Highlights of the
2012 Annual Report on the
ISO New England Markets
David B. Patton, Ph.D.
Potomac Economics
External Market Monitor
June 12, 2013
1
Introduction
•
Potomac Economics serves as the External Market Monitor (“EMM”) for the ISO
New England. In this role, we:
 Evaluate and report on the competitive performance and operation of the wholesale
markets operated by ISO New England;
 Identify and recommend necessary changes to existing and proposed market rules,
tariff provisions and market design elements; and
 Evaluate the quality and appropriateness of mitigation by the Internal Market
Monitor.
•
This presentation summarizes our assessment of New England’s wholesale power
markets in 2012. We address two primary areas:
 The prices and the operational efficiency of the markets; and
 The competitive performance of the markets.
•
In addition to our findings in these two areas, we also present recommendations for
potential improvements in the ISO’s markets.
-2-2-
Introduction
•
•
The current wholesale electricity markets began operation in March 2003.
•
ISO New England’s markets currently include:
ISO New England has made enhancements to the markets and introduced new
markets for other products that have improved market performance.
 Day-ahead and real-time energy: coordinates commitment and production from the
region’s generation and demand resources, and facilitates wholesale energy trading;
 Financial Transmission Rights (“FTRs”): allows participants to hedge the
congestion costs associated with delivering power over the network;
 Forward and real-time operating reserves: ensures that sufficient resources are
available when a contingency occurs;
 Regulation: allows the ISO to instruct specific units to adjust output moment-bymoment to balance system supply and demand; and
 Forward Capacity Market (“FCM”): intended to provide efficient long-term market
signals to govern decisions to invest in new generation and demand resources and to
maintain existing resources.
-3-
Benefits of the ISO New England Markets
The ISO New England markets produce substantial benefits in the following areas:
•
Efficient commitment of generation: Coordinated commitment of generation
through the day-ahead market produces savings relative to decentralized systems by:
 Reducing the quantity of generation that is committed; and
 Ensuring that the most economic generation is committed.
•
Efficient dispatch and congestion management: Total dispatch costs are reduced by:
 Producing energy from the most economic supply and demand resources;
 Employing the lowest cost re-dispatch options to manage congestion; and
 Fuller utilizing of the transmission capability in the region.
•
Enhanced reliability: Reliability is improved because the real-time dispatch provides
much more responsive and accurate control of power flows on the transmission
system than the previous Transmission Line Loading Relief procedures (“TLR”).
•
Efficient price signals: The prices produced by the energy and capacity markets
provide a transparent economic signal to guide short-term and long-term decisions
by participants and regulators.
-4-4-
Highlights of Market Performance in 2012
•
•
Based on our evaluation of the markets in New England (in both constrained areas
and the broader market), we find that the markets performed competitively in 2012.
Energy prices fell 22 percent from 2011 to 2012, due primarily to the reduction in
natural gas prices (the dominant fuel in New England), which fell 21 percent on
average from 2011.
 The correspondence of fuel prices and offer prices in New England is an indication of
the competitiveness of ISO-NE’s markets.
•
Other variations in supply and demand contributed to the reduction in energy prices:
 On the demand side, average load fell in 2012 by 1 percent across all hours and by 6
percent in the first quarter because of milder winter weather. The summer peak load
fell 7 percent from 2011 to 2012.
 On the supply side, a new 620 MW gas-fired combined cycle unit in Connecticut
entered the market in mid-2011.
– In addition, nuclear generation and imports from neighboring areas rose by an
average of 570 MW combined in 2012.
•
Real-time automated mitigation was successfully implemented in April 2012.
 This enables the ISO to identify and prevent the abuse of market power in a more
timely and accurate fashion than the previous manual process.
-5-
Prices and Market Operations
Energy Prices
•
The first figure shows the load-weighted average day-ahead price at the New England
Hub and the average natural gas price for each month in 2011 and 2012.
 Overall, energy prices fell 22 percent from 2011 to 2012, primarily due to the 21
percent decrease in natural gas prices.
– Lower fuel costs should translate to lower offer prices and, thus, lower market clearing
prices in a competitive, well-functioning market.
•
Implied Marginal Heat Rates (energy price ÷ gas price) in the second figure isolate
changes in energy prices that are not related to the changes in natural gas prices.
