Q2
State of the Market Report for PJM
January through June

Monitoring Analytics, LLC

2021

Independent
Market Monitor
for PJM
8.12.2021

Preface

Preface
The PJM Market Monitoring Plan provides:
The Market Monitoring Unit shall prepare and submit contemporaneously to the Commission, the State Commissions, the PJM Board, PJM Management
and to the PJM Members Committee, annual state-of-the-market reports on the state of competition within, and the efficiency of, the PJM Markets,and quarterly reports that update selected portions of the annual report and which may focus on certain topics of particular interest to the Market
Monitoring Unit. The quarterly reports shall not be as extensive as the annual reports. In its annual, quarterly and other reports, the Market Monitoring
Unit may make recommendations regarding any matter within its purview. The annual reports shall, and the quarterly reports may, address, among
other things, the extent to which prices in the PJM Markets reflect competitive outcomes, the structural competitiveness of the PJM Markets, theeffectiveness of bid mitigation rules, and the effectiveness of the PJM Markets in signaling infrastructure investment. These annual reports shall, andthe quarterly reports may include recommendations as to whether changes to the Market Monitoring Unit or the Plan are required.1
Accordingly, Monitoring Analytics, LLC, which serves as the Market Monitoring Unit (MMU) for PJM Interconnection, L.L.C. (PJM),2 and is also known as the
Independent Market Monitor for PJM (IMM), submits this 2021 Quarterly State of the Market Report for PJM: January through June.3

1 PJM Open Access Transmission Tariff (OATT) Attachment M (PJM Market Monitoring Plan) § VI.A. Capitalized terms used herein and not otherwise defined have the meaning provided in the OATT, PJM Operating Agreement, PJM Reliability Assurance Agreement (RAA), the Consolidated
Transmission Owners Agreement (CTOA) or other tariffs that PJM has on file with the Federal Energy Regulatory Commission (FERC or Commission).
2 OATT Attachment M.
3 All references to this report should refer to the source as Monitoring Analytics, LLC, and should include the complete name of the report: 2021 Quarterly State of the Market Report for PJM: January through June.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June i2021 Quarterly State of the Market Report for PJM: January through Juneii

Preface© 2021 Monitoring Analytics, LLC

Table of Contents

Table of Contents

Overview: Section 12, Planning
Overview: Section 13, FTRs and ARRs

Prefacei

SECTION 1 Introduction

1

Q2 2021 in Review
PJM Market Summary Statistics
PJM Market Background
Conclusions
Energy Market Conclusion
Capacity Market Conclusion
Tier 2 Synchronized Reserve Market Conclusion
Day-Ahead Scheduling Reserve Market Conclusion
Regulation Market Conclusion
FTR Auction Market Conclusion

Role of MMU
ReportingMonitoring
Market Design

New Recommendations
New Recommendation from Section 3, Energy Market
New Recommendation from Section 4, Energy Uplift

1
5
5
6
7
9
10
10
11
11

12
12
12
13

14
14
14

Total Price of Wholesale Power

14

Components of Total Price

14

Section Overviews
Overview: Section 3, Energy Market
Overview: Section 4, Energy Uplift
Overview: Section 5, Capacity Market
Overview: Section 6, Demand Response
Overview: Section 7, Net Revenue
Overview: Section 8, Environmental and Renewables
Overview: Section 9, Interchange Transactions
Overview: Section 10, Ancillary Services
Overview: Section 11, Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

19
19
30
35
42
47
48
52
55
65

SECTION 2 Recommendations
New Recommendations
New Recommendation from Section 3, Energy Market
New Recommendation from Section 4, Energy Uplift

Complete List of Current MMU Recommendations
Section 3, Energy Market
Section 4, Energy Uplift
Section 5, Capacity Market
Section 6, Demand Response
Section 7, Net Revenue
Section 8, Environmental and Renewables
Section 9, Interchange Transactions
Section 10, Ancillary Services
Section 11, Congestion and Marginal Losses
Section 12, Planning
Section 13, FTRs and ARRs

SECTION 3 Energy Market
Overview
Supply and DemandCompetitive Assessment
Recommendations
Conclusion

Supply and Demand

66
73

81
81
82
82

82
82
86
88
91
93
93
94
95
97
97
99

103
104
104
106
108
112

116

Market Structure

116

Market Behavior

132

Generator Offers
Parameter Limited Schedules
Virtual Offers and Bids

132
135
140

2021 Quarterly State of the Market Report for PJM: January through June iii

2021 Quarterly State of the Market Report for PJM: January through June

Market Performance
LMP
Zonal LMP and Dispatch
Fuel Prices, LMP, and Dispatch
Components of LMP

Shortage
Emergency Procedures
Shortage and Shortage Pricing

Competitive Assessment
Market StructureMarket Behavior
Market PerformanceMarket Structure, Participant Behavior, and Market Performance

SECTION 4 Energy Uplift (Operating Reserves)
Overview
Energy Uplift Credits
Energy Uplift Charges
Geography of Charges and Credits
Recommendations
Conclusion

Energy Uplift Credits Results
Characteristics of Credits
Types of Units
Day-Ahead Unit Commitment for Reliability
Balancing Operating Reserve Credits
Lost Opportunity Cost Credits

Uplift Eligibility
Economic and Noneconomic Generation
Uplift Resettlement
Concentration of Energy Uplift Credits

Credits and Charges Categories
Energy Uplift Charges Resultsiv

Table of Contents

150
150
170
176
184

187
188
191

Energy Uplift Charges
Operating Reserve Rates
Reactive Services Rates
Balancing Operating Reserve Determinants
Geography of Charges and Credits

Energy Uplift Issues
Intraday Segments Uplift Settlement
Uplift Credits and Offer Capping

267
270
273
274
275

276
276
277

202
202
207
233
244

247
247
247
248
248
248
250

252

SECTION 5 Capacity Market
Overview
RPM Capacity Market
Reliability Must Run Service
Generator Performance
Recommendations
Conclusion

279
280
280
281
281
281
284

Installed Capacity

288

Fuel Diversity

290

RPM Capacity Market

291

Market StructureMarket Conduct
Market Performance

292
304
309

253
253
254
256
258

MOPR and FRR
CRF Issue
Timing of Unit Retirements
Reliability Must Run (RMR) Service
Generator Performance

314
316
318
318
320

260

Capacity Factor
Generator Performance Factors
Generator Forced Outage Rates

320
321
323

261
262
262

266
267

© 2021 Monitoring Analytics, LLC

Table of Contents

SECTION 6 Demand Response
Overview
Recommendations
ConclusionPJM Demand Response Programs
Non-PJM Demand Response Programs
PJM Demand Response Programs
Emergency and Pre-Emergency Load Response Programs
Economic Load Response Program

Energy Efficiency
Distributed Energy Resources

SECTION 7 Net Revenue
Overview
Net Revenue
Recommendations
Conclusion

Net Revenue
Spark Spreads and Dark Spreads
Theoretical Energy Market Net Revenue
New Entrant Combustion Turbine
New Entrant Combined Cycle
New Entrant Coal Plant
New Entrant Nuclear Plant
New Entrant Diesel
New Entrant Onshore Wind Installation
New Entrant Offshore Wind Installation
New Entrant Solar Installation
Historical New Entrant CC Revenue Adequacy
Nuclear Net Revenue Analysis© 2021 Monitoring Analytics, LLC

327
327
328
329

332
333
333
334
346

354
355

357
357
357
357
357

357
358
360
362
363
363
364
364
365
365
365
366
367

SECTION 8 Environmental and Renewable Energy
Regulations
Overview

375
375

Federal Environmental Regulation
State Environmental Regulation
State Renewable Portfolio Standards
Emissions Controls in PJM Markets
Renewable Generation
Recommendations
Conclusion

Federal Environmental Regulation
CAA: NESHAP/MATS
CAA: NAAQS/CSAPR
CAA: NSR
CAA: RICE
CAA: Greenhouse Gas Emissions
CWA: WOTUS Definition and Effluents
RCRA: Coal Ash

State Environmental Regulation
State Emissions Regulations
State Regulation of Greenhouse Gas Emissions
State Renewable Portfolio Standards
Alternative Compliance Payments

Emission Controlled Capacity and Emissions
Emission Controlled Capacity
Emissions

Renewable Energy Output
Wind and Solar Peak Hour Output
Wind Units
Solar Units

375
376
376
377
377
377
377

379
380
380
382
383
383
384
385

387
387
387
393
407

411
411
412

414
414
415
418

2021 Quarterly State of the Market Report for PJM: January through June v

2021 Quarterly State of the Market Report for PJM: January through June

SECTION 9 Interchange Transactions
Overview

421
421

Interchange Transaction Activity
Interactions with Bordering Areas
Recommendations
Conclusion

421
422
422
423

Interchange Transaction Activity

424

Charges and Credits Applied to Interchange Transactions
424
Aggregate Imports and Exports426
Real-Time Interface Imports and Exports428
Real-Time Interface Pricing Point Imports and Exports
429
Day-Ahead Interface Imports and Exports
432
Day-Ahead Interface Pricing Point Imports and Exports
434
Loop Flows438
PJM and MISO Interface Prices
446
PJM and NYISO Interface Prices
448
Summary of Interface Prices between PJM and Organized Markets 450
Neptune Underwater Transmission Line to Long Island, New York 450
Linden Variable Frequency Transformer (VFT) facility
452
Hudson Direct Current (DC) Merchant Transmission Line
454
Interchange Activity During High Load Hours
455

Operating Agreements with Bordering Areas

455

PJM and MISO Joint Operating Agreement
456
PJM and New York Independent System Operator Joint Operating
Agreement (JOA)458
PJM and TVA Joint Reliability Coordination Agreement (JRCA)
459
PJM and Duke Energy Progress, Inc. Joint Operating Agreement 459
PJM and VACAR South Reliability Coordination Agreement
460
VACAR Reserve Sharing Agreement
460
Balancing Authority Operations Coordination Agreement between
Wisconsin Electric Power Company (WEC) and PJM
Interconnection, LLC
460
Northeastern ISO-Regional Transmission Organization Planning
Coordination Protocol
460

vi

Table of Contents

Interchange Transaction Issues

460

PJM Transmission Loading Relief Procedures (TLRs)
Up To Congestion Transactions
Sham Scheduling
Elimination of Ontario Interface Pricing PointPJM and NYISO Coordinated Interchange Transactions
Reserving Ramp on the PJM/NYISO Interface
PJM and MISO Coordinated Interchange Transaction Proposal
Willing to Pay Congestion and Not Willing to Pay Congestion
Spot Imports
Interchange Optimization
Interchange Cap During Emergency Conditions
45 Minute Schedule Duration RuleMISO Multi-Value Project Usage Rate (MUR)

SECTION 10 Ancillary Service Markets

479

Overview

480

Primary Reserve
Tier 1 Synchronized Reserve
Tier 2 Synchronized Reserve Market
Nonsynchronized Reserve Market
Secondary Reserve (DASR)
Regulation Market
Black Start Service
Reactive
Frequency Response
Ancillary Services Costs per MWh of Load
Market Procurement of Real-Time Ancillary Services
Recommendations
Conclusion

Primary Reserve
Market Structure
Price and Cost

460
461
464
465
466
470
470
473
474
475
475
476
477

480
480
481
482
482
483
484
485
485
485
486
487
489

490
490
494

© 2021 Monitoring Analytics, LLC

Table of Contents

Tier 1 Synchronized Reserve
Market Structure
Tier 1 Synchronized Reserve Payments

Tier 2 Synchronized Reserve Market
Market StructureMarket Behavior
Market Performance

Nonsynchronized Reserve Market
Market Structure

Secondary Reserve (DASR)
Market StructureMarket Conduct
Market Performance

Regulation Market
Market Design
Market StructureMarket Conduct
Market PerformanceBlack Start Service

495
495
497

499
500
502
504

510
510

513
513
515
515

517
517
531
536
538

542

CRF Issues
NERC – CIP
Minimum Tank Suction Level (MTSL)

545
547
547

Reactive Power Service and Capability

548

Recommended Market Approach to Reactive Costs
Improvements to Current Approach
Reactive Costs

Frequency Response
Frequency Control Definition

VACAR Reserve Sharing Agreement
IssuesRecommendations© 2021 Monitoring Analytics, LLC

549
550
553

554
554

554

SECTION 11 Congestion and Marginal Losses
Overview
Congestion Cost
Marginal Loss Cost
System Energy Cost
Conclusion

Issues

557
558
558
559
559
560

560

Closed Loop Interfaces and CT Pricing Logic
Balancing Congestion Cost Calculation Logic Change

Locational Marginal Price (LMP)
Components
Hub Components

Congestion
Congestion Accounting
Total Congestion

Charges and Credits versus Congestion: Virtual Transactions,
Load and Generation
Congested Facilities
Congestion by Facility Type and Voltage
Constraint Frequency
Constraint Costs
Congestion Event Summary: Impact of Changes in UTC Volumes

Marginal Losses
Marginal Loss Accounting
Total Marginal Loss Cost

System Energy Costs
Energy Accounting
Total System Energy Costs

560
561

563
563
568

569
569
572

573
584
584
589
591
594

595
595
597

602
602
602

555
555

2021 Quarterly State of the Market Report for PJM: January through June vii

2021 Quarterly State of the Market Report for PJM: January through June

SECTION 12 Generation and Transmission Planning
Overview
Generation Interconnection Planning
Regional Transmission Expansion Plan (RTEP)
Transmission Facility Outages
Recommendations
Conclusion

Generation Interconnection Planning
Existing Generation Mix
Generation Retirements
Generation Queue

Regional Transmission Expansion Plan (RTEP)
RTEP Process
Market Efficiency Process
PJM MISO Interregional Market Efficiency Process (IMEP)PJM MISO Targeted Market Efficiency Process (TMEP)
Supplemental Transmission Projects
Competitive Planning Process Exclusions
Storage As A Transmission Asset (SATA)
Board Authorized Transmission Upgrades
Qualifying Transmission Upgrades (QTU)
Cost Allocation

Transmission Line Ratings
Transmission Facility Outages
Scheduling Transmission Facility Outage Requests
Rescheduling Transmission Facility Outage Requests
Long Duration Transmission Facility Outage Requests
Transmission Facility Outage Analysis for the FTR Market
Transmission Facility Outage Analysis in the Day-Ahead Energy
Marketviii

Table of Contents

607
607
607
608
609
609
612

613
613
620
626

654
654
654
657
658
659
663
664
664
664
665

665
667
667
671
672
672

SECTION 13 Financial Transmission and Auction
Revenue Rights
Overview
Auction Revenue Rights
Financial Transmission Rights
Recommendations
Conclusion
Proposed Design

683
687
687
687
689
690
692

Auction Revenue Rights

693

Market Design
Market StructureMarket Performance
IARRs

694
695
695
700

Financial Transmission Rights
Market Performance

701
707

Surplus Congestion Revenue
Revenue Adequacy
ARRs as an Offset to Congestion for Load

723
726
729

Zonal ARR Congestion Offset
Offset Available from Self Scheduling

731
733

CreditGreenHat Settlement Proceedings
Default Portfolio Considerations

FTR Forfeitures

734
734
734

735

680

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

Introduction
Q2 2021 in Review
Reliability is a core goal of PJM. Maintaining and improving competitivemarkets should also be a core goal of PJM. The goal of competition in PJM
is to provide customers reliable wholesale power at the lowest possible price,
but no lower. The PJM markets have done that. The PJM markets work, even
if not perfectly. The results of PJM markets were reliable in the first six
months of 2021. The results of the energy market were competitive in thefirst six months of 2021. The results of the 2021/2022 base capacity auctionthat created capacity market prices currently in effect were not competitive,
but the Commission is now addressing one of the underlying issues, theoverstated market seller offer cap in the capacity market. The PJM markets
bring customers the benefits of competition.
The PJM markets, and wholesale power markets in the U.S., continue to facechallenges that potentially threaten the viability of competitive wholesale
power markets. Markets provide incentives for innovation and efficiency.
Organized, competitive wholesale power markets are the best way tofacilitate the least cost path to decarbonization. Renewables can compete,
without guaranteed long term contracts. Innovation will occur in renewable
technologies in unpredictable and beneficial ways. But the PJM markets are
not perfect. Significant changes to the core market design continue, including
some that improve markets and some that do not. Significant issues with thecore market design remain. It is not guaranteed that the market design will
successfully adapt to the changing realities, including the role of renewables
and intermittents, the role of distributed resources and the role of states insubsidizing resources.
One of the benefits of competitive power markets is that changes in input prices
and changes in the balance of supply and demand are reflected immediately
in energy prices.
The total price per MWh of wholesale power increased from $43.03 in the firstsix months of 2020 to $54.97 in the first six months of 2021, an increase of© 2021 Monitoring Analytics, LLC

27.8 percent. Energy, capacity and transmission charges are the three largest
components of the total price per MWh of wholesale power, comprising 97.1
percent of the total price per MWh in the first six months of 2021. Starting in
the third quarter of 2019, for the first time since the start of the RPM capacity
market design in 2007, the cost of transmission per MWh of wholesale poweris higher than the cost of capacity.
Energy prices increased significantly in the first six months of 2021 fromthe very low levels in 2020, but were still 9.5 percent below the five year
average for the first six months of the five year period from 2015 through2019. Energy prices were lower in 2020 than in any year since PJM markets
were established in 1999. The load-weighted average, real-time LMP was 57.8
percent higher in the first six months of 2021 than in the first six monthsof 2020, $30.62 per MWh versus $19.40 per MWh. Of the $11.22 per MWh
increase, 91.7 percent was a direct result of higher fuel costs, particularly
higher natural gas prices. Load increased due to colder winter and hotter
summer weather and the economic recovery. PJM load increased by 5.9
percent compared to the first six months of 2020, and load increased by 1.6
percent even after controlling for the impact of weather.
Net revenue is a key measure of overall market performance as well as ameasure of the incentive to invest in new generation to serve PJM markets.
Theoretical net revenues from the energy market increased for all unit types
in the first six months of 2021 compared to the first six months of 2020.
Theoretical net revenues increased by 69 percent for a new combustion
turbine, 53 percent for a new combined cycle, 3,288 percent (from a levelnear zero in 2020) for a new coal unit, and 57 percent for a new nuclear plant.
As input prices change, markets react immediately. In 2020, coal fired
generation was markedly less competitive with gas fired generation. Higher
energy prices and higher gas costs made coal units more economic in thefirst six months of 2021. The share of total PJM energy produced from coalincreased from 17.6 percent in the first six months of 2020 to 23.5 percent in
the first six months of 2021, still below the coal share in the first six monthsof 2019, while the share of energy produced from natural gas decreased from2021 Quarterly State of the Market Report for PJM: January through June 1

2021 Quarterly State of the Market Report for PJM: January through June

39.2 to 35.6 percent, still above the natural gas share in the first six monthsof 2019. Even with the reduction in the first six months of 2021, gas fired
generation produces more energy than any other source. The role of gas
fired generation highlights the importance of ensuring that PJM has current,
detailed and complete information on the gas supply arrangements of all
generators and that PJM consider rules requiring capacity resources to havefirm fuel supplies. It is also essential that FERC consider and address theimplications of the inconsistencies between the gas pipeline business modeland the power producer business model and the issue of market power in thegas commodity market under extreme weather conditions.
If more PJM states decide that carbon is a pollutant with a negative value,a market approach to carbon is preferred to an inefficient technology orunit specific subsidy approach or inconsistent RPS rules that in some cases
subsidize carbon emitting resources. Delaware, Maryland and New Jersey
were members of RGGI in 2020. Virginia joined RGGI on January 1, 2021.
Pennsylvania is preparing to join RGGI, and Illinois is discussing a carbon
price. Implementation of a carbon price is a market approach which would
let market participants respond in efficient and innovative ways to the pricesignal rather than relying on planners to identify specific technologies orresources to be subsidized. Implementation of a carbon price using RGGI
or a similar market mechanism by the states would mean that the states
control the carbon price and that no FERC approval would be required andno PJM rule changes would be required. The carbon price would become
part of the marginal costs of power plants and the impacts on production
and consumption decisions would be market based. States would control the
resulting revenues. This is the case regardless of the number of PJM states thatjoin RGGI or a similar market.
The MMU continues to recommend that PJM provide a full analysis of the
impact of carbon pricing on PJM generating units and carbon pricing revenues
to all PJM states in order to permit states to consider the development of amultistate framework that could benefit all states: for REC market design;for potential agreement on carbon pricing; for potential agreement on the2Section 1 Introduction

distribution of carbon pricing revenues; and for coordination with PJM
wholesale markets.
Despite suggestions that PJM needs a flexibility product, the PJM fleet
already includes the flexibility needed to offset the fluctuations in output
inherent in renewable energy. PJM does not need a flexibility product. PJM
needs to provide incentives to existing and new entrant resources to unlock
the significant flexibility potential that already exists and to stop creating
incentives for inflexibility. This means enforcing parameter limited schedules,
enforcing must offer requirements, enhancing generator modelling to support
combined cycle resources, and requiring resources to follow PJM’s dispatch
instructions in order to be eligible for uplift payments. There is no reason toconsider a new flexibility product until the existing rules are enforced andrefined.
PJM interventions in the market have substantial effects on energy market
outcomes. For example, transmission line ratings, transmission penalty factors,
load forecast bias, hydro resource schedules, and unit ramp rate adjustmentschange the dispatch of the system, affect prices, and can create significant
price increases through transmission line limit violations or restrictions on
the resources available to resolve constraints. PJM interventions to reduceline ratings unnecessarily trigger transmission constraint penalty factors andsignificantly increase prices. For example, in the first six months of 2021, 11.2
percent of load-weighted LMP was the result of the transmission constraint
violation penalty factors. PJM reduced transmission line ratings in almost
all of these cases, increasing the number and impact of such penalties. PJM
also increased the constraint penalty factor from $2,000 per MWh to $3,000
per MWh in some cases, for reasons that are not clear. PJM should limit
its interventions in the market and provide greater transparency about thereasons and impacts, if any such interventions continue, in order to enhancemarket efficiency.
There are two key changes to the PJM energy markets that will be madein the near future that could significantly increase energy market prices inways not consistent with competitive markets. Fast start pricing will create© 2021 Monitoring Analytics, LLC

Section 1 Introduction

an inefficient wedge between the competitive price and the effective pricewhen it is implemented. PJM’s current calculations show that fast start pricing
is applied to 18 percent of marginal resources and increases overall energy
market prices by five percent. This is a significant increase to energy prices
given that there are no changes to the underlying market supply and demand
fundamentals. The extended ORDC is a form of administrative pricing thatwill affect prices in a majority of hours and that will go into effect on May
1, 2022, unless the Commission changes its order. Under the rules for theextended ORDC, PJM energy market prices can exceed $14,000 per MWh in
emergency conditions. While appropriate shortage pricing is important, there
is no demonstrated benefit to imposing extreme prices for either long term
generation incentives to invest in reliable capacity or customer incentives
to curtail usage during an emergency. The extended ORDC will impose
administrative pricing in excess of competitive levels. A circuit breaker to limit
energy pricing during emergencies would not resolve the market inefficiencies
inherent in the extended ORDC.

In the capacity market, the Minimum Offer Price Rule (MOPR) has been acontentious issue. Both FERC and the states have significant and overlapping
authority affecting wholesale power markets. While FERC’s MOPR approach
was designed to ensure that subsidies did not affect the wholesale power
markets, the states have ultimate authority over the generation choices madein the states. Accommodation of the states’ authority over generation isrequired, given the overlapping authorities of the Commission and the states.

The competitiveness of energy market prices cannot be taken for granted.
Despite low average marginal unit markups in the first six months of 2021,
3.9 percent of marginal units set price with positive markups, in some cases
over $150 per MWh, despite failing the Three Pivotal Supplier (TPS) test in
the real-time energy market. This was the result of documented flaws in theapplication of offer capping when units fail the TPS test. PJM also schedules
and pays uplift to units that fail the TPS test without requiring that units
use flexible operating parameters, an issue that FERC raised in a June 17,
2021 Order to Show Cause. In addition to the existing issues with market
power mitigation, the definition of a competitive energy offer is overstatedthrough the inclusion of major maintenance costs which do not vary in the
short run with energy output and are not short run marginal costs. Further,
the use of and applicability of fuel cost policies have been undermined. Fuelcost policies ensure that the costs in generator offers are clearly defined andare verifiable and systematic. Fuel cost policies are required for effective andaccurate market power mitigation. Some generation owners prefer to not haveclearly defined costs in order to exercise market power and in order to avoid
taking responsibility for the accuracy of their offers.

It is possible to retain a clear MOPR rule while recognizing state authority
over the generation facilities in each state. PJM’s proposed approach to MOPR
reforms does not meet that test. The MMU’s proposed modifications to the
MOPR rules would retain the fundamentals of the current capacity market
design and result in a de minimis impact on competitive market outcomeswhile recognizing defined state authority. The proposed modifications would
permit exemptions from MOPR for state programs designed to support specificemerging technologies that would not otherwise be competitive. All othertechnologies, including renewables and nuclear, are competitive and are
expected to clear in capacity auctions, even with the application of MOPR.
The proposed modifications would not impede or interfere with authorizedstate policies, regardless of the targeted technology. The MMU’s proposed
modifications also recognize that the definition of a competitive offer, the
MOPR floor, is net avoidable cost (ACR) and not the much higher net cost of
new entry (CONE). Even when the MOPR rules are applied, the MOPR floors
are defined to be competitive offers and expected to clear when consistent
with market fundamentals. A competitive offer is a competitive offer. The
MOPR offer floor is the same as the market seller offer cap (MSOC).

© 2021 Monitoring Analytics, LLC

With the expected elimination of the current MOPR rules, the capacity market
design must accommodate the choices made by states to subsidize renewableor clean resources in a way that maximizes the role of competition, to ensurethat customers pay the lowest amount possible, consistent with state goals
and the costs of providing the desired resources. Such an approach can takeseveral forms, but none require the dismantling of the PJM capacity market
design. The PJM capacity market design can adapt to a wide range of state
supported resources and state programs.

2021 Quarterly State of the Market Report for PJM: January through June 3

2021 Quarterly State of the Market Report for PJM: January through June

If PJM markets are going to continue to be sustainable, it is essential that thebasic structure of the current capacity market remain, including the single
definition of reliability for the PJM market, the incorporation of transmission
constraints and locational supply and demand fundamentals, and a clear
definition of capacity and the contribution of capacity to reliability. The basic
structure of the capacity market also includes a must offer and a must buy
requirement that are essential and have been demonstrated to be essential tolimiting market power and operating a competitive market. The PJM Capacity
Market has never been nor was it ever intended to be a residual market,
as evidenced by the must buy and must sell provisions of the market rules.
Reliability is only definable at the level of the entire PJM market, including
locational differences based on transmission constraints. The market reflects theinteractions across free flowing ties throughout the entire network. There aretransmission constraints that prevent the lowest cost capacity from providing
reliability in constrained areas. Locational prices reflect the combination oftransmission constraints and local supply and demand conditions.
Purely bilateral markets are characterized by a lack of transparency, acorresponding asymmetry in access to information that favors market sellers,
and the resultant ability of sellers to exercise market power. Transparent
clearing markets are the best way to facilitate bilateral contracts.
It is also essential that the contribution of different types of capacity becalculated in a comparable manner. The contribution of one MW of solar orwind resources is not the same as the contribution of one MW of a gas fired
combined cycle resource. Capacity must be defined in a homogeneous mannerso that the clearing price is the same for all MW of capacity that provide thesame contribution to reliability. Capacity should be offered and cleared in thecapacity market only at a MW level that reflects its contribution to reliability.
For most wind and solar resources that means a capacity value appropriately
derated from the nameplate capability.

type with the Effective Load Carrying Capability (ELCC) approach. PJM’s
approach to calculating ELCC values by technology is badly flawed. Fixing the
PJM approach to ELCC is a manageable task if there is a shared goal of letting
markets reflect the actual, marginal contribution of all types of capacity toreliability without assumptions that arbitrarily favor some resource types.
Renewable energy was a relatively small share of PJM total energy andcapacity in the first six months of 2021 but many renewable projects areunder development. While renewables currently make up the majority ofboth projects and nameplate MW in the interconnection queue, historicalcompletion rates and derating factors must be accounted for when evaluating
the share of capacity resources that are likely to be contributed by renewables
and by thermal resources. Of the 22,808.6 MW of combined cycle projects inthe queue, 14,211.6 MW (62.3 percent) are expected to go in service basedon historical completion rates as of June 30, 2021, providing both energy
and capacity at that level. Of the 160,392.1 MW of renewable projects in thequeue, only 19,623.3 MW (12.2 percent) are expected to go in service basedon historical completion rates and be available to supply energy. Of those
19,623.3 MW, only 7,714.3 MW (4.8 percent of the total) are expected to becapacity resources, based on the average derate factors for wind and solar.
The evolution of wholesale power markets is far from complete. The market
design can be improved and made more efficient and more competitive. PJM
and its market participants will need to continue to work constructively torefine the competitive market design and to ensure the continued effectivenessof PJM markets in providing customers wholesale power at the lowest possible
price, but no lower.

In order for the capacity market to provide competitive price signals,
particularly with more renewable and intermittent resources, the ELCC values
must be accurate. PJM has replaced default derating factors by technology

4

Section 1 Introduction© 2021 Monitoring Analytics, LLC

Section 1 Introduction

PJM Market Summary Statistics

Figure 1-1 PJM’s footprint and its 21 control zones

Table 1-1 shows selected summary statistics describing PJM markets.
Table 1-1 PJM market summary statistics: January through June, 2020 and
20211
Average Hourly Load Plus Exports (MW)Average Hourly Generation Plus Imports (MW)Peak Load (MW)Installed Capacity at June 30 (MW)Load Weighted Average Real Time LMP ($/MWh)Total Congestion Costs ($ Million)
Total Uplift Credits ($ Million)
Total PJM Billing ($ Billion)

Jan-Jun 2020
86,34487,861
135,900
184,576$19.40$179.8$23.5$15.57

Jan-Jun 2021
90,96092,655
148,667
183,962$30.62$354.0$79.2$20.41

Percent Change
5.3%
5.5%
9.4%
(0.3%)
57.8%
96.9%
236.9%
31.1%

PJM Market Background
The PJM Interconnection, L.L.C. (PJM) operates a centrally dispatched,competitive wholesale electric power market that, as of June 30, 2021, had
installed generating capacity of 183,962 megawatts (MW) and 1,041 members
including market buyers, sellers and traders of electricity in a region including
more than 65 million people in all or parts of 13 states (Delaware, Illinois,
Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio,
Pennsylvania, Tennessee, Virginia, West Virginia) and the District of Columbia(Figure 1-1).2 3 4
As part of the market operator function, PJM coordinates and directs theoperation of the transmission grid and plans transmission expansion
improvements to maintain grid reliability in this region.

1 In Table 1-1, Average Hourly Load includes load and exports, and Average Hourly Generation includes generation and imports. Versionsof this table prior to the 2020 Quarterly State of the Market Report for PJM: January through June did not include exports or imports inthese calculations.
2 See PJM. “Member List,” which can be accessed at: <http://pjm.com/about-pjm/member-services/member-list.aspx>.
3 See PJM. “Who We Are,” which can be accessed at: <http://pjm.com/about-pjm/who-we-are.aspx>.
4 See the 2020 State of the Market Report for PJM, Volume II, Appendix A: “PJM Overview” for maps showing the PJM footprint and its
evolution prior to 2021.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 5

2021 Quarterly State of the Market Report for PJM: January through June

In the first six months of 2021, PJM had total billings of $20.41 billion, an
increase of 31.1 percent from $15.57 billion in the first six months of 2020
(Figure 1-2).5
Figure 1-2 PJM reported monthly billings ($ Billion): 2008 through June 2021
$12

$10

Monthly Gross Billings ($ Billion)

$8

$6

$4

$2

$0

PJM operates the day-ahead energy market, the real-time energy market,
the Reliability Pricing Model (RPM) capacity market, the regulation market,
the synchronized reserve market, the day-ahead scheduling reserve (DASR)
market and the financial transmission rights (FTRs) markets.
PJM introduced energy pricing with cost-based offers and market-clearing
nodal prices on April 1, 1998, and market-clearing nodal prices with marketbased offers on April 1, 1999. PJM introduced the Daily Capacity Market on
January 1, 1999, and the Monthly and Multimonthly Capacity Markets for theJanuary through May 1999 period. PJM implemented FTRs on May 1, 1999.
5 Monthly and year to date billing values are provided by PJM.

6

Section 1 Introduction

PJM implemented the day-ahead energy market and the regulation market
on June 1, 2000. PJM modified the regulation market design and added amarket in Synchronized Reserve on December 1, 2002. PJM introduced an
Auction Revenue Rights (ARR) allocation process and an associated Annual
FTR Auction effective June 1, 2003. PJM introduced the RPM capacity market
effective June 1, 2007. PJM implemented the DASR market on June 1, 2008.
PJM introduced the Capacity Performance capacity market design effective on
August 10, 2015, with the Base Residual Auction for 2018/2019.6 7

Conclusions
This report assesses the competitiveness of the markets managed by PJM in
the first six months of 2021, including market structure, participant behavior
and market performance. This report was prepared by and represents theanalysis of the Independent Market Monitor for PJM, also referred to as theMarket Monitoring Unit or MMU.
For each PJM market, the market structure is evaluated as competitive or
not competitive, and participant behavior is evaluated as competitive or notcompetitive. Most important, the outcome of each market, market performance,is evaluated as competitive or not competitive.
The MMU also evaluates the market design for each market. The market design
serves as the vehicle for translating participant behavior within the market
structure into market performance. This report evaluates the effectivenessof the market design of each PJM market in providing market performance
consistent with competitive results.
Market structure refers to the cost, demand, and ownership structure of themarket. The three pivotal supplier (TPS) test is the most relevant measureof market structure because it accounts for the ownership of assets and the
6 See also the 2020 State of the Market Report for PJM, Volume II, Appendix A: “PJM Overview.”
7 Analysis of 2021 market results requires comparison to prior years. During calendar years 2004 and 2005, PJM conducted the phased
integration of five control zones: ComEd, American Electric Power (AEP), The Dayton Power & Light Company (DAY), Duquesne Light
Company (DUQ) and Dominion. In June 2011, PJM integrated the American Transmission Systems, Inc. (ATSI) Control Zone. In January
2012, PJM integrated the Duke Energy Ohio/Kentucky (DUKE) Control Zone. In June 2013, PJM integrated the Eastern Kentucky Power
Cooperative (EKPC). In December 2018, PJM integrated the Ohio Valley Electric Corporation (OVEC.) By convention, control zones bear
the name of a large utility service provider working within their boundaries. The nomenclature applies to the geographic area, not to any
single company. For additional information on the integrations, their timing and their impact on the footprint of the PJM service territory
prior to 2020, see 2019 State of the Market Report for PJM, Volume 2, Appendix A: “PJM Overview.”© 2021 Monitoring Analytics, LLC

Section 1 Introduction

relationship among the pattern of ownership, the resource costs, and themarket demand using actual market conditions with both temporal andgeographic granularity. Market shares and the related Herfindahl-HirschmanIndex (HHI) are also measures of market structure.
Participant behavior refers to the actions of individual market participants,
also sometimes referred to as participant conduct.
Market performance refers to the outcomes of the market. Market performance
results from the behavior of market participants within a market structure,
mediated by market design.
Market design means the rules under which the entire relevant market operates,
including the software that implements the market rules. Market rules include
the definition of the product, the definition of short run marginal cost, rules
governing offer behavior, market power mitigation rules, and the definitionof demand. Market design is characterized as effective, mixed or flawed. An
effective market design provides incentives for competitive behavior andpermits competitive outcomes. A mixed market design has significant issues
that constrain the potential for competitive behavior to result in competitivemarket outcomes, and does not have adequate rules to mitigate market power
or incent competitive behavior. A flawed market design produces inefficient
outcomes which cannot be corrected by competitive behavior.

Energy Market Conclusion
The Market Monitoring Unit (MMU) analyzed measures of market structure,
participant conduct and market performance, including market size,
concentration, pivotal suppliers, offer behavior, markup, and price. The MMU
concludes that the PJM energy market results were competitive in the first six
months of 2021.

