Section 10 – Ancillary Service Markets - Monitoring Analytics

34 Pages·2013·0.98 MB·English

Section 10 Ancillary Services
Ancillary Service Markets mitigation requires competitive offers when the three pivotal supplier test
is failed and there was no evidence of generation owners engaging in
The United States Federal Energy Regulatory Commission (FERC) defined anti-competitive behavior.
six ancillary services in Order No. 888: 1) scheduling, system control and
• Market performance was evaluated as indeterminate, after the introduction
dispatch; 2) reactive supply and voltage control from generation service; 3)
of the new market design. It is too early to reach a definitive conclusion
regulation and frequency response service; 4) energy imbalance service; 5)
about performance under the new market design because important
operating reserve – synchronized reserve service; and 6) operating reserve –
parts of the design are inefficient and because there is not yet enough
supplemental reserve service.1 Of these, PJM currently provides regulation,
information on performance.
energy imbalance, synchronized reserve, and operating reserve – supplemental
reserve services through market-based mechanisms. PJM provides energy • Market design was evaluated as indeterminate, after the introduction of
imbalance service through the Real-Time Energy Market. PJM provides the the new market design. While the market design continues to include
remaining ancillary services on a cost basis. Although not defined by the the incorrect definition of opportunity cost, overall the changes were
FERC as an ancillary service, black start service plays a comparable role. Black positive. The market design also includes the incorrect definition of the
start service is provided on the basis of incentive rates or cost.2 marginal benefits factor for purposes of settlement.3 It is too early to
reach a definitive conclusion about the new market design because there
The Market Monitoring Unit (MMU) analyzed measures of market structure, is not yet enough information about actual implementation of the design.
conduct and performance for the PJM Regulation Market, the two regional
Table 10‑2 The Synchronized Reserve Markets results were competitive
Synchronized Reserve and Non-Synchronized Reserve Markets, and the PJM
DASR Market for the first nine months of 2013. Market Element Evaluation Market Design
Market Structure: Regional Markets Not Competitive
Participant Behavior Competitive
Table 10‑1 The Regulation Market results were indeterminate for January
Market Performance Competitive Effective
through September, 2013
January through September 2013
Market Element Evaluation Market Design • The Synchronized Reserve Market structure was evaluated as not
Market Structure Not Competitive competitive because of high levels of supplier concentration. The MMU
Participant Behavior Competitive
estimates that the Synchronized Reserve Market had one or more pivotal
Market Performance To Be Determined To Be Determined
suppliers which failed the three pivotal supplier test in 5.6 percent of the
hours in January through September, 2013.
• The Regulation Market structure was evaluated as not competitive for the
• Participant behavior was evaluated as competitive because the market
year because the Regulation Market had one or more pivotal suppliers
rules require competitive, cost based offers.
which failed PJM’s three pivotal supplier (TPS) test in 91 percent of the
hours in January through September, 2013.
• Participant behavior in the Regulation Market was evaluated as 3 On October 2, 2013 FERC issued an order directing PJM to compensate regulating resources (the portion of each resource’s compensation
based on performance) based on a mileage ratio multiplier. This ratio will be the hourly mileage of the RegD signal / mileage of the RegA
competitive for January through September, 2013 because market power signal. This ratio increases the regulation performance compensation paid to high performing resources compared with regular resources.
Between October 2012 and September 2013 the average mileage ratio has been 3.11 compared to an average marginal benefit factor of
2.63. PJM will begin to settle the regulation market (performance segment) using the mileage ratio on November 1, 2013. PJM will then
1 75 FERC ¶ 61,080 (1996). recalculate performance regulation settlement for the purpose of adjusting the credits from October 1, 2012, through October 31, 2013.
2 For more details, see the 2012 State of the Market Report for PJM, Volume II, Section 9, “Ancillary Service Markets.” The regulation performance clearing price will not change.
© 2013 Monitoring Analytics, LLC 2013 Quarterly State of the Market Report for PJM: January through September 251
2013 Quarterly State of the Market Report for PJM: January through September
• Market performance was evaluated as competitive because the interaction Overview
of the participant behavior with the market design results in competitive
Regulation Market
prices.