 This metric typically rises when natural gas prices fall because a small share of
generation costs is not related to fuel prices.
 However, the implied marginal heat rates fell 1 percent from 2011 to 2012, due to:
–
1 percent decrease in average load levels;
–
300 MW increase in average net imports from neighboring areas; and
–
260 MW increase in nuclear generation due to fewer outages.
-7-
Day-Ahead Energy and Natural Gas Prices
2011 & 2012
Monthly Average Day-Ahead Prices and Natural Gas Prices
New England Hub, 2011 to 2012
$80
Average Prices
Day-Ahead Natural Gas
2011
$48.57
$5.08
2012
$38.09
$4.00
Day-Ahead Price
Natural Gas Price
$60
$7.5
$50
$40
$5.0
$30
$20
$2.5
$10
$0
2011
Note: The energy prices are load-weighted averages.
-8-
2012
Dec
Nov
Oct
Sep
Aug
Jul
Jun
May
Apr
Mar
Feb
Jan
Dec
Nov
Oct
Sep
Aug
Jul
Jun
May
Apr
Mar
Feb
$0.0
Jan
Electricity Price ($/MWh)
$70
Natural Gas Price ($/MMbtu)
$10.0
Average Implied Marginal Heat Rate
Monthly Average
2011 Marginal
& 2012 Heat Rate
Based on Day-Ahead Prices at the New England Hub, 2011 to 2012
Implied Marginal Heat Rate
2011
9.6
2012
9.5
12
10
8
6
4
2
2011
2012
-9-
Dec
Nov
Oct
Sep
Aug
Jul
Jun
May
Apr
Mar
Feb
Jan
Dec
Nov
Oct
Sep
Aug
Jul
Jun
May
Apr
Mar
Feb
0
Jan
Average Heat Rate (MMbtu/MWh)
14
Operating Reserve Constraints and Clearing Prices
•
The next figure summarizes average reserve clearing prices in each quarter of 2011
and 2012 for: (a) all three service types outside the local reserve zones (on the left);
and (b) for 30-min reserves only in the three local reserve zones (on the right).
 Each price is broken into components associated with each class of reserve.
– For example, the system-level 10-min spinning price is based on the costs of meeting
three requirements: the 10-min spinning, 10-min total, and 30-min requirements.
•
The figure shows that reserve constraints bound infrequently in 2011 and 2012.
 The system-level 10-min spinning reserve requirement bound most frequently (in
roughly 3.4 percent of the intervals), down slightly from 2011.
 30-min reserve prices in local areas were almost identical to those in other areas
because the local reserve requirements were rarely binding.
•
The clearing prices for all reserve types rose from 2011 to 2012, primarily in the
second half of 2012, due primarily to two significant market rule changes.
 The RCPF for the system-level 30-min reserve rose from $100 to $500/MWh on June
1, 2012 (which sets prices during reserve shortages).
 The system-level 30-min reserve requirement rose in July 2012, consistent with the
25 percent increase in the system-level 10-min requirement.
-10-
Operating Reserve Constraints and Clearing Prices
By Quarter 2011-2012
$6
Local 30-Minute Component 2
$5
Local 30-Minute Component 1
System 10-Minute Spin Component
Average Price ($/MWh)
System 10-Minute Component
$4
System 30-Minute Component
$3
$2
$1
$0
2011 2012
TMSR
2011 2012
TMNSR
Rest of System
2011 2012
TMOR
-11-
2011 2012
SW Conn
2011 2012
2011 2012
Connecticut
Boston
Local Area TMOR
Virtual Trading and Uplift Allocation
•
The overall volume of virtual scheduling have decreased substantially since 2010.
 Most of the decline was due to a sharp decrease at the nodal level in May 2010. The
ISO deployed a software solution in May 2010 to correct an inconsistency in loss
modeling at certain locations that had motivated a large share of the nodal trading.
 Virtual trading at hubs and zones decreased in 2012 in response to smaller
differences between DA and RT prices.
 Recent FERC enforcement actions against virtual traders in a number of markets
have likely increased the perceived regulatory risks associated with virtual trading.
•
NCPC charges to virtual trades remained high in 2012 largely because the reduction
in virtual trading reduced the base of deviations to which costs are allocated.