© 2021 Monitoring Analytics, LLC

Table 1-2 The energy market results were competitive
Market Element
Market Structure: Aggregate Market
Market Structure: Local Market
Participant Behavior
Market Performance

Evaluation
Partially Competitive
Not Competitive
Competitive
Competitive

Market Design

Effective• The aggregate market structure was evaluated as partially competitive

because the aggregate market power test based on pivotal suppliers
indicates that the aggregate day-ahead market structure was notcompetitive on every day. The hourly HHI (Herfindahl-Hirschman Index)
results indicate that the PJM aggregate energy market in the first six
months of 2021 was, on average, unconcentrated by FERC HHI standards.
Average HHI was 751 with a minimum of 574 and a maximum of 1118 in
the first six months of 2021. The peaking segment of supply was highly
concentrated. The fact that the average HHI is in the unconcentrated
range does not mean that the aggregate market was competitive in all
hours. As demonstrated for the day-ahead market, it is possible to havepivotal suppliers in the aggregate market even when the HHI level is notin the highly concentrated range. It is possible to have an exercise of
market power even when the HHI level is not in the highly concentrated
range. The number of pivotal suppliers in the energy market is a more
precise measure of structural market power than the HHI. The HHI is nota definitive measure of structural market power.

• The local market structure was evaluated as not competitive due to thehighly concentrated ownership of supply in local markets created bytransmission constraints and local reliability issues. The results of the threepivotal supplier (TPS) test, used to test local market structure, indicate
the existence of market power in local markets created by transmission
constraints. The local market performance is competitive as a result of
the application of the TPS test. While transmission constraints create thepotential for the exercise of local market power, PJM’s application of thethree pivotal supplier test identified local market power and resulted inoffer capping to force competitive offers, correcting for structural issues
created by local transmission constraints. There are, however, identified

2021 Quarterly State of the Market Report for PJM: January through June 7

2021 Quarterly State of the Market Report for PJM: January through June

issues with the definition of cost-based offers and the application ofmarket power mitigation to resources whose owners fail the TPS test thatneed to be addressed because unit owners can exercise market power evenwhen they fail the TPS test.

• Participant behavior was evaluated as competitive because the analysis ofmarkup shows that marginal units generally make offers at, or close to,their marginal costs in both the day-ahead and real-time energy markets,
although the behavior of some participants both routinely and during
periods of high demand represents economic withholding. The ownershipof marginal units is concentrated. The markups of pivotal suppliers in theaggregate market and of many pivotal suppliers in local markets remain
unmitigated due to the lack of aggregate market power mitigation and theflawed implementation of offer caps for resources that fail the TPS test.
The markups of those participants affected LMP.

• Market performance was evaluated as competitive because market resultsin the energy market reflect the outcome of a competitive market, as PJM
prices are set, on average, by marginal units operating at, or close to, their
marginal costs in both day-ahead and real-time energy markets, althoughhigh markups for some marginal units did affect prices.

• Market design was evaluated as effective because the analysis showsthat the PJM energy market resulted in competitive market outcomes. In
general, PJM’s energy market design provides incentives for competitive
behavior and results in competitive outcomes. In local markets, where
market power is an issue, the market design identifies market power andcauses the market to provide competitive market outcomes in most cases
although issues with the implementation of market power mitigationand development of cost-based offers remain. The role of UTCs in the
day-ahead energy market continues to cause concerns. Market design
implementation issues, including inaccuracies in modeling of thetransmission system and of generator capabilities as well as inefficiencies
in real-time dispatch and price formation, undermine market efficiency
in the energy market. PJM plans to resolve the problems with real time
dispatch and pricing in November 2021, but the implementation of fast
start pricing and the extended ORDC in September 2021 and March 2022

8

Section 1 Introduction

will undermine market efficiency by setting inefficient prices that areinconsistent with the dispatch signals.
PJM markets are designed to promote competitive outcomes derived from theinteraction of supply and demand in each of the PJM markets. Market design
itself is the primary means of achieving and promoting competitive outcomesin PJM markets. One of the MMU’s core functions is to identify actual or
potential market design flaws.8 The approach to market power mitigation in
PJM has focused on market designs that promote competition (a structural
basis for competitive outcomes) and on mitigating market power in instanceswhere the market structure is not competitive and thus where market design
alone cannot mitigate market power. FERC relies on effective market power
mitigation when it approves market sellers to participate in the PJM market atmarket based rates.9 In the PJM energy market, market power mitigation occurs
primarily in the case of local market power. When a transmission constraint
creates the potential for local market power, PJM applies a structural test
to determine if the local market is competitive, applies a behavioral test to
determine if generator offers exceed competitive levels and applies a market
performance test to determine if such generator offers would affect the market
price.10 There are, however, identified issues with the application of market
power mitigation to resources whose owners fail the TPS test that can result in
the exercise of local market power even when market power mitigation rules
are applied. These issues need to be addressed. FERC recognized these issues in
its June 17, 2021 order.11 Some units with market power have positive markups
and some have inflexible parameters, which means that the cost-based offer
was not used and that the process for offer capping units that fail the TPS test
does not consistently result in competitive market outcomes in the presence ofmarket power. There are issues related to the definition of gas costs includable
in energy offers that need to be addressed. There are issues related to thelevel of maintenance expense includable in energy offers that need to beaddressed. There are currently no market power mitigation rules in place that
limit the ability to exercise market power when aggregate market conditions
8 OATT Attachment M (PJM Market Monitoring Plan).
9 See Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System
Operator Markets, Order No. 861, 168 FERC ¶ 61,040 (July 18, 2019); order on reh’g, Order No. 861-A; 170 FERC ¶ 61,106 (2020).
10 The market performance test means that offer capping is not applied if the offer does not exceed the competitive level and therefore
market power would not affect market performance.
11 PJM Interconnection, L.L.C., Order to Show Cause, (June 17, 2021) 175 FERC ¶ 61,231.

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

are tight and there are pivotal suppliers in the aggregate market. Aggregate
market power needs to be addressed. Market design must reflect appropriate
incentives for competitive behavior, the application of local market power
mitigation needs to be fixed, the definition of a competitive offer needs tobe fixed, and aggregate market power mitigation rules need to be developed.
The importance of these issues is amplified by the rules permitting cost-based
offers in excess of $1,000 per MWh.

Capacity Market Conclusion
The Market Monitoring Unit (MMU) analyzed market structure, participant
conduct and market performance in the PJM Capacity Market, including supply,
demand, concentration ratios, pivotal suppliers, volumes, prices, outage rates
and reliability.12 The conclusions are a result of the MMU’s evaluation of thelast Base Residual Auction, for the 2021/2022 Delivery Year. The MMU has
not completed its analysis of the 2022/2023 RPM Base Residual Auction.
Table 1-3 The capacity market results were not competitive
Market Element
Market Structure: Aggregate Market
Market Structure: Local Market
Participant Behavior
Market Performance

Evaluation
Not Competitive
Not Competitive
Not Competitive
Not Competitive

Market Design

Mixed• The aggregate market structure was evaluated as not competitive. For

almost all auctions held from 2007 to the present, the PJM region failed
the three pivotal supplier test (TPS), which is conducted at the time of
the auction.13 Structural market power is endemic to the capacity market.

• The local market structure was evaluated as not competitive. For almost

every auction held, all LDAs have failed the TPS test, which is conductedat the time of the auction.14

12 The values stated in this report for the RTO and LDAs refer to the aggregate level including all nested LDAs unless otherwise specified. For
example, RTO values include the entire PJM market and all LDAs. Rest of RTO values are RTO values net of nested LDA values.
13 In the 2008/2009 RPM Third Incremental Auction, 18 participants in the RTO market passed the TPS test. In the 2018/2019 RPM Second
Incremental Auction, 35 participants in the RTO market passed the test.
14 In the 2012/2013 RPM Base Residual Auction, six participants included in the incremental supply of EMAAC passed the TPS test. In the
2014/2015 RPM Base Residual Auction, seven participants in the incremental supply in MAAC passed the TPS test. In the 2021/2022
RPM First Incremental Auction, two participants in the incremental supply in EMAAC passed the TPS test. In the 2021/2022 RPM Second
Incremental Auction, two participants in the incremental supply in EMAAC passed the TPS test.

© 2021 Monitoring Analytics, LLC• Participant behavior was evaluated as not competitive in the 2021/2022

RPM Base Residual Auction. The MMU has not completed its analysisof the 2022/2023 RPM Base Residual Auction. Market power mitigation
measures were applied when the capacity market seller failed the market
power test for the auction, the submitted sell offer exceeded the definedoffer cap, and the submitted sell offer, absent mitigation, would increase
the market clearing price. But the net CONE times B offer cap under thecapacity performance design, in the absence of 30 performance assessment
hours, exceeds the competitive level and should be reevaluated for each
BRA. In the 2021/2022 RPM Base Residual Auction, some participants’offers were above the competitive level. The MMU recognizes that thesemarket participants followed the capacity market rules by offering at lessthan the stated offer cap of Net CONE times B. But Net CONE times B is not
a competitive offer when the expected number of performance assessment
intervals is zero or a very small number and the nonperformance charge
rate is defined as Net CONE/30. Under these circumstances, a competitive
offer, under the logic defined in PJM’s capacity performance filing, is net
ACR. That is the way in which most market participants offered in thisand prior capacity performance auctions.

• Market performance was evaluated as not competitive based on the2021/2022 RPM Base Residual Auction. Although structural market power
exists in the Capacity Market, a competitive outcome can result fromthe application of market power mitigation rules. The outcome of the2021/2022 RPM Base Residual Auction was not competitive as a result ofparticipant behavior which was not competitive, specifically offers which
exceeded the competitive level. The MMU has not completed its analysisof the 2022/2023 RPM Base Residual Auction.

• Market design was evaluated as mixed because while there are many
positive features of the Reliability Pricing Model (RPM) design and thecapacity performance modifications to RPM, there are several featuresof the RPM design which still threaten competitive outcomes. These
include the definition of DR which permits inferior products to substitutefor capacity, the replacement capacity issue, the definition of unit offer

2021 Quarterly State of the Market Report for PJM: January through June 9

2021 Quarterly State of the Market Report for PJM: January through June•parameters, the inclusion of imports which are not substitutes for internal
capacity resources, and the definition of the default offer cap.
As a result of the fact that the capacity market design was found to be
not just and reasonable by FERC and a final market design had not been
approved, the 2022/2023 Base Residual Auction was delayed and held in
May 2020, the 2023/2024 Base Residual Auction is delayed and scheduledfor December 2021, and first and second incremental auctions for the2022/2023 through 2025/2026 Delivery Years are canceled if within 10
months of the revised BRA schedule.15

Tier 2 Synchronized Reserve Market Conclusion
The MMU analyzed measures of market structure, conduct and performancefor the PJM Synchronized Reserve Market for the first six months of 2021.
Table 1-4 The tier 2 synchronized reserve market results were competitive
Market Element
Market Structure: Regional Markets
Participant Behavior
Market Performance

Evaluation
Not Competitive
Competitive
Competitive

Market Design

Mixed• The tier 2 synchronized reserve market structure was evaluated as notcompetitive because of high levels of supplier concentration.

• Participant behavior was evaluated as competitive because the market
rules require cost-based offers.

• Market performance was evaluated as competitive because the interactionof participant behavior with the market design results in competitive
prices.

• Market design was evaluated as mixed. Market power mitigation

Day-Ahead Scheduling Reserve Market Conclusion
The MMU analyzed measures of market structure, conduct and performancefor the PJM DASR Market for the first six months of 2021.
Table 1-5 The day-ahead scheduling reserve market results were competitive
Market Element
Market Structure
Participant Behavior
Market Performance

Evaluation
Not Competitive
Mixed
Competitive

Market Design

Mixed• The DASR market would have failed a three pivotal supplier test in 45.8

percent of hours where the DASRMCP was greater than $0.01 in the firstsix months of 2021.

• Participant behavior was evaluated as mixed because while most offers
were equal to marginal costs, a significant proportion of offers reflectedeconomic withholding.

• Market performance was evaluated as competitive because there wereadequate offers in every hour to satisfy the requirement and the clearing
prices reflected those offers, although there is concern about offers above
the competitive level affecting prices. The day-ahead scheduling reserve
market clearing price was above $0 in 448 hours in the first six months of2021. In 98.1 percent of hours when the clearing price was above $0, theclearing price was the offer price of the marginal unit. In the remaining
1.9 percent of hours, the price included lost opportunity cost.

• Market design was evaluated as mixed because the DASR product does notinclude performance obligations. Offers should be based on opportunity
cost only, to ensure competitive outcomes and that market power cannot
be exercised.

rules result in competitive outcomes despite high levels of supplierconcentration. However, tier 1 reserves are inappropriately compensatedwhen the nonsynchronized reserve market clears with a nonzero price.

15 174 FERC ¶ 61,036 (2021).

10

Section 1 Introduction© 2021 Monitoring Analytics, LLC

Section 1 Introduction

Regulation Market Conclusion

Table 1-7 The FTR auction markets results were partially competitive

The MMU analyzed measures of market structure, conduct and performancefor the PJM Regulation Market for the first six months of 2021.

Market Element
Market Structure
Participant Behavior
Market Performance

Table 1-6 The regulation market results were not competitive
Market Element
Market Structure
Participant Behavior
Market Performance

Evaluation
Not Competitive
Competitive
Not Competitive

Market Design

Flawed• The regulation market structure was evaluated as not competitive because
the PJM Regulation Market failed the three pivotal supplier (TPS) test in
87.7 percent of the hours in the first six months of 2021.

• Participant behavior in the PJM Regulation Market was evaluatedas competitive in the first six months of 2021 because market power
mitigation requires competitive offers when the three pivotal supplier test
is failed, although the inclusion of a positive margin raises questions.

• Market performance was evaluated as not competitive, because all units
are not paid the same price on an equivalent MW basis.

• Market design was evaluated as flawed. The market design has failed

to correctly incorporate a consistent implementation of the marginal
benefit factor in optimization, pricing and settlement. The market results
continue to include the incorrect definition of opportunity cost. The
result is significantly flawed market signals to existing and prospective
suppliers of regulation.

FTR Auction Market Conclusion
The Market Monitoring Unit (MMU) analyzed measures of market structure,
participant conduct and market performance, including market size,
concentration, offer behavior, and price. The MMU concludes that the PJM
FTR auction market results were partially competitive in the first six monthsof 2021.

© 2021 Monitoring Analytics, LLC

Evaluation
Competitive
Partially Competitive
Partially Competitive

Market Design

Flawed• Market structure was evaluated as competitive. The ownership of FTR
obligations is unconcentrated for the individual years of the 2020/2023
Long Term FTR Auction, the 2020/2021 Annual FTR Auction and eachperiod of the Monthly Balance of Planning Period Auctions. The ownershipof FTR options is moderately or highly concentrated for every Monthly FTR
Auction period and moderately concentrated for the 2020/2021 Annual
FTR Auction. Ownership of FTRs is disproportionately (78.3 percent) byfinancial participants. The ownership of ARRs is unconcentrated.

• Participant behavior was evaluated as partially competitive as a result of

the behavior of GreenHat Energy, LLC. ARR holders who are the sellers of
FTRs are not permitted to participate in the market clearing.

• Market performance was evaluated as partially competitive because of
the flaws in the market design. Sellers, the ARR holders, cannot set a saleprice. Buyers can reclaim some of their purchase price after the market
clears if the product does not meet a profitability target. The market
resulted in a substantial shortfall in congestion payments to load andsignificant and unsupportable disparities among zones in the share ofcongestion returned to load. FTR purchases by financial entities remain
persistently profitable in part as a result of the flaws in the market design.

• Market design was evaluated as flawed because there are significant

and fundamental flaws with the basic ARR/FTR design. The FTR auction
market is not actually a market because the sellers have no independentrole in the process. ARR holders cannot determine the price at which
they are willing to sell rights to congestion revenue. Buyers have theability to reclaim some of the price paid for FTRs after the market clears.
The market design is not an efficient or effective way to ensure that therights to all congestion revenues are assigned to load. The product soldto FTR buyers is incorrectly defined as target allocations rather than a2021 Quarterly State of the Market Report for PJM: January through June 11

2021 Quarterly State of the Market Report for PJM: January through Juneshare of congestion revenue. ARR holders’ rights to congestion revenues
are not correctly defined because the contract path based assignment ofcongestion rights is inadequate and incorrect. Ongoing PJM subjective
intervention in the FTR market that affects market fundamentals is also
an issue and a symptom of the fundamental flaws in the design. The
product, the quantity of the product and the price of the product are allincorrectly defined.

• The fact that load is not able to define its willingness to sell FTRs or

the prices at which it is willing to sell FTRs and the fact that sellers are
required to return some of the cleared auction revenue to FTR buyers when
FTR profits are not adequate, means that the FTR design does not actuallyfunction as a market and is evidence of basic flaws in the market design.

Role of MMU
FERC assigns three core functions to MMUs: reporting, monitoring andmarket design.16 These functions are interrelated and overlap. The PJM
Market Monitoring Plan establishes these functions, providing that the MMU
is responsible for monitoring: compliance with the PJM Market Rules; actualor potential design flaws in the PJM Market Rules; structural problems in the
PJM Markets that may inhibit a robust and competitive market; the actual or
potential exercise of market power or violation of the market rules by a Market
Participant; PJM’s implementation of the PJM Market Rules or operation of
the PJM Markets; and such matters as are necessary to prepare reports.17

Reporting
The MMU performs its reporting function primarily by issuing and filingannual and quarterly state of the market reports; regular reports on market
issues, such as RPM auction reports; reports responding to requests from
regulators and other authorities; and ad hoc reports on specific topics. The
state of the market reports provide a comprehensive analysis of market
structure, participant conduct and market performance for the PJM markets.
State of the market reports and other reports are intended to inform PJM,
16 18 CFR § 35.28(g)(3)(ii); see also Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, FERC Stats. & Regs.
¶31,281 (2008) (“Order No. 719”), order on reh’g, Order No. 719-A, FERC Stats. & Regs. ¶31,292 (2009), reh’g denied, Order No. 719-B, 129
FERC ¶ 61,252 (2009).
17 OATT Attachment M § IV; 18 CFR § 1c.2.

12

Section 1 Introduction

the PJM Board, FERC, other regulators, other authorities, market participants,
stakeholders and the general public about how well PJM markets achieve thecompetitive outcomes necessary to realize the goals of regulation throughcompetition, and how the markets can be improved.
The MMU presents reports directly to PJM stakeholders, PJM staff, FERC staff,
state commission staff, state commissions, other regulatory agencies and thegeneral public. Report presentations provide an opportunity for interested
parties to ask questions, discuss issues, and provide feedback to the MMU.

Monitoring
To perform its monitoring function, the MMU screens and monitors the
conduct of Market Participants under the MMU’s broad purview to monitor,
investigate, evaluate and report on the PJM Markets.18 The MMU has direct,
confidential access to FERC.19 The MMU may also refer matters to the attentionof state commissions.20
The MMU monitors market behavior for violations of FERC Market Rules
and PJM Market Rules, including the actual or potential exercise of market
power.21 The MMU will investigate and refer “Market Violations,” which refer
to any of “a tariff violation, violation of a Commission-approved order, ruleor regulation, market manipulation, or inappropriate dispatch that creates
substantial concerns regarding unnecessary market inefficiencies...”22 23 24 The
18 OATT Attachment M § IV.
19 OATT Attachment M § IV.K.3.
20 OATT Attachment M § IV.H.
21 OATT § I.1 (“FERC Market Rules” mean the market behavior rules and the prohibition against electric energy market manipulation codified
by the Commission in its Rules and Regulations at 18 CFR §§ 1c.2 and 35.37, respectively; the Commission-approved PJM Market
Rules and any related proscriptions or any successor rules that the Commission from time to time may issue, approve or otherwise
establish… “PJM Market Rules” mean the rules, standards, procedures, and practices of the PJM Markets set forth in the PJM Tariff,
the PJM Operating Agreement, the PJM Reliability Assurance Agreement, the PJM Consolidated Transmission Owners Agreement, thePJM Manuals, the PJM Regional Practices Document, the PJM-Midwest Independent Transmission System Operator Joint Operating
Agreement or any other document setting forth market rules.“)
22 FERC defines manipulation as engaging “in any act, practice, or course of business that operates or would operate as a fraud or deceit
upon any entity.” 18 CFR § 1c.2(a)(3). Manipulation may involve behavior that is consistent with the letter of the rules, but violates their
spirit. An example is market behavior that is economically meaningless, such as equal and opposite transactions, which may entitle thetransacting party to a benefit associated with volume. Unlike market power or rule violations, manipulation must be intentional. The
MMU must build its case, including an inference of intent, on the basis of market data.
23 OATT § I.1.
24 The MMU has no prosecutorial or enforcement authority. The MMU notifies FERC when it identifies a significant market problem ormarket violation. OATT Attachment M § IV.I.1. If the problem or violation involves a market participant, the MMU discusses the matterwith the participant(s) involved and analyzes relevant market data. If that investigation produces sufficient credible evidence of aviolation, the MMU prepares a formal referral and thereafter undertakes additional investigation of the specific matter only at thedirection of FERC staff. Id. If the problem involves an existing or proposed law, rule or practice that exposes PJM markets to the risk thatmarket power or market manipulation could compromise the integrity of the markets, the MMU explains the issue, as appropriate, toFERC, state regulators, stakeholders or other authorities. The MMU may also initiate, participate as a party or provide information or
testimony in regulatory or other proceedings.

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

MMU also monitors PJM for compliance with the rules, in addition to market
participants.25
An important component of the monitoring function is the review of inputs
to mitigation. The actual or potential exercise of market power is addressed inpart through ex ante mitigation rules incorporated in PJM’s market clearing
software for the energy market, the capacity market and the regulation market.
If a market participant fails the TPS test in any of these markets its offer is set
to the lower of its price-based or cost-based offer. This prevents the exercise
of market power and ensures competitive pricing, provided that the costbased offer accurately reflects short run marginal cost.
If cost-based offers do not accurately reflect short run marginal cost, themarket power mitigation process does not ensure competitive pricing in PJM
markets. The MMU evaluates the fuel cost policy for every unit as well as
the other inputs to cost-based offers. PJM Manual 15 does not clearly or
accurately describe the short run marginal cost of generation. Manual 15
should be replaced with a straightforward description of the components ofcost offers based on short run marginal costs and the correct calculation of
cost offers. The MMU evaluates every offer in each capacity market (RPM)
auction using data submitted to the MMU through web-based data input
systems developed by the MMU.26
The MMU also reviews operational parameter limits included with unit offers,
evaluates compliance with the requirement to offer into the energy andcapacity markets, evaluates the economic basis for unit retirement requests
and evaluates and compares offers in the day-ahead and real-time energy
markets.27 28 29 30
The MMU reviews offers and inputs in order to evaluate whether those offers
raise market power concerns. Market participants, not the MMU, determine
and take responsibility for offers that they submit and the market conduct
25 OATT Attachment M § IV.C.
26 OATT Attachment M–Appendix § II.E.
27 OATT Attachment M–Appendix § II.B.
28 OATT Attachment M–Appendix § II.C.
29 OATT Attachment M–Appendix § IV.
30 OATT Attachment M–Appendix § VII.

© 2021 Monitoring Analytics, LLC

that those offers represent. If the MMU has a concern about an offer, the MMU
may raise that concern with FERC or other regulatory authorities. FERC andother regulators have enforcement and regulatory authority that they may
exercise with respect to offers submitted by market participants. PJM also
reviews offers, but it does so in order to determine whether offers comply with
the PJM tariff and manuals. PJM, in its role as the market operator, may reject
an offer that fails to comply with the market rules. The respective reviews
performed by the MMU and PJM are separate and non-sequential.
The PJM markets monitored by the MMU include market related procurement
processes conducted by PJM, such as for Black Start resources included in the
PJM system restoration plan.31 32
The MMU also monitors transmission planning, interconnections and rules forvertical market power issues, and with the introduction of competitive transmission
development policy in Order No. 1000, horizontal market power issues.33

Market Design
In order to perform its role in PJM market design, the MMU evaluates existingand proposed PJM Market Rules and the design of the PJM Markets.34 The
MMU initiates and proposes changes to the design of such markets or the
PJM Market Rules in stakeholder or regulatory proceedings.35 In supportof this function, the MMU engages in discussions with stakeholders, State
Commissions, PJM Management, and the PJM Board; participates in PJM
stakeholder meetings or working groups regarding market design matters;
publishes proposals, reports or studies on such market design issues; andmakes filings with the Commission on market design, market rules andmarket rule implementation issues, including complaints or petitions.36 The
MMU also recommends changes to the PJM Market Rules to the staff of theCommission’s Office of Energy Market Regulation, State Commissions, and
31 OATT Attachment M–Appendix § II(p).
32 OATT Attachment M–Appendix § III.
33 OA Schedule 6 § 1.5.
34 OATT Attachment M § IV.D.
35 Id.
36 Id.; see also, e.g., 171 FERC ¶ 61,039; 167 FERC ¶ 61,084 at PP 70–76, reh’g denied, 168 FERC ¶ 61,141.

2021 Quarterly State of the Market Report for PJM: January through June 13

2021 Quarterly State of the Market Report for PJM: January through June

the PJM Board.37 The MMU may provide in its annual, quarterly and otherreports “recommendations regarding any matter within its purview.”38

New Recommendations
Consistent with its core function to “[e]valuate existing and proposed market
rules, tariff provisions and market design elements and recommend proposed
rule and tariff changes,” the MMU recommends specific enhancements toexisting market rules and implementation of new rules that are required forcompetitive results in PJM markets and for continued improvements in thefunctioning of PJM markets.39
In this 2021 Quarterly State of the Market Report for PJM: January throughJune, the MMU includes two new recommendations.

New Recommendation from Section 3, Energy Market• The MMU recommends, if PJM implements extended downward sloping

ORDCs, that PJM calculate the probability of reserves falling below theminimum reserve requirement (MRR) based on ten minute rather than
30 minute forecast error, and on forced outages in the ten minute rather
than the 30 minute look ahead window to model the uncertainty in the
inputs to RT SCED. (Priority: Medium. New recommendation. Status: Not
adopted.)New Recommendation from Section 4, Energy Uplift• The MMU recommends that units not be paid lost opportunity cost

uplift when PJM directs a unit to reduce output based on a transmission
constraint or other reliability issue. There is no lost opportunity because
the unit is required to reduce for the reliability of the unit and the system.
(Priority: High. New recommendation. Status: Not adopted.)

Total Price of Wholesale PowerThe total price of wholesale power is the total price per MWh of wholesale
electricity in PJM markets.40 The total price is an average price. Prices vary bylocation and time period. The total price includes the price of energy, capacity,transmission service, ancillary services, and administrative fees, regulatory
support fees and uplift charges billed through PJM systems. Table 1-8 shows
the average price, by component, for the first six months of 2020 and 2021.
The total billing values shown in Table 1-8 are the total price per MWh, by
category, multiplied by the total load. This total is different from the totalbilling that PJM reports as shown in Figure 1-2. PJM’s reported total billing
represents the total dollars that pass through the PJM settlement process.
There are issues with the PJM total billing calculations. The PJM total billing
calculation includes all billing line item charges including monthly billing
adjustments for the month in which PJM makes the adjustment rather thanthe month to which the adjustment applies. Rather than adding positive andnegative spot market and congestion charges, PJM calculates the averageof the absolute value of the positive and negative charges. PJM also makes
adjustments to eliminate certain transmission owners’ network charges andmonthly bilateral corrections.
Each of the components in Table 1-8 is defined in PJM’s Open AccessTransmission Tariff (OATT) and PJM Operating Agreement and each iscollected through PJM’s billing system.

Components of Total Price• The Energy component is the real-time load weighted average PJM
locational marginal price (LMP).

• The Capacity component is the average price per MWh of Reliability
Pricing Model (RPM) payments.

37 Id.
38 OATT Attachment M § VI.A.
39 18 CFR § 35.28(g)(3)(ii)(A); see also OATT Attachment M § IV.D.

14

Section 1 Introduction

40 Accounting load is used in the calculation of total price because accounting load is the load customers pay for in PJM settlements. The
use of accounting load with losses before June 1, and without losses after June 1, 2007, is consistent with PJM’s calculation of LMP.
Before June 1, 2007, transmission losses were included in accounting load. After June 1, 2007, transmission losses were excluded fromaccounting load and losses were addressed through the incorporation of marginal loss pricing in LMP.

© 2021 Monitoring Analytics, LLC

Section 1 Introduction• The Transmission Service Charges component is the average price per• The Transmission Owner (Schedule 1A) component is the average cost

• The Energy Uplift (Operating Reserves) component is the average price per• The Synchronized Reserve component is the average cost per MWh• The Reactive component is the average cost per MWh of reactive supply• The Black Start component is the average cost per MWh of black start• The Regulation component is the average cost per MWh of regulation• The RTO Startup and Expansion component is the average cost per MWh• The PJM Administrative Fees component is the average cost per MWh• The NERC/RFC component is the average cost per MWh of NERC and RFC

MWh of network integration charges, and firm and nonfirm point topoint transmission service.41
MWh of day-ahead and balancing operating reserves and synchronous
condensing charges.42
and voltage control from generation and other sources.43
procured through the PJM Regulation Market.

44

of PJM’s monthly expenses for a number of administrative services,
including Advanced Control Center (AC2) and OATT Schedule 9 fundingof FERC, OPSI, CAPS and the MMU.

• The Transmission Enhancement Cost Recovery component is the average
cost per MWh of PJM billed (and not otherwise collected through utility
rates) costs for transmission upgrades and projects, including annual
recovery for the TrAIL and PATH projects.45

per MWh of transmission owner scheduling, system control and dispatch
services charged to transmission customers.49

of synchronized reserve procured through the Synchronized Reserve
Market.50
service.51

of charges to recover AEP, ComEd and DAY’s integration expenses.52
charges, plus any reconciliation charges.53• The Economic Load Response component is the average cost per MWhof day-ahead and real-time economic load response program charges to
LSEs.54• The Transmission Facility Charges component is the average cost per
MWh of Ramapo Phase Angle Regulators charges allocated to PJM MidAtlantic transmission owners.55• The Capacity (FRR) component is the average cost per MWh under the• The nonsynchronized reserve component is the average cost per MWh• The Emergency Load Response component is the average cost per MWh• The Emergency Energy component is the average cost per MWh of

Fixed Resource Requirement (FRR) Alternative for an eligible LSE tosatisfy its Unforced Capacity obligation.46of the PJM Emergency Load Response Program.47• The Day-Ahead Scheduling Reserve component is the average cost perof non-synchronized reserve procured through the Non-Synchronized
Reserve Market.56
emergency energy.57

MWh of Day-Ahead scheduling reserves procured through the day-aheadscheduling reserve market.48

41 OATT §§ 13.7, 14.5, 27A & 34.
42 OA Schedules 1 §§ 3.2.3 & 3.3.3.
43 OATT Schedule 2 and OA Schedule 1 § 3.2.3B. The line item in Table 1-8 includes all reactive services charges.
44 OA Schedules 1 §§ 3.2.2, 3.2.2A, 3.3.2, & 3.3.2A; OATT Schedule 3.
45 OATT Schedule 12.
46 RAA Schedule 8.1.
47 OATT PJM Emergency Load Response Program.
48 OA Schedules 1 §§ 3.2.3A.01 & OATT Schedule 6.

© 2021 Monitoring Analytics, LLC

49 OATT Schedule 1A.
50 OA Schedule 1 § 3.2.3A.01; PJM OATT Schedule 6.
51 OATT Schedule 6A. The line item in Table 1-8 includes all Energy Uplift (Operating Reserves) charges for Black Start.
52 OATT Attachments H-13, H-14 and H-15 and Schedule 13.
53 OATT Schedule 10-NERC and OATT Schedule 10-RFC.
54 OA Schedule 1 § 3.6.
55 OA Schedule 1 § 5.3b.
56 OA Schedule 1 § 3.2.3A.001.
57 OA Schedule 1 § 3.2.6.

2021 Quarterly State of the Market Report for PJM: January through June 15

2021 Quarterly State of the Market Report for PJM: January through June

Table 1-8 shows that energy, capacity and transmission charges are the three largest components of the total price per MWh of wholesale power, comprising 97.1
percent of the total price per MWh in the first six months of 2021. The total price per MWh of wholesale power increased from $43.03 in the first six monthsof 2020 to $54.97 in the first six months of 2021, an increase of 27.8 percent. Starting in the third quarter of 2019, for the first time since the start of the PJM
RPM Capacity Market in 2007, the cost of transmission has been a larger share of the total price per MWh of wholesale power than the cost of capacity.
Table 1-8 Total price per MWh by category: January through June, 2020 and 202158 59 60 61
Category
Load Weighted Energy
Capacity
Capacity
Capacity (FRR)
Capacity (RMR)
Transmission
Transmission Service Charges
Transmission Enhancement Cost Recovery
Transmission Owner (Schedule 1A)
Transmission Seams Elimination Cost Assignment (SECA)
Transmission Facility Charges
Ancillary
Reactive
Regulation
Black Start
Synchronized Reserves
Non-Synchronized Reserves
Day Ahead Scheduling Reserve (DASR)
AdministrationPJM Administrative Fees
NERC/RFCRTO Startup and Expansion
Energy Uplift (Operating Reserves)
Demand Response
Load Response
Emergency Load Response
Emergency Energy
Total Price
Total Load (GWh)
Total Billing ($ Billions)

Jan - Jun 2020 Jan - Jun 2020 Jan - Jun 2020 Jan - Jun 2021 Jan - Jun 2021 Jan - Jun 2021$/MWh($ Millions) Percent of Total$/MWh($ Millions) Percent of Total Percent Change$19.40$6,88445.1%$30.62$11,431
55.7%
57.8%
$9.83
$3,48722.8%$9.84$3,674
17.9%
0.2%
$9.83
$3,48722.8%$9.84$3,674
17.9%
0.2%
$0.00
$0
0.0%
$0.00
$0
0.0%
0.0%
$0.00
$0
0.0%
$0.00
$0
0.0%
0.0%
$12.48$4,43029.0%$12.93$4,82923.5%
3.6%$11.78$4,181
27.4%$12.20$4,556
22.2%
3.6%
$0.61
$216
1.4%
$0.64
$238
1.2%
4.7%
$0.09
$32
0.2%
$0.09
$35
0.2%
2.1%
$0.00
$0
0.0%
$0.00
$0
0.0%
0.0%
$0.00
$0
0.0%
$0.00
$0
0.0%
0.0%
$0.71
$251
1.6%
$0.80
$300
1.5%
13.6%
$0.49
$175
1.1%
$0.50
$186
0.9%
1.2%
$0.09
$34
0.2%
$0.14
$51
0.2%
43.8%
$0.09
$33
0.2%
$0.09
$34
0.2%
(3.6%)
$0.02
$5
0.0%
$0.05
$19
0.1%
234.6%
$0.01
$2
0.0%
$0.02
$6
0.0%
141.8%
$0.00
$1
0.0%
$0.01
$4
0.0%
171.1%
$0.54
$192
1.3%
$0.56
$209
1.0%
3.3%
$0.50
$179
1.2%
$0.52
$196
1.0%
3.8%
$0.03
$12
0.1%
$0.04
$13
0.1%
4.9%
$0.00
$1
0.0%
$0.00
$0
0.0%
(100.0%)
$0.06
$23
0.2%
$0.21
$79
0.4%
227.0%
$0.00
$1
0.0%
$0.00
$0
0.0%
(65.2%)
$0.00
$1
0.0%
$0.00
$0
0.0%
(65.2%)
$0.00
$0
0.0%
$0.00
$0
0.0%
0.0%
$0.00
$0
0.0%
$0.00
$0
0.0%
0.0%
$43.03$15,268
100.0%$54.97$20,522100.0%
27.8%
354,842
373,3175.2%$15.27$20.52
34.4%

58 Note: The totals in this table include after the fact billing adjustments and may not match totals presented in past reports.
59 The total billing in this table does not match the PJM reported total billing due to differences in calculation methods. For example, PJM accounts for all adjustments in the month billed, whereas the totals presented in these tables account for those adjustments in the month for which
the adjustment was applied.
60 The total prices in this table are load weighted average system prices per MWh by category, even if each category is not charged on a per MWh basis.
61 The MMU publishes monthly detail of these components of PJM price. See <http://www.monitoringanalytics.com/data/pjm_price.shtml>.