The PJM Regulation Market continues to be operated as a single market.
• Market design was evaluated as effective because market power mitigation
rules result in competitive outcomes despite high levels of supplier
concentration. Market Structure
Table 10‑3 The Day‑Ahead Scheduling Reserve Market results were • Supply. In January through September 2013, the supply of offered and
competitive eligible regulation in PJM was both stable and adequate. The ratio of
Market Element Evaluation Market Design offered and eligible regulation to regulation required averaged 3.67. This
Market Structure Competitive is a 14.7 percent increase over January through September 2012 when
Participant Behavior Mixed
the ratio was 3.20.
Market Performance Competitive Mixed
• Demand. The on-peak regulation requirement is equal to 0.70 percent
of the forecast peak load for the PJM RTO for the day and the off-peak
• The Day-Ahead Scheduling Reserve Market structure was evaluated as
requirement is equal to 0.70 percent of the forecast valley load for the
competitive because market participants did not fail the three pivotal
PJM RTO for the day. The average hourly regulation demand in January
supplier test.
through September, 2013, was 784 MW. This is a 214 MW decrease in the
• Participant behavior was evaluated as mixed because while most offers
average hourly regulation demand of 998 MW in the same period of 2012.
appeared consistent with marginal costs (zero), 15 percent of offers
• Market Concentration. In January through September 2013, the PJM
reflected economic withholding.
Regulation Market had a weighted average Herfindahl-Hirschman Index
• Market performance was evaluated as competitive because there
(HHI) of 2063 which is classified as highly concentrated.4 In January
were adequate offers at reasonable levels in every hour to satisfy the
through September 2013, 91 percent of hours had one or more pivotal
requirement and the clearing price reflected those offers.
suppliers which failed PJM’s three pivotal supplier test (44 percent of hours
• Market design was evaluated as mixed because while the market is failed the three pivotal supplier test in January through September 2012).
functioning effectively to provide DASR, the three pivotal supplier test,
and cost-based offer capping when the test is failed, should be added to Market Conduct
the market to ensure that market power cannot be exercised at times of
• Offers. Daily regulation offer prices are submitted for each unit by the
system stress.
unit owner. Owners are required to submit a cost offer along with cost
parameters to verify the offer, and may optionally submit a price offer.
Under the new market design, offers include both a capability offer and
a performance offer. The performance offer is converted to $/MW by
multiplying the MW offer by the ΔMW/MW value of the signal type
4 See the 2012 State of the Market Report for PJM, Volume II, Section 2, “Energy Market,” at “Market Concentration” for a more complete
discussion of concentration ratios and the Herfindahl-Hirschman Index (HHI). Consistent with common application, the market share
and HHI calculations presented in the SOM are based on supply that is cleared in the market in every hour, not on measures of available
capacity.
252 Section 10 Ancillary Services © 2013 Monitoring Analytics, LLC
Section 10 Ancillary Services
of the unit. Owners must also specify which signal type the unit will of East Kentucky Power Cooperative (EKPC) into PJM on June 1, 2013,
be following, RegA or RegD.5 As of September 30, 2013, there were 22 had no impact on the Synchronized Reserve Market requirement because
resources offering performance regulation and following the RegD signal. the largest contingencies remain in the Mid-Atlantic Dominion Subzone.
The EKPC integration did, however, increase the availability of both Tier
• Price and Cost. The weighted average Regulation Market Clearing Price
1 and Tier 2 MW available throughout the RTO.
for the PJM Regulation Market for January through September 2013 was
$32.72. This is an increase of $17.80, or 119.3 percent, from the weighted In early June 2013, PJM implemented a modification to the way the
average price for regulation in January through September 2012. The cost transfer interface defines the Mid-Atlantic Dominion Subzone within the
of regulation from January through September 2013 was $37.35. This is a RTO Zone. The change makes calculations of the unit distribution factor
$16.77 (81.5 percent) increase from the same time period in 2012. (DFAX) values across the interface consistent with the way these values
are calculated in the energy market. Additionally, PJM calculates the most
Synchronized Reserve Market limiting interface in real time for each market optimization, ASO, IT-
Although PJM has retained the two synchronized reserve markets it implemented SCED and RT-SCED. For most hours it is Bedington – Black Oak. The
on February 1, 2007, their definition has changed. The RFC Synchronized second most common limiting interface is AP South.