 The high NCPC rate may have contributed to the decrease of virtual trading, which
likely hindered the natural market response to RT price premiums since 2010.
 The current NCPC allocation scheme over-allocates costs to deviations relative to the
portion of the NCPC they likely cause. We are working with the ISO and IMM to
develop changes to the NCPC allocation that would improve its efficiency.
•
Virtual traders netted a profit of $5 million (not including NCPC charges) in 2012.
 This indicates that virtual trades generally improved price convergence.
 However, when NCPC charges are considered, overall virtual trading was
unprofitable with an overall net loss of $4 million.
-12-
$10
$5
$0
1200
Cleared Virtual (MW/h)
1000
Virtual Load
Virtual Supply
VL Profit
VS Profit
$12
$10
800
$8
600
$6
400
$4
200
$2
0
$0
-200
-$2
-400
-$4
-600
-$6
-800
-$8
-$15.5
-1000
-$10
-1200
-$12
2010
2011
2012
2010
Nodes
2011
Zone/Hub/Proxy
-13-
2012
Virtual Profitability ($/MWh)
RT NCPC Rate ($/MWh)
Virtual Trading and Uplift Allocation
2010-2012
Transmission Congestion and FTRs
•
The following figure shows day-ahead and real-time congestion prices and FTR prices for
each of the eight ISO-NE load zones in 2011 and 2012.
•
Congestion increased modestly in 2012 --- day-ahead congestion revenues totaled $30
million in 2012, up from $18 million in 2011.
 The increased congestion level was attributable to several factors:
– Peak load conditions occurred more frequently in 2012, leading to more frequent
congestion into import-constrained areas in the summer months;
– Congestion increased in areas where planned transmission outages substantially
affected the network capability (e.g., Western Central Massachusetts) ; and
– Natural gas prices rose sharply in November and December 2012, increasing
redispatch costs and associated congestion-related price differences.
•
 Nonetheless, the levels of congestion revenues are still far below: (a) the historic
levels that prevailed before transmission upgrades completed in 2009; and (b) the
levels seen in other LMP markets.
The FTR markets performed reasonably well in 2012.
 The consistency of FTR prices and congestion patterns improved substantially overall
in 2011 and 2012 from prior years.
 As expected, monthly FTR prices were more consistent with congestion patterns than
annual FTR prices because more information is available.
-14-
Transmission Congestion and FTR Auction Prices
$2.0
FTR Monthly Clearing Price
$1.5
Day-Ahead Congestion Component
Real-Time Congestion Component
$1.0
$0.5
2011
2012
-15-
CT
NEMA
VT
WCMA
RI
SEMA
NH
ME
CT
NEMA
VT
WCMA
RI
SEMA
-$0.5
NH
$0.0
ME
Avg. Difference from New England Hub ($/MWh)
FTR Long-Term Clearing Price
External Interface Scheduling
•
•
Power is usually imported from Quebec and New Brunswick, rising in peak hours
(1,640 MW in 2012) and falling in off-peak hours (1,480 MW in 2012), consistent
with hydro operations.
New England and New York are connected by three interfaces.
 Exports are consistently scheduled across two small interfaces from Connecticut to
Long Island (averaging 360 MW in 2012).
 Power flows in either direction on an hourly basis over the large primary interface
between areas (averaging roughly 235 MW from New York in 2012).
– The spread in natural gas prices between New England and New York has been an
important driver of the variations in interchange between the two markets.
•
The following table evaluates the relationship between real-time schedules and
clearing prices for NE and NY across the three interfaces in 2012.
 Power was scheduled in the inefficient direction (from the high-priced market to the
low-priced market) in 48 percent of the hours across the primary interface and in 42
percent of the hours over the two smaller interfaces.
– This inefficiently raises costs in both areas and lowers reliability.
 NE and NY are pursuing CTS to improve coordination between markets. We
recommend that the ISO-NE continue to place a high priority on this initiative.
-16-
Efficiency of Real-Time Schedules Between NE and NY
2012
Average
Net Imports
(MW/h)
Avg Internal Minus
External Price
($/MWh)
Percent in
Efficient
Direction
237
$0.59
52%
-108
-251
-$4.18
-$7.74
57%
58%
Free-flowing Ties
Northen New England
Controllable Ties
1385 Line
Cross Sound Cable
-17-
Real-Time Pricing and Market Performance
•
•
Efficient real-time prices (particularly during shortages) are important because they
encourage competitive scheduling by suppliers, participation by demand response
resources, and investment in new resources when and where needed.