16

Section 1 Introduction© 2021 Monitoring Analytics, LLC

Section 1 Introduction

Table 1-9 shows the inflation adjusted average price, by component, for the first six months of 2020 and 2021. To calculate the inflation adjusted average prices,
the individual components’ prices are deflated using the US Consumer Price Index for all items, Urban Consumers (with a base period of January 1998).62
Table 1-9 Inflation adjusted total price per MWh by category: January through June, 2020 and 202163
Category
Load Weighted Energy
Capacity
Capacity
Capacity (FRR)
Capacity (RMR)
Transmission
Transmission Service Charges
Transmission Enhancement Cost Recovery
Transmission Owner (Schedule 1A)
Transmission Seams Elimination Cost Assignment (SECA)
Transmission Facility Charges
Ancillary
Reactive
Regulation
Black Start
Synchronized Reserves
Non-Synchronized Reserves
Day Ahead Scheduling Reserve (DASR)
AdministrationPJM Administrative Fees
NERC/RFCRTO Startup and Expansion
Energy Uplift (Operating Reserves)
Demand Response
Load Response
Emergency Load Response
Emergency Energy
Total Price
Total Load (GWh)
Total Billing ($ Billions)

Jan-Jun 2020$/MWh
$12.17
$6.17
$6.17
$0.00
$0.00
$7.83
$7.39
$0.38
$0.06
$0.00
$0.00
$0.44
$0.31
$0.06
$0.06
$0.01
$0.00
$0.00
$0.34
$0.32
$0.02
$0.00
$0.04
$0.00
$0.00
$0.00
$0.00
$26.99354,842$9.58

Jan-Jun 2020 Jan-Jun 2020($ Millions) Percent of Total$4,31845.1%$2,18822.8%$2,188
22.8%
$0
0.0%
$0
0.0%
$2,77929.0%$2,624
27.4%
$135
1.4%
$20
0.2%
$0
0.0%
$0
0.0%
$158
1.6%
$110
1.1%
$21
0.2%
$21
0.2%
$3
0.0%
$1
0.0%
$1
0.0%
$121
1.3%
$112
1.2%
$8
0.1%
$1
0.0%
$14
0.2%
$0
0.0%
$0
0.0%
$0
0.0%
$0
0.0%
$9,578100.0%

Jan-Jun 2021$/MWh$18.59
$5.97
$5.97
$0.00
$0.00
$7.85
$7.41
$0.39
$0.06
$0.00
$0.00
$0.49
$0.30
$0.08
$0.06
$0.03
$0.01
$0.01
$0.34
$0.32
$0.02
$0.00
$0.13
$0.00
$0.00
$0.00
$0.00
$33.37373,317$12.46

Jan-Jun 2021 Jan-Jun 2021($ Millions) Percent of Total Percent Change$6,94055.7%
52.8%$2,22817.9%(3.2%)$2,22817.9%(3.2%)
$0
0.0%
0.0%
$0
0.0%
0.0%
$2,93123.5%
0.2%$2,766
22.2%
0.2%
$144
1.2%
1.3%
$21
0.2%
(1.2%)
$0
0.0%
0.0%
$0
0.0%
0.0%
$182
1.5%
9.8%
$113
0.9%
(2.0%)
$31
0.2%
39.0%
$21
0.2%
(6.8%)$120.1%
222.9%$4
0.0%
133.3%$2
0.0%
158.3%
$127
1.0%
0.1%
$119
1.0%
0.5%
$8
0.1%
1.4%
$0
0.0%
(100.0%)$48
0.4%
215.8%$00.0%(64.3%)$00.0%(64.3%)
$0
0.0%
0.0%
$0
0.0%
0.0%
$12,456
100.0%
23.6%
5.2%
30.1%

62 US Consumer Price Index for all items, Urban Consumers (base period: January 1998), published by Bureau of Labor Statistics. <http://download.bls.gov/pub/time.series/‌cu/cu.data.1.AllItems> (July 13, 2021).
63 Note: The totals in this table include after the fact billing adjustments and may not match totals presented in past reports.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 17

2021 Quarterly State of the Market Report for PJM: January through June

Figure 1-3 shows the contributions of load-weighted energy, capacity andtransmission service charges to the total price of wholesale power for eachquarter since 1999.

Figure 1-4 shows the inflation adjusted contributions of load-weighted energy,
capacity and transmission service charges to the total price of wholesale
power for each quarter since 1999.65

Figure 1-3 Top three components of quarterly total price ($/MWh): January
1999 through June 202164

Figure 1-4 Inflation adjusted top three components of quarterly total price($/MWh): January 1999 through June 202166

$120

$120
Total Price
Load Weighted LMP$100

Total Price

Capacity$100

Transmission Service Charges

Load Weighted LMP
Capacity

$60

$40

$20

$20

2001

2003

2005

2007

2009

2011

2013

2015

2017

2019

2021

Year

64 Note: The totals presented in this figure include after the fact billing adjustments and may not match totals presented in past reports.

18

$60

$40

$0
1999

Transmission Service Charges$80
Total Price ($/MWh)Total Price ($/MWh)$80

Section 1 Introduction

$0
1999

2001

2003

2005

2007

2009

2011
Year

2013

2015

2017

2019

2021

65 US Consumer Price Index for all items, Urban Consumers (base period: January 1998), published by Bureau of Labor Statistics. <http://
download.bls.gov/pub/time.series/cu/‌cu.data.1.AllItems> (July 13, 2021).
66 Note: The totals presented in this figure include after the fact billing adjustments and may not match totals presented in past reports.

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

Figure 1-5 shows the total price of wholesale power and the inflation adjusted
total price of wholesale power for each quarter since 1999.67

Section Overviews

Figure 1-5 Quarterly total price and quarterly inflation adjusted total price($/MWh): January 1999 through June 202168

Supply and Demand$120

for spring 2020, and 151,376 MW for spring 2021. The average on-peakhourly offered real-time supply was 123,217 MW for spring 2020, and121,843 MW for spring 2021. In the first six months of 2021, 1,538.8 MWof new resources were added in the energy market, and 1,251.4 MW ofresources were retired.

Total Price (Inflation Adjusted)

Total Price ($/MWh)$80

PJM average hourly real-time cleared generation in the first six monthsof 2021 increased by 5.5 percent from the first six months of 2020, from87,044 MWh to 91,798 MWh

$60

$40

PJM average hourly day-ahead supply in the first six months of 2021,
including INCs and UTCs, decreased by 6.7 percent from the first six
months of 2020, from 109,126 MWh to 101,836 MWh.

$20

$0
1999

Market Structure• Supply. The average on-peak hourly day-ahead supply was 151,999 MW

Total Price$100

Overview: Section 3, Energy Market• Demand. The PJM system real-time hourly peak load plus exports in the
2001

2003

2005

2007

2009

2011
Year

2013

2015

2017

2019

2021

first six months of 2021 was 148,667 MWh (143,559 MW of load plus
5,108 MW of gross exports) in the HE 1700 on June 29, 2021, which was
12,767 MWh, 9.4 percent, higher than the PJM peak load plus exports inthe first six months of 2020, which was 135,900 MWh in the HE 1600 on
June 10, 2020.
PJM average hourly real-time load in the first six months of 2021
increased by 5.8 percent from the first six months of 2020, from 81,255
MWh to 85,958 MWh.
PJM average hourly day-ahead demand in the first six months of 2021,
including DECs and UTCs, decreased by 6.8 percent from the first six
months of 2020, from 104,164 MWh to 97,083 MWh.

67 US Consumer Price Index for all items, Urban Consumers (base period: January 1998), published by Bureau of Labor Statistics. <http://
download.bls.gov/pub/time.series/cu/‌cu.data.1.AllItems> (July 13, 2021).
68 Note: The totals presented in this figure include after the fact billing adjustments and may not match totals presented in past reports.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 19

2021 Quarterly State of the Market Report for PJM: January through June

Market Behavior• Generator Offers. In the day-ahead market in the first six months of 2021,

19.6 percent of MW were offered as must run, 28.0 percent were theeconomic minimum MW for dispatchable units, 51.7 percent were offered
as a dispatchable range, and 0.6 percent were offered as emergency
maximum MW.

• Virtual Offers and Bids. Any market participant in the PJM Day-Ahead

Energy Market can use increment offers, decrement bids, up to congestiontransactions, import transactions and export transactions as financial
instruments that do not require physical generation or load. The hourly
average submitted increment offer MW decreased by 13.2 percent andcleared MW decreased by 4.9 percent in the first six months of 2021
compared to the first six months of 2020. The hourly average submitted
decrement bid MW increased by 29.3 percent and cleared MW increased
by 17.5 percent in the first six months of 2021 compared to the first six
months of 2020. The hourly average submitted up to congestion bid MW
decreased by 50.1 percent and cleared MW decreased by 59.8 percent in
the first six months of 2021 compared to the first six months of 2020.

Market Performance• Generation Fuel Mix. In the first six months of 2021, coal units provided

23.5 percent, nuclear units 33.0 percent and natural gas units 35.6
percent of total generation. Compared to the first six months of 2020,
the generation from coal units increased 39.7 percent, from nuclear units
decreased 2.2 percent and from natural gas units decreased 4.6 percent.

• Fuel Diversity. The fuel diversity of energy generation for the first six
months of 2021, measured by the fuel diversity index for energy (FDIe),
increased 2.8 percent compared to the first six months of 2020.

• Marginal Resources. In the PJM Real-Time Energy Market in the firstsix months of 2021, coal units were 16.8 percent and natural gas units
were 68.7 percent of marginal resources. In the first six months of 2020,
coal units were 16.4 percent and natural gas units were 74.3 percent ofmarginal resources.

20

Section 1 Introduction

In the PJM Day-Ahead Energy Market in the first six months of 2021,
UTCs were 36.5 percent, INCs were 17.7 percent, DECs were 25.1 percent,and generation resources were 20.4 percent of marginal resources. In thefirst six months of 2020, UTCs were 52.3 percent, INCs were 14.3 percent,DECs were 14.2 percent, and generation resources were 19.2 percent ofmarginal resources.

• Prices. PJM load-weighted, average, real-time LMP in the first six monthsof 2021 increased 57.8 percent from the first six months of 2020, from
$19.40 per MWh to $30.62 per MWh.
PJM load-weighted, average day-ahead LMP in the first six months of2021 increased 61.2 percent from the first six months of 2020, from
$19.23 per MWh to $31.00 per MWh.

• Components of LMP. In the PJM Real-Time Energy Market in the first six

months of 2021, 14.0 percent of the load-weighted LMP was the result ofcoal costs, 51.7 percent was the result of gas costs and 3.2 percent was theresult of the cost of emission allowances. In the first six months of 2021,
11.2 percent of load-weighted LMP was the result of the transmission
constraint violation penalty factor due to an increased frequency oftransmission constraint violations, especially on the 500 kV system.
In the PJM Day-Ahead Energy Market, in the first six months of 2021,
27.7 percent of the load-weighted LMP was the result of gas costs, 28.3
percent was the result of DEC bids, 14.3 percent was the result of coal
costs, 12.4 percent was the result of INC offers, 0.7 percent was the resultof markup, and 2.2 percent was the result of UTCs.

• Price Convergence. Hourly and daily price differences between the
day-ahead and real-time energy markets fluctuate continuously andsubstantially from positive to negative. The difference between average
day-ahead and real-time prices was -$0.29 per MWh in the first six
months of 2021, and $0.15 per MWh in the first six months of 2020. The
difference between average day-ahead and real-time prices, by itself, is
not a measure of the competitiveness or effectiveness of the day-aheadenergy market.

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

Scarcity• There were ten intervals with five minute shortage pricing in the firstsix months of 2021. There were no emergency actions that resulted in
Performance Assessment Intervals in the first six months of 2021.

• There were 1,301 five minute intervals, or 2.5 percent of all five minuteintervals in the first six months of 2021 for which at least one RT SCED
solution showed a shortage of reserves, and 333 five minute intervals, or
0.6 percent of all five minute intervals in the first six months of 2021 forwhich more than one RT SCED solution showed a shortage of reserves.
PJM triggered shortage pricing for ten five minute intervals.

Competitive Assessment
Market Structure• Aggregate Pivotal Suppliers. The PJM energy market, at times, requires

generation from pivotal suppliers to meet load, resulting in aggregate
market power even when the HHI level indicates that the aggregate
market is unconcentrated.

• Local Market Power. In the first six months of 2021, 12 control zones

experienced congestion resulting from one or more constraints bindingfor 50 or more hours. For four out of the top 10 congested facilities (byreal-time binding hours) in the first six months of 2021, the average
number of suppliers providing constraint relief was three or less. There isa high level of concentration within the local markets for providing relief
to the most congested facilities in the PJM Real-Time Energy Market. The
local market structure is not competitive.

Market Behavior• Offer Capping for Local Market Power. PJM offer caps units when thelocal market structure is noncompetitive. Offer capping is an effectivemeans of addressing local market power when the rules are designed andimplemented properly. Offer capping levels have historically been low
in PJM. In the day-ahead energy market, for units committed to provide
energy for local constraint relief, offer-capped unit hours increased from© 2021 Monitoring Analytics, LLC

1.2 percent in the first six months of 2020 to 1.3 percent in the firstsix months of 2021. In the real-time energy market, for units committed
to provide energy for local constraint relief, offer-capped unit hours
increased from 0.9 percent in the first six months of 2020 to 1.3 percent
in the first six months of 2021. While overall offer capping levels havebeen low, there are a significant number of units with persistent structural
local market power that would have a significant impact on prices in theabsence of local market power mitigation.
The analysis of the application of the TPS test to local markets demonstrates
that it is working to identify pivotal owners when the market structure isnoncompetitive and to ensure that owners are not subject to offer capping
when the market structure is competitive. There are, however, identified
issues with the application of market power mitigation to resources whose
owners fail the TPS test that can result in the exercise of local market
power. These issues need to be addressed.

• Offer Capping for Reliability. PJM also offer caps units that are committed

for reliability reasons, including for reactive support. In the day-aheadenergy market, for units committed for reliability reasons, offer-capped
unit hours increased from 0.00 percent in the first six months of 2020
to 0.02 percent in the first six months of 2021. In the real-time energy
market, for units committed for reliability reasons, offer-capped unit
hours remained at 0.01 percent in the first six months of 2020 and 2021.
The low offer cap percentages do not mean that units manually committed
for reliability reasons do not have market power. All units manuallycommitted for reliability have market power and all are treated as if they
had market power. These units are not capped to their cost-based offers
because they tend to offer with a negative markup in their price-based
offers, particularly at the economic minimum level, which means that
PJM’s offer capping process results in the use of the price-based offer forcommitment even if it has less flexible operating parameters.

• Parameter Mitigation. In the first six months of 2021, 35.1 percent ofunit hours for units that failed the TPS test in the day-ahead market
were committed on price-based schedules that were less flexible thantheir cost-based schedules. In the first six months of 2021, on days when2021 Quarterly State of the Market Report for PJM: January through June 21

2021 Quarterly State of the Market Report for PJM: January through June

hot weather and cold weather alerts were declared, 31.8 percent of unit
hours in the day-ahead energy market were committed on price-basedschedules that were less flexible than their price PLS schedules.

• Frequently Mitigated Units (FMU) and Associated Units (AU). In 2020, fiveunits qualified for an FMU adder in at least one month. In the first six
months of 2021, one unit qualified for an FMU adder in January.

• Markup Index. The markup index is a summary measure of participant

offer behavior for individual marginal units. While the average markup
index in the real-time market was -0.02 in the first six months of 2021,
some marginal units did have substantial markups. The highest markup
for any marginal unit in the real-time market in the first six months of2021 was more than $400 per MWh when using unadjusted cost-based
offers.
While the average markup index in the day-ahead market was 0.04 in
the first six months of 2021, some marginal units did have substantial
markups. The highest markup for any marginal unit in the day-aheadmarket in the first six months of 2021 was more than $120 per MWhwhen using unadjusted cost-based offers.

• Markup. The markup frequency distributions show that a significant

proportion of units make price-based offers less than the cost-based
offers permitted under the PJM market rules. This behavior means thatcompetitive price-based offers reveal actual unit marginal costs and that
PJM market rules permit the inclusion of costs in cost-based offers thatare not short run marginal costs.
The markup behavior shown in the markup frequency distributions also
shows that a substantial number of units were offered with high markups,
consistent with the exercise of market power.

Market Performance• Markup. The markup conduct of individual owners and units has an

identifiable impact on market prices. Markup is a key indicator of thecompetitiveness of the energy market.

22

Section 1 Introduction

In the PJM Real-Time Energy Market in the first six months of 2021,
the unadjusted markup component of LMP was -$0.13 per MWh or -0.4
percent of the PJM load-weighted, average LMP. June had the highest
peak markup component, $2.76 per MWh, or 6.9 percent of the real-time,
peak hour load-weighted, average LMP for June.
In the PJM Day-Ahead Energy Market, INCs, DECs and UTCs have zero
markups. In the first six months of 2021, the markup component of LMP
was $0.22 per MWh or 0.7 percent of the PJM day-ahead load-weighted,
average LMP. February had the highest unadjusted peak markup
component, $2.13 per MWh.
Participant behavior was evaluated as competitive because the analysis
of markup shows that marginal units generally make offers at, or close
to, their marginal costs in both the day-ahead and real-time energy
markets, although the behavior of some participants represents economic
withholding.

• Markup and Local Market Power. Comparison of the markup behavior of

marginal units with TPS test results shows that for 3.8 percent of all realtime marginal unit intervals in the first six months of 2021, the marginalunit had both local market power as determined by the TPS test and apositive markup. The fact that units with market power had a positive
markup means that the cost-based offer was not used, that a higher pricebased offer was used, and that the process for offer capping units that failthe TPS test does not consistently result in competitive market outcomesin the presence of market power.

• Markup and Aggregate Market Power. In the first six months of 2021,

pivotal suppliers in the aggregate market set prices with high markups forsome real-time market intervals.

Section 3 Recommendations
Market Power• The MMU recommends that the market rules explicitly require thatoffers in the energy market be competitive, where competitive is defined
to be the short run marginal cost of the units. The short run marginal© 2021 Monitoring Analytics, LLC

Section 1 Introduction

cost should reflect opportunity cost when and where appropriate. The
MMU recommends that the level of incremental costs includable in costbased offers not exceed the short run marginal cost of the unit. (Priority:
Medium. First reported 2009. Status: Not adopted.)

Fuel Cost Policies• The MMU recommends that PJM require that all fuel cost policies be
algorithmic, verifiable, and systematic, and accurately reflect short
run marginal costs. (Priority: Medium. First reported 2016. Status: Not
adopted.)• The MMU recommends that the tariff be changed to allow units to haveof cost-based offers. (Priority: Medium. First reported 2016. Status: Not
adopted.)• The MMU recommends removal of all use of FERC System of Accounts in
the Cost Development Guidelines. (Priority: Medium. First reported 2016.
Status: Not adopted.)• The MMU recommends the removal of all use of cyclic starting andpeaking factors from the Cost Development Guidelines. (Priority: Medium.
First reported 2016. Status: Not adopted.)• The MMU recommends the removal of all labor costs from the Cost

Development Guidelines. (Priority: Medium. First reported 2016. Status:
Not adopted.)fuel cost policies that do not include fuel procurement practices, including
fuel contracts. Fuel procurement practices, including fuel contracts, may
be used as the basis for fuel cost policies but should not be required.
(Priority: Low. First reported 2018. Status: Adopted 2020.)• The MMU recommends the removal of all maintenance costs from theto apply only to units that will be offered with non-zero cost-based offers.
The PJM market rules should require that the cost-based offers of units
without an approved fuel cost policy be set to zero. (Priority: Low. First
reported 2018. Status: Adopted 2020.)

the amount and cost of consumables used when operating in order toverify that the total operating cost is consistent with the total quantity
used and the unit characteristics. (Priority: Medium. First reported 2020.
Status: Not adopted.)

Cost Development Guidelines. (Priority: Medium. First reported 2019.
Status: Not adopted.)• The MMU recommends that PJM change the fuel cost policy requirement• The MMU recommends that market participants be required to document• The MMU recommends that the temporary cost method be removed and• The MMU recommends, given that maintenance costs are currently allowedthat all units that submit nonzero cost-based offers be required to havean approved fuel cost policy. (Priority: Low. First reported 2020. Status:
Not adopted.)• The MMU recommends that the penalty exemption provision be removed

and that all units that submit nonzero cost-based offers be required tofollow their approved fuel cost policy. (Priority: Medium. First reported
2020. Status: Not adopted.)

Cost-Based Offers• The MMU recommends that Manual 15 (Cost Development Guidelines) be
replaced with a straightforward description of the components of costbased offers based on short run marginal costs and the correct calculation© 2021 Monitoring Analytics, LLC

in cost-based offers, that market participants be permitted to include
only variable maintenance costs, linked to verifiable operational eventsand that can be supported by clear and unambiguous documentationof the operational data (e.g. run hours, MWh, MMBtu) that support themaintenance cycle of the equipment being serviced/replaced. (Priority:
Medium. First reported 2020. Status: Not adopted.)• The MMU recommends explicitly accounting for soak costs and changing

the definition of the start heat input for combined cycles to include only
the amount of fuel used from first fire to the first breaker close in the Cost
Development Guidelines. (Priority: Medium. First reported 2016. Status:
Not adopted.)

2021 Quarterly State of the Market Report for PJM: January through June 23

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends the removal of nuclear fuel and nonfuel operations

and maintenance costs that are not short run marginal costs from the Cost
Development Guidelines. (Priority: Medium. First reported 2016. Status:
Not adopted.)• The MMU recommends revising the pumped hydro fuel cost calculation

to include day-ahead and real-time power purchases. (Priority: Low. First
reported 2016. Status: Not adopted.)• The MMU recommends revisions to the calculation of energy market

opportunity costs to incorporate all time based offer parameters and all
limitations that impact the opportunity cost of generating unit output.
(Priority: Medium. First reported 2016. Status: Adopted 2020.)• The MMU recommends removing the catastrophic designation for force

majeure fuel supply limitations in Schedule 2. (Priority: Medium. First
reported 2016. Status: Not adopted.)Market Power: TPS Test and Offer Capping• The MMU recommends that the rules governing the application of the

TPS test be clarified and documented. The TPS test application in the dayahead energy market is not documented. (Priority: High. First reported
2015. Status: Partially adopted.)• The MMU recommends that PJM require every market participant tomake available at least one cost schedule based on the same hourly fueltype(s) and parameters at least as flexible as their offered price schedule.
(Priority: Medium. First reported 2015. Status: Not adopted.)• The MMU recommends, in order to ensure effective market power
mitigation when the TPS test is failed, that markup be constant acrossthe full MWh range of price and cost-based offers. (Priority: High. First
reported 2015. Status: Not adopted.)• The MMU recommends, in order to ensure effective market power

mitigation when the TPS test is failed, that offer capping be applied tounits that fail the TPS test in the real-time market that were not offer
capped at the time of commitment in the day-ahead market or at a prior

24

Section 1 Introduction

time in the real-time market. (Priority: High. First reported 2020. Status:
Not adopted.)• The MMU recommends, in order to ensure effective market power
mitigation when the TPS test is failed, and during high load conditions
such as cold and hot weather alerts or more severe emergencies, thatthe operating parameters in the cost-based offer and the price-based
parameter limited schedule (PLS) offer be at least as flexible as theoperating parameters in the available price-based non-PLS offer, and thatthe price-MW pairs in the price-based PLS offer be exactly equal to theprice-based non-PLS offer. (Priority: High. First reported 2015. Status:
Not adopted.)• The MMU recommends, in order to ensure effective market power
mitigation, that PJM always enforce parameter limited values bycommitting units only on parameter limited schedules, when the TPS
test is failed or during high load conditions such as cold and hot weather
alerts or more severe emergencies. (Priority: High. First reported 2019.
Status: Not adopted.)• The MMU recommends that PJM retain the $1,000 per MWh offer cap

in the PJM energy market except when cost-based offers exceed $1,000
per MWh, and retain other existing rules that limit incentives to exercise
market power. (Priority: High. First reported 1999. Status: Partiallyadopted, 1999, 2017.)• The MMU recommends the elimination of FMU and AU adders. FMU and

AU adders no longer serve the purpose for which they were created andinterfere with the efficient operation of PJM markets. (Priority: Medium.
First reported 2012. Status: Partially adopted, 2014.)

Offer Behavior• The MMU recommends that resources not be allowed to violate the ICAP

must offer requirement. The MMU recommends that PJM enforce the
ICAP must offer requirement by assigning a forced outage to any unitthat is derated in the energy market below its committed ICAP without
an outage that reflects the derate. (Priority: Medium. First reported 2020.
Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Section 1 Introduction• The MMU recommends that storage and intermittent resources be subject•

to an enforceable ICAP must offer rule that reflects the limitations of theseresources. (Priority: Medium. First reported 2020. Status: Not adopted.)

The MMU recommends that capacity resources not be allowed to offer
any portion of their capacity market obligation as maximum emergency
energy. (Priority: Medium. First reported 2012. Status: Not adopted.)

Capacity Performance Resources•

The MMU recommends that capacity performance resources be held to
the OEM operating parameters of the capacity market CONE reference
resource for performance assessment and energy uplift payments and that
this standard be applied to all technologies on a uniform basis. (Priority:
Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that the parameters which determine

nonperformance charges and the amounts of uplift payments shouldreflect the flexibility goals of the capacity performance construct. The
operational parameters used by generation owners to indicate to PJM
operators what a unit is capable of during the operating day should not
determine capacity performance assessment or uplift payments. (Priority:
Medium. First reported 2015. Status: Partially adopted.)• The MMU recommends that PJM not include the balancing ratios

calculated for localized Performance Assessment Intervals (PAIs) in thecapacity market default offer cap, and only include those events thattrigger emergencies at a defined zonal or higher level. (Priority: Medium.
First reported 2018. Status: Not adopted.)

performance capacity resources. (Priority: Medium. First reported 2018.
Status: Not adopted.)• The MMU recommends that PJM institute rules that would not pay ashare of capacity market revenue to resources that choose to submit realtime values that are less flexible than their unit specific parameter limits
or approved parameter limit exceptions based on tariff defined reasons.
(Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that PJM not approve temporary exceptions
that are based on pipeline tariff terms that are not routinely enforced,
and based on inferior transportation service procured by the generator.
(Priority: Medium. First reported 2019. Status: Not adopted.)

Accurate System Modeling• The MMU recommends that PJM approve one RT SCED case for each fiveminute interval to dispatch resources during that interval using a fiveminute ramp time, and that PJM calculate prices using LPC for that fiveminute interval using the same approved RT SCED case. (Priority: High.
First reported 2019. Status: Not adopted.)• The MMU recommends that PJM explicitly state its policy on the use oftransmission penalty factors including: the level of the penalty factors;
the triggers for the use of the penalty factors; the appropriate line ratingsto trigger the use of penalty factors; the allowed duration of the violation;
the use of constraint relaxation logic; and when the transmission penalty
factors will be used to set the shadow price. (Priority: Medium. First
reported 2015. Status: Partially adopted 2020.)• The MMU recommends that PJM clearly define the business rules that

• The MMU recommends that PJM routinely review all transmission facility• The MMU recommends that PJM update the tariff to clarify that all• The MMU recommends that PJM not use closed loop interface or surrogate

apply to the unit specific parameter adjustment process, including PJM’s
implementation of the tariff rules in the PJM manuals to ensure market
sellers know the requirements for their resources. (Priority: Low. First
reported 2018. Status: Not adopted.)
generation resources are subject to unit specific parameter limits on
their cost-based offers using the same standard and process as capacity© 2021 Monitoring Analytics, LLC

ratings and any changes to those ratings to ensure that the normal,
emergency and load dump ratings used in modeling the transmission
system are accurate and reflect standard ratings practice. (Priority: Low.
First reported 2013. Status: Partially adopted.)
constraints to artificially override nodal prices based on fundamental LMP
logic in order to: accommodate rather than resolve the inadequacies of the2021 Quarterly State of the Market Report for PJM: January through June 25

2021 Quarterly State of the Market Report for PJM: January through June

demand side resource capacity product; address the inability of the power
flow model to incorporate the need for reactive power; accommodate
rather than resolve the flaws in PJM’s approach to scarcity pricing; orfor any other reason. (Priority: Medium. First reported 2013. Status: Not
adopted.)• The MMU recommends that PJM not use CT price setting logic to modify
transmission line limits to artificially override the nodal prices that are
based on fundamental LMP logic in order to reduce uplift. (Priority:
Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that if PJM believes it appropriate to implement

CT price setting logic, PJM first initiate a stakeholder process to determine
whether such modification is appropriate. PJM should file any proposedchanges with FERC to ensure review. Any such changes should beincorporated in the PJM tariff. (Priority: Medium. First reported 2016.
Status: Partially adopted.)• The MMU recommends that PJM update the outage impact studies,

the reliability analyses used in RPM for capacity deliverability, andthe reliability analyses used in RTEP for transmission upgrades to beconsistent with the more conservative emergency operations (postcontingency load dump limit exceedance analysis) in the energy market
that were implemented in June 2013. (Priority: Low. First reported 2013.
Status: Not adopted.)• The MMU recommends that PJM include in the tariff or appropriate

manual an explanation of the initial creation of hubs, the process formodifying hub definitions and a description of how hub definitions havechanged.69 70 (Priority: Low. First reported 2013. Status: Not adopted.)• The MMU recommends that all buses with a net withdrawal be treated asload for purposes of calculating load and load-weighted LMP, even if the
MW are settled to the generator. The MMU recommends that during hours
when a load bus shows a net injection, the energy injection be treatedas generation, not negative load, for purposes of calculating generation

69 According to minutes from the first meeting of the Energy Market Committee (EMC) on January 28, 1998, the EMC unanimously agreed
to be responsible for approving additions, deletions and changes to the hub definitions to be published and modeled by PJM. Since the
EMC has become the Market Implementation Committee (MIC), the MIC now appears to be responsible for such changes.
70 There is currently no PJM documentation in the tariff or manuals explaining how hubs are created and how their definitions are changed.
The general definition of a hub can be found in the PJM.com Glossary <http://www.pjm.com/Glossary.aspx>.

26

Section 1 Introduction

and load-weighted LMP, even if the injection MW are settled to the load
serving entity. (Priority: Low. First reported 2013. Status: Not adopted.)• The MMU recommends that PJM identify and collect data on available
behind the meter generation resources, including nodal location
information and relevant operating parameters. (Priority: Low. First
reported 2013. Status: Partially adopted.)• The MMU recommends that PJM document how LMPs are calculated
when demand response is marginal. (Priority: Low. First reported 2014.
Status: Not adopted.)• The MMU recommends that PJM not allow nuclear generators which do

not respond to prices or which only respond to manual instructions fromthe operator to set the LMPs in the real-time market. (Priority: Low. First
reported 2016. Status: Not adopted.)• The MMU recommends that PJM increase the coordination of outage andoperational restrictions data submitted by market participants via eDART/eGADs and offer data submitted via Markets Gateway. (Priority: Low. First
reported 2017. Status: Not adopted.)• The MMU recommends that PJM model generators’ operating transitions,

including soak time for units with a steam turbine, configurationtransitions for combined cycles, and peak operating modes. (Priority:
Medium. First reported 2019. Status: Not adopted.)• The MMU recommends that PJM clarify, modify and document its process

for dispatching reserves and energy when SCED indicates that supply isless than total demand including forecasted load and reserve requirements.
The modifications should define: a SCED process to economically convert
reserves to energy; a process for the recall of energy from capacity
resources; and the minimum level of synchronized reserves that would
trigger load shedding. (Priority: Medium. First reported 2020. Status: Not
adopted.)• The MMU recommends that PJM stop capping the system marginal pricein RT SCED and instead limit the sum of violated reserve constraint
shadow prices used in LPC to $1,700 per MWh. (Priority: Medium. First
reported Q1, 2021. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Section 1 Introduction• The MMU recommends, if PJM implements extended downward sloping

ORDCs, that PJM calculate the probability of reserves falling below theminimum reserve requirement (MRR) based on ten minute rather than
30 minute forecast error, and on forced outages in the ten minute rather
than the 30 minute look ahead window to model the uncertainty in the
inputs to RT SCED. (Priority: Medium. New recommendation. Status: Not
adopted.)Transparency• The MMU recommends that PJM market rules require the fuel type beidentified for every price and cost schedule and PJM market rules remove
nonspecific fuel types such as other or co-fire other from the list of fueltypes available for market participants to identify the fuel type associatedwith their price and cost schedules. (Priority: Medium. First reported 2015.
Status: Adopted 2019.)• The MMU recommends that PJM allow generators to report fuel typeon an hourly basis in their offer schedules and to designate schedule
availability on an hourly basis. (Priority: Medium. First reported 2015.
Status: Partially adopted.)• The MMU recommends that PJM define clear criteria for operator approvalof RT SCED cases, including shortage cases, that are used to send dispatch
signals to resources, and for pricing, to minimize discretion. (Priority:
High. First reported 2018. Status: Partially adopted.)

Virtual Bids and Offers• The MMU recommends eliminating up to congestion (UTC) bidding at
pricing nodes that aggregate only small sections of transmission zones
with few physical assets. (Priority: Medium. First reported 2020. Status:
Not adopted.)• The MMU recommends eliminating INC, DEC, and UTC bidding at pricing

nodes that allow market participants to profit from modeling issues.
(Priority: Medium. First reported 2020. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Section 3 Conclusion
The MMU analyzed key elements of PJM energy market structure, participant
conduct and market performance in the first six months of 2021, including
aggregate supply and demand, concentration ratios, aggregate pivotal
supplier results, local three pivotal supplier test results, offer capping, markup,
marginal units, participation in demand response programs, virtual bids andoffers, loads and prices.
PJM average hourly real-time load in the first six months of 2021 increased
by 5.8 percent from the first six months of 2020, from 81,255 MWh to 85,958
MWh. The relationship between supply and demand, regardless of the specificmarket, along with market concentration and the extent of pivotal suppliers,
is referred to as the supply-demand fundamentals or economic fundamentals
or market structure. The market structure of the PJM aggregate energy market
is partially competitive because aggregate market power does exist for asignificant number of hours. The HHI is not a definitive measure of structural
market power. The number of pivotal suppliers in the energy market is amore precise measure of structural market power than the HHI. It is possible
to have pivotal suppliers in the aggregate market even when the HHI levelis not in the highly concentrated range. Even a low HHI may be consistent
with the exercise of market power with a low price elasticity of demand. The
current market power mitigation rules for the PJM energy market rely on
the assumption that the ownership structure of the aggregate market ensurescompetitive outcomes. This assumption requires that the total demand forenergy can be met without the supply from any individual supplier or without
the supply from a small group of suppliers. This assumption is not correct.
There are pivotal suppliers in the aggregate energy market at times. High
markups for some units demonstrate the potential to exercise market powerboth routinely and during high demand conditions. The existing market
power mitigation measures do not address aggregate market power. The MMU
is developing an aggregate market power test and will propose market power
mitigation rules to address aggregate market power.

2021 Quarterly State of the Market Report for PJM: January through June 27

2021 Quarterly State of the Market Report for PJM: January through June

The three pivotal supplier test is applied by PJM on an ongoing basis for local
energy markets in order to determine whether offer capping is required fortransmission constraints.71 However, there are some issues with the applicationof market power mitigation in the day-ahead energy market and the real-timeenergy market when market sellers fail the TPS test. Many of these issues canbe resolved by simple rule changes.
The enforcement of market power mitigation rules is undermined if thedefinition of a competitive offer is not correct. A competitive offer is equal toshort run marginal costs. The significance of competition metrics like markup
is also undermined if the definition of a competitive offer is not correct. The
definition of a competitive offer, under the PJM Market Rules, is not currently
correct. The definition, that all costs that are related to electric production are
short run marginal costs, is not clear or correct. All costs and investmentsfor power generation are related to electric production. Under this definition,some unit owners include costs that are not short run marginal costs inoffers, especially maintenance costs. This issue can be resolved by simple rulechanges to incorporate a clear and accurate definition of short run marginal
costs.
Prices are a key outcome of markets. Prices vary across hours, days and years
for multiple reasons. Price is an indicator of the level of competition in amarket. In a competitive market, prices are directly related to the marginal
cost to serve load at a given time. The pattern of prices within days and acrossmonths and years illustrates how prices are directly related to supply anddemand conditions and thus also illustrates the potential significance of the
impact of the price elasticity of demand on prices. Energy market results inthe first six months of 2021 generally reflected supply-demand fundamentals,
although the behavior of some participants both routinely and during highdemand periods represents economic withholding. Economic withholding
occurs when generator offers are greater than competitive levels. There are
additional issues in the energy market including the uncertainties about
the pricing and availability of natural gas, the way that generation owners
incorporate natural gas costs in offers, and the lack of adequate incentives forunit owners to take all necessary actions to acquire fuel, staff their units, andoperate rather than economically withhold or physically withhold.
Prices in PJM are not too low. Prices in PJM are the result of input prices,consistent with a competitive market. Low natural gas prices have been a
primary cause of low PJM energy market prices. There is no evidence tosupport the need for a significant change to the calculation of LMP, such as
fast start pricing or the extended ORDC. Fast start pricing and the extended
ORDC will disconnect pricing from dispatch instructions and create greater
reliance on uplift as an incentive to follow PJM’s instructions. The extended
ORDCs will create shortage pricing when no reserve shortages exist. Rather
than undercutting the basic LMP logic that is core to market efficiency, it
would make more sense to directly address the design of RT SCED/LPC,
scarcity pricing, operator actions and the design of reserve markets. PJM has
made progress in addressing the timing of RT SCED and LPC and accepting
shortage pricing in some cases when SCED shows a shortage, but moreprogress is needed.
The PJM defined inputs to the dispatch tools, particularly the RT SCED, havesubstantial effects on energy market outcomes. Transmission line ratings,
transmission penalty factors, load forecast bias, hydro resource schedules, andunit ramp rate adjustments change the dispatch of the system, affect prices,and can create significant price increases through transmission line limit
violations or restrictions on the resources available to resolve constraints.
The automated adjustment of ramp rates by PJM, called Degree of Generator
Performance (DGP), modifies the values offered by generators and limits
the MW available to the RT SCED. Rather than sending dispatch signals
consistent with resource offers and holding resources accountable when they
fail to follow them, DGP accommodates resources that do not follow dispatch.
PJM operator interventions to reduce line ratings unnecessarily trigger
transmission constraint penalty factors and significantly increase prices.
PJM should evaluate its interventions in the market, consider whether theinterventions are appropriate, and provide greater transparency to enhancemarket efficiency.

