Reliable Market-Compatible
Operation by ISOs & Balancing
Authorities:
Unresolved Problems in North
American Experience
Presented to
North China Electric Power University
by
卜若柏
Robert Blohm
http://www.blohm.cnc.net
May 22, 2007
CONTENTS
1.
2.
3.
4.
Two Concepts of Reliability
Two Objects of Reliability
Two Methods of Reliability
Two Approaches to
System/Contingency Planning
5. Two Problems of 2003 NA Blackout
6. Two China Challenges
1
1. Two Concepts of Reliability

Emergency Reliability




system not under control
statistical measurement,
event vs normal operation
marketizable
Economic Reliability



long-term contract sufficiency
energy market incomplete
California experience
2
Decomposition of Near-Normal Distribution of Frequency Error
into Normal Distribution of Normal Errors, & Back-to-Back Chi-Square Distribution of Events.
Back-to-Back Chi-Square Distributions
NormalDistribution
0.0239
0.0209
0.0179
0.0119
0.0089
0.0059
0.0029
FrequencyError(Hz)
0.250
0.200
0.150
0.100
0.050
0.000
-0.050
-0.100
-0.150
-0.200
-0.0001
-0.250
Probability
0.0149
3
Reducing the Standard Deviation Bandwidth to Reduce the Area/Probability under the Tails of
the Distribution
NormalDistribution4SD
NormalDistribution
0.0239
0.0209
0.0179
0.0119
0.0089
0.0059
0.0029
FrequencyError(Hz)
0.250
0.200
0.150
0.100
0.050
0.000
-0.050
-0.100
-0.150
-0.200
-0.0001
-0.250
Probability
0.0149
4
SumOfDistributions.
Cumulative Tail Probablity.
Under (1) Gamma disturbance distribution and
(2) conservative interpretation of disturbance weight.
1.E+00
1.E-01
1.E-02
1.E-03
1.E-04
1.E-05
1.E-06
1.E-07
1.E-08
1.E-09
1.E-10
1.E-11
1.E-12
1.E-13
1.E-14
1.E-15
1.E-16
1.E-17
1.E-18
1.E-19
1.E-20
1.E-21
1.E-22
1.E-23
1.E-24
1.E-25
1.E-26
1.E-27
1.E-28
1.E-29
1.E-30
1.E-31
1.E-32
1.E-33
1.E-34
1.E-35
1.E-36
1.E-37
1.E-38
1.E-39
1.E-40
1.E-41
1.E-42
1.E-43
1.E-44
Norm S.D.+200%
Norm S.D.
Norm S.D.+100%
Imbalance (MW)
–Graph Adapted from
5000
4500
4000
3500
3000
2500
2000
1500
1000
500
0
-500
-1000
-1500
-2000
-2500
-3000
-3500
-4000
-4500
Indicates a reliability of one failure in 10 years
with a Frequency Response of 540 MW/0.1 Hz.
-5000
Probability
(Logarithmic scale)
Norm S.D.+300%
Norm S.D.-75%
5
price
Only physical/forward transmission
rights can prevent generators from
capturing congestion rents from
transmission owners. Cannot be
prevented by congestion contracts
that value congested transmission as
the difference in energy prices
across the congested interface.
Generators on the
cheap side of the
constraint collude
to raise prices to
capture congestion
rents from
transmission owner
congested price to consumer on expensive side
of constraint
Congestion charge
normally to
transmission owners
Supply curve
energy price to generator on cheap side
of constraint
Demand curve
congestion
quantity
6
2. Two Objects of Reliability

Transmission




Transmission Reliability Margin (TRM)
congestion management
centralized
Generation



balancing
frequency control
control operations
unscheduled power
decentralized
7
3. Two Methods of Reliability

performance measures



control performance standard (CPS)
covariance
recovery
BAAL (covariance)
capacity requirements


economic vs emergency
governor response
NERC’s Control Performance Standard Used for Pricing FCC
Approximate CPS1
8  : Instantaneous
Probability On average over the past year:
MW, or 
 : Annual standard
+
: in same direction as  F
deviation of  F
+
RMS
2
:
"No inadvertent allowed