Reserve Zone has incorporated the former Southern Synchronized Reserve • Market Concentration. For January through September 2013, the average
Zone into the RTO Reserve Zone. The former Mid-Atlantic Synchronized weighted HHI for cleared synchronized reserve in the Mid-Atlantic
Reserve Zone has incorporated the Dominion Zone to become the Mid-Atlantic Dominion Subzone was 4372 which is classified as highly concentrated.
Dominion Reserve Zone. PJM has the right to define new zones or subzones The average weighted cleared Synchronized Reserve Market HHI for
“as needed for system reliability.”6 the Mid-Atlantic Subzone in January through September, 2012, was
3202, which is classified as “highly concentrated.”7 In January through
Market Structure September, 2013, 58 percent of hours had a maximum market share
greater than 40 percent, compared to 45 percent of hours in January
• Supply. In January through September, 2013, the supply of offered
through September, 2012.
and eligible synchronized reserve was both stable and adequate. The
contribution of Demand Response (DR) to the Synchronized Reserve In the Mid-Atlantic Dominion Subzone, in January through September,
Market remains significant. Demand resources are relatively low cost, and 2013, the MMU estimates that 5.6 percent of hours that cleared a
their participation in this market lowers overall Synchronized Reserve synchronized reserve market had three or fewer pivotal suppliers. In
prices. January through September, 2012, the MMU estimates that 24 percent
of hours had three or fewer pivotal suppliers. The MMU concludes from
• Demand. PJM made a minor change to the default hourly required
these TPS results that the Mid-Atlantic Dominion Subzone Synchronized
synchronized reserve requirements on October 1, 2012. When the RFC
Reserve Market in January through September 2013 was characterized by
Zone became the RTO Zone on October 1, 2012, the synchronized reserve
structural market power.
requirement increased from 1,350 MW to 1,375 MW. Although the
Mid-Atlantic Subzone became the Mid-Atlantic Dominion Subzone on
October 1, 2012, the requirement remained at 1,300 MW. The integration
5 See the 2012 State of the Market Report for PJM, Volume II, Appendix F “Ancillary Services Markets.” 7 See Section 3, “Energy Market” at “Market Concentration” for a more complete discussion of concentration ratios and the Herfindahl-
6 See PJM. “Manual 11, Energy and Ancillary Services Market Operations,” Revision 61 (June 27, 2013), p. 66. Hirschman Index (HHI).
© 2013 Monitoring Analytics, LLC 2013 Quarterly State of the Market Report for PJM: January through September 253
2013 Quarterly State of the Market Report for PJM: January through September
Market Conduct DASR
• Offers. Daily cost based offer prices are submitted for each unit by the The purpose of the DASR Market is to satisfy supplemental (30-minute)
unit owner, and PJM adds opportunity cost calculated using the average reserve requirements with a market-based mechanism that allows generation
of 5-minute LMPs, which together comprise the total offer for each unit resources to offer their reserve energy at a price and compensates cleared
to the Synchronized Reserve Market. The synchronized reserve offer made supply at a single market clearing price. The DASR 30-minute reserve
by the unit owner is subject to an offer cap of marginal cost plus $7.50 requirements are determined for each reliability region.8 If the DASR Market
per MW, plus lost opportunity cost. All suppliers are paid the higher of does not result in procuring adequate scheduling reserves, PJM is required to
the market clearing price or their offer plus their unit specific opportunity schedule additional operating reserves.
cost.