71 The MMU reviews PJM’s application of the TPS test and brings issues to the attention of PJM.

28

Section 1 Introduction© 2021 Monitoring Analytics, LLC

Section 1 Introduction

The objective of efficient short run price signals is to minimize systemproduction costs, not to minimize uplift. Repricing the market to reflectcommitment costs prioritizes minimizing uplift over minimizing production
costs. The tradeoff exists because when commitment costs are included inprices, the price signal no longer equals the short run marginal cost andtherefore no longer provides the correct signal for efficient behavior formarket participants making decisions on the margin, whether resources, load,interchange transactions, or virtual traders. This tradeoff will be created by
PJM’s fast start pricing proposal as approved by FERC and would be createdin a much more extensive form by PJM’s pending extended ORDC pricing
changes.72
Units that start in one hour are not actually fast start units, and theircommitment costs are not marginal in a five minute market. The differences
between the actual LMP and the fast start LMP will distort the incentive formarket participants to behave competitively and to follow PJM’s dispatch
instructions. PJM will pay new forms of uplift in an attempt to counter the
distorted incentives. The magnitude of the new payments and their effects on
behavior are not well understood.
PJM’s arguments for changing energy market price formation asserted thatfast start pricing and the extended ORDC would price flexibility in the market,
but instead they will benefit inflexible units. The fast start pricing extended
ORDC solutions would undercut LMP logic rather than directly addressing theunderlying issues. The solution is not to accept that the inflexible CT shouldbe paid or set price based on its commitment costs rather than its short run
marginal costs. The question of why units make inflexible offers should be
addressed directly. Are units inflexible because they are old and inefficient,because owners have not invested in increased flexibility or because they
serve as a mechanism for the exercise of market power? The question of
why the unit was built, whether it was built under cost of service regulation
and whether it is efficient to retain the unit should be answered directly. The
question of how to provide market incentives for investment in flexible units,
for investment in increased flexibility of existing units, and for operating at
72 See 173 FERC ¶ 61,244 (2020).

© 2021 Monitoring Analytics, LLC

the full extent of existing flexibility should be addressed directly. The questionof whether inflexible units should be paid uplift at all should be addressed
directly. Marginal cost pricing without paying excess uplift to inflexible units
would create incentives for market participants to provide flexible solutions
including replacing inefficient units with flexible, efficient units.
With or without a capacity market, energy market design must permit scarcity
pricing when such pricing is consistent with market conditions and constrainedby reasonable rules to ensure that market power is not exercised and ensure no
scarcity pricing when such pricing is not consistent with market conditions.
Scarcity pricing can serve two functions in wholesale power markets:
revenue adequacy and price signals. Scarcity pricing for revenue adequacy,
as in PJM’s ORDC proposal, is not required in PJM. Scarcity pricing for pricesignals that reflect market conditions during periods of scarcity is requiredin PJM. Scarcity pricing is also part of an appropriate incentive structure
facing both load and generation owners in a working wholesale electric power
market design. Scarcity pricing must be designed to ensure that market prices
reflect actual market conditions, that scarcity pricing occurs with transparent
triggers based on measured reserve levels and transparent prices, that scarcity
pricing only occurs when scarcity exists, and that there are strong incentives
for competitive behavior and strong disincentives to exercise market power.
Such administrative scarcity pricing is a key link between energy and capacity
markets. Administrative scarcity pricing that establishes scarcity pricing in
about 85 percent of hours, as PJM’s ORDC proposal would, is not scarcity
pricing but simply a revenue enhancement mechanism, which could haveunintended consequences in an emergency, as was the case in ERCOT in
February 2021. PJM’s pending ORDC changes are not consistent with efficient
market design and are just a revenue enhancement mechanism.
The PJM Capacity Market is explicitly designed to provide revenue adequacy
and the resultant reliability. However, the explicit balancing mechanism that
included net revenues directly in unit offers in the prior capacity market design
is not present in the Capacity Performance design. The nature of a direct andexplicit energy pricing net revenue true up mechanism in the capacity market
should be addressed if energy revenues are expected to increase as a result of

2021 Quarterly State of the Market Report for PJM: January through June 29

2021 Quarterly State of the Market Report for PJM: January through June

scarcity events, as a result of increased demand for reserves, or as a result of
PJM’s inappropriate proposals related to fast start pricing and the inclusionof maintenance expenses as short run marginal costs. The true up mechanism
must address both cleared auctions and subsequent auctions. There are alsosignificant issues with PJM’s scarcity pricing rules, including the absence of aclear trigger based on measured reserve levels (the current triggers are basedon estimated reserves) and the lack of adequate locational scarcity pricing
options.
The overall energy market results support the conclusion that energy prices
in PJM are set, generally, by marginal units operating at, or close to, their
marginal costs, although this was not always the case in the first six monthsof 2021 or prior years. In the first six months of 2021, marginal units werepredominantly combined cycle gas generators. The frequency of combined
cycle gas units as the marginal unit type has risen rapidly, from 31.5 percent
in the first six months of 2016 to 61.1 percent in the first six months of 2021.
Overdue improvements in generator modeling in the energy market would
allow PJM to more efficiently commit and dispatch combined cycle plants
and to fully reflect the flexibility of these units. New combined cycle units
have placed competitive pressure on less efficient generators, and the market
has reliably served load with less congestion, less uplift, and less markup asa result. This is evidence of generally competitive behavior and competitivemarket outcomes, although the behavior of some participants represents
economic withholding. Given the structure of the energy market which
can permit the exercise of aggregate and local market power, the change
in some participants’ behavior is a source of concern in the energy market
and provides a reason to use correctly defined short run marginal cost as thesole basis for cost-based offers and a reason for implementing an aggregate
market power test and correcting the offer capping process for resources withlocal market power. The MMU concludes that the PJM energy market results
were competitive in the first six months of 2021.

30

Section 1 Introduction

Overview: Section 4, Energy Uplift
Energy Uplift Credits• Types of credits. In the first six months of 2021, energy uplift credits were
$79.2 million, including $7.2 million in day-ahead generator credits, $55.4
million in balancing generator credits, $11.1 million in lost opportunity
cost credits, and $4.6 million in local constraint control credits.

• Types of units. In the first six months of 2021, coal units received 74.8
percent of day-ahead generator credits, and combustion turbines received
93.8 percent of balancing generator credits and 98.3 percent of lost
opportunity cost credits.

• Economic and Noneconomic Generation. In the first six months of 2021,

89.1 percent of the day-ahead generation eligible for operating reserve
credits was economic and 62.3 percent of the real-time generation eligible
for operating reserve credits was economic.

• Day-Ahead Unit Commitment for Reliability. In the first six months of2021, 0.1 percent of the total day-ahead generation MWh was scheduled
as must run for reliability by PJM, of which 76.1 percent received energy
uplift payments.

• Concentration of Energy Uplift Credits. In the first six months of 2021,

the top 10 units receiving energy uplift credits received 16.8 percent
of all credits and the top 10 organizations received 71.4 percent of allcredits. The HHI for day-ahead operating reserves was 7670, the HHI for
balancing operating reserves was 2882 and the HHI for lost opportunity
cost was 6595, all of which are classified as highly concentrated.

• Lost Opportunity Cost Credits. Lost opportunity cost credits increased by$4.4 million or 66.7 percent, in the first six months of 2021 comparedto the first six months of 2020, from $6.6 million to $11.1 million.
Some combustion turbines and diesels are scheduled day-ahead but not
requested in real time, and receive day-ahead lost opportunity cost credits
as a result. This was the source of 97.9 percent of the $11.1 million. The
day-ahead generation paid LOC credits for this reason decreased by 343.5© 2021 Monitoring Analytics, LLC

Section 1 Introduction•

GWh or 64.0 percent during 2021, compared to 2020, from 536.5 GWh
to 193.1 GWh.
Following Dispatch. Some units are incorrectly paid uplift despite notmeeting uplift eligibility requirements, including not following dispatch,
not having the correct commitment status, or not operating with proper
offer parameters. Since 2018, the MMU has made cumulative resettlement
requests for overpaid units that total $13.0 million, of which PJM has
resettled 10.6 percent.

Energy Uplift Charges•

Energy Uplift Charges. Total energy uplift charges increased by $55.7
million, or 236.1 percent, in the first six months of 2021 compared to thefirst six months of 2020, from $23.5 million to $79.0 million.

• Energy Uplift Charges Categories. The increase of $55.7 million in thefirst six months of 2021 was comprised of a $4.2 million increase in dayahead operating reserve charges, a $51.1 million increase in balancing
operating reserve charges, and a $0.4 million increase in reactive services
charges.

Geography of Charges and Credits• In the first six months of 2021, 89.5 percent of all uplift charges allocatedregionally (day-ahead operating reserves and balancing operating
reserves) were paid by transactions at control zones, 3.5 percent bytransactions at hubs and aggregates, and 7.0 percent by transactions atinterchange interfaces.

• In the first six months of 2021, generators in the Eastern Region received
41.3 percent of all balancing generator credits, including lost opportunity
cost and canceled resources credits.

• In the first six months of 2021, generators in the Western Region received

56.1 percent of all balancing generator credits, including lost opportunity
cost and canceled resources credits.

• In the first six months of 2021, external generators received 2.6 percent

of all balancing generator credits, including lost opportunity cost andcanceled resources credits.

Section 4 Recommendations• Average Effective Operating Reserve Rates in the Eastern Region. Day-

• The MMU recommends that uplift be paid only based on operating• Average Effective Operating Reserve Rates in the Western Region. Day-

• The MMU recommends that PJM initiate an analysis of the reasons• Reactive Services Rates. PPL and MEC were the two zone with the highest• The MMU recommends that PJM develop and implement an accurateahead load paid $0.017 per MWh, real-time load paid $0.088 per MWh,
DECs and UTCs paid $0.354 per MWh and an INC and any load, generation
or interchange transaction deviation paid $0.337 per MWh.
ahead load paid $0.017 per MWh, real-time load paid $0.073 per MWh,
DECs and UTCs paid $0.317 per MWh and an INC and any load, generation
or interchange transaction deviation paid $0.300 per MWh in the first six
months of 2021.

local voltage support rates, excluding reactive capability payments. PPL
had a rate of $0.034 per MWh, MEC had a rate of $0.001 per MWh© 2021 Monitoring Analytics, LLC

parameters that reflect the flexibility of the benchmark new entrant unit
(CONE unit) in the PJM Capacity Market. (Priority: High. First reported
2018. Status: Not adopted.)

why a significant number of combustion turbines and diesels scheduledin the day-ahead energy market are not called in real time when they
are economic. (Priority: Medium. First Reported 2012. Status: Partiallyadopted, 2019.)
metric to define when a unit is following dispatch to determine eligibility
to receive balancing operating reserve credits and for assessing generator
deviations and that PJM not pay uplift to units not following dispatch.
(Priority: Medium. First reported 2018. Status: Not adopted.)

2021 Quarterly State of the Market Report for PJM: January through June 31

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends that PJM designate units whose offers are flagged

for fixed generation in Markets Gateway as not eligible for uplift. Units
that are flagged for fixed generation are not dispatchable. Following
dispatch is an eligibility requirement for uplift compensation. (Priority:
Medium. First reported 2020. Status: Not adopted.)• The MMU recommends eliminating intraday segments from the calculationof uplift payments and returning to calculating the need for uplift basedon the entire 24 hour operating day. (Priority: High. First reported 2018.
Status: Not adopted.)• The MMU recommends the elimination of day-ahead uplift to ensure that
units receive an energy uplift payment based on their real-time output andnot their day-ahead scheduled output. (Priority: Medium. First reported
2013. Status: Not adopted.)• The MMU recommends enhancing the current energy uplift allocation

rules to reflect the recommended elimination of day-ahead uplift, thetiming of commitment decisions and the commitment reasons. (Priority:
High. First reported 2012. Status: Not adopted.)• The MMU recommends that units not be paid lost opportunity cost

• The MMU recommends three modifications to the energy lost opportunity
cost calculations:— The MMU recommends calculating LOC based on 24 hour daily periods

for combustion turbines and diesels scheduled in the day-aheadenergy market, but not committed in real time. (Priority: Medium. First
reported 2014. Status: Not adopted.)— The MMU recommends that units scheduled in the day-ahead energy

market and not committed in real time should be compensated for
LOC based on their real-time desired and achievable output, not theirscheduled day-ahead output. (Priority: Medium. First reported 2015.
Status: Not adopted.)— The MMU recommends that only flexible fast start units (startup

plus notification times of 10 minutes or less) and units with shortminimum run times (one hour or less) be eligible by default for the
LOC compensation to units scheduled in the day-ahead energy market
and not committed in real time. Other units should be eligible for
LOC compensation only if PJM explicitly cancels their day-ahead
commitment. (Priority: Medium. First reported 2015. Status: Not
adopted.)uplift when PJM directs a unit to reduce output based on a transmission
constraint or other reliability issue. There is no lost opportunity because
the unit is required to reduce for the reliability of the unit and the system.
(Priority: High. New recommendation. Status: Not adopted.)• The MMU recommends that up to congestion transactions be required toas an offset in the calculation of balancing operating reserve credits.
(Priority: Medium. First reported 2009. Status: Not adopted.)transactions (IBTs) in the calculation of deviations used to allocatebalancing operating reserve charges. (Priority: High. First reported 2013.
Status: Adopted 2018.73)• The MMU recommends reincorporating the use of net regulation revenues• The MMU recommends that self scheduled units not be paid energy uplift

for their startup cost when the units are scheduled by PJM to start before
the self scheduled hours. (Priority: Low. First reported 2013. Status: Not
adopted.)pay energy uplift charges for both the injection and the withdrawal sidesof the UTC. (Priority: High. First reported 2011. Status: Partially adopted.)• The MMU recommends eliminating the use of internal bilateral• The MMU recommends allocating the energy uplift payments to units

scheduled as must run in the day-ahead energy market for reasons otherthan voltage/reactive or black start services as a reliability charge to realtime load, real-time exports and real-time wheels. (Priority: Medium. First
reported 2014. Status: Not adopted. Stakeholder process.)

73 As of November 1, 2018, internal bilateral transactions are no longer used for the calculation of deviations for purposes of allocatingbalancing operating reserve charges. See the 2018 State of the Market Report for PJM, Volume II, Section 3: “Energy Market” at “Internal
Bilateral Transactions” for an analysis of the impact of this change on virtual bidding activity.

32

Section 1 Introduction© 2021 Monitoring Analytics, LLC

Section 1 Introduction• The MMU recommends that the total cost of providing reactive support• The MMU recommends that PJM eliminate the exemption for fast start• The MMU recommends including real-time exports and real-time wheels

Section 4 Conclusion

be categorized and allocated as reactive services. Reactive services credits
should be calculated consistent with the balancing operating reserve
credit calculation. (Priority: Medium. First reported 2012. Status: Not
adopted. Stakeholder process.)in the allocation of the cost of providing reactive support to the 500
kV system or above, in addition to real-time load. (Priority: Low. First
reported 2013. Status: Not adopted.)• The MMU recommends modifications to the calculation of lost opportunity

costs credits paid to wind units. The lost opportunity costs credits paid
to wind units should be based on the lesser of the desired output, theestimated output based on actual wind conditions and the capacity
interconnection rights (CIRs). The MMU recommends that PJM allow
wind units to request CIRs that reflect the maximum output wind units
want to inject into the transmission system at any time. (Priority: Low.
First reported 2012. Status: Not adopted.)• The MMU recommends that PJM clearly identify and classify all reasonsfor incurring uplift in the day-ahead and the real-time energy markets
and the associated uplift charges in order to make all market participants
aware of the reasons for these costs and to help ensure a long term solution
to the issue of how to allocate the costs of uplift. (Priority: Medium. First
reported 2011. Status: Partially adopted.)• The MMU recommends that PJM revise the current uplift (operating

reserve) confidentiality rules in order to allow the disclosure of complete
information about the level of uplift (operating reserve charges) by unit
and the detailed reasons for the level of operating reserve credits by unit
in the PJM region. (Priority: High. First reported 2013. Status: Partiallyadopted.74)• The MMU recommends that PJM pay uplift based on the offer at the lowerof the actual unit output or the dispatch signal MW. (Priority: Medium.
First reported 2018. Status: Not adopted.)

74 On September 7, 2018, PJM made a compliance filing for FERC Order No. 844 to publish unit specific uplift credits. The compliance filing
was accepted by FERC on March 21, 2019. 166 FERC ¶ 61,210. PJM began posting unit specific uplift reports on May 1, 2019. 167 FERC ¶61,280 (2019).

© 2021 Monitoring Analytics, LLC

resources (CTs and diesels) from the requirement to follow dispatch.
The performance of these resources should be evaluated in a mannerconsistent with all other resources (Priority: Medium. First reported 2018.
Status: Not adopted.)

Competitive market outcomes result from energy offers equal to short run
marginal costs that incorporate flexible operating parameters. When PJM
permits a unit to include inflexible operating parameters in its offer and pays
uplift based on those inflexible parameters, there is an incentive for the unit
to remain inflexible. The rules regarding operating parameters should be
implemented in a way that creates incentives for flexible operations rather
than inflexible operations. The standard for paying uplift should be themaximum achievable flexibility, based on OEM standards for the benchmark
new entrant unit (CONE unit) in the PJM Capacity Market. Applying a weakerstandard effectively subsidizes inflexible units by paying them based on
inflexible parameters that result from lack of investment and that could bemade more flexible. The result both inflates uplift costs and suppresses energy
prices.
It is not appropriate to accept that inflexible units should be paid or set
price based on short run marginal costs plus start up and no load costs. The
question of why units make inflexible offers should be addressed directly. Are
units inflexible because they are old and inefficient, because owners have notinvested in increased flexibility or because they serve as a mechanism forthe exercise of market power? The question of why the inflexible unit was
built, whether it was built under cost of service regulation and whether it isefficient to retain the unit should be answered directly. The question of how toprovide market incentives for investment in flexible units and for investment
in increased flexibility of existing units should be addressed directly. The
question of whether inflexible units should be paid uplift at all should be
addressed directly. Marginal cost pricing without paying uplift to inflexible

2021 Quarterly State of the Market Report for PJM: January through June 33

2021 Quarterly State of the Market Report for PJM: January through June

units would create incentives for market participants to provide flexible
solutions including replacing inefficient units with flexible, efficient units.
Implementing combined cycle modeling, to permit the energy market model
optimization to take advantage of the versatility and flexibility of combined
cycle technology in commitment and dispatch, would provide significant
flexibility without requiring a distortion of the market rules.
The reduction of uplift payments should not be a goal to be achieved at theexpense of the fundamental logic of the LMP system. For example, the use of
closed loop interfaces to reduce uplift should be eliminated because it is notconsistent with LMP fundamentals and constitutes a form of subjective pricesetting. The same is true of what PJM terms its CT price setting logic. The
same is true of fast start pricing. The same is true of PJM’s proposal to modify
the ORDC in order to increase energy prices and reduce uplift.
Accurate short run price signals, equal to the short run marginal cost ofgenerating power, provide market incentives for cost minimizing production
to all economically dispatched resources and provide market incentives toload based on the marginal cost of additional consumption. The objective ofefficient short run price signals is to minimize system production costs, not tominimize uplift. Repricing the market to reflect commitment costs will createa tradeoff between minimizing production costs and reduction of uplift. The
tradeoff will exist because when commitment costs are included in prices, theprice signal no longer equals the short run marginal cost and therefore nolonger provides the correct signal for efficient behavior for market participants
making decisions on the margin, whether resources, load, interchangetransactions, or virtual traders. This tradeoff will be created by PJM’s fast
start pricing proposal (limited convex hull pricing). Fast start pricing has been
approved by FERC subject to a PJM compliance filing on the definition of fast
start resources, and is expected to be implemented in September 2021.75 Fast
start pricing will significantly affect uplift calculations.
When units receive substantial revenues through energy uplift payments,
these payments are not fully transparent to the market, in part because of the
75 See 173 FERC ¶ 61,244 (2020).

34

Section 1 Introduction

current confidentiality rules. As a result, other market participants, including
generation and transmission developers, do not have the opportunity tocompete to displace them. As a result, substantial energy uplift payments
to a concentrated group of units and organizations have persisted. FERC
Order No. 844 authorized the publication of unit specific uplift payments for
credits incurred after July 1, 2019.76 However, Order No. 844 failed to require
the publication of unit specific uplift credits for the largest units receiving
significant uplift payments, inflexible steam units committed for reliability inthe day-ahead market.
One part of addressing the level and allocation of uplift payments is to eliminate
all day-ahead operating reserve credits. It is illogical and unnecessary to pay
units day-ahead operating reserve credits because units do not incur any
costs to run and any revenue shortfalls are addressed by balancing operating
reserve credits.
On July 16, 2020, following its investigation of the issue, the Commission
ordered PJM to revise its rules so that UTCs are required to pay uplift on
the withdrawal side (DEC) only.77 The uplift payments for UTCs began on
November 1, 2020.78
PJM needs to pay substantially more attention to the details of uplift payments
including accurately tracking whether units are following dispatch, identifying
the actual need for units to be dispatched out of merit and determining whether
local reserve zones or better definitions of constraints would be a more market
based approach. PJM pays uplift to units even when they do not operate asrequested by PJM, i.e. they do not follow dispatch. PJM uses dispatcher logs asa primary screen to determine if units are eligible for uplift regardless of how
they actually operate or if they followed the PJM dispatch signal. The relianceon dispatcher logs for this purpose is impractical, inefficient, and incorrect.
PJM needs to define and implement rules for determining when units are
76 On March 21, 2019 FERC accepted PJM’s Order No. 844 compliance filing. 166 FERC ¶ 61,210 The filing stated that PJM would begin
posting unit specific uplift reports on May 1, 2019. On April 8, 2019, PJM filed for an extension on the implementation date of the zonal
uplift reports and unit specific uplift reports to July 1, 2019. On June 28, 2019, FERC accepted PJM’s request for extension of effective
dates. 167 FERC ¶ 61,280.
77 See 172 FERC ¶ 61,046.
78 On October 17, 2017, PJM filed a proposed tariff change at FERC to allocate uplift to UTC transactions in the same way uplift is allocatedto other virtual transactions, as a separate injection and withdrawal deviation. FERC rejected the proposed tariff change. See 162 FERC ¶61,019 (2018).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

following dispatch as a primary screen for eligibility for uplift payments. PJM
should not pay uplift to units that do not follow dispatch.
The MMU notifies PJM and generators of instances in which, based on the
PJM dispatch signal and the real time output of the unit, it is clear thatthe unit did not operate as requested by PJM. The MMU sends requests forresettlements to PJM to make these units ineligible for uplift credits. Since
2018, the MMU has identified $13.0 million of incorrect uplift credits.
While energy uplift charges are an appropriate part of the cost of energy,
market efficiency would be improved by ensuring that the level and variabilityof these charges are as low as possible consistent with the reliable operationof the system and consistent with pricing at short run marginal cost. The goal
should be to minimize the total incurred energy uplift charges and to increase
the transactions over which those charges are spread in order to reduce theimpact of energy uplift charges on markets. The result would be to reduce
the level of per MWh charges, to reduce the uncertainty associated withuplift charges and to reduce the impact of energy uplift charges on decisions
about how and when to participate in PJM markets. The result would also be
to increase incentives for flexible operation and to decrease incentives forthe continued operation of inflexible and uneconomic resources. PJM does
not need a flexibility product. PJM needs to provide incentives to existingand new entrant resources to unlock the significant flexibility potential that
already exists and to stop creating incentives for inflexibility.

Overview: Section 5, Capacity Market
RPM Capacity Market
Market Design
The Reliability Pricing Model (RPM) Capacity Market is a forward-looking,annual, locational market, with a must offer requirement for Existing
Generation Capacity Resources and mandatory participation by load, withperformance incentives, that includes clear market power mitigation rules andthat permits the direct participation of demand-side resources.79
79 The terms PJM Region, RTO Region and RTO are synonymous in this report and include all capacity within the PJM footprint.

© 2021 Monitoring Analytics, LLC

Under RPM, capacity obligations are annual.80 Base Residual Auctions (BRA)
are held for delivery years that are three years in the future. First, Second
and Third Incremental Auctions (IA) are held for each delivery year.81 First,
Second, and Third Incremental Auctions are conducted 20, 10, and threemonths prior to the delivery year.82 A Conditional Incremental Auction may
be held if there is a need to procure additional capacity resulting from a delay
in a planned large transmission upgrade that was modeled in the BRA for the
relevant delivery year.83
The 2021/2022 RPM Third Incremental Auction and the 2022/2023 RPM Base
Residual Auction were conducted in the first six months of 2021.
RPM prices are locational and may vary depending on transmission constraints
and local supply and demand conditions.84 Existing generation capable ofqualifying as a capacity resource must be offered into RPM auctions, except
for resources owned by entities that elect the fixed resource requirement (FRR)
option. Participation by LSEs is mandatory, except for those entities that electthe FRR option. There is an administratively determined demand curve thatdefines scarcity pricing levels and that, with the supply curve derived from
capacity offers, determines market prices in each BRA. RPM rules provide
performance incentives for generation, including the requirement to submit
generator outage data and the linking of capacity payments to the level of
unforced capacity, and the performance incentives have been strengthened
significantly under the Capacity Performance modifications to RPM. Under
RPM there are explicit market power mitigation rules that define the must
offer requirement, that define structural market power based on the marginal
cost of capacity, that define offer caps, that define the minimum offer price,and that have flexible criteria for competitive offers by new entrants. Market
power mitigation is effective only when these definitions are up to date andaccurate. Demand resources and energy efficiency resources may be offereddirectly into RPM auctions and receive the clearing price without mitigation.
80 Effective for the 2020/2021 and subsequent delivery years, the RPM market design incorporated seasonal capacity resources. Summer
period and winter period capacity must be matched either with commercial aggregation or through the optimization in equal MWamounts in the LDA or the lowest common parent LDA.
81 See 126 FERC ¶ 61,275 at P 86 (2009).
82 See Letter Order, FERC Docket No. ER10-366-000 (January 22, 2010).
83 See 126 FERC ¶ 61,275 at P 88 (2009). There have been no Conditional Incremental Auctions.
84 Transmission constraints are local capacity import capability limitations (low capacity emergency transfer limit (CETL) margin overcapacity emergency transfer objective (CETO)) caused by transmission facility limitations, voltage limitations or stability limitations.

2021 Quarterly State of the Market Report for PJM: January through June 35

2021 Quarterly State of the Market Report for PJM: January through June

Market Structure• RPM Installed Capacity. In the first six months of 2021, RPM installedcapacity decreased 307.7 MW or 0.2 percent, from 184,245.0 MW on
January 1 to 183,962.3 MW on June 30. Installed capacity includes net
capacity imports and exports and can vary on a daily basis.

• RPM Installed Capacity by Fuel Type. Of the total installed capacity on June30, 2021, 46.0 percent was gas; 26.5 percent was coal; 17.6 percent was
nuclear; 4.8 percent was hydroelectric; 3.0 percent was oil; 0.8 percent
was wind; 0.4 percent was solid waste; and 1.0 percent was solar.

• Market Concentration. In the 2022/2023 RPM Base Residual Auction allparticipants in the total PJM market as well as the LDA RPM markets failed
the three pivotal supplier (TPS) test.85 Offer caps were applied to all selloffers for resources which were subject to mitigation when the capacity
market seller did not pass the test, the submitted sell offer exceeded
the defined offer cap, and the submitted sell offer, absent mitigation,
increased the market clearing price.86 87 88• Imports and Exports. Of the 1,558.0 MW of imports in the 2022/2023 RPM

Base Residual Auction, 1,558.0 MW cleared. Of the cleared imports, 954.9
MW (61.3 percent) were from MISO.

• Demand-Side and Energy Efficiency Resources. Capacity in the RPM load

management programs was 12,115.9 MW for June 1, 2021, as a result ofcleared capacity for demand resources and energy efficiency resourcesin RPM auctions for the 2021/2022 Delivery Year (16,233.9 MW) lesspurchases of replacement capacity (4,118.0 MW).

85 There are 27 Locational Deliverability Areas (LDAs) identified to recognize locational constraints as defined in “Reliability Assurance
Agreement Among Load Serving Entities in the PJM Region,” Schedule 10.1. PJM determines, in advance of each BRA, whether thedefined LDAs will be modeled in the given delivery year using the rules defined in OATT Attachment DD § 5.10(a)(ii).
86 See OATT Attachment DD § 6.5.
87 Prior to November 1, 2009, existing DR and EE resources were subject to market power mitigation in RPM Auctions. See 129 FERC ¶61,081 at P 30 (2009).
88 Effective January 31, 2011, the RPM rules related to market power mitigation were changed, including revising the definition for Planned
Generation Capacity Resource and creating a new definition for Existing Generation Capacity Resource for purposes of the must offer
requirement and market power mitigation, and treating a proposed increase in the capability of a generation capacity resource the samein terms of mitigation as a Planned Generation Capacity Resource. See 134 FERC ¶ 61,065 (2011).

36

Section 1 Introduction

Market Conduct• 2022/2023 RPM Base Residual Auction. Of the 1,083 generation resourcesthat submitted Capacity Performance offers, the MMU calculated unit
specific offer caps for zero generation resources (0.0 percent).

Market Performance• The 2021/2022 RPM Third Incremental Auction and 2022/2023 RPM

Base Residual Auction were conducted in the first six months of 2021.89
The weighted average capacity price for the 2020/2021 Delivery Yearis $111.07 per MW-day, including all RPM auctions for the 2020/2021
Delivery Year. The weighted average capacity price for the 2021/2022
Delivery Year is $147.33 per MW-day, including all RPM auctions for the2021/2022 Delivery Year.

• For the 2021/2022 Delivery Year, RPM annual charges to load are $9.4
billion.

• In the 2021/2022 RPM Base Residual Auction, the market performance

was determined to be not competitive as a result of noncompetitive offersthat affected market results. The MMU has not completed its analysis of
the 2022/2023 RPM Base Residual Auction.

Reliability Must Run Service• Of the seven companies (23 units) that have provided RMR service,
two companies (seven units) filed to be paid for RMR service under thedeactivation avoidable cost rate (DACR), the formula rate. The other fivecompanies (16 units) filed to be paid for RMR service under the cost ofservice recovery rate.

89 FERC granted PJM’s request for waiver of its Open Access Transmission Tariff to delay the 2022/2023 RPM Base Residual Auction fromMay 2019 to August 2019. See 164 FERC ¶ 61,153 (2018). FERC subsequently denied PJM’s motion seeking clarification of the June 29,
2018, Order (163 FERC ¶ 61,236) and directed PJM not to run the 2022/2023 BRA in August 2019. See 168 FERC ¶ 61,051 (2019).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

Generator Performance• Forced Outage Rates. The average PJM EFORd in the first six months of2021 was 6.8 percent, an increase from 5.9 percent in the first six monthsof 2020.90• Generator Performance Factors. The PJM aggregate equivalent availability

factor in the first six months of 2021 was 82.5 percent, a decrease from85.8 percent in the first six months of 2020.

Section 5 Recommendations91
Definition of Capacity•

The MMU recommends the enforcement of a consistent definition of
capacity resource. The MMU recommends that the requirement to be aphysical resource be enforced and enhanced. The requirement to be aphysical resource should apply at the time of auctions and should also
constitute a commitment to be physical in the relevant delivery year. The
requirement to be a physical resource should be applied to all resource
types, including planned generation, demand resources and imports.92 93(Priority: High. First reported 2013. Status: Not adopted.)• The MMU recommends that DR providers be required to have a signed

contract with specific customers for specific facilities for specific levels of
DR at least six months prior to any capacity auction in which the DR isoffered. (Priority: High. First reported 2016. Status: Not adopted.)Market Design and Parameters• The MMU recommends that the test for determining modeled Locational
Deliverability Areas (LDAs) in RPM be redefined. A detailed reliability

90 The generator performance analysis includes all PJM capacity resources for which there are data in the PJM generator availability datasystems (GADS) database. Data was downloaded from the PJM GADS database on July 21, 2021. EFORd data presented in state of themarket reports may be revised based on data submitted after the publication of the reports as generation owners may submit correctionsat any time with permission from PJM GADS administrators.
91 The MMU has identified serious market design issues with RPM and the MMU has made specific recommendations to address thoseissues. These recommendations have been made in public reports. See Table 52.
92 See also Comments of the Independent Market Monitor for PJM, Docket No. ER14-503-000 (December 20, 2013).
93 See “Analysis of Replacement Capacity for RPM Commitments: June 1, 2007 to June 1, 2019,” <http://www.monitoringanalytics.com/
reports/Reports/2019/IMM_Analysis_of_Replacement_Capacity_for_RPM_Commitments_June_1_2007_to_June_1_2019_20190913.
pdf> (September 13, 2019).

© 2021 Monitoring Analytics, LLC

analysis of all at risk units should be included in the redefined model.
(Priority: Medium. First reported 2013. Status: Not adopted.)• The MMU recommends that the net revenue calculation used by PJM

to calculate the net Cost of New Entry (CONE) VRR parameter reflect
the actual flexibility of units in responding to price signals rather thanusing assumed fixed operating blocks that are not a result of actual unit
limitations.94 95 The result of reflecting the actual flexibility is higher
net revenues, which affect the parameters of the RPM demand curveand market outcomes. (Priority: High. First reported 2013. Status: Not
adopted.)• The MMU recommends that energy efficiency resources (EE) not be

included on the supply side of the capacity market, because PJM’s load
forecasts now account for future EE, unlike the situation when EE wasfirst added to the capacity market. However, the MMU recommends that
the PJM load forecast method should be modified so that EE impacts
immediately affect the forecast without the long lag times incorporated
in the current forecast method. If EE is not included on the supply side,
there is no reason to have an add back mechanism. If EE remains on the
supply side, the implementation of the EE add back mechanism should be
modified to ensure that market clearing prices are not affected. (Priority:
Medium. First reported 2016. Status: Not adopted.)• The MMU recommends that PJM reduce the number of incremental

auctions to a single incremental auction held three months prior to
the start of the delivery year and reevaluate the triggers for holding
conditional incremental auctions. (Priority: Medium. First reported 2013.
Status: Not adopted.)• The MMU recommends that PJM offer to sell back capacity in incremental

auctions only at the BRA clearing price for the relevant delivery year.
(Priority: Medium. First reported 2017. Status: Not adopted.)• The MMU recommends changing the RPM solution method to explicitly
incorporate the cost of make whole payments in the objective function.
(Priority: Medium. First reported 2014. Status: Not adopted.)

94 See PJM Interconnection, L.L.C., Docket No. ER12-513-000 (December 1, 2011) (“Triennial Review”).
95 See the 2019 State of the Market Report for PJM, Volume 2, Section 7: Net Revenue.