  2  F 
Limit
in the direction of
  F  : Year's Mean of  F
Frequency error when
F : 1-minute average of
"
Frequency error




F
+
Bi  0:Control area i's bias
-
-50
50
 10 Bi  F
F
+(mHz)
10 B i  F
: Control area
i's maximum allowed 1-minute average tie-line
error (plus response obligation) in direction of the frequency error:
:


Ti  10Bi    F 
 F

One-year probability density limit on 1-minute
averages of frequency error, adjusted for deviation of
the mean from 0
9
The value of resources lies not just in the amount of energy but also in
how readily the energy is available to counter sudden frequency error.
Resources
stacked by value
Frequency
Response
Regulation
Operating Reserves
Load Following Following
Energy Market Energy
Capacity
Response Time
in order of quickness
\\
Seconds
A Few to Several Minutes
10 to 15 Minutes
30 Minutes
Market Interval – One Hour
Response Not Defined
Adapted from Energy Mark, Inc.
10
Primary Response Stabilizes Frequency
Generator slows down while governor opens steam-control valve to stop the slow-down
by offsetting torque that otherwise reduces output. Fuel is increased to maintain pressure.
Interconnection’s Overall Primary Response equals Intcrconn.’s Overall Scheduling Error.
60
Seconds
15
59.925
Hz
(Shared)
Primary Response
60
59.925
Hz
1
Secondary Response (should be made by the BA who caused the disturbance)
10
Minutes
Secondary Response Restores Frequency
Operator increases fuel intake even more to produce more steam and raises steam-control
valve set-point to increase steam flow to even more than before to increase torque.
As generator speeds back up to normal speed, governor closes-back steam-control valve
eliminating the fueling of primary response, with more steam flow at same steam
pressure & same turbine speed as before the disturbance,for increased torque/output.
Balancing Authority’s Secondary Response to his own error
replaces Interconnection’s Shared Primary Response to that error.
11
icap supply is not discretionary.
It is all-at-once available for a price marginally above 0
when it exceeds demand.
When demand exceeds supply the price is infinite.
Price

icap supply curve
vertical
demand
curve
0
Quantity
12
4. Two Approaches to
System/Contingency Planning

deterministic


contingency basis
1st, & 2nd (applies to uncontrolled loss)
statistical

probability weighting
13
5. Two Problems of 2003 NA Blackout

Asymmetry



load vs generation
real-time redispatch
real-time power flow
Generation


long-distance power
reactive power
local generation & transmission adequacy
Time on August 14, 2003
15:15:38
15:15:16
15:14:56
15:14:26
15:14:03
15:13:40
15:13:18
15:12:53
15:12:32
15:12:06
15:11:42
15:11:22
15:10:58
15:10:38
15:10:12
15:09:52
15:09:30
15:09:06
15:08:46
15:08:20
15:08:00
15:07:36
15:07:16
15:06:54
15:06:30
15:06:08
15:05:42
Hertz
14
Eastern Interconnection Blackout
60.3
60.25
60.2
60.15
60.1
60.05
60
Frequency
59.95
59.9
59.85
59.8
15
Local Balancing
May Require Less
Transmission
Centralized Balancing
May Require More
Transmission
G
G
L
L
RISO
Rlocal
G
G
Sudden local generator loss
Rlocal
Local Balancing
Authority
deploys local
responsive
reserve
Sudden local generator loss
Congested transmission
L
ISO deploys
responsive reserve
from big central
source
L
RISO
G
Rlocal
Local responsive
reserve still
available to the
system
RISO
Sudden remote generator loss
G
G
Without congesting transmission
L
Build transmission
L
L
16
6. Two China Challenges