Market Structure
Market Performance
• Concentration. The MMU calculates that in January through September,
• Price. The weighted average price for Tier 2 synchronized reserve in the
2013, zero hours in the DASR market would have failed the three pivotal
Mid-Atlantic Dominion Subzone was $6.86 per MW in January through
supplier test. The current structure of PJM’s DASR Market does not
September, 2013, a decrease of three percent over January through
include the three pivotal supplier test. The MMU recommends that the
September 2012. The total cost of synchronized reserves per MW in
three pivotal supplier test be incorporated in the DASR market.
January through September 2013 was $14.82, a 35 percent increase from
the $10.92 cost of synchronized reserve in January through September • Demand. In 2013, the required DASR is 6.91 percent of peak load forecast,
2012. The market clearing price was 51 percent of the total synchronized down from 7.03 percent in 2012.
reserve cost per MW in January through September 2013, down from 64
percent in January through September 2012. Market Conduct
• Adequacy. A synchronized reserve deficit occurs when the combination • Withholding. Economic withholding remains an issue in the DASR
of Tier 1 and Tier 2 synchronized reserve is not adequate to meet the Market. The direct marginal cost of providing DASR is zero, but there is
synchronized reserve requirement. Neither PJM Synchronized Reserve an opportunity cost associated with providing DASR. As of September
Market experienced a deficit in January through September period of 2013. 30, 2013, 15 percent of offers reflected economic withholding. PJM rules
Although supplies were always adequate to meet demand, an extended require that all units with reserve capability that can be converted into
spinning event on September 10 raised concerns that the current method energy within 30 minutes offer into the DASR Market.9 Units that do not
for estimating Tier 1 is incorrect. PJM has initiated studies designed to offer have their offers set to zero.
improve the accuracy of Tier 1 estimation. It is expected that by January
• DR. Demand resources are eligible to participate in the DASR Market,
1, 2014, the amount of Tier 1 estimated, especially during periods of high
but no demand resource cleared the DASR Market in January through
demand, will decrease as a result of changes to the estimation method.
September, 2013.
8 See PJM. “Manual 13: Emergency Operations,” Revision 53, (June 1, 2013); pp 11-12.
9 See PJM. “Manual 11, Energy and Ancillary Services Market Operations,” Revision 60 (June 1, 2013), p. 144.
254 Section 10 Ancillary Services © 2013 Monitoring Analytics, LLC
Section 10 Ancillary Services
Market Performance Table 10‑4 History of ancillary services costs per MW of Load: January
through September 2002 through 2013
• Price. The weighted DASR market clearing price in January through
Scheduling,
September 2013 was $0.93 per MW. In January through September 2012,
Dispatch, and Synchronized Supplementary
the weighted price of DASR was $0.75 per MW. Year Regulation System Control Reactive Reserve Operating Reserve Total
2002 $0.47 $0.52 $0.21 $0.00 $0.66 $1.86
2003 $0.53 $0.59 $0.23 $0.09 $0.88 $2.32
Black Start Service
2004 $0.50 $0.64 $0.25 $0.14 $0.90 $2.43
Black start service is necessary to help ensure the reliable restoration of the 2005 $0.78 $0.47 $0.25 $0.11 $0.88 $2.49
2006 $0.55 $0.48 $0.28 $0.07 $0.44 $1.82
grid following a blackout. Black start service is the ability of a generating unit
2007 $0.65 $0.47 $0.29 $0.06 $0.58 $2.05
to start without an outside electrical supply, or is the demonstrated ability of 2008 $0.75 $0.34 $0.29 $0.07 $0.55 $2.00
a generating unit to automatically remain operating at reduced levels when 2009 $0.36 $0.36 $0.36 $0.05 $0.47 $1.60
2010 $0.37 $0.38 $0.36 $0.06 $0.75 $1.92
disconnected from the grid.10
2011 $0.35 $0.36 $0.39 $0.09 $0.87 $2.06
2012 $0.23 $0.44 $0.44 $0.03 $0.75 $1.89
In January through September 2013 black start charges were $80.3 million. 2013 $0.27 $0.41 $0.69 $0.04 $0.66 $2.07
Black start zonal charges in January through September 2013 ranged from
$0.03 per MW-day in the ATSI zone (total charges were $95,492) to $10.30 Conclusion
per MW-day in the AEP zone (total charges were $65,557,476). For each
The design of the Regulation Market changed significantly effective October
zone, Table 10-23 shows black start charges, the sum of monthly zonal peak
1, 2012. While the market design continues to include the incorrect definition
loads multiplied by the number of days of the month in which the peak load
of opportunity cost, overall the changes were positive. It is too early to reach
occurred, and black start rates (calculated as charges per MW-day). For black
a definitive conclusion about performance under the new market design
start service, point-to-point transmission customers paid on average $0.08
because there is not yet enough information on performance. It is essential
per MW.