2021 Quarterly State of the Market Report for PJM: January through June 37

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends that PJM clear the capacity market based on nodal

capacity resource locations and the characteristics of the transmission
system consistent with the actual electrical facts of the grid. The current
nested LDA structure used in the capacity market does not adequately
represent all the capacity transfers that are feasible among LDAs. Absent
a fully nodal capacity market clearing process, the MMU recommends that
PJM use a nonnested model for all LDAs and specify a VRR curve for each
LDA separately. Each LDA requirement should be met with the capacity
resources located within the LDA and exchanges from neighboring
LDAs up to the transmission limit. LDAs should price separate if thatis the result of the LDA supply curves and the transmission constraints.
(Priority: Medium. First reported 2017. Status: Not adopted.)• The MMU recommends that the maximum price on the VRR curve bedefined as net CONE. (Priority: Medium. First reported 2019. Status: Not
adopted.)• The MMU recommends that the Fixed Resource Requirement (FRR) rules,

including obligations and performance requirements, be revised andupdated to ensure that the rules reflect current market realities and that
FRR entities do not unfairly take advantage of those customers paying
for capacity in the PJM capacity market. (Priority: Medium. First reported
2019. Status: Not adopted.)Offer Caps, Offer Floors, and Must Offer• The MMU recommends use of the Sustainable Market Rule (SMR) in orderto protect competition in the capacity market from nonmarket revenues.96(Priority: High. First reported 2016. Status: Not adopted.)

96 Brief of the Independent Market Monitor for PJM, Docket No. EL16-49, ER18-1314-000,-001; EL18-178 (October 2, 2018).

38

Section 1 Introduction• The MMU recommends that, as part of the MOPR unit specific standardof review, all projects be required to use the same basic modelingassumptions. That is the only way to ensure that projects compete on thebasis of actual costs rather than on the basis of modeling assumptions.97(Priority: High. First reported 2013. Status: Not adopted.)• The MMU recommends that modifications to existing resources not betreated as new resources for purposes of market power related offer caps
or MOPR offer floors. (Priority: Low. First reported 2012. Status: Not
adopted.)• The MMU recommends that the RPM market power mitigation rule bemodified to apply offer caps in all cases when the three pivotal supplier
test is failed and the sell offer is greater than the offer cap. This will
ensure that market power does not result in an increase in make whole
payments. (Priority: Medium. First reported 2017. Status: Not adopted.)• The MMU recommends that the offer cap for capacity resources be definedas the net avoidable cost rate (ACR) of each unit so that the clearing
prices are a result of such net ACR offers, consistent with the fundamental
economic logic for a competitive offer of a CP resource. (Priority: High.
First reported 2017. Status: Not adopted.)• The MMU recommends that PJM develop a process for calculating

a forward looking estimate for the expected number of Performance
Assessment Intervals (H) to use in calculating the Market Seller Offer Cap(MSOC). The MMU recommends that the Nonperformance Charge Ratebe left at its current level. The MMU recommends that PJM develop a
forward looking estimate for the Balancing Ratio (B) during Performance
Assessment Intervals (PAIs) to use in calculating the MSOC. Both H
and B parameters should be included in the annual review of planningparameters for the Base Residual Auction, and should incorporate theactual observed reserve margins, and other assumptions consistent with

97 See 143 FERC ¶ 61,090 (2013) (“We encourage PJM and its stakeholders to consider, for example, whether the unit-specific review
process would be more effective if PJM requires the use of common modeling assumptions for establishing unit-specific offer floors
while, at the same time, allowing sellers to provide support for objective, individual cost advantages. Moreover, we encourage PJM and its
stakeholders to consider these modifications to the unit-specific review process together with possible enhancements to the calculationof Net CONE.”); see also, Comments of the Independent Market Monitor for PJM, Docket No. ER13-535-001 (March 25, 2013); Complaintof the Independent Market Monitor for PJM v. Unnamed Participant, Docket No. EL12-63-000 (May 1, 2012); Motion for Clarificationof the Independent Market Monitor for PJM, Docket No. ER11-2875-000, et al. (February 17, 2012); Protest of the Independent Market
Monitor for PJM, Docket No. ER11-2875-002 (June 2, 2011); Comments of the Independent Market Monitor for PJM, Docket Nos. EL11-20
and ER11-2875 (March 4, 2011).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction••

the annual IRM study. (Priority: High. First reported 2017. Status: Not
adopted.)The MMU recommends that capacity market sellers be required to request
the use of minimum MW quantities greater than 0 MW (inflexible selloffer segments) and that the requests should only be permitted for defined
physical reasons. (Priority: Medium. First reported 2018. Status: Not
adopted.)The MMU recommends that PJM update the values in the CRF table in thetariff when the components change. (Priority: High. First reported 2020.
Status: Not adopted.)

Performance Incentive Requirements of RPM•

The MMU recommends that any unit which is not capable of supplying
energy consistent with its day-ahead offer which should equal its ICAP,
reflect an appropriate outage. (Priority: Medium. First reported 2009.
Status: Not adopted.)• The MMU recommends that retroactive replacement transactions

associated with a failure to perform during a PAI not be allowed andthat, more generally, retroactive replacement capacity transactions not be
permitted. (Priority: Medium. First reported 2016. Status: Not adopted.)• The MMU recommends that there be an explicit requirement that capacity
resource offers in the day-ahead energy market be competitive, wherecompetitive is defined to be the short run marginal cost of the units.
(Priority: Low. First reported 2013. Status: Not adopted.)• The MMU recommends that Capacity Performance resources be required
to perform without excuses. Resources that do not perform should not be
paid regardless of the reason for nonperformance. (Priority: High. First
reported 2019. Status: Not adopted.)• The MMU recommends that the market data posting rules be modified

to allow the disclosure of expected performance, actual performance,
shortfall and bonus MW during a PAI by area without the requirementthat more than three market participants’ data be aggregated for posting.
(Priority: Low. First reported 2019. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Capacity Imports and Exports• The MMU recommends that all capacity imports be required to bedeliverable to PJM load prior to the relevant delivery year to ensure thatthey are full substitutes for internal, physical capacity resources. Pseudoties alone are not adequate to ensure deliverability. (Priority: High. First
reported 2016. Status: Not adopted.)• The MMU recommends that all costs incurred as a result of a pseudo tiedunit be borne by the unit itself and included as appropriate in unit offers
in the capacity market. (Priority: High. First reported 2016. Status: Not
adopted.)• The MMU recommends clear, explicit and detailed rules that define theconditions under which PJM will and will not recall energy from PJM
capacity resources and prohibit new energy exports from PJM capacity
resources. The MMU recommends that those rules define the conditions
under which PJM will purchase emergency energy while at the sametime not recalling energy exports from PJM capacity resources. PJM
has modified these rules, but the rules need additional clarification andoperational details. (Priority: Low. First reported 2010. Status: Partiallyadopted.)

Deactivations/Retirements• The MMU recommends that the notification requirement for deactivations

be extended from 90 days prior to the date of deactivation to 12 months
prior to the date of deactivation and that PJM and the MMU be provided
60 days rather than 30 days to complete their reliability and market
power analyses. (Priority: Low. First reported 2012. Status: Not adopted.)• The MMU recommends that RMR units recover all and only theincremental costs, including incremental investment costs, required by
the RMR service that the unit owner would not have incurred if the unit
owner had deactivated its unit as it proposed. Customers should bear no
responsibility for paying previously incurred costs, including a return on
or of prior investments. (Priority: Low. First reported 2010. Status: Not
adopted.)2021 Quarterly State of the Market Report for PJM: January through June 39

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends elimination of the cost of service recovery rate in
OATT Section 119, and that RMR service should be provided under thedeactivation avoidable cost rate in Part V. The MMU also recommends
specific improvements to the DACR provisions. (Priority: Medium. First
reported 2017. Status: Not adopted.)

Section 5 Conclusion
The analysis of PJM Capacity Markets begins with market structure, which
provides the framework for the actual behavior or conduct of market
participants. The analysis examines participant behavior within that market
structure. In a competitive market structure, market participants are constrained
to behave competitively. The analysis examines market performance, measured
by price and the relationship between price and marginal cost, that resultsfrom the interaction of market structure and participant behavior. Market
power is and will remain endemic to the structure of the PJM Capacity Market.
Nonetheless a competitive outcome can be assured by appropriate market
power mitigation rules.
The MMU concludes that the 2021/2022 RPM Base Residual Auction results
were not competitive as a result of offers above the competitive level bysome market participants. The MMU has not completed its analysis of the2022/2023 RPM Base Residual Auction. The MMU recognizes that thesemarket participants followed the capacity market rules by offering at lessthan the stated offer cap of net CONE times B. But net CONE times B is not
a competitive offer when the expected number of performance assessment
intervals is zero or a very small number and the nonperformance charge rateis defined as net CONE/30. Under these circumstances, a competitive offer,
under the logic defined in PJM’s capacity performance filing, is net ACR. Thatis the way in which most market participants offered in this and prior capacity
performance auctions.
The FERC approved PJM tariff defines the offer cap as net CONE times B,
rather than including the full logic supporting the definition of the offer cap
under the capacity performance paradigm. If the tariff had defined the offer

40

Section 1 Introduction

cap consistent with PJM’s filing in the capacity performance matter, the offer
cap would have been net ACR rather than net CONE times B.
The MMU filed a complaint with the Commission asserting that the market
seller offer cap is overstated.98 The result of an overstated market seller offer cap
is to permit the exercise of market power, as occurred in the 2021/2022 BRA.
The MMU has not completed its analysis of the 2022/2023 RPM Base ResidualAuction. On March 18, 2021, the Commission issued an order determining thatthe current default market seller offer cap “is incorrectly calibrated such thatit may unjustly and unreasonably prevent the appropriate review of offers,
thereby allowing potential exercises of market power.”99 The Commission
asked the parties to file briefs to address “whether an alternative method formarket power mitigation in the PJM capacity market would better address
the concern that the current methodology precludes the Market Monitor from
reviewing offers that raise market power concerns and mitigating offers whereappropriate.” The MMU filed a brief on the market seller offer cap issue.100
The MMU is required to identify market issues and to report them to theCommission and to market participants. The Commission decides on any
action related to the MMU’s findings.
The MMU found serious market structure issues, measured by the threepivotal supplier test results in the PJM Capacity Market in the last BRA andin subsequent incremental auctions. Explicit market power mitigation rules in
the RPM construct only partially offset the underlying market structure issues
in the PJM Capacity Market under RPM. In the 2021/2022 RPM Base ResidualAuction, the default offer cap of net CONE times B exceeded the competitive
offer for a number of resources. Some seasonal resources were paid additional
make whole based on a failure of the market power rules to apply offer
capping. The MMU has not completed its analysis of the 2022/2023 RPM Base
Residual Auction.
98 In 2019, the MMU filed a complaint seeking an order directing PJM to update the assumptions regarding the expected number of
performance assessment intervals (PAI) in calculating the default capacity market seller offer cap (MSOC). Complaint of the Independent
Market Monitor for PJM, Docket No. EL19-47-000 (February 21, 2019).
99 174 FERC ¶ 61,212.
100 B
 rief of the Independent Market Monitor for PJM, Docket No. EL19-47 and EL19-63, not consolidated (April 28, 2021).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

The MMU has identified serious market design issues with RPM and the MMU
has made specific recommendations to address those issues.101 102 103 104 105 106
In 2020 and 2021, the MMU prepared a number of RPM related reports andtestimony, shown in Table 5-2.
The capacity performance modifications to the RPM construct significantly
improved the capacity market and addressed a number of issues that had been
identified by the MMU. But significant issues remain in the PJM capacity
market design.
The PJM markets have worked to provide incentives to entry and to retain
capacity. PJM had excess reserves of 7,828.5 ICAP MW on June 1, 2021, andwill have excess reserves of 8,065.7 ICAP MW on June 1, 2022, based on
current positions.107 A majority of capacity investments in PJM were financed
by market sources.108 Of the 42,969.5 MW of additional capacity that cleared in
RPM auctions for the 2007/2008 through 2021/2022 Delivery Years, 31,509.22
MW (73.3 percent) were based on market funding. Of the 6,675.0 MW of
additional capacity that cleared in RPM auctions for the 2022/2023 through2023/2024 Delivery Years, 5,007.8 MW (75.0 percent) were based on market
funding. Those investments were made based on the assumption that markets
would be allowed to work and that inefficient units would exit.
The issue of external subsidies, particularly for economic nuclear power plants,
continued to evolve. The subsidies are not part of the PJM market design but
nonetheless threaten the foundations of the PJM Capacity Market as well as
101 See “Analysis of the 2018/2019 RPM Base Residual Auction Revised,” <http://www.monitoringanalytics.com/reports/Reports/2016/
IMM_Analysis_of_the_20182019_RPM_Base_Residual_Auction_20160706.pdf> (July 6, 2016).
102 See “Analysis of the 2019/2020 RPM Base Residual Auction Revised,” <http://www.monitoringanalytics.com/reports/Reports/2016/
IMM_Analysis_of_the_20192020_RPM_BRA_20160831-Revised.pdf> (August 31, 2016).
103 See “Analysis of the 2020/2021 RPM Base Residual Auction,” <http://www.monitoringanalytics.com/reports/Reports/2017/IMM_
Analysis_of_the_20202021_RPM_BRA_20171117.pdf> (November 11, 2017).
104 See “Analysis of the 2021/2022 RPM Base Residual Auction - Revised,” <http://www.monitoringanalytics.com/reports/Reports/2018/
IMM_Analysis_of_the_20212022_RPM_BRA_Revised_20180824.pdf> (August 24, 2018).
105 See “Analysis of Replacement Capacity for RPM Commitments: June 1, 2007 to June 1, 2017,” <http://www.monitoringanalytics.com/
reports/Reports/2017/IMM_Report_on_Capacity_Replacement_Activity_4_20171214.pdf> (December 14, 2017).
106 See “Analysis of Replacement Capacity for RPM Commitments: June 1, 2007 to June 1, 2019,” <http://www.monitoringanalytics.com/
reports/Reports/2019/IMM_Analysis_of_Replacement_Capacity_for_RPM_Commitments_June_1_2007_to_June_1_2019_20190913.
pdf> (September 13, 2019).
107 The calculated reserve margin for June 1, 2022, does not account for cleared buy bids that have not been used in replacement capacitytransactions.
108 “2020 PJM Generation Capacity and Funding Sources 2007/2008 through 2021/2022 Delivery Years,” <http://www.monitoringanalytics.
com/reports/Reports/2020/IMM_2020_PJM‌_Generation_Capacity_and_Funding_Sources_20072008_through_20212022_
DY_20200915.pdf> (September 15, 2020).

© 2021 Monitoring Analytics, LLC

the competitiveness of PJM markets overall. These subsidy programs originate
from the fact that competitive markets result in the exit of uneconomic anduncompetitive generating units. Regardless of the specific rationales offeredby unit owners, the proposed solution for all such generating units has been
to provide out of market subsidies in order to retain such units. The proposedsolution in all cases ignores the opportunity cost of subsidizing uneconomic
units, which is the displacement of new resources and technologies thatwould otherwise be economic. Some subsidies were requested by the ownersof economic resources. Some subsidies were requested by the owners ofspecific uneconomic generating units in order to improve the profitabilityof those specific units. These subsidies were not requested to accomplish
broader social goals. Broader social goals can all be met with market-based
mechanisms available to all market participants on a competitive basis andwithout discrimination.
Subsidies are contagious. Competition in the markets could be replaced andis now being replaced by competition to receive subsidies. Competition toreceive subsidies is now a reality and is accelerating in PJM.
It is essential that any approach to the PJM markets incorporate a consistentview of how the preferred market design is expected to provide competitive
results in a sustainable market design over the long run. A sustainable
market design means a market design that results in appropriate incentives
to competitive market participants to retire units and to invest in new units
over time such that reliability is ensured as a result of the functioning of themarket.
A sustainable competitive wholesale power market must recognize threesalient structural elements: state nonmarket revenues for renewable energy; asignificant level of generation resources subject to cost of service regulation;and the structure and performance of the existing market based generation
fleet.

2021 Quarterly State of the Market Report for PJM: January through June 41

2021 Quarterly State of the Market Report for PJM: January through June

Overview: Section 6, Demand Response• Demand Response Activity. Demand response activity includes economic

demand response (economic resources), emergency and pre-emergency
demand response (demand resources), synchronized reserves andregulation. Economic demand response participates in the energy
market. Emergency and pre-emergency demand response participates in
the capacity market and energy market.109 Demand response resources
participate in the synchronized reserve market. Demand response
resources participate in the regulation market.
Total demand response revenue increased by $9.7 million, 5.2 percent,from $185.1 million in the first six months of 2020 to $194.8 million
in the first six months of 2021. Emergency demand response revenue
accounted for 98.4 percent of all demand response revenue, economic
demand response for 0.1 percent, demand response in the synchronizedreserve market for 1.2 percent and demand response in the regulation
market for 0.4 percent.
Total emergency demand response revenue increased by $7.8 million, 4.2
percent, from $183.8 million in the first six months of 2020 to $191.6
million in the first six months of 2021.110
Economic demand response revenue increased by $0.2 million, 327.7
percent, from $0.06 million in the first six months of 2020 to $0.2
million in the first six months of 2021.111 Demand response revenue inthe synchronized reserve market increased by $1.7 million, 282.7 percent,from $0.6 million in the first six months of 2020 to $2.3 million in thefirst six months of 2021. Demand response revenue in the regulation
market increased by $0.1 million, 9.5 percent, from $0.6 million in thefirst six months of 2020 to $0.7 million in the first six months of 2021.

• Demand Response Energy Payments are Uplift. Energy payments toemergency and economic demand response resources are uplift. LMP does
not cover energy payments although emergency and economic demand

109 Emergency demand response refers to both emergency and pre-emergency demand response. With the implementation of the Capacity
Performance design, there is no functional difference between the emergency and pre-emergency demand response resource.
110 The total credits and MWh numbers for demand resources were calculated as of July 26, 2021 and may change as a result of continued
PJM billing updates.
111 Economic credits are synonymous with revenue received for reductions under the economic load response program.

42

Section 1 Introduction

response can and does set LMP. Energy payments to emergency demand
resources are paid by PJM market participants in proportion to their net
purchases in the real-time market. Energy payments to economic demand
resources are paid by real-time exports from PJM and real-time loads ineach zone for which the load-weighted, average real-time LMP for thehour during which the reduction occurred is greater than or equal to thenet benefits test price for that month.112• Demand Response Market Concentration. The ownership of economic

load response resources was highly concentrated in 2020 and the firstsix months of 2021. The HHI for economic resource reductions decreasedby 399 points from 9065 for 2020 to 8667 in the first six months of2021. The ownership of emergency load response resources was highly
concentrated in 2020. The HHI for emergency load response committed
MW was 2523 for the 2020/2021 Delivery Year. In the 2020/2021 Delivery
Year, the four largest CSPs owned 88.4 percent of all committed demand
response UCAP MW. The HHI for emergency demand response committed
MW is 2584 for the 2021/2022 Delivery Year. In the 2021/2022 Delivery
Year, the four largest CSPs own 89.0 percent of all committed demand
response UCAP MW.

• Limited Locational Dispatch of Demand Resources. With full implementationof the Capacity Performance rules in the capacity market in the 2020/2021
Delivery Year, PJM should be able to individually dispatch any capacity
performance resource, including demand resources. But PJM cannot
dispatch demand resources by node with the current rules because
demand resources are not registered to a node. Demand resources canbe dispatched by subzone only if the subzone is defined before dispatch.
Aggregation rules allow a demand resource that incorporates many small
end use customers to span an entire zone, which is inconsistent withnodal dispatch.

Section 6 Recommendations• The MMU recommends, as a preferred alternative to including demand

resources as supply in the capacity market, that demand resources be on

112 “PJM Manual 28: Operating Agreement Accounting,” § 11.2.2, Rev. 84 (Dec. 17, 2020).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

the demand side of the markets, that customers be able to avoid capacityand energy charges by not using capacity and energy at their discretion,that customer payments be determined only by metered load, and thatPJM forecasts immediately incorporate the impacts of demand side
behavior. (Priority: High. First reported 2014. Status: Not adopted.)• The MMU recommends that the option to specify a minimum dispatch price(strike price) for demand resources be eliminated and that participating
resources receive the hourly real-time LMP less any generation componentof their retail rate. (Priority: Medium. First reported 2010. Status: Not
adopted.)• The MMU recommends that the maximum offer for demand resources•

be the same as the maximum offer for generation resources. (Priority:
Medium. First reported 2013. Status: Not adopted.)
The MMU recommends that the demand resources be treated as economic
resources, responding to economic price signals like other capacity
resources. The MMU recommends that demand resources not be treatedas emergency resources, not trigger a PJM emergency and not trigger
a Performance Assessment Interval. (Priority: High. First reported 2012.
Status: Not adopted.)required, subzonal dispatch of demand resources with no advance noticerequired. (Priority: High. First reported 2015. Status: Not adopted.)• The MMU recommends that PJM not remove any defined subzones andmaintain a public record of all created and removed subzones. (Priority:
Low. First reported 2016. Status: Not adopted.)• The MMU recommends that PJM eliminate the measurement ofcompliance across zones within a compliance aggregation area (CAA).
The multiple zone approach is less locational than the zonal and subzonal
approach and creates larger mismatches between the locational need forthe resources and the actual response. (Priority: High. First reported 2015.
Status: Not adopted.)• The MMU recommends that measurement and verification methods fordemand resources be modified to reflect compliance more accurately.
(Priority: Medium. First reported 2009. Status: Not adopted.)• The MMU recommends that compliance rules be revised to include

submittal of all necessary hourly load data, and that negative values
be included when calculating event compliance across hours andregistrations. (Priority: Medium. First reported 2012. Status: Not adopted.)• The MMU recommends that the Emergency Program Energy Only option• The MMU recommends that PJM adopt the ISO-NE five-minute metering• The MMU recommends that, if demand resources remain in the capacity• The MMU recommends demand response event compliance be calculated• The MMU recommends that demand resources be required to provide• The MMU recommends that load management testing be initiated by PJM

be eliminated because the opportunity to receive the appropriate energy
market incentive is already provided in the economic program. (Priority:
Low. First reported 2010. Status: Not adopted.)
market, a daily energy market must offer requirement apply to demand
resources, comparable to the rule applicable to generation capacity
resources.113 (Priority: High. First reported 2013. Status: Not adopted.)
their nodal location, comparable to generation resources. (Priority: High.
First reported 2011. Status: Not adopted.)• The MMU recommends that PJM require nodal dispatch of demand
resources with no advance notice required or, if nodal location is not

113 See “Complaint and Motion to Consolidate of the Independent Market Monitor for PJM,” Docket No. EL14-20-000 (January 27, 2014)at 1.

© 2021 Monitoring Analytics, LLC

requirements in order to ensure that operators have the necessary
information for reliability and that market payments to demand resources
be calculated based on interval meter data at the site of the demand
reductions.114 (Priority: Medium. First reported 2013. Status: Not adopted.)
on a five minute basis for all capacity performance resources and that thepenalty structure reflect five minute compliance. (Priority: Medium. First
reported 2013. Status: Partially adopted.)
with limited warning to CSPs in order to more accurately represent the114 See ISO-NE Tariff, Section III, Market Rule 1, Appendix E1 and Appendix E2, “Demand Response,” <http://www.iso-ne.com/regulatory/
tariff/sect_3/mr1_append-e.pdf>. (Accessed October 17, 2017) ISO-NE requires that DR have an interval meter with five-minute datareported to the ISO and each behind the meter generator is required to have a separate interval meter. After June 1, 2017, demand
response resources in ISO-NE must also be registered at a single node.

2021 Quarterly State of the Market Report for PJM: January through June 43

2021 Quarterly State of the Market Report for PJM: January through Juneconditions of an emergency event. (Priority: Low. First reported 2012.
Status: Not adopted.)• The MMU recommends that shutdown cost be defined as the cost to curtailload for a given period that does not vary with the measured reduction or,
for behind the meter generators, be the start cost defined in Manual 15
for generators. (Priority: Low. First reported 2012. Status: Not adopted.)• The MMU recommends that the Net Benefits Test be eliminated and that•demand response resources be paid LMP less any generation componentof the applicable retail rate. (Priority: Low. First reported 2015. Status:
Not adopted.)

The MMU recommends that the tariff rules for demand response clarify
that a resource and its CSP, if any, must notify PJM of material changes
affecting the capability of the resource to perform as registered and mustterminate or modify registrations that are no longer capable of responding
to PJM dispatch directives at defined levels because load has been reduced
or eliminated, as in the case of bankrupt and/or out of service facilities.
(Priority: Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that there be only one demand response productin the capacity market, with an obligation to respond when called forany hour of the delivery year. (Priority: High. First reported 2011. Status:
Partially adopted.115)• The MMU recommends that the lead times for demand resources be•

shortened to 30 minutes with an hour minimum dispatch for all resources.
(Priority: Medium. First reported 2013. Status: Partially adopted.)

The MMU recommends setting the baseline for measuring capacity
compliance under winter compliance at the customers’ PLC, similar
to GLD, to avoid double counting. (Priority: High. First reported 2010.
Status: Partially adopted.)• The MMU recommends the Relative Root Mean Squared Test be required
for all demand resources with a CBL. (Priority: Low. First reported 2017.
Status: Partially adopted.)

115 PJM’s Capacity Performance design requires resources to respond when called for any hour of the delivery year, but demand resources
still have a limited mandatory compliance window.

44

Section 1 Introduction• The MMU recommends that PRD be required to respond during a PAI to
be consistent with all CP resources. (Priority: High. First reported 2017.
Status: Not adopted.)• The MMU recommends that the limits imposed on the pre-emergency andemergency demand response share of the synchronized reserve market beeliminated. (Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that 30 minute pre-emergency and emergency
demand response be considered to be 30 minute reserves. (Priority:
Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that energy efficiency MW not be included in the

PJM Capacity Market and that PJM should ensure that the impact of EE
measures on the load forecast is incorporated immediately rather thanwith the existing lag. (Priority: Medium. First reported 2018. Status: Not
adopted.)• The MMU recommends that demand reductions based entirely on behindthe meter generation be capped at the lower of economic maximum or
actual generation output. (Priority: High. First reported 2019. Status: Not
adopted.)• The MMU recommends that all demand resources register as PreEmergency Load Response and that the Emergency Load Response
Program be eliminated. (Priority: High. First reported Q1 2020. Status:
Not adopted.)

Section 6 Conclusion
A fully functional demand side of the electricity market means that end use
customers or their designated intermediaries will have the ability to see realtime energy price signals in real time, will have the ability to react to realtime prices in real time and will have the ability to receive the direct benefits
or costs of changes in real-time energy use. In addition, customers or theirdesignated intermediaries will have the ability to see current capacity prices,
will have the ability to react to capacity prices and will have the ability toreceive the direct benefits or costs of changes in the demand for capacity inthe same year in which demand for capacity changes. A functional demand© 2021 Monitoring Analytics, LLC

Section 1 Introduction

side of these markets means that customers will have the ability to makedecisions about levels of power consumption based both on how customers
value the power and on the actual cost of that power.
In the energy market, if there is to be a demand side program, demand
resources should be paid the value of energy, which is LMP less any generation
component of the applicable retail rate. There is no reason to have the net
benefits test. The necessity for the net benefits test is an illustration of theillogical approach to demand side compensation embodied in paying full
LMP to demand resources. The benefit of demand side resources is not thatthey suppress market prices, but that customers can choose not to consume
at the current price of power, that individual customers benefit from theirchoices and that the choices of all customers are reflected in market prices.
If customers face the market price, customers should have the ability to notpurchase power and the market impact of that choice does not require a test
for appropriateness.
If demand resources are to continue competing directly with generation
capacity resources in the PJM Capacity Market, the product must be definedsuch that it can actually serve as a substitute for generation. This is aprerequisite to a functional market design. Demand resources do not have amust offer requirement into the day-ahead energy market, are able to offer
above $1,000 per MWh without providing a fuel cost policy, or any rationale
for the offer. PJM automatically, and inappropriately, triggers a PAI when
demand resources are dispatched and demand resources do not have telemetry
requirements similar to other Capacity Performance resources.
In order to be a substitute for generation, demand resources should be definedin PJM rules as an economic resource, as generation is defined. Demand
resources should be required to offer in the day-ahead energy market andshould be called when the resources are required and prior to the declarationof an emergency. Demand resources should be available for every hour of
the year. The fact that PJM currently defines demand resources as emergency
resources and the fact that calling on demand resources triggers a performanceassessment interval (PAI) under the Capacity Performance design, both serve© 2021 Monitoring Analytics, LLC

as a significant disincentive to calling on demand resources and meanthat demand resources are underused. Demand resources should be treatedas economic resources like any other capacity resource. Demand resources
should be called when economic and paid the LMP rather than an inflated
strike price up to $1,849 per MWh that is set by the seller.
In order to be a substitute for generation, demand resources (DR) should be
subject to robust measurement and verification techniques to ensure thattransitional DR programs incent the desired behavior. The methods used in
PJM programs today are not adequate to determine and quantify deliberateactions taken to reduce consumption.
In order to be a substitute for generation, demand resources should provide a
nodal location and should be dispatched nodally to enhance the effectivenessof demand resources and to permit the efficient functioning of the energy
market. Both subzonal and multi-zone compliance should be eliminatedbecause they are inconsistent with an efficient nodal market.
In order to be a substitute for generation, compliance by demand resources
with PJM dispatch instructions should include both increases and decreases
in load. The current method applied by PJM simply ignores increases in load
and thus artificially overstates compliance.
In order to be a substitute for generation, reductions should be calculated
hourly for dispatched DR. The current rules use the average reduction forthe duration of an event. The average reduction across multiple hours does
not provide an accurate metric for each hour of the event and is inconsistent
with the measurement of generation resources. Measuring compliance hourly
would provide accurate information to the PJM system. Under the new CP
rules, the performance of demand response during Performance Assessment
Interval (PAI) will be measured on a five-minute basis.
In order to be a substitute for generation, any demand resource and its
Curtailment Service Provider (CSP), should be required to notify PJM
of material changes affecting the capability of the resource to perform as

2021 Quarterly State of the Market Report for PJM: January through June 45

2021 Quarterly State of the Market Report for PJM: January through June

registered and to terminate or modify registrations that are no longer capableof responding to PJM dispatch directives at the specified level, such as in
the case of bankrupt and out of service facilities. Generation resources are
required to inform PJM of any change in availability status, including outages
and shutdown status.
As a preferred alternative to being a substitute for generation in the capacityand energy markets, demand response resources should be on the demand sideof the capacity market rather than on the supply side. Rather than detailed
demand response programs with their attendant complex and difficult toadminister rules, customers would be able to avoid capacity and energy
charges by not using capacity and energy at their discretion and the level ofusage paid for would be defined by metered usage rather than a complex andinaccurate measurement protocol.
The MMU peak shaving proposal at the Summer-Only Demand Response
Senior Task Force (SODRSTF) is an example of how to create a demand sideproduct that is on the demand side of the market and not on the supply
side.116 The MMU proposal was based on the BGE load forecasting program
and the Pennsylvania Act 129 Utility Program.117 118 Under the MMU proposal,
participating load would inform PJM prior to an RPM auction of the MW
participating, the months and hours of participation and the temperaturehumidity index (THI) threshold at which load would be reduced. PJM would
reduce the load forecast used in the RPM auction based on the designatedreductions. Load would agree to curtail demand to at or below a defined FSL,
less than the customer PLC, when the THI exceeds a defined level or load
exceeds a specified threshold. By relying on metered load and the PLC, load
can reduce its demand for capacity and that reduction can be verified withoutcomplicated and inaccurate metrics to estimate load reductions. Under PJM’s
weakened version of the program, performance will be measured under thecurrent economic demand response CBL rules which means relying on load
116 See the MMU package within the SODRSTF Matrix, <http://www.pjm.com/-/media/‌committees-groups/task-forces/
sodrstf/20180802/20180802-item-04-sodrstf-matrix.ashx>.
117 Advance signals that can be used to foresee demand response days, BGE, <https://www.pjm.com/-/media/committees-groups/taskforces/sodrstf/20180309/20180309-item-05-bge-load-curtailment-programs.ashx> (Accessed March 6, 2019).
118 Pennsylvania ACT 129 Utility Program, CPower, <https://www.pjm.com/-/media/committees-groups/task-forces/
sodrstf/20180413/20180413-item-03-pa-act-129-program.ashx> (Accessed March 6, 2019).

46

Section 1 Introduction

estimates rather than actual metered load.119 PJM’s proposal includes only a
THI curtailment trigger and not an overall load curtailment trigger.
The long term appropriate end state for demand resources in the PJM markets
should be comparable to the demand side of any market. Customers should
use energy as they wish, accounting for market prices in any way they like,and that usage will determine the amount of capacity and energy for which
each customer pays. There would be no counterfactual measurement andverification.
Under this approach, customers that wish to avoid capacity payments would
reduce their load during expected high load hours. Capacity costs would be
assigned to LSEs and by LSEs to customers, based on actual load on the system
during these critical hours. Customers wishing to avoid high energy prices
would reduce their load during high price hours. Customers would pay forwhat they actually use, as measured by meters, rather than relying on flawedmeasurement and verification methods. No measurement and verification
estimates are required. No promises of future reductions which can only beverified by inaccurate and biased measurement and verification methods are
required. To the extent that customers enter into contracts with CSPs or LSEs
to manage their payments, measurement and verification can be negotiated aspart of a bilateral commercial contract between a customer and its CSP or LSE.
But the system would be paid for actual, metered usage, regardless of which
contractual party takes that obligation.
This approach provides more flexibility to customers to limit usage at theirdiscretion. There is no requirement to be available year round or every hour of
every day. There is no 30 minute notice requirement. There is no requirement
to offer energy into the day-ahead market. All decisions about interrupting
are up to the customers only and they may enter into bilateral commercial
arrangements with CSPs at their sole discretion. Customers would pay forcapacity and energy depending solely on metered load.
119 The PJM proposal from the SODRSTF weakened the proposal but was approved at the October 25, 2018 Members Committee meeting
and PJM filed Tariff changes on December 7, 2018. See “Peak Shaving Adjustment Proposal,” Docket No. ER19-511-000 (December 7,2018).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

A transition to this end state should be defined in order to ensure thatappropriate levels of demand side response are incorporated in PJM’s load
forecasts and thus in the demand curve in the capacity market. That transition
should be defined by the PRD rules, modified as proposed by the MMU.
This approach would work under the CP design in the capacity market. Thisapproach is entirely consistent with the Supreme Court decision in EPSA
as it does not depend on whether FERC has jurisdiction over the demandside.120 This approach will allow FERC to more fully realize its overriding
policy objective to create competitive and efficient wholesale energy markets.
The decision of the Supreme Court addressed jurisdictional issues and did
not address the merits of FERC’s approach. The Supreme Court’s decision has
removed the uncertainty surrounding the jurisdictional issues and created theopportunity for FERC to revisit its approach to demand side.

Overview: Section 7, Net Revenue
Net Revenue• Energy market net revenues are significantly affected by energy prices

and fuel prices. Energy prices and gas prices were higher in the first six
months of 2021 than in the first six months of 2020.

• In the first six months of 2021, average energy market net revenues

increased by 69 percent for a new combustion turbine (CT), 53 percent
for a new combined cycle (CC), 3,288 percent for a new coal plant (CP),57 percent for a new nuclear plant, 542 percent for a new diesel (DS),33 percent for a new onshore wind installation, 63 percent for a newoffshore wind installation and 48 percent for a new solar installationcompared to the first six months of 2020.

• The price of natural gas increased by significantly more than the price ofcoal in the first six months of 2021, as a result of very high gas prices in
mid February. As a result, the marginal costs of a new CC and a new CT
were greater than the marginal cost of a new CP in February 2021 but
lower in all other months in the first six months of 2021.

• Based on Western Hub prices, the spark spread in the first six months of2021 increased by 34 percent while the spark spread standard deviation
increased by 125 percent and the dark spread increased by 125 percent
while the dark spread standard deviation decreased by 145 percent.

Section 7 Recommendations• The MMU recommends that the net revenue calculation used by PJM tocalculate the net Cost of New Entry (CONE) and net ACR be based on a
forward looking estimate of expected energy and ancillary services net
revenues using forward prices for energy and fuel. (Priority: Medium.
First reported 2019. Status: Adopted 2020.)

Section 7 Conclusion
Wholesale electric power markets are affected by externally imposed
reliability requirements. A regulatory authority external to the market makes
a determination as to the acceptable level of reliability which is enforced
through a requirement to maintain a target level of installed or unforced
capacity. The requirement to maintain a target level of installed capacity canbe enforced via a variety of mechanisms, including government constructionof generation, full-requirement contracts with developers to constructand operate generation, state utility commission mandates to constructcapacity, or capacity markets of various types. Regardless of the enforcement
mechanism, the exogenous requirement to construct capacity in excess ofwhat is constructed in response to energy market signals has an impact onenergy markets. The reliability requirement results in maintaining a level ofcapacity in excess of the level that would result from the operation of anenergy market alone. The result of that additional capacity is to reduce thelevel and volatility of energy market prices and to reduce the duration of highenergy market prices. This, in turn, reduces net revenue to generation owners
which reduces the incentive to invest. The exact level of both aggregate andlocational excess capacity is a function of the calculation methods used by
RTOs and ISOs.