No demand-side market



energy inefficiency since 2002
oil prices trend above 50-year average
Prepare completely for a market


economatize reliability
avoid North America’s mistakes
3
Decomposition of Near-Normal Distribution of Frequency Error
into Normal Distribution of Normal Errors, & Back-to-Back Chi-Square Distribution of Events.
Back-to-Back Chi-Square Distributions
NormalDistribution
0.0239
0.0209
0.0179
0.0119
0.0089
0.0059
0.0029
FrequencyError(Hz)
0.250
0.200
0.150
0.100
0.050
0.000
-0.050
-0.100
-0.150
-0.200
-0.0001
-0.250
Probability
0.0149
4
SumOfDistributions.
Cumulative Tail Probablity.
Under (1) Gamma disturbance distribution and
(2) conservative interpretation of disturbance weight.
1.E+00
1.E-01
1.E-02
1.E-03
1.E-04
1.E-05
1.E-06
1.E-07
1.E-08
1.E-09
1.E-10
1.E-11
1.E-12
1.E-13
1.E-14
1.E-15
1.E-16
1.E-17
1.E-18
1.E-19
1.E-20
1.E-21
1.E-22
1.E-23
1.E-24
1.E-25
1.E-26
1.E-27
1.E-28
1.E-29
1.E-30
1.E-31
1.E-32
1.E-33
1.E-34
1.E-35
1.E-36
1.E-37
1.E-38
1.E-39
1.E-40
1.E-41
1.E-42
1.E-43
1.E-44
Norm S.D.+200%
Norm S.D.
Norm S.D.+100%
Imbalance (MW)
–Graph Adapted from
5000
4500
4000
3500
3000
2500
2000
1500
1000
500
0
-500
-1000
-1500
-2000
-2500
-3000
-3500
-4000
-4500
Indicates a reliability of one failure in 10 years
with a Frequency Response of 540 MW/0.1 Hz.
-5000
Probability
(Logarithmic scale)
Norm S.D.+300%
Norm S.D.-75%
5
2. The Two Basic Control Operations

Congestion management



to within safe Transmission limits
centralization to facilitate wide-area flow
Frequency-control/scheduling


to within safe Generation limits
decentralization to avoid wide-area cascading



multiple controllers’ errors cancel each other
proactive, smaller, local control steps emphasized
examples:


Texas ERCOT’s frequency deterioration when ERCOT centralized
control
Midwest ISO


congestion management centralized
frequency control decentralized to multiple Balancing Authorities
6
3. Decomposition of Frequency
Performance (Nate Cohn, father of
“control decomposition”)

into Balancing Authority (BA) scheduling
performances under



tie-line bias control.
Area Control Error (ACE) equation: ACE  Ti  10Bi F
Covarying a BA’s scheduling performance with
(system) frequency performance, within a target
band over a rolling 1-year time-average.


To maximize the benefit of interconnected operations
Control Performance Standard (CPS1) equation
CPS1: AVG[(Ti  10Bi Ft )Ft ]  10Bi 2
NERC’s Control Performance Standard Used for Pricing FCC
Approximate CPS1
7  : Instantaneous
Probability On average over the past year:
MW, or 
 : Annual standard
+
: in same direction as  F
deviation of  F
+
RMS
2
:
"No inadvertent allowed



  2  F 
Limit
in the direction of
  F  : Year's Mean of  F
Frequency error when
F : 1-minute average of
"
Frequency error




F
+
Bi  0:Control area i's bias
-
-50
50
 10 Bi  F
F
+(mHz)
10 B i  F
: Control area
i's maximum allowed 1-minute average tie-line
error (plus response obligation) in direction of the frequency error:
:


Ti  10Bi    F 
 F

One-year probability density limit on 1-minute
averages of frequency error, adjusted for deviation of
the mean from 0
8
4. Reliability Challenge of LongDistance Scheduled Flow (lessons
of the Great Blackout of 2003)

The more long distance power, the more reactive
power (RP) is needed close to loads



RP is not a long-distance commodity (limited to 100
miles), therefore not tradeable.
RP is properly a cost-based part of regulated
transmission service
RP can be acquired in a (capital) procurement market.
9
4. Reliability Challenge of LongDistance Scheduled Flow (lessons
of the Great Blackout of 2003) (cont.)

Scheduled loading of interties makes power surge
the new reliability threat


To share the trading benefit of an interconnected
system, all Balancing Authorities are now imbalanced in
internal schedules
The 2003 Blackout was 1st-time over-frequency blackout
The system of impedence relays


was designed to curtail only unscheduled flow when BAs were
balanced in their internal schedules and
now creates power surge and wide-area cascading because it
interrupts schedules.
10
4. Reliability Challenge of LongDistance Scheduled Flow (lessons
of the Great Blackout of 2003) (cont.)