that the Regulation Market incorporate the consistent implementation of
Ancillary services costs per MW of load: January the marginal benefit factor in optimization, pricing and settlement. But the
experience of the last quarter of 2012 and the first three quarters of 2013 is
through September 2002 - 2013
cause for optimism with respect the performance of the Regulation Market
Table 10-4 shows PJM ancillary services costs for January through September under the new market design.
2002 through 2013, on a per MW of load basis. The Scheduling, System
Control, and Dispatch category of costs is comprised of PJM Scheduling, The structure of each Synchronized Reserve Market has been evaluated and
PJM System Control and PJM Dispatch; Owner Scheduling, Owner System the MMU has concluded that these markets are not structurally competitive
Control and Owner Dispatch; Other Supporting Facilities; Black Start Services; as they are characterized by high levels of supplier concentration and
Direct Assignment Facilities; and ReliabilityFirst Corporation charges. inelastic demand. (The term Synchronized Reserve Market refers only to Tier
Supplementary Operating Reserve includes Day-Ahead Operating Reserve; 2 synchronized reserve.) As a result, these markets are operated with market-
Balancing Operating Reserve; and Synchronous Condensing. clearing prices and with offers based on the marginal cost of producing
the service plus a margin. As a result of these requirements, the conduct
of market participants within these market structures has been consistent
10 OATT Schedule 1 § 1.3BB.
© 2013 Monitoring Analytics, LLC 2013 Quarterly State of the Market Report for PJM: January through September 255
2013 Quarterly State of the Market Report for PJM: January through September
with competition, and the market performance results have been competitive. Regulation Market Changes for Performance Based
Compliance with calls to respond to actual spinning events has been an issue.
Regulation
Compliance with the synchronized reserve must-offer requirement has also
Regulation is a key part of PJM’s effort to minimize ACE in order to keep the
been an issue.
reportable metrics CPS1 and BAAL within acceptable limits. On October 20,
The MMU concludes that the structure of the DASR Market was competitive 2011, FERC issued Order No. 755 directing PJM and other RTOs/ISOs to modify
in the first nine months of 2013, although concerns remain about economic their regulation market rules to make use of and properly compensate a mix of
withholding and the absence of the three pivotal supplier test in this market. fast and traditional response regulation resources.”13 Order No. 755 also sought
to correct “certain practices of some RTOs and ISOs result in economically
The benefits of markets are realized under these approaches to ancillary inefficient economic dispatch of frequency regulation resources.”14
service markets. Even in the presence of structurally noncompetitive markets,
there can be transparent, market clearing prices based on competitive offers A rationale for the new market design was the assumption that new, fast
that account explicitly and accurately for opportunity cost. This is consistent response technologies could be used, in combination with traditional resources,
with the market design goal of ensuring competitive outcomes that provide to reduce the total amount of resources needed to meet regulation requirements
appropriate incentives without reliance on the exercise of market power and and thereby reduce the cost of regulation. Order No. 755 required that the new
with explicit mechanisms to prevent the exercise of market power. and traditional resources be purchased in a single market, with compensation
for both capacity (MW) and miles (total MW per minute measured in ΔMW/
Overall, the MMU concludes that it is not yet possible to reach a definitive MW) provided.15 Prior to October 1, 2012, regulation consisted of energy that
conclusion about the new Regulation Market design, but there is reason for could be added or removed within five minutes following a traditional (RegA)
optimism. The MMU concludes that the Synchronized Reserve Market results signal. On October 1, 2012, the PJM introduced a single market that included
were competitive in the first nine months of 2013. The MMU concludes that two distinct types of frequency response: RegA (traditional and slower
the DASR Market results were competitive in the first nine months of 2013. oscillation signal) and RegD (faster oscillation signal). Within this new market
design, resources can choose to follow RegA or RegD.