The next two analyses evaluate the efficiency of real-time pricing during periods
when fast-start units were deployed in merit order in 2012.
 The first figure evaluates the extent to which the costs of fast-start units started by
UDS are reflected in energy prices by comparing their average offer costs with the
average real-time LMP over the commitment period (usually one hour).
–
Starts are shown according to the size of the difference between the average total offer
and the average real-time LMP over the initial commitment period.
–
This comparison is shown separately for hydro and thermal peaking units.
 The second figure evaluates how real-time prices would be affected if the average
total offers were fully reflected in real-time LMPs.
–
The lower portion shows how frequently thermal and hydro fast-start units were
started by UDS in merit order when their average total offers were greater than the
real-time LMP during the initial commitment period.
–
The upper portion shows the difference between the average total offer and the realtime LMP from these periods averaged over the year by hour of day.
-18-
Real-Time Pricing of Fast-Start Resources
• The full deployment costs of peaking units (particularly thermal units) were
frequently higher than real-time LMPs. In 2012:
 Less than 30 percent of thermal peaking starts and hydro starts were ‘economic’ (i.e.,
the average total offer < the average real-time LMP).
 29 percent of offers from thermal peaking units and 5 percent of offers from hydro
units exceeded the average real-time LMP by at least 50 percent.
 NCPC results when fast-starts are started and their costs are not reflected in LMPs.
• Fast-start units were started by UDS when their average total offer exceeded the realtime LMP over the initial commitment period in 9 percent of all hours in 2012.
 If the average total offers were fully reflected in the energy price, the average realtime LMP would increase by more than $2/MWh and the uplift would reduce by more
than $6 million in 2012.
– The impact can be much higher on individual days or during individual hours (e.g.,
the average price impact during hour 19 would be over $7/MWh.)
– These estimates likely overstate the impact from more efficient RT pricing because
they do not consider the market responses to the higher RT prices.
 Although hydro generation accounted for the majority (over 80 percent) of fast-start
generation that was started by UDS in merit order, the operation of thermal peaking
resources occurred during tighter operating conditions.
-19-
Real-Time LMPs vs. Offers of Fast-Start Generators
First Hour Following Start-up by UDS, 2012
500
2000
Offer (w/o Startup) > LMP by 50% or more
Offer (w/o Startup) > LMP by 0 to 25%
1600
Offer (w/o Startup) < LMP
350
1400
Offer (including Startup) < LMP
1000
200
800
150
600
100
400
50
200
0
2011
2012
250
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
1200
2011
2012
300
2012
Avg
2012
Avg
Thermal Peaking Generation
Hydro Generation
-20-
0
Average Megawatt-Start Per Day (Hydro)
400
1800
Offer (w/o Startup) > LMP by 25 to 50%
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Average Megawatt-Start Per Day (Thermal)
450
Difference Between RT LMPs and Offers of Fast-Start Units
First Hour Following Start-up by UDS - 2012
$8
Average Price Effect of Setting
LMPs based on Total Offer Costs
Thermal and Hydro
Hydro Only
$4
$2
$0
30%
20%
0%
2011
2012
10%
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Percent of Intervals
Frequency of Intervals When
Average Total Offer > LMP
2012
Avg
-21-
$/MWh
$6
Real-Time Pricing and Market Performance
•
We also evaluated three other important aspects regarding the RT pricing and dispatch and
made a total of three recommendations to improve real-time market performance.
 Real-Time Pricing during Operating Reserve Shortages: When the marginal cost of
meeting system-level 30-min reserve requirements exceeds the RCPF, this can result
in inefficient real-time prices.
–

Real-Time Pricing During Demand Response Activation: Demand response has
surged from 530 MW in January 2006 to nearly 2,800 MW in January 2013.
–
–

The ISO replaced the $100 RCPF for system-level 30-minute reserves with the $500
RCPF on June 1, 2012. This has reduced the need for manual actions to maintain
reserves and provide more efficient price signals during reserve shortages.