Scheduled loading of interties makes power surge
the new reliability threat (cont.)

Near real-time redispatch of generation is required to
preserve the previous level of reliability and eliminate
power surge.


Transmission Loading Relief (TLR) is based on NERC’s
Interchange Distribution Calculator (IDC), a DC model of
scheduled flow only, updated every 24 hours.
1-minute intertie data is universally available for 1-minute
updating of scheduled and unscheduled flow to


make IDC near-real-time and do near real-time
TLR to arm over-frequency relaying of selected generation.
Time on August 14, 2003
15:15:38
15:15:16
15:14:56
15:14:26
15:14:03
15:13:40
15:13:18
15:12:53
15:12:32
15:12:06
15:11:42
15:11:22
15:10:58
15:10:38
15:10:12
15:09:52
15:09:30
15:09:06
15:08:46
15:08:20
15:08:00
15:07:36
15:07:16
15:06:54
15:06:30
15:06:08
15:05:42
Hertz
11
Eastern Interconnection Blackout
60.3
60.25
60.2
60.15
60.1
60.05
60
Frequency
59.95
59.9
59.85
59.8
12
5. Locating Contingency Reserve to
Maximize Reliability vs Locating
Transmission to Maximize Economic
Interest

Local reserve is more reliable.




1 less contingency, transmission.
Smaller increments of reserve are deployable locally
and proactively
Tends to reduce congestion and prices
Remote reserve is less reliable


Bulked for deployment by a single, central operator
Deliverability risk, mitigated by transmission
reservation.
13
5. Locating Contingency Reserve to
Maximize Reliability vs Locating
Transmission to Maximize Economic
Interest (cont.)

Economic transmission (affected users pay)
versus Reliability transmission (system pays)


When contingency reserve is remote sourced, local
energy prices are usually higher than otherwise, and
this can prompt building of economic transmission
resulting in increased remote sourcing.
Shaky mathematical basis for reliability transmission:
probabilistic methods are not used for contingency
stressing.
14
5. Locating Contingency Reserve to
Maximize Reliability vs Locating
Transmission to Maximize Economic
Interest (cont.)

Example of New England ISO: Prefers
transmission construction, for redeployment of
remote stranded generation.
15
Local Balancing
May Require Less
Transmission
Centralized Balancing
May Require More
Transmission
G
G
L
L
RISO
Rlocal
G
G
Sudden local generator loss
Rlocal
Local Balancing
Authority
deploys local
responsive
reserve
Sudden local generator loss
Congested transmission
L
ISO deploys
responsive reserve
from big central
source
L
RISO
G
Rlocal
Local responsive
reserve still
available to the
system
RISO
Sudden remote generator loss
G
G
Without congesting transmission
L
Build transmission
L
L
16


6. Ancillary Services (A/S) Market:
Energy Market or Options Market?
Pyramid of ancillary services. Option value is
rapidity of deployment.
A/S dispatch decision versus economic dispatch
decision