Regulation Market
In a market defined in terms of units of RegA equivalent regulation service,
The PJM Regulation Market continues to be operated as a single market.
the marginal benefits factor of all units following the RegA signal is one,
Significant technical and structural changes were made to the Regulation
while the marginal benefits factor of units following the RegD signal depends
Market in 2012. On May 7, 2012, PJM switched to an improved optimizer
on how much RegD following resources are used. Under PJM’s August 15,
called the Ancillary Services Optimizer (ASO). On October 1, 2012, PJM
2012, proposal, the benefits factor can be as high as 2.9 but never lower
made additional technical changes to the optimized solution and, to comply
than zero. Effective regulation is a function of two components, the benefits
with FERC Order No. 755, implemented Performance Based Regulation.11 On
factor, which itself is a function of the amount of RegD regulation already
November 16, 2012, FERC modified the PJM market design that was introduced
committed; and the historical performance of the unit as measured by the
on October 1, 2012.12
100-hour average of performance scores. A unit’s regulation capability MW
13 Order No. 755 at P 3. FERC ordered PJM “to compensate frequency regulation resources based on the actual service provided, including
11 For a description of the full history of the changes to the tariff provisions governing the Regulation Market, see the 2011 State of the a capacity payment that includes the marginal unit’s opportunity costs and a payment for performance that reflects the quantity of
Market Report for PJM, Volume II, Section 9, Ancillary Service Markets.” frequency regulation service provided by a resource when the resource is accurately following the dispatch signal.”
12 PJM Interconnection, L.L.C., 139 FERC ¶ 141,134 (November 16, 2012) 14 Id. at P 2.
15 Id. at PP 99, 131 & 177
256 Section 10 Ancillary Services © 2013 Monitoring Analytics, LLC
Section 10 Ancillary Services
multiplied by its benefits factor, and modified by its performance score, results Figure 10‑1 Average performance score grouped by unit type and regulation
in that unit’s effective RegA signal following regulation MW. signal type: January through September 2013
100%
FERC’s November 16, 2012 order only partially accepted the market design RegA
in PJM’s August 15, 2012, filing. FERC’s November 16, 2012, order fixed the 90% Steam (RegA)
Hydro (RegA)
marginal benefits factor for RegD resources at a value of 1.0 for purposes of
DSR (RegA)
80%
payment. This created a dichotomy in the PJM regulation market between the CT (RegA)
marginal value of RegD resources in the dispatch, and the resulting market W RegD
M70%
price and payments to resources in the settlement process in PJM’s regulation e
p
market through the first quarter of 2013. al) Ty60%
n
g
Si
Performance tracking is an essential element of the performance based e (50%
urc
Regulation Market. Regulation performance scores (0.0 to 1.0) measure the o
es
R40%
response of a regulating unit to its chosen regulation signal (RegA or RegD) of
e
every ten seconds by measuring: delay, the time delay of the regulation ntag30%
response to a change in the regulation signal; correlation, the relationship erce
P
between the regulating resource output and the regulation signal; and 20%
precision, the difference in energy provided from the difference in energy
requested.16 An hourly performance score is calculated and multiplied by the 10%
MW cleared when calculating payment. Additionally, hourly scores are stored
0%
and used as part of a 100 hour rolling average historical performance score 0.51-0.60 0.61-0.70 0.71-0.80 0.81-0.90 0.91-1.00
to obtain an effective capability MW and performance MW used in clearing. Performance Score Range
Figure 10-1 shows the average performance score by unit type and signal
followed. Using a performance score to measure the accuracy of a regulating resource,
a mileage ratio to compare the effective MW of differing types of resources,
and effective MW as a means of translating the value of actual MW for high
performance units are the reasons that the required regulation has been
lowered from 1.0 percent to 0.7 percent of forecast peak load.