Although these resources provide substantial benefits, they also pose significant
challenges for efficient real-time pricing (i.e., real-time price levels did not always
fully reflect the cost of deploying these resources to maintain reliability).
However, in 2012, there were no capacity deficiencies that required activation of
emergency DR resources, so the markets were not affected by the pricing issues.
Ex Ante and Ex Post Pricing: the ISO re-calculates prices after each interval (“ex
post pricing”) rather than using the prices produced by the real-time dispatch model.
Our evaluation of ex post prices in New England indicates that it:
– Biases prices upward slightly in uncongested areas, and
– Sometimes distorts the value of congestion into constrained areas.
-22-
Commitments for Local and System Reliability
•
•
The ISO commits additional resources after the day-ahead market to maintain
reliability. These commitments increase uplift costs and affect real-time prices.
Following the completion of transmission upgrades in Boston, CT, and SEMA in
2009, the need to commit generation to satisfy local reliability fell significantly.
 Local reliability commitments also help satisfy system-wide requirements.
 Hence, supplemental commitment for system-wide reserves has increased since 2009.
•
The following figure shows that supplemental commitments rose modestly in 2012.
 Local reliability commitment rose in Maine and Western Central Massachusetts
where planned transmission outages led to increased local needs.
 System-wide supplemental commitments also rose in 2012, although the amount was
still significantly lower than in the years prior to 2010.
– The sharp rise in supplemental commitment following the arrival of Superstorm Sandy
accounted for a substantial share of the increase.
•
Variations in supplemental commitments led to similar changes in uplift charges.
 Uplift payments for local reliability rose by $12 million in 2012.
 “Economic” NCPC uplift associated with non fast-start resources (which are
primarily committed for system-level reserves) rose by more than $6 million in 2012.
-23-
Commitment for Reliability by Zone
Committment
for Hour,
Local Reliability
Zone
Daily Peak
2011 by
– 2012
Daily Peak Hour, 2011-2012
200
RAA/RT - Local 2nd Contingency
180
RAA/RT - 1st Contingency & System Reserves
Committed Capacity (MW)
160
RAA/RT - Voltage Support
140
SCR
120
DA - Voltage Support
100
80
60
40
20
0
2011
2012
Maine/N.H.
/ Vermont
2011
2012
West-Central
Massachusetts
2011
2012
Rhode Island
2011
2012
Southeast
Massachusetts
2011
2012
2011
Connecticut
Note: The category RAA/RT – First Contingency & System Reserves shows capacity committed for
local first contingency protection and for system-level reserve requirements together since the ISO
does not maintain data that distinguishes between these two reasons for commitment.
-24-
2012
Boston
Improvements in Market Operations
We are supportive of several ISO initiatives that will improve the recognition of the
capacity required to maintain reliability:
• Replacement Reserves Procurement – The ISO proposes a Replacement Reserve
requirement before the 2013/14 Winter period, which will result in the procurement
of additional 30-minute reserves using an RCPF reflecting their value ($250/MWh).
• Off-line Reserve Auditing – The ISO is improving its methods for determining the
off-line reserve capability of fast-start resources to help ensure consistency between
the offered performance and the actual performance.
• On-line Reserve Auditing – The ISO is also improving its methods for determining
the capability of on-line resources to provide reserves.
• These initiatives are expected to lead to more accurate calculation of the amount of
available resources, which should:
 Lead to higher real-time clearing prices for energy and reserves during tight operating
conditions when reliable generator performance is most important;
 Reduce NCPC uplift charges, improve the incentives for generator commitment in the
day-ahead market, and provide signals for investments to improve performance by
both new and existing resources..
-25-
Forward Capacity Market
•
Each FCA held so far has procured a significant amount of excess capacity, largely
due to the effects of the price floor that prevents capacity prices from falling
sufficiently to clear only the minimum requirement.
 When the floor is eliminated beginning in FCA 8, the clearing price will likely fall
significantly due to the level of existing capacity and the vertical demand curve
implicit in the FCM design.
•
Despite improvements made in recent years, the current FCM design is not likely
facilitate the efficient entry and exit of resources in New England.
 Most of the new investment in generation under FCM has been motivated by out-ofmarket payments related to RFPs of the Connecticut DPUC.
 A large share of capacity that has attempted to go out-of-service by de-listing has
been unable to do so for reliability reasons.