A/S decision includes the cost of meeting the next
contingency
Options market assesses reliability risk; Energy market
may reflect immediate reliability.
When a sub-hourly energy market and an A/S
market coexist, energy market clearing price
cannot capture the full value of A/S because all the
A/S are not selected in that energy market.
17
The value of resources lies not just in the amount of energy but also in
how readily the energy is available to counter sudden frequency error.
Resources
stacked by value
Frequency
Response
Regulation
Operating Reserves
Load Following Following
Energy Market Energy
Capacity
Response Time
in order of quickness
\\
Seconds
A Few to Several Minutes
10 to 15 Minutes
30 Minutes
Market Interval – One Hour
Response Not Defined
Adapted from Energy Mark, Inc.
18
Ancillary Service Dispatch Decision
Marginal-Energy-Cost Not the Most Economic Basis for Reliability
•
Three 500 MW Units with 5% Droop.
5 % Droop means
- 100 % of capacity needed to arrest freq. drop of 5 % of 60 Hz = 3 Hz
- Response Requirement of 10 % of capacity (= 150 MW = 50MW per gen.) to arrest
conceivable .3 Hz freq. drop (= 0.5% of 60 Hz).
•
•
•
•
•
•
Each Loaded to 425 MW
Unit 1 – Incremental Price = $30/MWh
Unit 2 – Incremental Price = $40/MWh
Unit 3 – Incremental Price = $50/MWh
How should a 75 MW increase in balancing energy be delivered?
Alternative 1: Variable-cost Based Decision: load Unit 1 an additional 75 MW.
–
–
•
Cost
$ 2,250
Remaining resp. to next .3Hz drop: 100 MW 
 only 2 available generators left @ 50 MW per generator = 1/3rd shortfall from response needed
to arrest next frequency drop. Need to buy 500 MW of new excess capacity to make up the lost
50 MW of response
Alternative 2: Capacity-cost Reliability Based Decision: load each unit an additional
25 MW.
–
–
Cost
$ 3,000
Remaining resp. to next .3Hz drop 150 MW 
 all 3 generators available @ 50 MW per generator = No shortfall from the response needed to
arrest next frequency drop
–Table Adapted from
19
7. 2-Part Bidding or Single-Part
Bidding: Who Takes the Risk for ISO
Forecast Error?

2-part bidding:



2 simultaneous bids by generator of same capacity to
energy market and to A/S market.
ISO accepts both bids, one or none, and decides in
which market to implement
If both bids accepted by ISO, ISO is absorbing that
generator’s cost of ISO’s forecast error.
20
7. 2-Part Bidding or Single-Part
Bidding: Who Takes the Risk for ISO
Forecast Error? (cont.)

Single-part bidding:


Generator bids either into energy market or into A/S
market.
Generator absorbs cost of ISO’s energy forecast error if


Generator’s energy-market bid was rejected because ISO
underforecast energy, or
Generator’s A/S bid was rejected because ISO overforecast
energy and underforecast A/S.
21
7. 2-Part Bidding or Single-Part
Bidding: Who Takes the Risk for ISO
Forecast Error? (cont.)

Does the ISO represent consumers or the
system?


If the ISO represents only consumers, consumers are
paying for the ISO’s risk
If the ISO represents the entire system, the ISO’s risk
becomes the system’s which can then assess the ISO
for its performance.
22
Successful Two-part bidding into both the energy market and the Ancillary
Services market ensures that the ISO pays for its own forecasting error.
Generator successfully two-part offers
both to energy market & to A/S market:
2 cases of ISO forecast error; in each
case the ISO pays for the error
actual
Generator single-part offers to either
energy market or to A/S market:
2 cases where generator pays for ISO’s
forecasting error:
actual
forecast
energy
A/S
ISO put generator in energy market by mistake.
ISO exercises generator’s A/S option to back down.
Result: ISO receives fuel & O&M and pays option
forecast
energy
A/S
Generator offered A/S & would have been
accepted & exercised but for ISO’s for. error
Result: Generator loses A/S charge.
actual
actual
forecast
energy
A/S
ISO put generator in A/S market by mistake. ISO
exercises gen’s A/S option to increment generation
Result: ISO pays A/S cost to increment you
forecast
energy
A/S
Generator offered energy and would have
been called but for ISO’s forecast error
Result: Generator loses energy
23
8. Should the ISO Take a Position in the
Forward Energy Market to Create
Reserve?
If the ISO is “for profit”, it will weigh the cost
of creating contingency reserve by
 buying new A/S, or
 buying forward energy in order to back
down generators under existing
agreements to provide response, and
thereby create new response capability.
24
9. Reliability & Market Stability are
Properly Addressed by a Market for
Unscheduled, not Scheduled, Power.
Which Market Need the ISO Operate?

2nd “market compatible” definition of Reliability:
Reliability is strictly about:
keeping control of the system during a sudden
unplanned event and therefore about
 sudden, unscheduled flows.
This is done on a planned, proactive basis.

25
9. Which Market Need the ISO Operate?
(cont.)