120 577 U.S. 260 (2016).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 47

2021 Quarterly State of the Market Report for PJM: January through June

Overview: Section 8, Environmental and Renewables
Federal Environmental Regulation• MATS. The U.S. Environmental Protection Agency’s (EPA) Mercury and Air

Toxics Standards rule (MATS) applies the Clean Air Act (CAA) maximum
achievable control technology (MACT) requirement to new or modified
sources of emissions of mercury and arsenic, acid gas, nickel, selenium
and cyanide.121 On May 22, 2020, the EPA published its determination that
MATS is not appropriate and necessary based on a cost-benefit analysis.122
The list of coal steam units subject to MATS, however, remains in place.123
All coal steam units in PJM are compliant with the state and federal
emissions limits established by MATS. The EPA’s May 22, 2020, finding isunder review pursuant to Executive Order 13990.

• Air Quality Standards (NO and SO Emissions). The CAA requires eachX

2state to attain and maintain compliance with fine particulate matter (PM)and ozone national ambient air quality standards (NAAQS). The CAA also
requires that each state prohibit emissions that significantly interfere withthe ability of another state to meet NAAQS.124 On March 15, 2021, theEPA finalized decreases to allowable emissions under the Cross-State Air
Pollution Rule (CSAPR) and the 2008 ozone NAAQS for 10 PJM states.125• NSR. On August 1, 2019, the EPA proposed to reform the New Source•

Review (NSR) permitting program.126 NSR requires new projects andexisting projects receiving major overhauls that significantly increase
emissions to obtain permits. Recent EPA proposals would reduce thenumber of projects that require permits.
RICE. Stationary reciprocating internal combustion engines (RICE) areelectrical generation facilities like diesel engines typically used for backup,

121 National Emission Standards for Hazardous Air Pollutants From Coal and Oil-Fired Electric Utility Steam Generating Units andStandards of Performance for Fossil Fuel Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-CommercialInstitutional Steam Generating Units, EPA Docket No. EPA-HQ-OAR-2009-0234, 77 Fed. Reg. 9304 (Feb. 16, 2012).
122 See National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—
Reconsideration of Supplemental Finding and Residual Risk and Technology Review, Docket No. EPA–HQ–OAR–2018–0794, 85 Fed. Reg.
31286.
123 Id. at 31291.
124 CAA § 110(a)(2)(D)(i)(I).
125 Revised Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS, Docket No. EPA–HQ–OAR–2020–0272; FRL–10013–42– OAR,
85 Fed. Reg. 23054 (Apr. 30, 2021).
126 Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR): Project Emissions Accounting, EPA Docket
No. EPA–HQ–OAR–2018–0048; FRL–9997–95–OAR, 84 Fed. Reg. 39244 (Aug. 9, 2019).

48

Section 1 Introduction

emergency or supplemental power. RICE must be tested annually.127 RICE
do not have to meet the same emissions standards if they are emergency
stationary RICE. Environmental regulations allow emergency stationary
RICE participating in demand response programs to operate for up to
100 hours per calendar year when providing emergency demand responsewhen there is a PJM declared NERC Energy Emergency Alert Level 2 orthere are five percent voltage/frequency deviations.
PJM does not prevent emergency stationary RICE that cannot meet its
capacity market obligations as a result of EPA emissions standards fromparticipating in PJM markets as DR. Some emergency stationary RICE
that cannot meet its capacity market obligations as a result of emissions
standards are now included in DR portfolios. Emergency stationary RICE
should be prohibited from participation as DR either when registeredindividually or as part of a portfolio if it cannot meet its capacity market
obligations as a result of emissions standards.

• Greenhouse Gas Emissions. On January 19, 2021, the U.S. Court of Appeals

for the District of Columbia Circuit vacated the EPA’s Affordable Clean
Energy (ACE) rule which would have permitted more CO2 emissions thanunder the Clean Power Plan (CPP), which ACE had replaced.128 Neither the
ACE nor CPP is currently effective.

• Cooling Water Intakes. An EPA rule implementing Section 316(b) of the

Clean Water Act (CWA) requires that cooling water intake structures reflect
the best technology available for minimizing adverse environmental
impacts.129• Waters of the United States. On June 9, 2021, the EPA and the Departmentof the Army concluded their review pursuant to Executive Order 13990
and announced their intention to initiate a new rulemaking process anddevelop a new definition of Waters of the United States that restores theprotections in place prior to the 2015.

127 See 40 CFR § 63.6640(f).
128 American Lung Association et al. v. EPA, No. 19-1140.
129 See EPA, National Pollutant Discharge Elimination System—Final Regulations to Establish Requirements for Cooling Water Intake
Structures at Existing Facilities and Amend Requirements at Phase I Facilities, EPA-HQ-OW-2008-0667, 79 Fed. Reg. 48300 (Aug. 15,
2014).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction• Coal Ash. The EPA administers the Resource Conservation and Recovery

Act (RCRA), which governs the disposal of solid and hazardous waste.130
The EPA has proposed significant changes to the implementing regulations.

State Environmental Regulation• Regional Greenhouse Gas Initiative (RGGI). The Regional Greenhouse
Gas Initiative (RGGI) is a CO2 emissions cap and trade agreement among
Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire,
New Jersey, New York, Rhode Island, Vermont and Virginia that applies
to power generation facilities. New Jersey rejoined on January 1, 2020.131
Virginia joined RGGI on January 1, 2021, and Pennsylvania is preparing
to join.132 133 The auction price in the June 2, 2021, auction was $7.97 perton, or $8.79 per metric tonne.

• Carbon Price. If the price of carbon were $50.00 per metric tonne, short

run marginal costs would increase by $24.52 per MWh or 77.3 percent for
a new combustion turbine (CT) unit, $16.71 per MWh or 77.0 percent for
a new combined cycle (CC) unit and $43.15 per MWh or 143.6 percent for
a new coal plant (CP) for January through June, 2021.

State Renewable Portfolio Standards• RPS. In PJM, ten of 14 jurisdictions have enacted legislation requiringthat a defined percentage of retail suppliers’ load be served by renewable
resources, for which definitions vary. These are typically known as
renewable portfolio standards, or RPS. As of June 30, 2021, Delaware,
Illinois, Maryland, Michigan, New Jersey, North Carolina, Ohio,
Pennsylvania, Virginia and Washington, DC have renewable portfolio
standards. Virginia had a voluntary RPS in 2020, but a new mandatory
RPS became effective on January 1, 2021. Indiana has voluntary renewable

portfolio standards. Kentucky, Tennessee and West Virginia do not haverenewable portfolio standards.

• RPS Cost. The cost of complying with RPS, as reported by the states, is$5.6 billion over the six year period from 2014 through 2019, an averageannual RPS compliance cost of $936.7 million. The compliance cost for
2019, the most recent year with almost complete data, was $1.2 billion.134

Emissions Controls in PJM Markets• Regulations. Environmental regulations affect decisions about emission

control investments in existing units, investment in new units anddecisions to retire units. As a result of environmental regulations andagreements to limit emissions, many PJM units burning fossil fuels haveinstalled emission control technology.

• Emissions Controls. In PJM, as of June 30, 2021, 93.5 percent of coalsteam MW had some type of flue-gas desulfurization (FGD) technology
to reduce SO2 emissions, while 99.8 percent of coal steam MW had some
type of particulate control, and 94.6 percent of fossil fuel fired capacity
had NOX emission control technology. All coal steam units in PJM arecompliant with the state and federal emissions limits established by MATS.

Renewable Generation• Renewable Generation. Wind and solar generation was 4.6 percent of total

generation in PJM in the first six months of 2021. RPS Tier I generation
was 6.2 percent of total generation in PJM and RPS Tier II generation was
2.1 percent of total generation in PJM in the first six months of 2021.
Only Tier I generation is defined to be renewable but Tier 1 includes somecarbon emitting generation.

Section 8 Recommendations
130 42 U.S.C. §§ 6901 et seq.
131 ”Statement on New Jersey Greenhouse Gas Rule,” RGGI Inc., (June 17, 2019) <https://www.rggi.org/sites/default/files/Uploads/PressReleases/2019_06_17_NJ_‌Announcement_Release.pdf>.
132 ”Statement on Virginia Greenhouse Gas Rule,” RGGI, (July 8, 2020) <https://www.rggi.org/news-releases/rggi-releases>.
133 Executive Order–2019-07. Commonwealth Leadership in Addressing Climate Change through Electric Sector Emissions Reductions, Tom
Wolf, Governor, October 3, 2019, <https://www.governor.pa.gov/newsroom/executive-order-2019-07-commonwealth-leadership-inaddressing-climate-change-through-electric-sector-emissions-reductions/>.

© 2021 Monitoring Analytics, LLC• The MMU recommends that renewable energy credit markets based onstate renewable portfolio standards be brought into PJM markets as they134 The 2019 compliance cost value for PJM states does not include Illinois, Michigan or North Carolina. Based on past data these states
generally account for 3.0 percent of the total RPS compliance cost of PJM states.

2021 Quarterly State of the Market Report for PJM: January through June 49

2021 Quarterly State of the Market Report for PJM: January through June

are an increasingly important component of the wholesale energy market.
(Priority: Medium. First reported 2010. Status: Not adopted.)• The MMU recommends that the Commission reconsider its disclaimer
of jurisdiction over RECs markets because, given market changes sincethat decision, it is clear that RECs materially affect jurisdictional rates.
(Priority: High. First reported 2018. Status: Not adopted.)• The MMU recommends that PJM provide a full analysis of the impact

of carbon pricing on PJM generating units and carbon pricing revenues
to the PJM states in order to permit the states to consider a potential
agreement on the development of a multistate framework for carbon
pricing and the distribution of carbon revenues. (Priority: High. First
reported 2018. Status: Not adopted.)• The MMU recommends that jurisdictions with a renewable portfolio
standard make the price and quantity data on supply and demand moretransparent. (Priority: Low. First reported 2018. Status: Not adopted.)• The MMU recommends that load and generation located at separate

nodes be treated as separate resources in order to ensure that load andgeneration face consistent incentives throughout the markets. (Priority:
High. First reported 2019. Status: Not adopted.)• The MMU recommends that emergency stationary RICE be prohibitedfrom participation as DR either when registered individually or as part ofa portfolio if it cannot meet the capacity market requirements to be DR
as a result of emissions standards that impose environmental run hour
limitations. (Priority: Medium. First reported 2019. Status: Not adopted.)

Section 8 Conclusion
Environmental requirements and renewable energy mandates at both thefederal and state levels have a significant impact on the cost of energy andcapacity in PJM markets. Renewable energy credit (REC) markets are markets
related to the production and purchase of wholesale power, but FERC hasdetermined that RECs are not regulated under the Federal Power Act unlessthe REC is sold as part of a transaction that also includes a wholesale sale

50

Section 1 Introductionof electric energy in a bundled transaction.135 The MMU recommends that
the Commission reconsider its disclaimer of jurisdiction over RECs markets
because, given market changes since that decision, it is clear that RECs
materially affect jurisdictional rates.
RECs clearly affect prices in the PJM wholesale power market. Some resources
are not economic except for the ability to purchase or sell RECs. RECs provide
out of market payments to qualifying renewable resources, primarily windand solar. The credits provide an incentive to make negative energy offers
and more generally provide an incentive to enter the market, to remain in
the market and to operate whenever possible. These subsidies affect the offer
behavior and the operational behavior of these resources in PJM markets andin some cases the existence of these resources and thus the market prices andthe mix of clearing resources. FERC’s recent MOPR order addressed these
impacts.
RECs markets are, as an economic fact, integrated with PJM markets including
energy and capacity markets, but are not formally recognized as part of PJM
markets. It would be preferable to have a single, transparent market forRECs operated by the PJM RTO on behalf of the states that would meet thestandards and requirements of all states in the PJM footprint including thosewith no RPS. This would provide better information for market participants
about supply and demand and prices and contribute to a more efficient andcompetitive market and to better price formation. This could also facilitate
entry by qualifying renewable resources by reducing the risks associated withlack of transparent market data. The MMU recommends that PJM provide afull analysis of the impact of carbon pricing on PJM generating units andcarbon pricing revenues to states in order to permit states to consider thedevelopment of a multistate framework: for RECs markets; for potential
agreement on carbon pricing including the distribution of carbon revenues;
and for coordination with PJM wholesale markets.
135 See 139 FERC ¶ 61,061 at PP 18, 22 (2012) (“[W]e conclude that unbundled REC transactions fall outside of the Commission’s jurisdiction
under sections 201, 205 and 206 of the FPA. We further conclude that bundled REC transactions fall within the Commission’s
jurisdiction under sections 201, 205 and 206 of the FPA,… [A]lthough a transaction may not directly involve the transmission or saleof electric energy, the transaction could still fall under the Commission’s jurisdiction because it is ’in connection with’ or ’affects’jurisdictional rates or charges.”).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

REC markets are not consistently or adequately transparent. Data on REC
prices, clearing quantities and markets are not publicly available for all PJM
states. The provision of more complete data would facilitate competition toprovide energy from renewable sources.
The economic logic of RPS programs and the associated REC and SREC prices
is not always clear. The price of carbon implied by REC prices ranges from
$8.14 per tonne in Washington, DC to $18.38 per tonne in New Jersey. The
price of carbon implied by SREC prices ranges from $67.29 per tonne in
Pennsylvania to $879.12 per tonne in Washington, DC. The effective prices forcarbon compare to the RGGI clearing price in June 2021 of $8.79 per tonne
and to the social cost of carbon which is estimated in the range of $50 per
tonne.136 The impact on the cost of generation from a new combined cycle
unit of a $50 per tonne carbon price would be $16.71 per MWh.137 The impactof an $800 per tonne carbon price would be $267.30 per MWh. This wide
range of implied carbon prices is not consistent with an efficient, competitive,
least cost approach to the reduction of carbon emissions.
In addition, even the explicit environmental goals of RPS programs are notclear. While RPS is frequently considered to target carbon emissions, Tier
1 resources include some carbon emitting generation and Tier 2 resources
include additional carbon emitting generation.
PJM markets provide a flexible mechanism for incorporating the costs ofenvironmental controls and meeting environmental requirements in a costeffective manner. Costs for environmental controls are part of offers forcapacity resources in the PJM Capacity Market. The costs of emissions credits
are included in energy offers. PJM markets also provide a flexible mechanismthat incorporates renewable resources and the impacts of renewable energy
credit markets, and ensures that renewable resources have access to a broad
market. PJM markets provide efficient price signals that permit valuation
136 “Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis – Under Executive Order 12899,” Interagency Working
Group on the Social Cost of Greenhouse Gases, United States Government, (Aug. 2016), <https://19january2017snapshot.epa.gov/‌sites/
production/files/2016-12/documents/sc_co2_tsd_august_2016.pdf>.
137 The cost impact calculation assumes a heat rate of 6.296 MMBtu per MWh and a carbon emissions rate of 0.053070 tonne per MMBtu.
The $800 per tonne carbon price represents the approximate upper end of the carbon prices implied by the 2019 REC and SREC prices in
the PJM jurisdictions with RPS. Additional cost impacts are provided in Table 818.

© 2021 Monitoring Analytics, LLC

of resources with very different characteristics when they provide the same
product.
PJM markets could also provide a flexible mechanism to limit carbon output,
for example by incorporating a consistent carbon price in unit offers which
would be reflected in PJM’s economic dispatch. If there is a social decision
to limit carbon output, a consistent carbon price would be the most efficient
way to implement that decision. The states in PJM could agree, if they decided
it was in their interests, with the appropriate information, on a carbon priceand on how to allocate the revenues from a carbon price that would make allstates better off. A mechanism like RGGI leaves all decision making with thestates. The carbon price would not be FERC jurisdictional or subject to PJM
decisions. The MMU continues to recommend that PJM provide modelinginformation to the states adequate to inform such a decision making process.
Such modeling information would include the impact on the dispatch of every
unit, the impact on energy prices and the carbon pricing revenues that would
flow to each state. This would permit states to make critical decisions aboutcarbon pricing. For example, states receiving high levels of revenue could shiftrevenue to states disproportionately hurt by a carbon price if they believedthat all states would be better off as a result. A carbon price would also be
an alternative to specific subsidies to individual nuclear power plants and tothe current wide range of implied carbon prices embedded in RPS programs
and instead provide a market signal to which any resource could respond. The
imposition of specific and prescriptive environmental dispatch rules would, in
contrast, pose a threat to economic dispatch and efficient markets and create
very difficult market power monitoring and mitigation issues. The provisionof subsidies to individual units creates a discriminatory regime that is notconsistent with competition. The use of inconsistent implied carbon prices bystate is also inconsistent with an efficient market and inconsistent with theleast cost approach to meeting state environmental goals.
The annual average cost of complying with RPS over the six year period from2014 through 2019 for the nine jurisdictions that had RPS was $936.7 million,
or a total of $5.6 billion over six years. The RPS compliance cost for 2019, the2021 Quarterly State of the Market Report for PJM: January through June 51

2021 Quarterly State of the Market Report for PJM: January through Junemost recent year for which there is almost complete data, was $1.2 billion.138
RPS costs are payments by customers to the sellers of qualifying resources.
The revenues from carbon pricing flow to the states.
If all the PJM states participated in a regional carbon market, the estimatedrevenue returned to the states/customers from selling carbon allowances would
be approximately $2.6 billion per year if the carbon price were $7.97 per short
ton and emissions levels were five percent below 2020 emission levels. If all
the PJM states participated in a regional carbon market, the estimated revenue
returned to the states/customers from selling carbon allowances would beapproximately $16.6 billion if the carbon price were $50 per short ton andemission levels were five percent below 2020 levels. If only the current RPS
states participated in a regional carbon market, the estimated revenue returnedto the states/customers from selling carbon allowances at $7.97 per short ton
would be about $1.8 billion. The costs of a carbon price are the impact onenergy market prices, net of the revenue returned to states/customers.

Overview: Section 9, Interchange Transactions
Interchange Transaction Activity• Aggregate Imports and Exports in the Real-Time Energy Market. In thefirst six months of 2021, PJM was a monthly net exporter of energy inthe real-time energy market in all months.139 In the first six months of2021, the real-time net interchange was -18,001.2 GWh. The real-time netinterchange in the first six months of 2020 was -18,655.2 GWh.

• Aggregate Imports and Exports in the Day-Ahead Energy Market. In thefirst six months of 2021, PJM was a monthly net exporter of energy in the
day-ahead energy market in all months. In the first six months of 2021,
the total day-ahead net interchange was -12,063.7 GWh. The day-ahead
net interchange in the first six months of 2020 was -4,760.2 GWh.

• Aggregate Imports and Exports in the Day-Ahead and the Real-Time
Energy Market. In the first six months of 2021, gross imports in the day-

138 The 2019 compliance cost value for PJM states does not include Illinois, Michigan or North Carolina. Based on past data these states
generally account for 3.0 percent of the total RPS compliance cost of PJM states.
139 Calculated values shown in Section 9, “Interchange Transactions,” are based on unrounded, underlying data and may differ from
calculations based on the rounded values in the tables.

52

Section 1 Introduction

ahead energy market were 121.2 percent of gross imports in the real-timeenergy market (616.2 percent in the first six months of 2020). In the firstsix months of 2021, gross exports in the day-ahead energy market were76.3 percent of the gross exports in the real-time energy market (120.3
percent in the first six months of 2020).

• Interface Imports and Exports in the Real-Time Energy Market. In thefirst six months of 2021, there were net scheduled exports at 15 of PJM’s
19 interfaces in the real-time energy market.

• Interface Pricing Point Imports and Exports in the Real-Time Energy

Market. In the first six months of 2021, there were net scheduled exports
at seven of PJM’s nine interface pricing points eligible for real-timetransactions in the real-time energy market.140• Interface Imports and Exports in the Day-Ahead Energy Market. In thefirst six months of 2021, there were net scheduled exports at 13 of PJM’s
19 interfaces in the day-ahead energy market.

• Interface Pricing Point Imports and Exports in the Day-Ahead Energy

Market. In the first six months of 2021, there were net scheduled exports
at seven of PJM’s nine interface pricing points eligible for day-aheadtransactions in the day-ahead energy market.141• Up To Congestion Interface Pricing Point Imports and Exports in the Day-

Ahead Energy Market. In the first six months of 2021, up to congestiontransactions were net exports at five of PJM’s nine interface pricing points
eligible for day-ahead transactions in the day-ahead energy market.142• Inadvertent Interchange. In the first six months of 2021, net scheduledinterchange was -18,001 GWh and net actual interchange was -18,008
GWh, a difference of 7 GWh. In the first six months of 2020, the difference
was 3 GWh. This difference is inadvertent interchange.

• Loop Flows. In the first six months of 2021, the Northern Indiana PublicService (NIPS) Interface had the largest loop flows of any interface with140 On June 1, 2021, PJM consolidated the SouthIMP and SouthEXP interface pricing points to one new SOUTH interface pricing point. This
reduces the number of real-time interface pricing points to eight.
141 O
 n April 15, 2021, PJM retired the Southeast interface pricing point from the Day-Ahead Market. The Southeast interface pricing
point can still be assigned to transactions under the VACAR reserve sharing agreement in the Real-Time Market. On June 1, 2021, PJM
consolidated the SouthIMP and SouthEXP interface pricing points to one new SOUTH interface pricing point. This reduces the number of
day-ahead interface pricing points to seven.
142 Id.

© 2021 Monitoring Analytics, LLC

Section 1 Introduction-680 GWh of net scheduled interchange and -5,910 GWh of net actualinterchange, a difference of 5,231 GWh. In the first six months of 2021,
the SouthIMP interface pricing point had the largest loop flows of any
interface pricing point with 1,769 GWh of net scheduled interchange and10,298 GWh of net actual interchange, a difference of 8,529 GWh.

Interactions with Bordering Areas
PJM Interface Pricing with Organized Markets• PJM and MISO Interface Prices. In the first six months of 2021, thedirection of the hourly flow was consistent with the real-time hourly
price differences between the PJM/MISO Interface and the MISO/PJM
Interface in 61.7 percent of the hours.

• PJM and New York ISO Interface Prices. In the first six months of 2021,

the direction of the hourly flow was consistent with the real-time hourly
price differences between the PJM/NYIS Interface and the NYISO/PJM
proxy bus in 55.3 percent of the hours.

• Neptune Underwater Transmission Line to Long Island, New York. In thefirst six months of 2021, the hourly flow (PJM to NYISO) was consistent
with the real-time hourly price differences between the PJM Neptune
Interface and the NYISO Neptune bus in 67.5 percent of the hours.

• Linden Variable Frequency Transformer (VFT) Facility. In the first six
months of 2021, the hourly flow (PJM to NYISO) was consistent with thereal-time hourly price differences between the PJM Linden Interface andthe NYISO Linden bus in 75.3 percent of the hours.

• Hudson DC Line. In the first six months of 2021, the hourly flow (PJM
to NYISO) was consistent with the real-time hourly price differences
between the PJM Hudson Interface and the NYISO Hudson bus in 67.5
percent of the hours.

Interchange Transaction Issues• PJM Transmission Loading Relief Procedures (TLRs). PJM issued two

TLRs of level 3a or higher in the first six months of 2021, compared tozero such TLRs issued in the first six months of 2020.

© 2021 Monitoring Analytics, LLC• Up To Congestion. The average number of up to congestion bids submitted

in the day-ahead energy market decreased by 82.5 percent, from 52,781
bids per day in the first six months of 2020 to 26,781 bids per day in thefirst six months of 2021. The average cleared volume of up to congestion
bids submitted in the day-ahead energy market decreased by 59.8 percent,from 469,113 MWh per day in the first six months of 2020, to 188,479
MWh per day in the first six months of 2021.

Section 9 Recommendations• The MMU recommends that PJM implement rules to prevent shamscheduling. The MMU recommends that PJM apply after the fact market
settlement adjustments to identified sham scheduling segments to ensurethat market participants cannot benefit from sham scheduling. (Priority:
High. First reported 2012. Status: Not adopted.)• The MMU recommends that PJM implement a validation method forsubmitted transactions that would prohibit market participants frombreaking transactions into smaller segments to defeat the interface pricing
rule by concealing the true source or sink of the transaction. (Priority:
Medium. First reported 2013. Status: Not adopted.)• The MMU recommends that PJM implement a validation method forsubmitted transactions that would require market participants to submit
transactions on paths that reflect the expected actual power flow in orderto reduce unscheduled loop flows. (Priority: Medium. First reported 2013.
Status: Not adopted.)• The MMU recommends that PJM end the practice of maintaining outdated

definitions of interface pricing points, eliminate the NIPSCO, Southeast
and Southwest interface pricing points from the day-ahead and real-timeenergy markets and, with VACAR, assign the transactions created under
the reserve sharing agreement to the SOUTH interface pricing point.
(Priority: High. First reported 2013. Status: Partially adopted, Q2 2020.)143

143 The grandfathered agreements associated with the Southwest interface pricing point expired in 2012. The Southwest interface pricing
point is no longer an eligible pricing point in the day-ahead or real-time energy markets. Effective June 1, 2020, PJM retired the NIPSCO
interface pricing point.

2021 Quarterly State of the Market Report for PJM: January through June 53

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends that transactions sourcing in the WesternInterconnection be priced at either the MISO interface pricing point or
the SOUTH interface pricing point based on the locational price impact
of flows between the DC tie line point of connection with the EasternInterconnection and PJM. (Priority: High. First reported Q1, 2020. Status:
Not adopted.)• The MMU recommends that PJM eliminate the IMO interface pricing point,

and assign the transactions that originate or sink in the IESO balancing
authority to the MISO interface pricing point. (Priority: Medium. First
reported 2013. Status: Not adopted.)• The MMU recommends that PJM monitor, and adjust as necessary, theweights applied to the components of the interfaces to ensure that theinterface prices reflect ongoing changes in system conditions. The MMU
also recommends that PJM review the mappings of external balancing
authorities to individual interface pricing points to reflect changes to theimpact of the external power source on PJM tie lines as a result of system
topology changes. The MMU recommends that this review occur at least
annually. (Priority: Low. First reported 2009. Status: Not adopted.)• The MMU recommends that, in order to permit a complete analysis ofloop flow, FERC and NERC ensure that the identified data are madeavailable to market monitors as well as other industry entities determined
appropriate by FERC. (Priority: Medium. First reported 2003. Status: Not
adopted.)• The MMU recommends that PJM explore an interchange optimization

solution with its neighboring balancing authorities that would remove
the need for market participants to schedule physical transactions across
seams. Such a solution would include an optimized, but limited, joint
dispatch approach that uses supply curves and treats seams between
balancing authorities as constraints, similar to other constraints within an
LMP market. (Priority: Medium. First reported 2014. Status: Not adopted.)• The MMU recommends that PJM permit unlimited spot market imports aswell as unlimited nonfirm point to point willing to pay congestion imports

54

Section 1 Introductionand exports at all PJM interfaces in order to improve the efficiency of themarket. (Priority: Medium. First reported 2012. Status: Not adopted.)• The MMU recommends that the emergency interchange cap be replacedwith a market based solution. (Priority: Low. First reported 2015. Status:
Not adopted.)• The MMU recommends that the submission deadline for real-time

dispatchable transactions be modified from 1800 on the day prior, tothree hours prior to the requested start time, and that the minimum
duration be modified from one hour to 15 minutes. These changes would
give PJM a more flexible product that could be used to meet load in themost economic manner. (Priority: Medium. First reported 2014. Status:
Partially adopted, 2015.)• The MMU recommends modifications to the FFE calculation to ensurethat FFE calculations reflect the current capability of the transmission
system as it evolves. The MMU recommends that the Commission set a
deadline for PJM and MISO to resolve the FFE freeze date and related
issues. (Priority: Medium. First reported 2019. Status: Not adopted.)

Section 9 Conclusion
Transactions between PJM and multiple balancing authorities in the EasternInterconnection are part of a single energy market. While some of thesebalancing authorities are termed market areas and some are termed nonmarket
areas, all electricity transactions are part of a single energy market. Nonetheless,there are significant differences between market and nonmarket areas. Market
areas, like PJM, include essential features of an energy market including
locational marginal pricing, financial congestion offsets (FTRs and ARRs
in PJM) and transparent, least cost, security constrained economic dispatch
for all available generation. Nonmarket areas do not include these features.
Pricing in the market areas is transparent and pricing in the nonmarket areas
is not transparent.
The MMU’s recommendations related to transactions with external balancing
authorities all share the goal of improving the economic efficiency of© 2021 Monitoring Analytics, LLC

Section 1 Introduction

interchange transactions. The standard of comparison is an LMP market. In
an LMP market, redispatch based on LMP and competitive generator offers
results in an efficient dispatch and efficient prices. The goal of designinginterface transaction rules should be to match the outcomes that would exist
in an LMP market across the interfaces.
It is not appropriate to have special pricing agreements between PJM andany external entity. The same market pricing should apply to all transactions.
External entities wishing to receive the benefits of the PJM LMP market
should join PJM.
In 2020, PJM terminated a number of interface pricing points, consistent
with longstanding MMU recommendations. Following the termination of theNorthwest pricing point on October 1, 2020, PJM failed to correctly map thepricing points to transactions that had been mapped to the Northwest pricing
point to pricing points that are consistent with electrical impacts on the PJM
system. The MMU recommends that transactions sourcing in the WesternInterconnection be priced at either the MISO interface pricing point or the
SOUTH interface pricing point based on the electrical impact of flows between
the DC tie line point of connection with the Eastern Interconnection and PJM.
The MMU continues to recommend the termination of the Southeast interface
pricing point and the Ontario interface pricing point. The Southeast pricing
point is inappropriately used to support a special agreement and the Ontariointerface pricing point is noncontiguous to the PJM footprint that creates
opportunities for market participants to engage in sham scheduling activities.

Overview: Section 10, Ancillary Services
Primary Reserve
PJM’s primary reserves are made up of resources, both synchronized andnonsynchronized, that can provide energy within 10 minutes. Primaryreserve is PJM’s implementation of the NERC 15-minute contingency reserve
requirement.144
144 See PJM. “Manual 10: Pre-Scheduling Operations,” § 3.1.1 Day-ahead Scheduling (Operating Reserve, Rev. 39 (Nov. 19, 2020).

© 2021 Monitoring Analytics, LLC

PJM determines the primary reserve requirement based on the most severe
single contingency plus 190 MW in every approved RT SCED case. Every realtime market solution calculates the available tier 1 synchronized reserve. The
required synchronized reserve and nonsynchronized reserve are calculated
and dispatched in every real-time market solution, and there are associatedclearing prices (SRMCP and NSRMCP) assigned every five minutes. Scheduled
resources are credited based on a dispatched assignment and a five minuteclearing price.

Market Structure• Supply. Primary reserve is satisfied by both synchronized reserve(generation or demand response currently synchronized to the grid andavailable within 10 minutes), and nonsynchronized reserve (generation
currently off line but available to start and provide energy within 10
minutes).

• Demand. The PJM primary reserve requirement is 150 percent of the most

severe single contingency plus 190 MW. In the first six months of 2021,
the average primary reserve requirement was 2,427.3 MW in the RTO
Zone and 2,427.2 in the MAD Subzone.

Tier 1 Synchronized Reserve
Synchronized reserve is provided by generators and demand response resources
synchronized to the grid and capable of increasing output or decreasing load
within 10 minutes in response to a PJM declared synchronized reserve event.
Synchronized reserve consists of tier 1 and tier 2 synchronized reserves.
Tier 1 synchronized reserve is the capability of online resources following
economic dispatch to ramp up in 10 minutes from their current output in
response to a synchronized reserve event. There is no formal market for tier 1
synchronized reserve.

• Supply. No offers are made for tier 1 synchronized reserves. The market

solution estimates tier 1 synchronized reserve as available 10 minuteramp from the energy dispatch. In the first six months of 2021, there wasan average hourly supply of 1,611.4 MW of tier 1 available in the RTO
2021 Quarterly State of the Market Report for PJM: January through June 55

2021 Quarterly State of the Market Report for PJM: January through June

Zone and an average hourly supply of 807.9 MW of tier 1 synchronizedreserve available within the MAD Subzone.

• Demand. The synchronized reserve requirement is calculated for eachreal-time dispatch solution as the most severe single contingency plus
190 MW within both the RTO Zone and the MAD Subzone.

• Tier 1 Synchronized Reserve Event Response. Tier 1 synchronized reserveis paid when a synchronized reserve event occurs and it responds. Whena synchronized reserve event is called, all tier 1 response is paid forincreasing its output (or reducing load for demand response) at the rateof $50 per MWh in addition to LMP.145 This is the Synchronized Energy
Premium Price.

When the synchronized reserve requirement cannot be met with tier 1
synchronized reserve, PJM uses the tier 2 synchronized reserve market tosatisfy the balance of the requirement. The tier 2 synchronized reserve market
includes the PJM RTO Reserve Zone and a subzone, the Mid-Atlantic Dominion
Reserve Subzone (MAD).

there is no incremental cost associated with the ability to ramp up fromthe current economic dispatch point and the appropriate payment for
responding to an event is the synchronized energy premium price of $50
per MWh. The tariff requires payment of the tier 2 synchronized reserve
market clearing price to tier 1 resources whenever the nonsynchronizedreserve market clearing price rises above zero. This requirement is
unnecessary and inconsistent with efficient markets. This change had asignificant impact on the cost of tier 1 synchronized reserves, resulting ina windfall payment of $89,719,045 to tier 1 resources in 2014, $34,397,441
in 2015, $4,948,084 in 2016, $2,197,514 in 2017, $4,732,025 in 2018, and$3,217,178 in 2019. The nonsynchronized reserve market clearing price
was above $0 in 2,015 intervals (1.9 percent of intervals) in 2020 resulting
in a payment to tier 1 resources of $3,319,263. In the first six months of2021, the nonsynchronized reserve market clearing price was above $0
in 29.6 percent of all intervals resulting in a net payment of $2,372,703.

Market Structure• Issues. The competitive offer for tier 1 synchronized reserves is zero, as

Tier 2 Synchronized Reserve Market
Tier 2 synchronized reserve is part of primary reserve and is comprisedof resources that are synchronized to the grid, that may incur costs to besynchronized, and that have an obligation to respond to PJM declaredsynchronized reserve events. Tier 2 synchronized reserve is penalized for
145 See PJM. “Manual 11: Energy & Ancillary Services Market Operations,”§ 4.2.10 Settlements, Rev. 115 (June 1, 2021).

56

failure to respond to a PJM declared synchronized reserve event. In PJM therequired amount of synchronized reserve is defined to be no less than thelargest single contingency, and 10 minute primary reserve as no less than
150 percent of the largest single contingency, plus 190 MW. This is stricter
than the NERC standard of the greater of 80 percent of the largest single
contingency or 900 MW.146

Section 1 Introduction• Supply. In the first six months of 2021, the supply of daily offered andeligible tier 2 synchronized reserve was 36,322.9 MW in the RTO Zone ofwhich 4,649.6 MW was located in the MAD Subzone.

• Demand. The average hourly synchronized reserve requirement was

1,699.5 MW in the RTO Reserve Zone and 1,672.6 in the Mid-Atlantic
Dominion Reserve Subzone. The hourly average cleared tier 2 synchronizedreserve was 239.7 MW in the MAD Subzone and 612.6 MW in the RTO.

• Market Concentration. Both the Mid-Atlantic Dominion Subzone Tier 2

Synchronized Reserve Market and the RTO Synchronized Reserve Zone
Market were characterized by structural market power in the first six
months of 2021.
The average HHI for tier 2 synchronized reserve in the RTO Zone was5235 which is classified as highly concentrated.

Market Conduct• Offers. There is a must offer requirement for tier 2 synchronized reserve.

All nonemergency generation capacity resources are required to submit adaily offer for tier 2 synchronized reserve, unless the unit type is exempt.
Tier 2 synchronized reserve offers from generating units are subject to

146 NERC (June 2, 2020) <NERC Reliability Standard BAL 002-2 Glossary_of_Terms.pdf>.

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

an offer cap of marginal cost plus $7.50 per MW, plus opportunity costwhich is calculated by PJM. PJM automatically enters an offer of $0 fortier 2 synchronized reserve when an offer is not entered by the owner.

Market Performance• Price. The weighted average price for tier 2 synchronized reserve forall cleared hours in the MAD subzone was $5.54 per MW in the firstsix months of 2021. The weighted average price for tier 2 synchronizedreserve for all cleared intervals in the RTO Synchronized Reserve Zone
was $5.48 per MW in the first six months of 2021.