•
We believe it is critical to introduce market reforms to address these issues before the
current surplus of capacity declines and recommend that the ISO:
 Adopt a sloped demand curve that recognizes the benefits of installed capacity
beyond what is necessary to satisfy planning reserve requirements; and
 Determine whether the Rationing Election and the Capacity Commitment Period
Election will promote efficient investment and FCM outcomes over the long-term.
-26-
Competitive Assessment
Structural Indicators of Market Power
•
•
The competitive assessment includes structural assessments of market power in New
England and evaluations of participant conduct.
The structural assessment relies on a pivotal supplier analysis, which helps identify
conditions when a supplier may have market power.
 A supplier is “pivotal” when energy and operating reserve needs cannot be satisfied
without the supplier in the real-time market.
•
The following figure summarizes the pivotal supplier analyses, showing:
 The largest suppliers in Connecticut and Boston were pivotal in almost 60 percent of
hours and in 34 percent of hours in all of New England.
 When we exclude nuclear capacity, results in Boston are unchanged while a supplier
was pivotal in 25 percent of hours in All of New England and in only 1 percent of
hours in Connecticut.
 The pivotal frequency in All of NE fell notably in 2012 because:
– The size of some large suppliers decreased during 2012 (e.g., the portfolio of the
largest supplier fell 750 MW and the third largest supplier lost about 600 MW); and
– A significant portion in the largest supplier’s portfolio is coal-fired capacity, which
was economically committed less frequently in 2012 than in prior years because of
lower natural gas prices.
-28-
Frequency of Pivotal Suppliers by Region
2011 – 2012
Frequency of One or More Pivotal Suppliers
All Hours - 2011 - 2012
Fraction of Hours With Pivotal Supplier
100%
90%
All Capacity
80%
Excluding Nuclear Capacity
70%
60%
50%
40%
30%
20%
10%
0%
2011
2012
All New
England
2011
2012
Connecticut
2011
2012
Southwest
Connecticut
-29-
2011
2012
West
Connecticut
2011
2012
NorwalkStamford
2011
2012
Boston
Competitive Assessment: Evaluation of Potential Withholding
•
The competitive assessment examines market participant behavior to identify
potential exercises of market power through:
 Economic withholding (i.e., raising offer prices to reduce output and raise prices); or
 Physical withholding (i.e., reducing the claimed capability of a resource or falsely
taking a resource out of service to reduce output and raise prices).
•
The next two figures summarize our analyses, showing the results by load level for
the largest suppliers in New England and all other suppliers.
 Indicators of potential withholding are relatively low; and
 The quantity of potential withholding for the largest suppliers was comparable to the
levels for other suppliers (that are not likely to have market power).
•
Our report shows similar results for load pockets where the pivotal supplier analysis
indicated there was significant potential for local market power.
 Based on these results and the ongoing monitoring we performed over the year, we
find very little evidence that suppliers withheld capacity to raise clearing prices.
•
Suppliers can also exercise market power by raising their offer prices to inflate the
NCPC payments they receive when committed for local reliability.
 This was not significant in 2012 due to: (a) the relatively low level of local reliability
commitments; and (b) the mitigation rules made to address such conduct.
-30-
Average Output Gap by Load Level and Supplier
Average Output Gap by Load Level and by Supplier
New England - 2012
All of New England, 2012
5%
Offline Non-Quick Start
4%
3%
2%
1%
Supplier A
Supplier B
Supplier C
Other NE
Supplier A
Supplier B
Supplier C
Other NE
Supplier A
Supplier B
Supplier C
Other NE
Supplier A
Supplier B
Supplier C
Other NE
Supplier A
Supplier B
Supplier C
Other NE
0%
Supplier A
Supplier B
Supplier C
Other NE
Output Gap divided by Capacity
Online or Quick Start
Up to 15
15 to 17
17 to 19
19 to 21
21 to 23
23 and Up
New England Load Level (GWs)
-31-
Forced Outages and Deratings by Load Level and Supplier
The Ratio of Outage and Derating to Capacity
by Load Level and by Supplier
New England - 2012
All of New England, 2012
25%
Other Derate
Forced Outage
20%
15%
10%
Up to 15
15 to 17
17 to 19
19 to 21
New England Load Level (GWs)
-32-
21 to 23
Other NE
Supplier C
Supplier B
Supplier A
Other NE
Supplier C
Supplier B
Supplier A
Other NE
Supplier C
Supplier B
Supplier A
Other NE
Supplier C
Supplier B
Supplier A
Other NE
Supplier C
Supplier B
Supplier A
Other NE
Supplier C
0%
Supplier B
5%
Supplier A
Outage and Derate divided by Capacity
30%
23 and Up
Real-Time Automated Mitigation Procedure (“AMP”)
•
ISO-NE implemented real-time AMP in Apr. 18, 2012, which includes:
 System wide mitigation – All units are subject to a market-wide Pivotal Supplier Test
and conduct thresholds of: i) a $100/MWh or 300% increase in the energy offers; or ii) a
200% increase in the commitment offers (i.e., start-up and no-load).