So, operating a market for scheduled power is
irrelevant to the ISO’s reliability role. The ISO
could operate the “market” for unscheduled power
in the form of:


the market for Ancillary Services (if it centrally procures
A/S) and spread both the option cost and any difference
between the option exercise price and the price of
energy proportionately among the system participants
who caused the use of A/S and/or
the market for the contribution to frequency by
scheduling errors (Inadvertent Interchange), where A/S
may or may not be self-provided. I helped develop the
mechanism proposed by NERC’s Joint Inadvertent
Interchange Taskforce:
26




Balancing Authorities’ average hourly contribution to
frequency error in a month is assessed by taking the slope of a
line through the points representing hourly Inadvertent
Interchange and average frequency.
Balancing Authorities’s frequency contributions sum to zero
because all Inadvertent Interchange on an interconnected
system sums to zero.
The value of the Balancing Authority’s frequency contribution
is approximately megawatts times frequency error times some
single monetary unit.
A price may eventually be set in a market where BAs trade
frequency-control-contribution allowances to avoid any
penalty for non-compliance with NERC’s Control Performance
Standard 1.
Price arbitrage between separate A/S options market
and the market for frequency control contributions
(FCC). If the price for A/S options is cheaper, I will buy


A/S options to improve my performance in the FCC market,
instead of buying
allowances in the FCC market to avoid a performance penalty.

27
Markets for scheduled power will fail until
unscheduled power is priced. Market participants
will bypass the scheduled market in order to take
or give unscheduled power for free



IPPs control gas turbines to a constant thermal rate for
minimum fuel cost, causing overgeneration and
overfrequency.
Balancing Authorities wind up passing these costs to
other Balancing Authorities, who hesitate to take unpaid
counter control-measures, or take those measures and
accumulate those positions without settling
Time-error correction is used on the Western
Interconnection


to automatically force immediate payback of Inadvertent
Interchange and prevent accumulation of unpaid unscheduled
power. But this method causes
further frequency instability generated by the rapid payback-inkind of unscheduled power.
28
Perverse Governor Response
40.8
60.2
40.6
60.1
60
40.4
40.2
59.9
Frequency
59.8
40
59.7
39.8
59.6
39.6
59.5
Poplar Hills MW Output
39.4
39.2
8:24:00
59.4
8:31:12
8:38:24
8:45:36
8:52:48
9:00:00
9:07:12
POPLAR H.A790S POPLAR HILL GEN .AV
9:14:24
9:21:36
Freq
9:28:48
59.3
9:36:00
29
Measuring a BA’s FCC.
A Balancing Authority i's Frequency Contribution Component is the negative of a "2-dimensional average" of Inadvertent and Frequency-error each weighted by Frequency error.
The "2-dimensional weighted average" is the slope of a line from the origin
through the
intersection of the lines intercepting the two weighted averages.
Period t
1
2
3
4
Sum =
Ft
4
1
-4
1
2
2
I i, t I i ,t Ft F t
-2
-1
4
8
9
-8
-1
-16
8
-17
I
in MW
i
4-period scatter of Balancing Authority i's
<Frequency-error, Inadvertent>
points
16
1
16
1
 Ft , I i, t 
denoted by the 4 red dots
34
Average Frequency-error
weighted by Frequency-error
34
1 4
F   (F t F t)  F 2t 
4
4 t 1
8

I i,t Ft
F t
2
8
2
 -½
Slope
is "2-dimensional average"
of Inadvertent & Frequency-error
each weighted by Frequency-error
8 F in mHz
i's Average Inadvertent
weighted by Frequency-error
1 4
-17
I i   ( I i, t   Ft)  I i ,t  Ft
4 t 1
4
30
Hz of F h
31
Pricing FCC by Trading CPS1 Deviation Rights.
CPS1's cut/band becomes FCC p’s cut when bias Bi=0 for inframarginal Inadvertent not
being subject to CPS1 compliance, and provided p10 = k  Fh) 2 .
Settlement of all FCC p puts everyone at FCC p’s cut.
FCChor Inadvertent Interchange (II) is traded just to put everyone inside CPS1’s cut/band .
There is excess demand for traded FCC h s outside CPS1's cut/band when  F t  
whence purchase of new resources reduces the excess demand and  Ft .
CPS1
 FCC p
 F
 F
h
-
+
t
Isoquants
AVG I i  F h 
+ Isoquants
 T  F
AVG  i
 -10Bi
t
 F
2
t