Nonsynchronized Reserve Market
Nonsynchronized reserve is part of primary reserve and includes the RTO
Reserve Zone and the Mid-Atlantic Dominion Reserve Subzone (MAD).
Nonsynchronized reserve is comprised of nonemergency energy resources not
currently synchronized to the grid that can provide energy within 10 minutes.
Nonsynchronized reserve is available to fill the primary reserve requirement
above the synchronized reserve requirement. Generation owners do not
submit supply offers for nonsynchronized reserve. PJM defines the demand
curve for nonsynchronized reserve and PJM defines the supply curve based onnonemergency generation resources that are available to provide energy andcan start in 10 minutes or less (based on offer parameters), and on the resource
opportunity costs calculated by PJM.

Market Structure• Supply. In the first six months of 2021, the average supply of eligible andavailable nonsynchronized reserve was 1,537.3 MW in the RTO Zone.

• Demand. Demand for nonsynchronized reserve equals the primary reserve

requirement minus the tier 1 synchronized reserve estimate and minus thescheduled tier 2 synchronized reserve.147

147 See PJM. “Manual 11: Energy & Ancillary Services Market Operations,” § $b.2.2 Non-Synchronized Reserve Zones and Levels, Rev. 115(June 1, 2021). “Because Synchronized Reserve may be utilized to meet the Primary Reserve requirement, there is no explicit requirement
for non-synchronized reserves. “© 2021 Monitoring Analytics, LLC• Market Concentration. The MMU calculates that the three pivotal supplier

test would have been failed in 95.6 percent of intervals where the price
was above $0.01 in the first six months of 2021.

Market Conduct• Offers. Generation owners do not submit supply offers. Nonemergency

generation resources that are available to provide energy and can start in
10 minutes or less are considered available for nonsynchronized reservesby the market solution software. PJM calculates the associated offer
prices based on PJM calculations of resource specific opportunity costs.

Market Performance• Price. The nonsynchronized reserve price is determined by the opportunity

cost of the marginal nonsynchronized reserve unit. The nonsynchronizedreserve weighted average price for all intervals in the RTO Reserve Zone
was $0.25 per MW in the first six months of 2021.

Secondary Reserve (DASR)
There is no NERC standard for secondary reserve. PJM defines secondary
reserve in the day-ahead market as reserves (online or offline available fordispatch) that can be converted to energy in 30 minutes. PJM defines asecondary reserve requirement but is not required to maintain this level ofsecondary reserve in real time.
PJM maintains a day-ahead, offer-based market for 30 minute day-ahead
secondary reserve. The PJM Day-Ahead Scheduling Reserve Market (DASR)
has no performance obligations except that a unit which clears the DASR
market may not be on an outage in real time.148 If DASR units are on an
outage in real time or cleared DASR MW are not available, the DASR payment
is not made.

148 See PJM, “Manual 11: Energy & Ancillary Services Market Operations,” § 11.2.7 Day-Ahead Scheduling Reserve Performance, Rev. 115(June 1, 2021).

2021 Quarterly State of the Market Report for PJM: January through June 57

2021 Quarterly State of the Market Report for PJM: January through June

Market Structure• Supply. The DASR market is a must offer market. Any resources that do

not make an offer have their offer set to $0.00 per MW. DASR is calculatedby the day-ahead market solution as the lesser of the 30 minute energy
ramp rate or the economic maximum MW minus the day-ahead dispatch
point for all resources that can provide energy within 30 minutes of arequest from PJM Dispatch. In the first six months of 2021, the averageavailable hourly DASR was 17,368.1 MW.149• Demand. The DASR requirement is the sum of the PJM requirement and theDominion requirement based on the VACAR reserve sharing agreement.
For November 2020 through October 2021, the DASR requirement is 4.72
percent of peak load forecast. The average hourly DASR MW purchasedin the first six months of 2021 was 4,563.4 MW, a reduction from the4,987.2 hourly MW in 2020.

• Concentration. The three pivotal supplier test would have failed in 216
hours in the first six months of 2021.

Market Conduct• Withholding. Economic withholding remains an issue in the DASR Market.

The direct marginal cost of providing DASR is zero. PJM calculates theopportunity cost for each resource. All offers by resource owners greaterthan zero constitute economic withholding. In the first six months of2021, 39.3 percent of daily unit offers were above $0.00 and 15.8 percent
of daily unit offers were above $5.

• DR. Demand resources are eligible to participate in the DASR Market.
Some demand resources have entered offers for DASR. No demand
resources cleared the DASR market in the first six months of 2021.

Market Performance• Price. In the first six months of 2021, the weighted average DASR pricefor all hours when the DASRMCP was above $0.00 was $0.95.

149 The average hourly available DASR MW are modified from previously reported values due to a calculation error which has been fixed.

58

Section 1 Introduction

Regulation Market
The PJM Regulation Market is a real-time market. Regulation is provided
by generation resources and demand response resources that qualify tofollow one of two regulation signals, RegA or RegD. PJM jointly optimizes
regulation with synchronized reserve and energy to provide all three products
at least cost. The PJM regulation market design includes three clearing pricecomponents: capability; performance; and opportunity cost. The RegA signal
is designed for energy unlimited resources with physically constrained ramp
rates. The RegD signal is designed for energy limited resources with fast ramp
rates. In the regulation market RegD MW are converted to effective MW usinga marginal rate of technical substitution (MRTS), called a marginal benefit
factor (MBF). Correctly implemented, the MBF would be the marginal rateof technical substitution (MRTS) between RegA and RegD, holding the levelof regulation service constant. The current market design is critically flawed
as it has not properly implemented the MBF as an MRTS between RegA and
RegD resource MW and the MBF has not been consistently applied in the
optimization, clearing and settlement of the regulation market.

Market Structure• Supply. In the first six months of 2021, the average hourly offered supplyof regulation for nonramp hours was 758.5 performance adjusted MW(751.6 effective MW). This was an increase of 57.4 performance adjusted
MW (an increase of 45.7 effective MW) from the first six months of 2020.
In the first six months of 2021, the average hourly offered supply of
regulation for ramp hours was 1,072.8 performance adjusted MW (1,093.8
effective MW). This was an increase of 91.3 performance adjusted MW (anincrease of 65.1 effective MW) from the first six months of 2020, when
the average hourly offered supply of regulation was 981.5 performanceadjusted MW (1,028.7 effective MW).

• Demand. The hourly regulation demand is 525.0 effective MW for
nonramp hours and 800.0 effective MW for ramp hours.

• Supply and Demand. The nonramp regulation requirement of 525.0

effective MW was provided by a combination of RegA and RegD resources
equal to 491.3 hourly average performance adjusted actual MW in the© 2021 Monitoring Analytics, LLC

Section 1 Introduction

first six months of 2021. This is an increase of 1.7 performance adjusted
actual MW from the first six months of 2020, when the average hourly
total regulation cleared performance adjusted actual MW for nonramp
hours were 489.6 performance adjusted actual MW. The ramp regulation
requirement of 800.0 effective MW was provided by a combination of
RegA and RegD resources equal to 707.3 hourly average performanceadjusted actual MW in the first six months of 2021. This is an increase of
3.2 performance adjusted actual MW from the first six months of 2020,
where the average hourly regulation cleared MW for ramp hours were704.1 performance adjusted actual MW.
The ratio of the average hourly offered supply of regulation to averagehourly regulation demand (performance adjusted cleared MW) for ramp
hours was 1.52 in the first six months of 2021 (1.39 in the first six monthsof 2020). The ratio of the average hourly offered supply of regulation toaverage hourly regulation demand (performance adjusted cleared MW)
for nonramp hours was 1.54 in the first six months of 2021 (1.43 in thefirst six months of 2020).

• Market Concentration. In the first six months of 2021, the three pivotal

supplier test was failed in 87.7 percent of hours. In the first six monthsof 2021, the actual MW weighted average HHI of RegA resources was
2288 which is highly concentrated and the weighted average HHI of RegD
resources was 1670 which is moderately concentrated. The weighted
average HHI of all resources was 1218, which is moderately concentrated.

Market Conduct• Offers. Daily regulation offer prices are submitted for each unit by theunit owner. Owners are required to submit a cost-based offer and may
submit a price-based offer. Offers include both a capability offer and aperformance offer. Owners must specify which signal type the unit will
be following, RegA or RegD.150 In the first six months of 2021, there were
219 resources following the RegA signal and 50 resources following the
RegD signal.

150 See the 2019 State of the Market Report for PJM, Vol. II, Appendix F “Ancillary Services Markets.”© 2021 Monitoring Analytics, LLC

Market Performance• Price and Cost. The weighted average clearing price for regulation was$17.46 per MW of regulation in the first six months of 2021, an increaseof $5.73 per MW, or 48.9 percent, from the weighted average clearing
price of $11.73 per MW in the first six months of 2020. The weighted
average cost of regulation in the first six months of 2021 was $21.66 per
MW of regulation, an increase of 46.4 percent, from the weighted average
cost of $14.79 per MW in the first six months of 2020.

• Prices. RegD resources continue to be incorrectly compensated relative to
RegA resources due to an inconsistent application of the marginal benefit
factor in the optimization, assignment and settlement processes. If theregulation market were functioning efficiently and competitively, RegD
and RegA resources would be paid the same price per effective MW.

• Marginal Benefit Factor. The marginal benefit factor (MBF) is intended

to measure the operational substitutability of RegD resources for RegA
resources. The marginal benefit factor is incorrectly defined and appliedin the PJM market clearing. The current incorrect and inconsistent
implementation of the MBF has resulted in the PJM Regulation Market
over procuring RegD relative to RegA in most hours and in an inefficient
market signal about the value of RegD in every hour.

Black Start Service
Black start service is required for the reliable restoration of the grid following a
blackout. Black start service is the ability of a generating unit to start without
an outside electrical supply, or is the demonstrated ability of a generating unit
to automatically remain operating at reduced levels when disconnected fromthe grid (automatic load rejection or ALR).151
In the first six months of 2021, total black start charges were $33.6 million,
including $33.3 million in revenue requirement charges and $0.2 million in
uplift charges. Black start revenue requirements consist of fixed black start
service costs, variable black start service costs, training costs, fuel storage
costs, and an incentive payment. Black start uplift charges are paid to units
151 OATT Schedule 1 § 1.3BB. There are no ALR units currently providing black start service.

2021 Quarterly State of the Market Report for PJM: January through June 59

2021 Quarterly State of the Market Report for PJM: January through Junescheduled in the day-ahead energy market or committed in real time to provide
black start service under the ALR option or for black start testing. Black start
zonal charges in the first six months of 2021 ranged from $0.02 per MW-day
in the BGE Zone (total charges were $22,716) to $4.13 per MW-day in the PE
Zone (total charges were $2,176,976).
CRF values are a key determinant of total payments to black start units. The
CRF values in PJM tariff tables should have been changed for both black startand the capacity market when the tax laws changed in December 2017. As aresult, CRF values have overcompensated black start units since the changes
to the tax code.

Reactive
Reactive service, reactive supply and voltage control are provided bygeneration and other sources of reactive power (measured in MVAr). Reactive
power helps maintain appropriate voltage levels on the transmission system
and is essential to the flow of real power (measured in MW). The sameequipment provides both MVAr and MW. The current rules permit double
recovery of some fixed costs.
Reactive capability charges are based on FERC approved filings that permit
recovery based on an outdated cost of service approach.152 All capacity costsof generators should be incorporated in the capacity market. The nonmarket
cost of service approach to reactive capability payments should be eliminated.
Reactive service charges are paid to units that operate in real time outsideof their normal range at the direction of PJM for the purpose of providing
reactive service. Total reactive charges increased 4.81 percent from $174.8
million in the first six months of 2020 to $182.5 million in 2021. Reactive
capability charges increased 4.51 percent from $174.6 million in the first six
months of 2020 to $182.460 million in 2021. Total reactive service charges in
the first six months of 2021 ranged from $0 in the REC and OVEC Zones, to$25.0 million in the AEP Zone.

152 OATT Schedule 2.

60

Section 1 Introduction

Frequency Response
On February 15, 2018, the Commission issued Order No. 842, which modified
the pro forma large and small generator interconnection agreements andprocedures to require newly interconnecting generating facilities, bothsynchronous and nonsynchronous, to include equipment for primary frequency
response capability as a condition to receive interconnection service.153 PJM
filed revisions in compliance with Order No. 842 that incorporated the pro
forma agreements into its market rules.154
The PJM Tariff requires that all new generator interconnection customers(Nuclear Regulatory Commission regulated facilities are exempt from thisprovision) have hardware and/or software that provides frequency responsive
real power control with the ability to sense changes in system frequency
and autonomously adjust real power output in a direction to correct forfrequency deviations. This includes a governor or equivalent controls capableof operating with a maximum five percent droop and a +/- 0.036 deadband.155
In addition to resource capability, resource owners must comply by setting
control systems to autonomously adjust real power output in a direction tocorrect for frequency deviations.
The response of generators within PJM to NERC identified frequency events
remains under evaluation. A frequency event is declared when the frequency
goes outside +/-40mHz for 60 continuous seconds. The NERC BAL-003-2
requirement for balancing authorities (PJM is a balancing authority) uses athreshold value (L10) equal to -261.1 MW/0.1 Hz and has selected four events
between June 1, 2020 and December 31, 2020 as well as two events in Januaryof 2021 to evaluate.

Market Procurement of Real Time Ancillary Services
PJM uses market mechanisms to varying degrees in the procurement ofancillary services, including primary reserves and regulation. Ideally, allancillary services would be procured taking full account of the interactions
153 See 157 FERC ¶ 61,122 (2016).
154 See 164 FERC ¶ 61,224 (2018).
155 OATT Attachment O § 4.7.2 (Primary Frequency Response).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

with the energy market. When a resource is used for an ancillary service
instead of providing energy in real time, the cost of removing the resource,
either fully or partially, from the energy market should be weighed against
the benefit the ancillary service provides. The degree to which PJM markets
account for these interactions depends on the timing of the product clearing
and software limitations and the accuracy of unit parameters and offers.
The synchronized reserve market clearing is more integrated with the energy
market clearing than the other ancillary services. Resources categorized as
flexible tier 2 reserve, those that can provide reserves by backing down
according to their ramp rate, are jointly cleared along with energy in every
real-time market solution. Given the joint clearing of energy and flexible
tier 2, the synchronized reserve market clearing price should always cover
the opportunity cost of providing flexible tier 2. PJM should never need to
pay uplift to flexible tier 2. The uplift paid to flexible tier 2 results fromissues with the dispatch and pricing software timing. Inflexible tier 2 reserves,
provided by resources that require longer notice to take actions to prepare forreserve deployment, are not cleared along with energy in the real-time market
solution. Inflexible tier 2 reserves are cleared hourly by the Ancillary Service
Optimizer (ASO). The ASO uses forward looking information about the energy
market, flexible tier 2, tier 1, and regulation to estimate the costs and benefitsof using a resource for inflexible tier 2 synchronized reserves.
Nonsynchronized reserves are cleared with every real-time energy market
solution, but their costs are not fully known by the real-time energy market
software (RT SCED) because the resources are offline. PJM uses an estimateof the cost of using a resource for nonsynchronized reserve instead of energy
from a previously solved IT SCED solution. IT SCED runs every 15 minutes
looking ahead at target dispatch times up to two hours in the future. Theenergy commitment decisions for the offline resources have already been
made when the RT SCED clears the nonsynchronized reserve market. RT SCED
compares the IT SCED estimated cost of nonsynchronized reserve clearing to
the RT SCED determined cost of synchronized reserve clearing in satisfying
the primary reserve requirement. Nonsynchronized reserve clearing indirectly© 2021 Monitoring Analytics, LLC

interacts with energy clearing through both products’ substitutability withsynchronized reserves.
Prices for the regulation and reserve markets are set by the pricing calculator(LPC), which is based on the RT SCED solution. The software determining theprices (RT SCED) is partially, but not fully clearing the reserve market. The
software determining the prices is not clearing the regulation market.

Section 10 Recommendations• The MMU recommends that all data necessary to perform the regulation

market three pivotal supplier test be saved by PJM so that the test can be
replicated. (Priority: Medium. First reported 2016. Status: Not adopted.)• The MMU recommends that the total regulation (TReg) signal sent on a

fleet wide basis be eliminated and replaced with individual regulation
signals for each unit. (Priority: Low. First reported 2019. Status: Not
adopted.)• The MMU recommends that the ability to make dual offers (to make offers

as both a RegA and a RegD resource in the same market hour) be removed
from the regulation market. (Priority: High. First reported 2019. Status:
Not adopted.)• The MMU recommends that the regulation market be modified toincorporate a consistent application of the marginal benefit factor (MBF)
throughout the optimization, assignment and settlement process. The
MBF should be defined as the Marginal Rate of Technical Substitution(MRTS) between RegA and RegD. (Priority: High. First reported 2012.
Status: Not adopted. FERC rejected.156)• The MMU recommends that the lost opportunity cost in the ancillary
services markets be calculated using the schedule on which the unit wasscheduled to run in the energy market. (Priority: High. First reported 2010.
Status: Not adopted.157 FERC rejected.158)

156 162 FERC ¶ 61,295 (2018), reh’g denied, 170 FERC ¶ 61,259 (2020).
157 This recommendation was adopted by PJM for the energy market. Lost opportunity costs in the energy market are calculated using theschedule on which the unit was scheduled to run. In the regulation market, this recommendation has not been adopted, as the LOC
continues to be calculated based on the lower of price or cost in the energy market offer.
158 162 FERC ¶ 61,295 (2018), reh’g denied, 170 FERC ¶ 61,259 (2020).

2021 Quarterly State of the Market Report for PJM: January through June 61

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends that the lost opportunity cost calculation used

• The MMU recommends that the components of the cost-based offers for

enforced in the regulation market as a reduction in performance score
and/or a forfeiture of revenues when resource owners elect to deassign
assigned regulation resources within the hour. (Priority: Medium. First
reported 2016. Status: Not adopted. FERC rejected.160)• The MMU recommends that the rule requiring that tier 1 synchronized• The MMU recommends that, to prevent gaming, there be a penalty• The MMU recommends enhanced documentation of the implementationof the regulation market design. (Priority: Medium. First reported 2010.
Status: Not adopted. FERC rejected.161)• The MMU recommends that PJM be required to save data elements

necessary for verifying the performance of the regulation market.
(Priority: Medium. First reported 2010. Status: Not adopted.)• The MMU recommends that the $12.00 margin adder be eliminated fromthe definition of the cost based regulation offer because it is a markup
and not a cost. (Priority: Medium. First reported Q1, 2021. Status: Not
adopted.)• The MMU recommends that PJM replace the static MidAtlantic/Dominion

Reserve Subzone with a reserve zone structure consistent with the actual
deliverability of reserves based on current transmission constraints.
(Priority: High. First reported 2019. Status: Not adopted.)• The MMU recommends that the $7.50 margin be eliminated from thedefinition of the cost of tier 2 synchronized reserve because it is amarkup and not a cost. (Priority: Medium. First reported 2018. Status:
Not adopted.)• The MMU recommends that the variable operating and maintenance costbe eliminated from the definition of the cost of tier 2 synchronized reserveand that the calculation of synchronized reserve variable operations and

159 Id.
160 Id.
161 Id.

62

maintenance costs be removed from Manual 15. (Priority: Medium. First
reported 2019. Status: Not adopted.)in the regulation market be based on the resource’s dispatched energy
offer schedule, not the lower of its price or cost offer schedule. (Priority:
Medium. First reported 2010. Status: Not adopted. FERC rejected.159)

Section 1 Introduction

providing regulation and synchronous condensing be defined in Schedule
2 of the Operating Agreement. (Priority: Low. First reported 2019. Status:
Not adopted.)reserve resources be paid the tier 2 price when the nonsynchronizedreserve price is above zero be eliminated immediately and that, under
the current rule, tier 1 synchronized reserve resources not be paid the tier2 price when they do not respond. (Priority: High. First reported 2013.
Status: Not adopted.)• The MMU recommends that the tier 2 synchronized reserve must

offer requirement be enforced on a daily and hourly basis. The MMU
recommends that PJM define a set of acceptable reasons why a unit canbe made unavailable daily or hourly and require unit owners to select areason in Markets Gateway whenever making a unit unavailable either
daily or hourly or setting the offer MW to 0 MW. (Priority: Medium. First
reported 2013. Status: Partially adopted.)• The MMU recommends that, for calculating the penalty for a tier 2

resource failing to meet its scheduled obligation during a spinning event,the penalty should be based on the actual time since the last spinning
event of 10 minutes or longer during which the resource performed
because performance is only measured for events 10 minutes or longer.
(Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that aggregation not be permitted to offset unit
specific penalties for failure to respond to a synchronized reserve event.
(Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that PJM eliminate the use of Degree of Generator
Performance (DGP) in the synchronized reserve market solution andimprove the actual tier 1 estimate. If PJM continues to use DGP, DGP
should be documented in PJM’s manuals. (Priority: Medium. First reported
2018. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Section 1 Introduction• The MMU recommends that the details of VACAR Reserve Sharing
Agreement (VRSA) be made public, including any responsibilities assigned
to PJM and including the amount of reserves that Dominion commits tomeet its obligations under the VRSA. (Priority: Medium. First reported
2020. Status: Not adopted.)• The MMU recommends that the VRSA be terminated and, if necessary,

replaced by a reserve sharing agreement between PJM and VACAR South,
similar to agreements between PJM and other bordering areas. (Priority:
Medium. First reported 2020. Status: Not adopted.)• The MMU recommends that a reason code be attached to every hourin which PJM market operations adds additional DASR MW. (Priority:
Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that PJM modify the DASR market to ensure that
all resources cleared incur a real-time performance obligation. (Priority:
Low. First reported 2013. Status: Not adopted.)• The MMU recommends that, in order to mitigate market power, offers in

the DASR market be based on opportunity cost only. (Priority: Low. First
reported 2009. Modified, 2018. Status: Not adopted.)• The MMU recommends that all resources, new and existing, have arequirement to include and maintain equipment for primary frequency
response capability as a condition of interconnection service. The PJM
capacity and energy markets already compensate resources for frequency
response capability and any marginal costs. (Priority: Medium. First
reported 2018. Status: Not adopted.)• The MMU recommends that new CRF rates for black start units,

incorporating current tax code changes, be implemented immediately.
The new CRF rates should apply to all black start units. The black start
units should be required to commit to providing black start service for thelife of the unit. (Priority: High. First reported 2020. Status: Not adopted.)• The MMU recommends for oil tanks shared with other resources that

only a proportionate share of the minimum tank suction level (MTSL) be
allocated to black start service. The MMU further recommends that the
PJM tariff be updated to clearly state how the MTSL will be calculated for© 2021 Monitoring Analytics, LLC

black start units sharing oil tanks. (Priority: Medium. First reported 2017.
Status: Not adopted.)• The MMU recommends that separate cost of service payments for reactive
capability be eliminated and the cost of reactive capability be recoveredin the capacity market. (Priority: Medium. First reported 2016. Status: Not
adopted.)• The MMU recommends that payments for reactive capability, if continued,
be based on the 0.90 power factor that PJM has determined is necessary.
(Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that, if payments for reactive are continued,
fleet wide cost of service rates used to compensate resources for reactive
capability be eliminated and replaced with compensation based on unit
specific costs. (Priority: Low. First reported 2019.162 Status: Partiallyadopted.)• The MMU recommends that Schedule 2 to OATT be revised to state

explicitly that only generators that provide reactive capability to thetransmission system that PJM operates and has responsibility for are
eligible for reactive capability compensation. Specifically, such eligibility
should be determined based on whether a generation facility’s point ofinterconnection is on a transmission line that is a Monitored Transmission
Facility as defined by PJM and is on a Reportable Transmission Facility
as defined by PJM.163 (Priority: Medium. First reported 2020. Status: Not
adopted.)Section 10 Conclusion
The design of the PJM Regulation Market is significantly flawed.164 The
market design does not correctly incorporate the marginal rate of technicalsubstitution (MRTS) in market clearing and settlement. The market designuses the marginal benefit factor (MBF) to incorrectly represent the MRTS anduses a mileage ratio instead of the MBF in settlement. This failure to correctly
162 The MMU has discussed this recommendation in state of the market reports since 2016 but Q3, 2019 was the first time it was reported
as a formal MMU recommendation.
163 See PJM Transmission Facilities (note that this requires you first log into a PJM Tools account. If you do not, then the link sends you toan Access Request page, <https://pjm.com/markets-and-operations/ops-analysis/transmission-facilities>.
164 The current PJM regulation market design that incorporates two signals using two resource types was a result of FERC Order No. 755
and subsequent orders. Order No. 755, 137 FERC ¶ 61,064 at PP 197–200 (2011).

2021 Quarterly State of the Market Report for PJM: January through June 63

2021 Quarterly State of the Market Report for PJM: January through Juneand consistently incorporate the MRTS into the regulation market design has
resulted in both underpayment and overpayment of RegD resources and in theover procurement of RegD resources in all hours. The market results continue
to include the incorrect definition of opportunity cost. These issues are thebasis for the MMU’s conclusion that the regulation market design is flawed.
To address these flaws, the MMU and PJM developed a joint proposal which
was approved by the PJM Members Committee on July 27, 2017, and filed with
FERC on October 17, 2017.165 The PJM/MMU joint proposal addresses issues
with the inconsistent application of the marginal benefit factor throughout
the optimization and settlement process in the PJM Regulation Market. FERC
rejected the joint proposal on March 30, 2018, as being noncompliant with
Order No. 755.166 The MMU and PJM separately filed requests for rehearing,which were denied by order issued March 26, 2020.167
The structure of the tier 2 synchronized reserve market has been evaluated andthe MMU has concluded that these markets are not structurally competitive as
they are characterized by high levels of supplier concentration and inelastic
demand. As a result, these markets are operated with market clearing prices
and with offers based on the marginal cost of producing the product plus a
margin. As a result of these requirements, the conduct of market participants
within these market structures has been consistent with competition, andthe market performance results have been competitive. However, the $7.50
margin is not a cost. The margin is effectively a rule-based form of economic
withholding and is therefore not consistent with a competitive outcome. The$7.50 margin should be eliminated. The variable operating and maintenancecomponent of the synchronized reserve offer should also be eliminated. Allvariable operating and maintenance costs are incurred to provide energy andto make units available to provide energy. There are no variable operating andmaintenance costs associated with providing synchronized reserve.

remains significantly less than 100 percent. Actual participant performancemeans that the penalty structure is not an adequate incentive for performance.
The rule that requires payment of the tier 2 synchronized reserve price to tier
1 synchronized reserve resources when the nonsynchronized reserve price isgreater than zero, is inefficient and results in a substantial windfall payment
to the holders of tier 1 synchronized reserve resources. Tier 1 resources haveno obligation to perform and pay no penalties if they do not perform, and tier1 resources do not incur any costs when they are part of the tier 1 estimate
in the market solution. Tier 1 resources are already paid for their response if
they do respond to a synchronized reserve event. Tier 1 resources require no
additional payment. If tier 1 resources wish to be paid as tier 2 resources, therules provide the opportunity to make competitive offers in the tier 2 market
and take on the associated obligations. Overpayment of tier 1 resources basedon this rule has added more than $100 million to the cost of primary reserve
since 2014.
The benefits of markets are realized under these approaches to ancillary
service markets. Even in the presence of structurally noncompetitive markets,
there can be transparent, market clearing prices based on competitive offersthat account explicitly and accurately for opportunity cost. This is consistent
with the market design goal of ensuring competitive outcomes that provide
appropriate incentives without reliance on the exercise of market power andwith explicit mechanisms to prevent the exercise of market power.
The MMU concludes that the regulation market results were not competitive,
and the market design is significantly flawed. The MMU concludes that thesynchronized reserve market results were competitive, although the $7.50
margin should be removed. The MMU concludes that the DASR market results
were competitive, although offers above the competitive level continue toaffect prices.

Participant performance has not been adequate for tier 2 synchronized reserve.
Compliance with calls to respond to actual synchronized reserve events
165 18 CFR § 385,211 (2017)
166 162 FERC ¶ 61,295.
167 170 FERC ¶ 61,259.

64

Section 1 Introduction© 2021 Monitoring Analytics, LLC

Section 1 Introduction

Overview: Section 11, Congestion and Marginal
LossesCongestion Cost

• Total Congestion. Total congestion costs increased by $174.2 million•

or 96.9 percent, from $179.8 million in the first six months of 2020 to$354.0 million in the first six months of 2021.
Day-Ahead Congestion. Day-ahead congestion costs increased by $265.3
million or 112.2 percent, from $236.4 million in the first six months of2020 to $501.7 million in the first six months of 2021.

• Balancing Congestion. Negative balancing congestion costs increased

by $91.1 million, from -$56.6 million in the first six months of 2020
to -$147.7 million in the first six months of 2021. Negative balancing
explicit charges increased by $23.8 million, from -$37.0 million in thefirst six months of 2020 to -$60.8 million in the first six months of 2021.

• Real-Time Congestion. Real-time congestion costs increased by $403.9
million, from $239.9 million in the first six months of 2020 to $643.8
million in the first six months of 2021.

• Monthly Congestion. Monthly total congestion costs in the first six

months of 2021 ranged from $29.1 million in January to $94.0 million
in May.

Day-ahead congestion frequency decreased by 16.9 percent from 35,292
congestion event hours in the first six months of 2020 to 29,311 congestion
event hours in the first six months of 2021.
Real-time congestion frequency increased by 3.6 percent from 10,829
congestion event hours in the first six months of 2020 to 11,216 congestion
event hours in the first six months of 2021.

• Congested Facilities. The monthly average of daily day-ahead congestion

event hours decreased in November 2020 as a result of decreased
UTC activity due to a FERC order issued effective November 1, 2020,
directing PJM to charge uplift to up to congestion transactions.168 Dayahead, congestion event hours decreased on all types of facilities except
flowgates.
The Bagley - Raphael Road Line was the largest contributor to congestion
costs in the first six months of 2021. With $20.9 million in total congestion
costs, it accounted for 5.9 percent of the total PJM congestion costs in thefirst six months of 2021.

• CT Price Setting Logic and Closed Loop Interface Related Congestion. CT
Price Setting Logic caused -$0.2 million of day-ahead congestion in thefirst six months of 2021 and -$5.9 million of balancing congestion in thefirst six months of 2021. None of the closed loop interfaces was binding
in the first six months of 2021 or 2020.

• Geographic Differences in CLMP. Differences in CLMP among eastern,• Zonal Congestion. AEP had the highest zonal congestion costs among• Congestion Frequency. Congestion frequency continued to be significantly

Marginal Loss Costsouthern and western control zones in PJM were primarily a result ofcongestion on the Bagley - Raphael Road Line, the Three Mile Island
Transformer, the Harwood - Susquehanna Line, the Pleasant View –Ashburn Line and the Cumberland – Juniata Line.
higher in the day-ahead energy market than in the real-time energy
market in the first six months of 2021. The number of congestion event
hours in the day-ahead energy market was about three times the numberof congestion event hours in the real-time energy market.

all control zones in the first six months of 2021. AEP had $61.3 million
in zonal congestion costs, comprised of $83.4 million in day-aheadcongestion costs and -$22.2 million in balancing congestion costs.

• Total Marginal Loss Costs. Total marginal loss costs increased by $182.5

million or 94.3 percent, from $193.4 million in the first six months of2020 to $375.9 million in the first six months of 2021. The loss MWh in
PJM increased by 685.0 GWh or 10.1 percent, from 6,758.9 GWh in thefirst six months of 2020 to 7,443.9 GWh in the first six months of 2021.

168 172 FERC ¶ 61,046 (2020).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 65

2021 Quarterly State of the Market Report for PJM: January through June

The loss component of real-time LMP in the first six months of 2021 was$0.02, compared to $0.01 in the first six months of 2020.

• Day-Ahead Marginal Loss Costs. Day-ahead marginal loss costs increased

by $175.0 million or 79.8 percent, from $219.4 million in the first six
months of 2020 to $394.4 million in the first six months of 2021.

• Balancing Marginal Loss Costs. Negative balancing marginal loss costs
decreased by $7.5 million or 28.9 percent, from -$25.9 million in the firstsix months of 2020 to -$18.4 million in the first six months of 2021.

• Total Marginal Loss Surplus. The total marginal loss surplus increased by$74.4 million or 124.7 percent, from $59.7 million in the first six monthsof 2020, to $134.0 million in the first six months of 2021.

• Monthly Total Marginal Loss Costs. Monthly total marginal loss costs inthe first six months of 2021 ranged from $42.5 million in April to $102.7
million in February.

System Energy Cost

• Total System Energy Costs. Total system energy costs decreased by $106.8

million or 79.7 percent, from -$133.9 million in the first six months of2020 to -$240.7 million in the first six months of 2021.

• Day-Ahead System Energy Costs. Day-ahead system energy costs

decreased by $97.4 million or 55.5 percent, from -$175.6 million in thefirst six months of 2020 to -$273.0 million in the first six months of 2021.

• Balancing System Energy Costs. Balancing system energy costs decreased

by $9.7 million or 23.6 percent, from $41.2 million in the first six monthsof 2020 to $31.4 million in the first six months of 2021.

• Monthly Total System Energy Costs. Monthly total system energy costsin the first six months of 2021 ranged from -$63.0 million in February to-$28.5 million in April.

Section 11 Conclusion
Congestion is defined as the total payments by load in excess of the total
payments to generation, excluding marginal losses. The level and distribution
66

Section 1 Introductionof congestion reflects the underlying characteristics of the power system,
including the nature and capability of transmission facilities, the offers andgeographic distribution of generation facilities, the level and geographic
distribution of incremental bids and offers and the geographic and temporal
distribution of load.
Total congestion costs increased by $174.2 million or 96.9 percent, from
$179.8 million in the first six months of 2020 to $354.0 million in the first six
months of 2021. The total day-ahead congestion costs and negative balancing
congestion costs increased significantly compared to the first six monthsof 2020. This was the combined result of higher demand and higher prices,cold weather in February of 2021, CT pricing logic, and transmission facility
outages in March and May.
The monthly total congestion costs ranged from $29.1 million in January to$94.0 million in May in the first six months of 2021.
The current ARR/FTR design does not serve as an efficient way to ensurethat load receives the rights to all congestion revenues. The congestion
offset for the 2020/2021 planning period was 46.2 percent. The cumulative
offset of congestion by ARRs for the 2011/2012 planning period through the2020/2021 planning period, using the rules effective for each planning period,
was 73.7 percent. Load has been underpaid by $2.4 billion from the 2011/2012
planning period through the 2020/2021 planning period.

Overview: Section 12, Planning
Generation Interconnection Planning
Existing Generation Mix• As of June 30, 2021, PJM had a total installed capacity of 196,804.7

MW, of which 49,210.4 MW (25.0 percent) are coal fired steam units,
50,508.7 MW (25.7 percent) are combined cycle units and 33,452.6 MW(17.0 percent) are nuclear units. This measure of installed capacity differsfrom capacity market installed capacity because it includes energy only

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

units, excludes all external units, and uses nameplate values for solar andwind resources.

• Of the 196,804.7 MW of installed capacity, 72,239.7 MW (36.7 percent)are from units older than 40 years, of which 37,799.4 MW (52.3 percent)are coal fired steam units, 191.0 MW (0.3 percent) are combined cycle
units and 17,342.6 MW (24.0 percent) are nuclear units.

Generation Retirements169• There are 51,429.8 MW of generation that have been, or are planned to•be, retired between 2011 and 2024, of which 36,120.2 MW (70.2 percent)are coal fired steam units. Coal unit retirements are primarily a result of
the inability of coal units to compete with efficient combined cycle units
burning low cost natural gas.
In the first six months of 2021, 1,251.4 MW of generation retired. The
largest generators that retired in the first six months of 2021 were the667.0 MW Chalk Point Unit 1 and 2 coal fired steam units located in the
PEPCO Zone. Of the 1,251.4 MW of generation that retired, 667.0 MW(53.3 percent) were located in the PEPCO Zone.

• As of June 30, 2021, there are 10,161.0 MW of generation that haverequested retirement after June 30, 2021, of which 5,280.6 MW (52.0
percent) are located in the COMED Zone. Of the generation requesting
retirement in the COMED Zone, 4,086.5 MW (77.4 percent) are nuclear
units.

Generation Queue170• There were 173,182.4 MW in generation queues, in the status of active,

under construction or suspended, at the end of 2020. In the first six
months of 2021, the AG2 queue window closed and the AH1 queue
window opened. As projects move through the queue process, projects canbe removed from the queue due to incomplete or invalid data, withdrawn
by the market participant or placed in service. On June 30, 2021, there

169 See PJM. Planning. “Generator Deactivations,” (Accessed on June 30, 2021) <http://www.pjm.com/‌planning/services-requests/gendeactivations.aspx>.
170 See PJM. Planning. “New Services Queue,” (Accessed on June 30, 2021) <https://www.pjm.com/‌planning/services-requests/
interconnection-queues.aspx>.