The performance based Regulation Market requires that unit owners provide
two-part offers for their regulation resources, an offer for regulation capability
in terms of $/MW and a regulation performance offer in terms of $/ΔMW. In
addition, unit owners must enter the regulation signal type the unit will follow,
RegA or RegD. Owners may enter price based offers subject to a combined
offer cap of $100/MW.
16 A full specification of each of the three criteria used in the performance score is presented in PJM “Manual 12: Balancing Operations”
Rev. 27 (December 20, 2012); 4.5.6, p 52.
© 2013 Monitoring Analytics, LLC 2013 Quarterly State of the Market Report for PJM: January through September 257
2013 Quarterly State of the Market Report for PJM: January through September
Market Structure lost opportunity cost, of the most expensive cleared regulation resource in
each interval. The total clearing price for the hour is the simple average of
Supply
the twelve interval prices within the hour. The total clearing price for the
Table 10-5 shows capability, average daily offer and average hourly eligible hour (RMCP) is in two parts, the performance clearing price (RMPCP) and the
MW for all hours. The hourly regulation capability decreased in January capability clearing price (RMCCP). The performance clearing price ($/MW)
through September 2013, to 8,411 MW from 9,413 MW during the same time is equal to the most expensive performance offer cleared for the hour. The
period of 2012. capability clearing price ($/MW) is equal to the difference between the total
clearing price for the hour and the performance clearing price for the hour.
Table 10‑5 PJM regulation capability, daily offer17 and hourly eligible: January
through September 2012 and 201318 Since the implementation of Regulation Performance on October 1, 2012, both
regulation price and regulation cost per MW are higher than they were prior
Regulation Average Daily Percent of Average Hourly Percent of
Period Capability (MW) Offer (MW) Capability Offered Eligible (MW) Capability Eligible to October 1, 2012 (Table 10-12). Since the implementation of shortage pricing
2013 (Jan-Sep) 8,441 3,981 47% 1,716 20%
and changing the regulation requirement to 0.70 percent of peak load forecast
2012 (Jan-Sep) 9,413 6,656 71% 3,089 33%
(from one percent of peak load forecast prior to October 1) the price and cost
of regulation have remained high. The weighted average regulation price for
The supply of regulation can be affected by regulating units retiring from
January through September 2013 was $32.72. The regulation cost for January
service. Table 10-6 shows what the impact on the Regulation Market would
through June 2013 was $37.35. The ratio of price to cost is significantly
be if all units retire that are requesting retirement through the end of 2015.
higher at 88 percent (compared with 72 percent in Q3 of 2012), meaning that
more of the costs are now part of the price.
Table 10‑6 Impact on PJM Regulation Market of currently regulating units
scheduled to retire through 2015
As of September 30, 2013, there were 22 resources following the RegD signal.
Current For January through September 2013, the weighted-average HHI of the set of
Regulation Units, Settled MW, Settled MW of Units Percent Of
RegD resources was 5494 (highly concentrated).
January through January through Units Scheduled To Scheduled To Retire Regulation MW To
September 2013 September 2013 Retire Through 2015 Through 2015 Retire Through 2015
306 5,125,625 33 54,484 1.06% In the period from January 1, 2013, through September 30, 2013, the marginal
benefit factor for cleared RegD following resources has ranged from 1.743
The cost of each unit is calculated in market clearing using its offer price, to 2.899 with an average over all hours of 2.595. For purposes of market
lost opportunity cost, capability MW, and the miles to MW ratio of the signal settlement and payments, FERC has required PJM to set the marginal benefit
type they choose to follow, modified by resource benefit factor and historic factor at 1.000. Figure 10-2 shows the disparity between the actual marginal
performance score. As of October 1, 2012, a regulation resource’s total offer benefit factor used in clearing the Regulation Market and the FERC required
is equal to the sum of its total capability ($/MW) and performance offer ($/ marginal benefit factor used in settling the Regulation Market.