I i ,bad Ti , good
I i , good
Ti,bad
-
 
+
 F h
Vertical cut
 F
+
t
Horizontal band
: buys FCC,
II, or response
: buys
regulation
FCCp's vertical cut gets stretched right from the middle into CPS1's horizontal band.
BA outside his CPS1 cut/band buys enough FCC h or II from BAs & to get inside his
CPS1 cut/band & avoid CPS1 penalty, and thereby helps set the FCC h settlement price p10 
or the II settlement price pI and position the dots in FCCp for systemwide settlement at that price.
32
10. Narrowing the (Sub-Hourly) Energy
Market Interval Addresses Reliability
Ineffectively.



Decreasing the energy-market interval increases the ISO’s
forecasting error.
In intervals less than 15 minutes, at least 50 % of quantity
varies randomly, and so is impossible to predict.
1 hour energy market interval is sufficient, with offschedule variability captured entirely by the A/S options
market because


Variability exclusively drives option prices (by increasing the
opportunity to exercise the option). So
Options better reflect variability than any attempt to predict
quantity in short subhourly energy market intervals.
33
11. Economic Reserve and Energy
(=Forward) Markets

2nd “market compatible” definition of Reliability
(continued): Reliability is not about satisfying economic
demand at any particular price. That is the market’s job
alone.


No economic reserve requirement. The market is a substitute
for targeting/planning supply and demand at a given price.
A forward market for bilateral contracts provides market-based
economic reserve and a “natural” cap on prices.
34
11. Economic reserve and energy
(=forward) markets (cont.)

Too much use of spot markets:



causes price volatility and prompts price capping. Price
capping
inhibits capital-cost recovery. So, this
prompts use of an icap market to attempt to recover capital cost.
Icap markets fail because already installed capacity is not price
sensitive. Price is:


zero when supply exceeds demand, and
infinity when demand exceeds supply. In other words
icap market has a vertical supply curve
35
icap supply is not discretionary.
It is all-at-once available for a price marginally above 0
when it exceeds demand.
When demand exceeds supply the price is infinite.
Price

icap supply curve
vertical
demand
curve
0
Quantity
36
12. Contingency Reserve:
Performance Requirement or
Reserve Requirement?



No scientific basis exists for determining
contingency reserve adequacy
Reserve adequacy is reflected in good
performance
A performance requirement leaves determination
of reserve adequacy up to each Balancing
Authority.
37
12. Contingency Reserve:
Performance Requirement or
Reserve Requirement? (cont.)

NERC’s CPS1 Performance standard is scientific
and based on the less-than-one-event-in-tenyears definition of “reliable”. If the probability of
at least the largest contingency is greater than
once-in-10-years, then reduce it by narrowing the
CPS1 average-frequency-deviation allowance
band to narrow the probability distribution of
frequency error and slim the tails .
38
Reducing the Standard Deviation Bandwidth to Reduce the Area/Probability under the Tails of
the Distribution
NormalDistribution4SD
NormalDistribution
0.0239
0.0209
0.0179
0.0119
0.0089
0.0059
0.0029
FrequencyError(Hz)
0.250
0.200
0.150
0.100
0.050
0.000
-0.050
-0.100
-0.150
-0.200
-0.0001
-0.250
Probability
0.0149
39
13. Maintaining Frequency Performance
by Economic Control-Performance
Assessment. Maintaining System
“Bias” by Governor Response
Requirement.

