
Interface
500
Interface
500
Interface
500
Interface
500
Interface
500
Line
500
Line
500
Interface
500
Line
500
Line
500
Transformer
500
Line
500
Line
500
Line
500
© 2013 Monitoring Analytics, LLC
Load
Payments
$48.3
$2.5
$13.6
$8.3
($2.6)
$0.2
$1.3
$0.4
($0.9)
$0.0
$0.3
$0.0
$0.0
($0.0)
($0.0)
Day Ahead
Generation Explicit
Credits
Costs
($20.0)
$2.2
($24.7)
($0.5)
($6.0)
$0.4
($3.9)
$0.7
($8.1)
($0.6)
($4.1)
$0.5
($1.1)
$0.1
($1.3)
$0.1
($1.6)
$0.1
$0.0
$0.0
($0.0)
($0.0)
$0.0
$0.0
$0.0
$0.0
($0.0)
$0.0
($0.0)
$0.0
Congestion Costs (Millions)
Balancing
Load Generation Explicit
Total Payments
Credits
Costs
$70.5
$8.3
$7.6
($2.7)
$26.7
$1.6
$4.0
$0.1
$20.0
$1.0
$1.1
($0.7)
$12.9
$1.0
$4.2
($0.4)
$4.8
$0.1
$0.5
($0.1)
$4.8
$2.5
$3.5
$0.3
$2.5
$0.0
$0.0
$0.0
$1.7
$0.1
$2.0
($1.9)
$0.8
$0.0
$0.0
($0.0)
$0.0
$0.1
$0.1
($0.8)
$0.3
$0.0
$0.0
$0.0
$0.0
$0.0
($0.0)
($0.0)
$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
($2.1)
($2.3)
($0.8)
($3.6)
($0.5)
($0.6)
$0.0
($3.9)
($0.0)
($0.8)
$0.0
$0.0
$0.0
$0.0
$0.0
Grand
Total
$68.5
$24.4
$19.1
$9.3
$4.4
$4.2
$2.5
($2.1)
$0.8
($0.7)
$0.3
$0.1
$0.0
$0.0
$0.0
Event Hours
Day
Real
Ahead
Time
2,586
351
841
130
780
54
2,095
61
209
5
191
128
80
0
38
117
214
2
7
61
128
0
12
19
0
2
2
0
2
0
2012 State of the Market Report for PJM 315
2012 State of the Market Report for PJM
Table 10‑32 Regional constraints summary (By facility): 2011
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Constraint
AP South
5004/5005 Interface
West
AEP - DOM
Bedington - Black Oak
East
Cloverdale - Lexington
Central
Mount Storm - Pruntytown
Doubs - Mount Storm
Harrison - Pruntytown
Kammer
Dominion East
Conemaugh - Hunterstown
Type
Interface
Interface
Interface
Interface
Interface
Interface
Line
Interface
Line
Line
Line
Transformer
Interface
Line
Location
500
500
500
500
500
500
500
500
500
500
500
500
500
500
Load
Payments
$96.1
($25.2)
($19.3)
$14.6
$10.9
($11.5)
$4.9
($1.5)
$0.1
$0.0
$0.0
($0.0)
$0.0
$0.0
Day Ahead
Generation Explicit
Credits
Costs
($140.1)
($0.1)
($101.5)
($4.6)
($83.4)
($5.0)
($21.5)
$2.1
($14.6)
($2.0)
($31.5)
($1.2)
($2.9)
$1.3
($2.8)
($0.0)
($0.2)
$0.0
($0.3)
($0.0)
($0.1)
$0.0
($0.1)
($0.0)
$0.0
$0.0
$0.0
$0.0
Congestion Costs (Millions)
Balancing
Load Generation Explicit
Total Payments
Credits
Costs
$236.1
$18.7
$16.0
$0.0
$71.7
$16.1
$19.3
$7.6
$59.1
$0.2
$0.1
$0.1
$38.2
$2.0
$1.5
($0.4)
$23.5
$0.2
$0.1
$0.0
$18.7
$0.2
$1.3
$0.1
$9.1
$3.3
$2.1
($3.8)
$1.3
($0.1)
($0.1)
($0.1)
$0.3
$0.2
$0.0
($0.1)
$0.3
($0.0)
$0.0
($0.0)
$0.1
($0.0)
($0.0)
$0.0
$0.1
$0.0
$0.0
$0.0
$0.0
$0.3
$0.1
($0.2)
$0.0
$0.0
$0.0
$0.0
Total
$2.8
$4.3
$0.3
$0.1
$0.1
($1.0)
($2.7)
($0.1)
$0.0
($0.0)
$0.0
$0.0
$0.0
($0.0)
Grand
Total
$238.9
$76.1
$59.3
$38.3
$23.7
$17.8
$6.4
$1.2
$0.3
$0.3
$0.1
$0.1
$0.0
($0.0)
Event Hours
Day Real
Ahead Time
4,120 1,013
905
470
879
20
1,789 185
679
7
523
22
602 427
118
8
29
38
9
4
10
4
13
0
0
38
0
9
Congestion Costs by Physical and Financial Participants
In order to evaluate the ownership of virtual bids, the MMU categorized all participants making virtual bids in PJM as
either physical or financial. Physical entities include utilities and customers which primarily take physical positions
in PJM markets. Financial entities include banks and hedge funds which primarily take financial positions in PJM
markets. International market participants that primarily take financial positions in PJM markets are generally
considered to be financial entities even if they are utilities in their own countries. In 2012, financial companies as a
group were net recipients of congestion credits, whereas physical companies were net payers of congestion charges.37
In 2012, financial companies received $83.1 million, a decrease of $91.6 million or 52.4 percent compared to 2011.
In 2012, physical companies paid $612.1 million in congestion charges, a decrease of $561.5 million or 47.8 percent
compared to 2011.
Table 10-33 Congestion cost by the type of the participant: Calendar year 2012
Participant
Type
Financial
Physical
Total
Load
Payments
($0.2)
$135.8
$135.5
Day Ahead
Generation
Credits Explicit Costs
$11.1
$90.1
($523.6)
$41.8
($512.5)
$131.9
Total
$78.8
$701.1
$779.9
Congestion Costs (Millions)
Balancing
Load
Generation
Payments
Credits Explicit Costs
($25.2)
($1.3)
($137.9)
$28.3
$69.8
($47.5)
$3.0
$68.5
($185.4)
Total
($161.9)
($89.0)
($250.9)
Inadvertent
Charges
$0.0
$0.0
$0.0
Grand
Total
($83.1)
$612.1
$529.0
Total
($207.5)
($38.5)
($246.0)
Inadvertent
Charges
$0.0
$0.0
$0.0
Grand
Total
($174.7)
$1,173.6
$999.0
Table 10-34 Congestion cost by the type of the participant: Calendar year 2011
Participant
Type
Financial
Physical
Total
Load
Payments
($22.2)
$58.5
$36.2
Day Ahead
Generation
Credits Explicit Costs
$14.4
$69.5
($1,156.2)
($2.6)
($1,141.8)
$66.9
Total
$32.9
$1,212.1
$1,245.0
Congestion Costs (Millions)
Balancing
Load
Generation
Payments
Credits Explicit Costs
($26.8)
$9.1
($171.7)
$102.7
$122.8
($18.4)
$75.9
$131.9
($190.0)
37 The total zonal congestion numbers were calculated as of March 2, 2013 and are, based on continued PJM billing updates, subject to change.
316
Section 10 Congestion and Marginal Losses
© 2013 Monitoring Analytics, LLC