 Constrained area mitigation – Units in these areas are subject to more stringent
thresholds of: (a) a $25/MWh or 50% increase in the energy offers; or (b) a 25% increase
in the commitment offers.
 Local reliability mitigation – Units committed for local reliability are subject to the
threshold of a $80 or 10% increase in the low load commitment cost.
•
The next figure shows the frequency of each type of AMP mitigation by resource type
and the total number of hours that were affected in each month of 2012.
 As expected, mitigation rose considerably under the AMP, which occurred more than
250 times in 2012.
– AMP enables the ISO to identify and prevent the abuse of market power in a more
timely and accurate fashion than the previous manual process.
 Commitment mitigation accounted for 63% of all mitigation, while energy mitigation
accounted for the remaining 37%.
– We have reviewed the mitigation and found that most were appropriate.
– However, some of mitigation can be attributed to inaccurate reference levels (MPs and
the IMM have been working on improving the reference levels).
-33-
Real-Time Automated Market Power Mitigation
200
359
343
150
100
50
Total Number of Mitigations
40
0
35
Thermal CC/Steam
30
Thermal Peaker
Hydro
25
20
15
10
5
0
AM J J A S O N D AM J J A S O N D AM J J A S O N D AM J J A S O N D AM J J A S O N D
Energy
Commitment
Commitment
Energy
Commitment
(CAE)
(CAC)
(RC)
(ME)
(MC)
Constrained Area
Local Reliability
Market Wide
Mitigation Type - Month
-34-
# of Hours Mitigated
April – December 2012
Recommendations
List of Recommendations
2012 ISO-NE Market Assessment
Recommendation
Wholesale
Mkt Plan
High
Benefit1
Feasible
in ST2
Energy Markets
1. Develop pricing changes to allow the costs of fast-start
units and operator actions to maintain reliability (e.g.,
export curtailments) to be reflected in real-time prices.


3. Develop provisions to coordinate the physical interchange
between New York and New England in real-time.


4. Modify allocation of “Economic” NCPC charges to make
it more consistent with a “cost causation” principle.


2. Develop pricing changes to allow the costs of deployed
demand response resources to be reflected in prices when
they are needed to avoid a shortage.

5. Modify inputs to the ex post pricing process to improve
consistency with ex ante prices.
6. Provide suppliers with the flexibility to modify their offers
closer to real time to reflect changes in marginal costs.



Notes:
Reserve Markets
1. Feasible in Short Term: Complexity and required software modifications are likely limited.
-367. High
Allow
ISO toWill
varylikely
the quantity
of considerable
replacement
reserves
in benefits.
2.
Benefit:
produce
efficiency
List of Recommendations (cont.)
High
Benefit1
Feasible
in ST2
1. Allow ISO to vary the quantity of replacement reserves in
the operating day to improve consistency between the
market outcomes and the ISO’s reliability needs.


2. Consider introducing day-ahead operating reserve markets
that are co-optimized with the day-ahead energy market.

Wholesale
Mkt Plan
Recommendation
Reserve Markets
Capacity Markets
3. Replace the current capacity requirement (i.e., vertical
demand curve) with sloped demand curve that recognizes
the value of additional capacity.
4. Evaluate the interaction of the Rationing Election and the
Capacity Commitment Period Election to determine
whether they will promote efficient investment and FCM
outcomes over the long-term.
-37-