MW). As of October 1, 2012, the within hour five minute clearing price for
regulation is determined by the total offer, including the actual within hour
17 Average Daily Offer MW excludes units that have offers but are unavailable for the day.
18 Total offer capability is defined as the sum of the maximum daily offer volume for each offering unit during the period, without regard
to the actual availability of the resource or to the day on which the maximum was offered.
258 Section 10 Ancillary Services © 2013 Monitoring Analytics, LLC
Section 10 Ancillary Services
Figure 10‑2 Daily (simple) average marginal benefit factor; January through Figure 10‑3 Daily average actual cleared MW of regulation, effective cleared
September 2013 MW of regulation, and average performance score; all cleared regulation;
January through September 2013
3.000
1,400 1
2.500 0.9
1,200
0.8
2.000 1,000 0.7
Factor 0.6 Score
Marginal Benefit 1.500 MW 680000 00..45 Performance
1.000
400 0.3
0.2
0.500 200 Cleared Effective MW
Operations Marginal Benefit Factor Cleared Actual MW 0.1
Actual MW Weighted Average Performance Score
Market Settlements Marginal Benefit Factor
0 0
0.000 Jan Feb Mar Apr May Jun Jul Aug Sep
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Although the benefits factor for traditional (RegA following) resources is
1.0, the effective MW of RegA following resources is lower than the offered
MW because the performance score is less than 1 (Figure 9-2). For January
through September, 2013, the MW-weighted average RegA performance score
was 0.80.
© 2013 Monitoring Analytics, LLC 2013 Quarterly State of the Market Report for PJM: January through September 259
2013 Quarterly State of the Market Report for PJM: January through September
Figure 10‑4 Daily average actual cleared MW of regulation, effective cleared several times. It had been scheduled to be reduced from one percent of peak
MW of regulation, and average performance score; RegD units only; January load forecast to 0.9 percent on October 1, 2012, but instead it was changed
through September 2013 from 1 percent of peak load forecast to 0.78 percent of peak load forecast. It
was further reduced to 0.74 percent of peak load forecast on November 22,
300 1.1
Cleared Effective MW 2012. Then it was reduced to its current value of 0.70 percent of peak load
Cleared Actual MW
Actual MW Weighted Average Performance Score 1 forecast on December 18, 2012.
250
0.9
Table 10-7 shows the average hourly required regulation by month and its
0.8 relationship to the supply of regulation.
e
200 or
0.7 Sc
nce Table 10‑7 PJM Regulation Market required MW and ratio of eligible supply
a
W 0.6 m to requirement: January through September 2012 and 2013
M 150 erfor
0.5 P Average Required Average Required Ratio of Supply to Ratio of Supply to
Month Regulation (MW), 2012 Regulation (MW), 2013 Requirement, 2012 Requirement, 2013
0.4 Jan 1,005 851 3.29 3.66
100 Feb 979 870 3.45 4.65
0.3 Mar 876 766 3.14 4.86
Apr 826 656 3.19 2.55
0.2 May 918 678 3.26 3.91
50
Jun 1,055 801 3.21 4.34
0.1 Jul 1,246 911 2.94 1.66
Aug 1,134 832 2.97 2.60
0 0 Sep 941 693 3.33 4.80
Jan Feb Mar Apr May Jun Jul Aug Sep
PJM’s performance as measured by CPS and BAAL standards has not declined
For RegD resources, the effective MW are higher than the actual MW because
as a result of the lower regulation requirement.19
their benefits factor at current participant levels is significantly greater than
1.0 (Figure 9-3). For January through September, 2013, the MW-weighted
average RegD resource performance score was 0.89.
Demand
Demand for regulation does not change with price. The regulation requirement
is set by PJM in accordance with NERC control standards, based on reliability
objectives and forecast load. Prior to October 1, 2012, the regulation
requirement was 1.0 percent of the forecast peak load for on peak hours and
1.0 percent of the forecast valley load for off peak hours. Between October
1, 2012, and December 31, 2012, PJM changed the regulation requirement
19 See the 2012 State of the Market Report for PJM, Appendix F: Ancillary Services.
260 Section 10 Ancillary Services © 2013 Monitoring Analytics, LLC