Bad scheduling performance


ISOs charge all consumers for the cost of Ancillary
Services instead of charging the bad
performers/schedulers.
Scheduled frequency has drifted on the US Eastern
Interconnection reflecting economically-driven
accumulation of unsettled accounts for Inadvertent
mInterchange for lack of any settlement requirement or
pricing.
40

Bad governor response

Disabling of governors by merchant generators because




No required level of governor response (“bias obligation”)
NERC control performance loophole. The single CPS1
performance equation includes



service not paid for, and
governor response is the most expensive A/S due to generator
wear & tear.
governor response as one of 2 variables.
Slower response (AGC, regulation, load following) is the other
variable.
So, BAs achieve CPS1 average performance target by
reducing governor response and increasing slower
response.
Result: halving of Eastern Interconnection “bias”.
Greater likelihood to trip load-shed relays.
41
in The New York Times, August 20, 2003:
10
42
Primary Response Stabilizes Frequency
Generator slows down while governor opens steam-control valve to stop the slow-down
by offsetting torque that otherwise reduces output. Fuel is increased to maintain pressure.
Interconnection’s Overall Primary Response equals Intcrconn.’s Overall Scheduling Error.
60
Seconds
15
59.925
Hz
(Shared)
Primary Response
60
59.925
Hz
1
Secondary Response (should be made by the BA who caused the disturbance)
10
Minutes
Secondary Response Restores Frequency
Operator increases fuel intake even more to produce more steam and raises steam-control
valve set-point to increase steam flow to even more than before to increase torque.
As generator speeds back up to normal speed, governor closes-back steam-control valve
eliminating the fueling of primary response, with more steam flow at same steam
pressure & same turbine speed as before the disturbance,for increased torque/output.
Balancing Authority’s Secondary Response to his own error
replaces Interconnection’s Shared Primary Response to that error.
43
Eastern Interconnection Frequency Response
3800
MW/0.1Hertz
3700
y = -70.531x + 144335
3600
3500
3400
3300
3200
3100
3000
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
44
MW/0.1 Hz
WECC Frequency Response
1600
1550
1500
1450
1400
1350
1300
1250
1200
1150
1100
1998
1999
2000
Year
2001
2002
45
46
47
E a s te rn In te rc o n n e c tio n 4 /2 3 /0 2
T o ta l L o a d 2 8 0 ,0 0 0 MW G e n e ra tio n L o s s 2 5 0 0 MW
L o a d L in e a r w ith F re q . p lu s 1 0 0 0 MW o f G o v. R e s e rve s
Gen & L o ad (MW )
59.5 Hz relay trip not reached and no load is shed
281000
61
280000
6 0 .8
279000
6 0 .6
278000
6 0 .4
GEN
277000
6 0 .2
LOA D
276000
60
275000
5 9 .8
274000
5 9 .6
273000
5 9 .4
272000
5 9 .2
271000
59
FRE Q
48
14. Proper Transmission Congestion
Management.


Transmission and generation are substitutable but
generation has been favored.
Spot-market rights to congested transmission
collapse its value to the difference between energy
prices across a congested interface
49

14. Proper Transmission Congestion
Management. (cont.)
Need for physical rights or forward-market rights
to congested transmission, not just spot market
rights because



price certainty needed by builders/owners of new
transmission otherwise vulnerable to the risk that
sudden new generation makes the transmission
investment uneconomic
established firm value of transmission independent from
generation needed to prevent generators on the cheap
side of the constraint from raising prices to capture
transmission rents.
Forward rights tend to be flow-path based rather
than transaction-path based.
50
price
Only physical/forward transmission
rights can prevent generators from
capturing congestion rents from
transmission owners. Cannot be
prevented by congestion contracts
that value congested transmission as
the difference in energy prices
across the congested interface.
Generators on the
cheap side of the
constraint collude
to raise prices to
capture congestion
rents from
transmission owner
congested price to consumer on expensive side
of constraint
Congestion charge
normally to
transmission owners
Supply curve
energy price to generator on cheap side
of constraint
Demand curve
congestion
quantity
51
15. Eliminate Priority of Unscheduled
Flow & Loop Flow by Performing
Near-Real-Time Transmission
Loading Relief.


To prevent unscheduled flow and loop flow from
preempting scheduled transactions, available
hourly, not daily, data on unscheduled flow and
not just on scheduled flow needs to be fed into
NERC’s Interchange Distribution Calculator used
for Transmission Loading Relief.
Same procedure as needed to prevent wide-area
cascading by power surge.