© 2021 Monitoring Analytics, LLC

were 217,381.6 MW in generation queues, in the status of active, underconstruction or suspended, an increase of 44,199.2 MW (25.5 percent)from the end of 2020.171• As of June 30, 2021, 6,483 projects, representing 711,962.4 MW, haveentered the queue process since its inception in 1998. Of those, 985
projects, representing 74,169.9 MW, went into service. Of the projects thatentered the queue process, 3,145 projects, representing 420,410.9 MW(59.0 percent of the MW) withdrew prior to completion. Such projects may
create barriers to entry for projects that would otherwise be completed bytaking up queue positions, increasing interconnection costs and creating
uncertainty.

• As of June 30, 2021, 217,381.6 MW were in generation request queues inthe status of active, under construction or suspended. Based on historicalcompletion rates, 39,081.6 MW (17.9 percent) of new generation in thequeue are expected to go into service.

• The number of queue entries has increased during the past several years,

primarily renewable projects. Of the 3,831 projects entered from January
2015 through June 2021, 2,879 projects (75.2 percent) were renewable. Of
the 641 projects entered in the first six months of 2021, 483 projects (75.4
percent) were renewable. Renewable projects make up 77.4 percent of all
projects in the queue and those projects account for 73.8 percent of thenameplate MW currently active, suspended or under construction in thequeue as of June 30, 2021.
But of the 160,392.1 MW of renewable projects in the queue, only 7,714.3
MW (4.8 percent) of capacity resources are expected to go into service,
based on both historical completion rates and average derate factors forwind and solar.

Regional Transmission Expansion Plan (RTEP)
Market Efficiency Process• There are significant issues with PJM’s benefit/cost analysis that should
be addressed prior to approval of additional projects. PJM’s benefit/cost

171 The queue totals in this report are the winter net MW energy for the interconnection requests (“MW Energy”) as shown in the queue.

2021 Quarterly State of the Market Report for PJM: January through June 67

2021 Quarterly State of the Market Report for PJM: January through June

analysis does not correctly account for the costs of increased congestion
associated with market efficiency projects.

• Through June 30, 2021, PJM has completed four market efficiency cycles
under Order No. 1000.172

PJM MISO Interregional Market Efficiency Process (IMEP)• PJM and MISO developed a process to facilitate the construction ofinterregional projects in response to the Commission’s concerns about
interregional coordination along the PJM-MISO seam. This process,called the Interregional Market Efficiency Process (IMEP), operates on
a two year study schedule and is designed to address forward looking
congestion.

But the use of an inaccurate cost-benefit method by PJM and the correct
method by MISO results in an over allocation of the costs associated withjoint PJM/MISO projects to PJM participants and in some cases approvalof projects that do not pass an accurate cost-benefit test.

PJM MISO Targeted Market Efficiency Process (TMEP)• PJM and MISO developed the Targeted Market Efficiency Process (TMEP)

to facilitate the resolution of historic congestion issues that could be
addressed through small, quick implementation projects.

Supplemental Transmission Projects• Supplemental projects are defined to be “transmission expansions or

enhancements that are not required for compliance with PJM criteria
and are not state public policy projects according to the PJM Operating
Agreement. These projects are used as inputs to RTEP models, but are notrequired for reliability, economic efficiency or operational performance
criteria, as determined by PJM.”173 Supplemental projects are exempt fromthe competitive planning process.

172 See Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, FERC Stats. &Regs. ¶ 31,323 (2011) (Order No. 1000), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132 (2012).
173 See PJM. “Transmission Construction Status,” (Accessed on June 30, 2021) <http://www.pjm.com/‌planning/rtep-upgrades-status/
construct-status.aspx>.

68

Section 1 Introduction• The average number of supplemental projects in each expected in service
year increased by 785.0 percent, from 20 for years 1998 through 2007(pre Order No. 890174) to 177 for years 2008 through 2021 (post Order890).

End of Life Transmission Projects• An end of life transmission project is a project submitted for the purposeof replacing existing infrastructure that is at, or is approaching, the end ofits useful life. End of life transmission projects should be included in the
RTEP process and should be subject to a transparent, robust and clearly
defined mechanism to permit competition to build the project. Under thecurrent approach, end of life projects are excluded from competition.

Board Authorized Transmission Upgrades• The Transmission Expansion Advisory Committee (TEAC) reviews internaland external proposals to improve transmission reliability throughout
PJM. These proposals, which include reliability baseline, network, market
efficiency and targeted market efficiency projects, as well as scopechanges and project cancellations, but exclude supplemental and end oflife projects, are periodically presented to the PJM Board of Managers for
authorization.175 In the first six months of 2021, the PJM Board approved$680.6 million in upgrades. As of June 30, 2021, the PJM Board has
approved $38.5 billion in system enhancements since 1999.

Transmission Competition• The MMU makes several recommendations related to the competitivetransmission planning process. The recommendations include improved
process transparency, incorporation of competition between transmission
and generation alternatives and the removal of barriers to competition
from nonincumbent transmission. These recommendations would help
ensure that the process is an open and transparent process that results inthe most competitive solutions.

174 See Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 118 FERC ¶ 61,119, order on reh’g, OrderNo. 890-A, 121 FERC ¶ 61,297 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126
FERC ¶ 61,228, order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).
175 Supplemental Projects, including the end of life subset of supplemental projects, do not require PJM Board of Managers authorization.

© 2021 Monitoring Analytics, LLC

Section 1 Introduction• On May 24, 2018, the PJM Markets and Reliability Committee (MRC)

approved a motion that required PJM, with input from the MMU, todevelop a comparative framework to evaluate the quality and effectivenessof competitive transmission proposals with binding cost containment
proposals compared to proposals from incumbent and nonincumbent
transmission companies without cost containment provisions.

Qualifying Transmission Upgrades (QTU)• A Qualifying Transmission Upgrade (QTU) is an upgrade to the transmission

system that increases the Capacity Emergency Transfer Limit (CETL) into
an LDA and can be offered into capacity auctions as capacity. Once a
QTU is in service, the upgrade is eligible to continue to offer the approved
incremental import capability into future RPM Auctions. As of June 30,
2021, no QTUs have cleared a Base Residual Auction or an Incremental
Auction.

Transmission Facility Outages• PJM maintains a list of reportable transmission facilities. When the

Section 12 Recommendations
Generation Retirements• The MMU recommends that the question of whether Capacity

Interconnection Rights (CIRs) should persist after the retirement of a unit
be addressed. The rules need to ensure that incumbents cannot exploit
control of CIRs to block or postpone entry of competitors.177 (Priority:
Low. First reported 2013. Status: Partially adopted, 2012.)

Generation Queue• The MMU recommends that barriers to entry be addressed in a timely

manner in order to help ensure that the capacity market will result in theentry of new capacity to meet the needs of PJM market participants andreflect the uncertainty and resultant risks in the cost of new entry used toestablish the capacity market demand curve in RPM. (Priority: Low. First
reported 2012. Status: Not adopted.)• The MMU recommends improvements in queue management includingthat PJM establish a review process to ensure that projects are removed
from the queue if they are not viable, as well as a process to allow
commercially viable projects to advance in the queue ahead of projects
which have failed to make progress, subject to rules to prevent gaming.
(Priority: Medium. First reported 2013. Status: Partially adopted.)reportable transmission facilities need to be taken out of service, PJM
transmission owners are required to report planned transmission facility
outages as early as possible. PJM processes the transmission facility
outage requests according to rules in PJM’s Manual 3 to decide if theoutage is on time or late and whether or not they will allow the outage.176• The MMU recommends continuing analysis of the study phase of PJM’s

2020/2021 planning period. Of the requested outages, 78.0 percent of therequested outages were planned for less than or equal to five days and7.6 percent of requested outages were planned for greater than 30 days.
Of the requested outages, 41.4 percent were late according to the rules in
PJM’s Manual 3.

• The MMU recommends outsourcing interconnection studies to an• There were 20,671 transmission outage requests submitted in the

176 See PJM. “PJM Manual 03: Transmission Operations,” Rev. 59 (May 27, 2021).

© 2021 Monitoring Analytics, LLC

transmission planning to reduce the need for postponements of study
results, to decrease study completion times, and to improve the likelihoodthat a project at a given phase in the study process will successfully
go into service. (Priority: Medium. First reported 2014. Status: Partiallyadopted.)independent party to avoid potential conflicts of interest. Currently,
these studies are performed by incumbent transmission owners under
PJM’s direction. This creates potential conflicts of interest, particularly
when transmission owners are vertically integrated and the owner of

177 See “Comments of the Independent Market Monitor for PJM,” Docket No. ER12-1177-000 (March 12, 2012) <http://www.
monitoringanalytics.com/filings/2012/IMM_Comments_ER12-1177-000_20120312.PDF>.

2021 Quarterly State of the Market Report for PJM: January through June 69

2021 Quarterly State of the Market Report for PJM: January through Junetransmission also owns generation. (Priority: Low. First reported 2013.
Status: Not adopted.)Market Efficiency Process• The MMU recommends that the market efficiency process be eliminatedbecause it is not consistent with a competitive market design. (Priority:
Medium. First reported 2019. Status: Not adopted.)• The MMU recommends that, if the market efficiency process is retained,
PJM modify the rules governing benefit/cost analysis, the evaluation
process for selecting among competing market efficiency projects andcost allocation for economic projects in order to ensure that all costs,
including increased congestion costs and the risk of project cost increases,
in all zones are included in order to ensure that the correct metrics areused for defining benefits. (Priority: Medium. First reported 2018. Status:
Not adopted.)Comparative Cost Framework• The MMU recommends that PJM modify the project proposal templates

to include data necessary to perform a detailed project lifetime financial
analysis. The required data includes, but is not limited to: capital
expenditure; capital structure; return on equity; cost of debt; tax
assumptions; ongoing capital expenditures; ongoing maintenance; andexpected life. (Priority: Medium. First reported 2020. Status: Not adopted.)Transmission Competition• The MMU recommends, to increase the role of competition, that theexemption of supplemental projects from the Order No. 1000 competitive
process be terminated and that the basis for all such exemptions bereviewed and modified to ensure that the supplemental project designation
is not used to exempt transmission projects from a transparent, robust andclearly defined mechanism to permit competition to build such projects orto effectively replace the RTEP process. (Priority: Medium. First reported
2017. Status: Not adopted. Rejected by FERC.) 178

178 The FERC accepted tariff provisions that exclude supplemental projects from competition in the RTEP. 162 FERC ¶ 61,129 (2018), reh’gdenied, 164 FERC ¶ 61,217 (2018).

70

Section 1 Introduction• The MMU recommends, to increase the role of competition, that theexemption of end of life projects from the Order No. 1000 competitive
process be terminated and that end of life transmission projects be
included in the RTEP process and should be subject to a transparent,robust and clearly defined mechanism to permit competition to build
such projects. (Priority: Medium. First reported 2019. Status: Not adopted.
Rejected by FERC.)179• The MMU recommends that PJM enhance the transparency and queue
management process for nonincumbent transmission investment. Issues
related to data access and complete explanations of cost impacts should
be addressed. The goal should be to remove barriers to competition fromnonincumbent transmission providers. (Priority: Medium. First reported
2015. Status: Not adopted.)• The MMU recommends that PJM continue to incorporate the principlethat the goal of transmission planning should be the incorporation oftransmission investment decisions into market driven processes as muchas possible. (Priority: Low. First reported 2001. Status: Not adopted.)• The MMU recommends the creation of a mechanism to permit a directcomparison, or competition, between transmission and generation
alternatives, including which alternative is less costly and who bears therisks associated with each alternative. (Priority: Low. First reported 2013.
Status: Not adopted.)• The MMU recommends that PJM establish fair terms of access to rights of

way and property, such as at substations, in order to remove any barriers toentry and permit competition between incumbent transmission providers
and nonincumbent transmission providers in the RTEP. (Priority: Medium.
First reported 2014. Status: Not adopted.)• The MMU recommends that rules be implemented to permit competition

to provide financing for transmission projects. This competition could
reduce the cost of capital for transmission projects and significantly

179 In recent decisions addressing competing proposals on end of life projects, the Commission accepted a transmission owner proposal
excluding end of life projects from competition in the RTEP process, 172 FERC ¶ 61,136 (2020), reh’g denied, 173 FERC ¶ 61,225 (2020),
and rejected a proposal from PJM stakeholders that would have included end of life projects in competition in the RTEP process, 173
FERC ¶ 61,242 (2020).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction••

reduce total costs to customers. (Priority: Low. First reported 2013. Status:
Not adopted.)
The MMU recommends that rules be implemented to require that project
cost caps on new transmission projects be part of the evaluation ofcompeting projects. (Priority: Medium. First reported 2015. Status:
Adopted 2020.)
The MMU recommends that storage resources not be includable astransmission assets for any reason. (Priority: High. First reported 2020.
Status: Not adopted.)

Cost Allocation• The MMU recommends a comprehensive review of the ways in which thesolution based dfax is implemented. The goal for such a process would beto ensure that the most rational and efficient approach to implementing
the solution based dfax method is used in PJM. Such an approach shouldallocate costs consistent with benefits and appropriately calibrate the
incentives for investment in new transmission capability. No replacement
approach should be approved until all potential alternatives, including
the status quo, are thoroughly reviewed. (Priority: Medium. First reported
2020. Status: Not adopted.)• The MMU recommends consideration of changing the minimum
distribution factor in the allocation from 0.01 to 0.00 and adding athreshold minimum usage impact on the line.180 (Priority: Medium. First
reported 2015. Status: Not adopted.)Transmission Line Ratings• The MMU recommends that all PJM transmission owners use the same

methods to define line ratings, subject to NERC standards and guidelines,
subject to review by NERC and approval by FERC. (Priority: Medium. First
reported 2019. Status: Not adopted.)

180 See the 2015 State of the Market Report for PJM, Volume II, Section 12: Generation and Transmission Planning, at p. 463, Cost
Allocation Issues.

© 2021 Monitoring Analytics, LLC

Transmission Facility Outages• The MMU recommends that PJM reevaluate all transmission outage

tickets as on time or late as if they were new requests when an outage
is rescheduled, and apply the standard rules for late submissions to any
such outages. (Priority: Low. First reported 2014. Status: Not adopted.)• The MMU recommends that PJM draft a clear definition of the congestion

analysis required for transmission outage requests to include in Manual
3 after appropriate review. (Priority: Low. First reported 2015. Status: Not
adopted.)• The MMU recommends that PJM modify the rules to reduce or eliminate
the approval of late outage requests submitted or rescheduled after the
FTR auction bidding opening date. (Priority: Low. First reported 2015.
Status: Not adopted.)• The MMU recommends that PJM not permit transmission owners to divide

long duration outages into smaller segments to avoid complying withthe requirements for long duration outages. (Priority: Low. First reported
2015. Status: Not adopted.)

Section 12 Conclusion
The goal of PJM market design should be to enhance competition and to ensurethat competition is the driver for all the key elements of PJM markets. But
transmission investments have not been fully incorporated into competitivemarkets. The construction of new transmission facilities has significant
impacts on the energy and capacity markets. But when generating units retireor load increases, there is no market mechanism in place that would require
direct competition between transmission and generation to meet loads in theaffected area. In addition, despite FERC Order No. 1000, there is not yet atransparent, robust and clearly defined mechanism to permit competition tobuild transmission projects, to ensure that competitors provide a total project
cost cap, or to obtain least cost financing through the capital markets.
The MMU recognizes that the Commission has recently issued orders that areinconsistent with the recommendations of the MMU and that PJM cannot

2021 Quarterly State of the Market Report for PJM: January through June 71

2021 Quarterly State of the Market Report for PJM: January through June

unilaterally modify those directives. It remains the recommendation of the
MMU that the PJM rules for competitive transmission development throughthe RTEP should build upon FERC Order No. 1000 to create real competition
between incumbent transmission providers and nonincumbent transmission
providers. The ability of transmission owners to block competition for
supplemental projects and end of life projects and reasons for that policy
should be reevaluated. PJM should enhance the transparency and queue
management process for nonincumbent transmission investment. Issues related
to data access and complete explanations of cost impacts should be addressed.
The goal should be to remove barriers to competition from nonincumbent
transmission. Another element of opening competition would be to considertransmission owners’ ownership of property and rights of way at or aroundtransmission substations. In many cases, the land acquired included property
intended to support future expansion of the grid. Incumbents have included
the costs of the property in their rate base, paid for by customers. Because PJM
now has the responsibility for planning the development of the grid under its
RTEP process, property bought to facilitate future expansion should be a partof the RTEP process and be made available to all providers on equal terms.
The process for determining the reasonableness or purpose of supplemental
transmission projects that are asserted to be not needed for reliability,
economic efficiency or operational performance as defined under the RTEP
process needs additional oversight and transparency. If there is a need for a
supplemental project, that need should be clearly defined and there should bea transparent, robust and clearly defined mechanism to permit competition tobuild the project. If there is no defined need for of a supplemental project for
reliability, economic efficiency or operational performance then the project
should not be included in rates.
Managing the generation queues is a highly complex process. The PJM queue
evaluation process has been substantially improved in recent years and it ismore efficient and effective as a result. The PJM queue evaluation process
should continue to be improved to help ensure that barriers to competition for
new generation investments are not created. Issues that need to be addressed
include the ownership rights to CIRs, whether transmission owners should

72

Section 1 Introduction

perform interconnection studies, and improvements in queue management toensure that projects are removed from the queue if they are not viable, as well asa process to allow commercially viable projects to advance in the queue aheadof projects which have failed to make progress. But the behavior of project
developers also creates issues with queue management. When developers
put multiple projects in the queue to maintain their own optionality whileplanning to build only one they also affect all the projects that follow them inthe queue. Project developers may also enter speculative projects in the queue
and then put the project in suspended status while they address financing. The
incentives for such behavior should also be addressed, including appropriate
nonrefundable fees, appropriate credit requirements, appropriate limits on theuse of the suspended option and appropriate milestone requirements.
The addition of a planned transmission project changes the parameters of thecapacity auction for the area, changes the amount of capacity needed in thearea, changes the capacity market supply and demand fundamentals in thearea and may effectively forestall the ability of generation to compete. But
there is no mechanism to permit a direct comparison, let alone competition,
between transmission and generation alternatives. There is no mechanism
to evaluate whether the generation or transmission alternative is less costly,
whether there is more risk associated with the generation or transmission
alternatives, or who bears the risks associated with each alternative. Creatingsuch a mechanism should be an explicit goal of PJM market design.
The current market efficiency process does exactly the opposite by permitting
transmission projects to be approved without competition from generation.
The broader issue is that the market efficiency project approach explicitly
allows transmission projects to compete against future generation projects, but
without allowing the generation projects to compete. Projecting speculativetransmission related benefits for 15 years based on the existing generation
fleet and existing patterns of congestion eliminates the potential for new
generation to respond to market signals. The market efficiency process allows
assets built under the cost of service regulatory paradigm to displace generation
assets built under the competitive market paradigm. In addition, there are
significant issues with PJM’s current benefit/cost analysis which cause it to© 2021 Monitoring Analytics, LLC

Section 1 Introduction

consistently overstate the potential benefits of market efficiency projects. The
MMU recommends that the market efficiency process be eliminated.

Overview: Section 13, FTRs and ARRs

In addition, the use of an inaccurate cost-benefit method by PJM and thecorrect method by MISO results in an over allocation of the costs associatedwith joint PJM/MISO projects to PJM participants and in some cases approvalof projects that do not pass an accurate cost-benefit test.

Market Structure

If it is retained, there are significant issues with PJM’s benefit/cost analysis
that should be addressed prior to approval of additional projects. The current
benefit/cost analysis for a regional project, for example, explicitly andincorrectly ignores the increased congestion in zones that results from an
RTEP project when calculating the energy market benefits. All costs should
be included in all zones and LDAs. The definition of benefits should also be
reevaluated.
The benefit/cost analysis should also account for the fact that the transmission
project costs are not subject to cost caps and may exceed the estimated costs
by a wide margin. When actual costs exceed estimated costs, the cost benefit
analysis is effectively meaningless and low estimated costs may result ininappropriately favoring transmission projects over market generation projects.
The risk of cost increases for transmission projects should be incorporated in
the cost benefit analysis.
There are currently no market incentives for transmission owners to submit
and complete transmission outages in a timely and efficient manner. Requiringtransmission owners to pay does not create an effective incentive whenthose payments are passed through to transmission customers. The process
for the submission of planned transmission outages needs to be carefully
reviewed and redesigned to limit the ability of transmission owners to submit
transmission outages that are late for FTR auction bid submission dates andare late for the day-ahead energy market. The submission of late transmission
outages can inappropriately affect market outcomes when market participants
do not have the ability to modify market bids and offers.

© 2021 Monitoring Analytics, LLC

Auction Revenue Rights• ARR Ownership. In the 2021/2022 planning period ARRs were allocatedto 1,459 individual participants, held by 131 parent companies. ARR
ownership for the 2021/2022 planning period was unconcentrated with
an HHI of 700.

Market Behavior• Self Scheduled FTRs. For the 2021/2022 planning period, 26.1 percent ofeligible ARRs were self scheduled as FTRs.

Market Performance• ARRs as an Offset to Congestion. ARRs have not served as an effective

mechanism to return all congestion revenues to load. For the 2020/2021
planning period, ARRs offset only 46.2 percent of total congestion.
Congestion payments by load in some zones were more than offset andcongestion payments in some zones were less than offset. Load has
been underpaid congestion revenues by $2.4 billion from the 2011/2012
planning period through the 2020/2021 planning period. The cumulative
offset for that period was 73.7 percent of total congestion.

• ARR Payments. For the 2020/2021 planning period, the ARR target

allocations, which are based on the nodal price differences from theAnnual FTR Auction, were $517.1 million, while PJM collected $691.2
million from the combined Long Term, Annual and Monthly Balanceof Planning Period FTR Auctions, making ARRs revenue adequate. For
the 2019/2020 planning period, the ARR target allocations were $752.2
million while PJM collected $982.0 million from the combined Annual
and Monthly Balance of Planning Period FTR Auctions.

• Residual ARRs. Residual ARRs are only available on contract paths

prorated in Stage 1 of the annual ARR allocation, are only effective forsingle, whole months and cannot be self scheduled. Residual ARR clearing
prices are based on monthly FTR auction clearing prices. Residual ARRs
2021 Quarterly State of the Market Report for PJM: January through June 73

2021 Quarterly State of the Market Report for PJM: January through Junewith negative target allocations are not allocated to participants. Instead
they are removed and the model is rerun.
In the 2020/2021 planning period, PJM allocated a total of 25,028.0 MW
of residual ARRs with a total target allocation of $11.7 million, downfrom 27,233.2 MW, with a total target allocation of $12.4 million, in the
2019/2020 planning period.

• ARR Reassignment for Retail Load Switching. There were 29,776 MW of

ARRs associated with $426,700 of revenue that were reassigned in the2020/2021 planning period. There were 31,683 MW of ARRs associatedwith $657,300 of revenue that were reassigned for the same time frameof the 2019/2020 planning period.

Financial Transmission Rights
Market Design• Monthly Balance of Planning Period FTR Auctions. The design of theMonthly Balance of Planning Period FTR Auctions was changed effectivewith the 2020/2021 planning period. The new design includes auctions foreach remaining month in the planning period. The prior design included
auctions for the next three individual months plus remaining quarters.

Market Structure• Patterns of Ownership. For the Monthly Balance of Planning Period

Auctions, financial entities purchased 84.5 percent of prevailing flow
and 91.9 percent of counter flow FTRs for January through June, 2021.
Financial entities owned 78.3 percent of all prevailing and counter flow
FTRs, including 71.7 percent of all prevailing flow FTRs and 85.9 percent
of all counter flow FTRs during the period from January through June
2021. Self scheduled FTRs account for 3.0 percent of all FTRs held.

• Market Concentration. For prevailing flow obligation FTRs in the Monthly

Balance of Planning Period Auctions for the 2020/2021 planning period,
all market periods were unconcentrated. For counter flow obligation
FTRs for the 2020/2021 planning period, two periods were moderately
concentrated and all others were unconcentrated. All periods were highly

74

Section 1 Introduction

concentrated for FTR options. FTR options in the Annual FTR Auction
were moderately concentrated.

Market Behavior• Sell Offers. In a given auction, market participants can sell FTRs acquired

in preceding auctions or preceding rounds of auctions. In the 2021/2024
Long Term FTR Auction, total participant FTR sell offers were 446,464
MW. In the 2021/2022 Annual FTR Auction, total participant FTR selloffers were 466,575 MW. In the Monthly Balance of Planning Period FTR
Auctions for the 2020/2021 planning period, total participant FTR selloffers were 16,226,420 MW.

• Buy Bids. In the 2021/2024 Long Term FTR auction, total FTR buy bids

were 2,743,836 MW, up 23.9 percent from 2,213,927 MW the previous
long term auction. There were 2,070,424 MW of buy and self scheduledbids in the 2021/2022 Annual FTR Auction, down 12.3 percent from
2,361,145 MW the previous planning period. The total FTR buy bids from
the Monthly Balance of Planning Period FTR Auctions for the 2020/2021
planning were 35,023,755 MW.

• FTR Forfeitures. Total FTR forfeitures were $4.6 million for the 2020/2021

planning period. On May 20, 2021, FERC issued an order ruling the $0.01
definition of an increase in the value of an FTR unjust and unreasonable,
but upheld the other parts of PJM’s forfeiture rule, and required PJM tomodify the rule.

• Credit. There were five collateral defaults in 2021. There were five payment

defaults in 2021 not involving GreenHat Energy, LLC for a total of $1.8
million. GreenHat Energy’s default payments ended with the 2020/2021
planning period. GreenHat Energy accrued total accrued payment defaults
of $162.0 million, including the auction liquidation costs.181 In addition,
PJM added the settlement fee and claimant payee funds to the default
allocation, resulting in allocations of $12.5 million and $5.0 million fora total of $179.5 million.

181 S ee the 2019 Quarterly State of the Market Report for PJM: January through June for a more complete explanation of credit issues that
occurred in 2019.

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

Market Performance• Quantity. The 2021/2023 Long Term FTR Auction cleared 426,602 MW(15.5 percent) of FTR buy bids, up 54.8 percent from 275,655 (12.5 percent)in the 2020/2023 Long Term FTR Auction. The Long Term FTR Auction
also cleared 77,230 MW (17.3 percent) of FTR sell offers, compared to49,411 (17.4 percent), a 56.3 percent increase.

• In the 2021/2024 Long Term FTR Auction, 426,602 MW (15.5 percent) of

buy bids cleared and 77,230 MW (17.3 percent) of sell offers cleared. In
the Annual FTR Auction for the 2021/2022 planning period 562,293 MW(27.2 percent) of buy and self schedule bids cleared, down 3.7 percent
from 583,629 (24.7 percent) for the previous planning period. In the2020/2021 planning period, Monthly Balance of Planning Period FTR
Auctions cleared 5,686,087 (16.2 percent) of FTR buy bids and 2,770,301
MW (17.1 percent) of FTR sell offers. For the 2019/2020 planning period,
Monthly Balance of Planning Period FTR Auctions cleared 4,124,903(17.8 percent) of FTR buy bids and 1,995,514 MW (21.3 percent) of FTR
sell offers.

• Price. The weighted average buy bid FTR price in the 2021/2024 Long
Term FTR Auction was $0.05 per MW, down from $0.08 per MW for the
2020/2023 planning period. The weighted average buy bid FTR price in
the Annual FTR Auction for the 2021/2022 planning period was $0.56
per MW, up from $0.45 per MW in the 2020/2021 planning period. The
weighted average buy bid cleared FTR price in the Monthly Balance ofPlanning Period FTR Auctions for all periods of the 2020/2021 planning
period was $0.13 per MWh.

• Revenue. The 2021/2024 Long Term FTR Auction generated $93.9 millionof net revenue for all FTRs, up 153.1 percent from $37.1 million from the2020/2023 Long Term FTR Auction. The 2021/2022 Annual FTR Auction
generated $692.4 million in net revenue, up from $577.0 million for the
2020/2021 Annual FTR Auction. The Monthly Balance of Planning Period
FTR Auctions resulted in net revenue of $41.4 million in the 2020/2021
planning period, down from $52.9 million for the same time period in the
2019/2020 planning period.

© 2021 Monitoring Analytics, LLC• Revenue Adequacy. FTRs were paid at 98.7 percent of the target allocationlevel for the 2020/2021 planning period, including distribution of thecurrent surplus revenue.

• Profitability. FTR profitability is the difference between the revenue

received directly from holding an FTR plus any revenue from the saleof an FTR, and the cost of the FTR. In the 2020/2021 planning period,
physical entities made $79.9 million in profits on FTRs purchased directly(not self scheduled), up from $92.5 million in losses in the 2019/2020
planning period and financial entities made $280.6 million in profits, up
from $21.1 million in losses in the 2019/2020 planning period.

Section 13 Recommendations
Market Design• The MMU recommends that the current ARR/FTR design be replacedwith defined congestion revenue rights (CRRs). A CRR is the right toactual congestion that is paid by physical load at a specific bus, zone oraggregate. (Priority: High. First reported 2015. Status: Not adopted.)

ARR• The MMU recommends that the ARR/FTR design be modified to ensurethat the rights to all congestion revenues are assigned to load. (Priority:
High. First reported 2015. Status: Not adopted.)• The MMU recommends that all historical generation to load paths beeliminated as a basis for assigning ARRs. The MMU recommends thatthe current design be replaced with a design in which the rights to actual
congestion paid are assigned directly to the load that paid that congestion
by node. (Priority: High. First reported 2015. Status: Partially adopted.)• The MMU recommends that, under the current FTR design, the rights to allcongestion revenue be allocated as ARRs prior to sale as FTRs. Reductions
for outages and increased system capability should be reserved for ARRs
rather than sold in the Long Term FTR Auction. (Priority: High. First
reported 2017. Status: Not adopted.)

2021 Quarterly State of the Market Report for PJM: January through June 75

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends that IARRs be eliminated from PJM’s tariff, but• The MMU recommends that the forfeiture amount from the FTR forfeiture

FTR• The MMU recommends that FTR funding be based on total congestion,

Surplus• The MMU recommends that PJM enforce the FTR auction bid limits at the• The MMU recommends that, under the current FTR design, all congestionthat if IARRs are not eliminated, IARRs should be subject to the sameproration rules that apply to all other ARR rights. (Priority: Low. First
reported 2018. Status: Not adopted.)

including day-ahead and balancing congestion. (Priority: High. First
reported 2017. Status: Not adopted.)parent company level starting immediately. (Priority: High. First reported
2020. Status: Adopted 2021.)• The MMU recommends a requirement that the details of all bilateral FTR

transactions be reported to PJM. (Priority: High. First reported 2020.
Status: Not adopted.)• The MMU recommends that PJM continue to evaluate the bilateralindemnification rules and any asymmetries they may create. (Priority:
Low. First reported 2018. Status: Not adopted.)• The MMU recommends that PJM reduce FTR sales on paths withpersistent overallocation of FTRs, including a clear definition of persistentoverallocation and how the reduction will be applied. (Priority: High. First
reported 2013. Status: Partially adopted, 2014/2015 planning period.)• MMU recommends that PJM eliminate generation to generation paths•

and all other paths that do not represent the delivery of power to load.
(Priority: High. First reported 2018. Status: Not adopted.)

The MMU recommends that the Long Term FTR product be eliminated. If
the Long Term FTR product is not eliminated, the Long Term FTR Market
should be modified so that the supply of prevailing flow FTRs in the Long
Term FTR Market is based solely on counter flow offers in the Long Term
FTR Market. (Priority: High. First reported 2017. Status: Not adopted.)• The MMU recommends that PJM improve transmission outage modelingin the FTR auction models, including the use of probabilistic outage
modeling. (Priority: Low. First reported 2013. Status: Not adopted.)

76

Section 1 Introduction

rule be based on the correct hourly cost of an FTR, rather than a simple
daily price divided by 24. (Priority: High. First reported 2018. Status:
Adopted 2019.)• The MMU recommends that all FTR auction revenue be distributed to ARR
holders monthly, regardless of FTR funding levels. (Priority: High. First
reported 2015. Status: Not adopted.)revenue in excess of FTR target allocations be distributed to ARR holders
on a monthly basis. (Priority: High. First reported 2018. Status: Not
adopted.)• The MMU recommends that FTR auction revenues not be used by PJM tobuy counter flow FTRs for the purpose of improving FTR payout ratios.182(Priority: High. First reported 2015. Status: Not adopted.)

FTR Subsidies• The MMU recommends that PJM eliminate portfolio netting to eliminate

cross subsidies among FTR market participants. (Priority: High. First
reported 2012. Status: Not adopted. Rejected by FERC.)• The MMU recommends that PJM eliminate subsidies to counter flow

FTRs by applying the payout ratio to counter flow FTRs in the same way
the payout ratio is applied to prevailing flow FTRs. (Priority: High. First
reported 2012. Status: Not adopted.)• The MMU recommends that PJM eliminate geographic cross subsidies.
(Priority: High. First reported 2013. Status: Not adopted.)• The MMU recommends that PJM examine the mechanism by which selfscheduled FTRs are allocated when load switching among LSEs occurs
throughout the planning period. (Priority: Low. First reported 2011.
Status: Not adopted.)

182 See “PJM Manual 6: Financial Transmission Rights,” Rev. 26 (Jan. 27, 2021).

© 2021 Monitoring Analytics, LLC

Section 1 Introduction

FTR Liquidation•

The MMU recommends that the FTR portfolio of a defaulted member becanceled rather than liquidated or allowed to settle as a default cost on
the membership. (Priority: High. First reported 2018. Status: Not adopted.)

Section 13 Conclusion
Solutions
The annual ARR allocation should be designed to ensure that the rights to allcongestion revenues are assigned to load, without requiring contract path orpoint to point physical or financial transmission rights that are inconsistent
with the network based delivery of power and the actual way congestionis generated in security constrained LMP markets. When there are bindingtransmission constraints and locational price differences, load pays morefor energy than generation is paid to produce that energy. The difference iscongestion. As a result, congestion belongs to load and should be returned
to load.
The current contract path based design should be replaced with a designin which the rights to actual congestion paid are assigned directly to theload that paid that congestion by node. The assigned right is to the actual
difference between load payments, both day-ahead and balancing, andrevenues paid to the generation used to serve that load. The load can retain
the right to the congestion revenues or sell the rights through auctions. The
correct assignment of congestion revenues to load is fully consistent withretaining FTR auctions for the sale by load of their congestion revenue rights.

IssuesIf the original PJM FTR approach had been designed to return congestion
revenues to load without use of the generation to load contract paths, and if
the distortions subsequently introduced into the FTR design not been added,
many of the subsequent issues with the FTR design and complex redesigns
would have been avoided. PJM would not have had to repeatedly intervenein the functioning of the FTR system in an effort to meet the artificial andincorrectly defined goal of revenue adequacy.

© 2021 Monitoring Analytics, LLC

PJM has persistently and subjectively intervened in the FTR market in order toaffect the payments to FTR holders. These interventions are not appropriate.
For example, in the 2014/2015, 2015/2016 and 2016/2017 planning periods,
PJM significantly reduced the allocation of ARR capacity, and FTRs, in orderto guarantee full FTR funding. PJM reduced system capability in the FTR
auction model by including more outages, reducing line limits and including
additional constraints. PJM’s modeling changes resulted in significant
reductions in Stage 1B and Stage 2 ARR allocations, a corresponding reductionin the available quantity of FTRs, a reduction in congestion revenues assigned
to ARRs, and an associated surplus of congestion revenue relative to FTR
target allocations. This also resulted in a significant redistribution of ARRs
among ARR holders based on differences in allocations between Stage 1A andStage 1B ARRs. Starting in the 2017/2018 planning period, with the allocationof balancing congestion and M2M payments to load rather than FTRs, PJM
increased system capability allocated to Stage 1B and Stage 2 ARRs, but
continued to conservatively select outages to manage FTR funding levels.
PJM has intervened aggressively in the FTR market since its inception inorder to meet various subjective objectives including so called revenue
adequacy. PJM should not intervene in the FTR market to subjectively manage
FTR funding. PJM should fix the FTR/ARR design and then should let themarket work to return congestion to load and to let FTR values reflect actual
congestion.
Load should never be required to subsidize payments to FTR holders,regardless of the reason.183 The FERC order of September 15, 2016, introduced
a subsidy to FTR holders at the expense of ARR holders.184 The order requires
PJM to ignore balancing congestion when calculating total congestion dollars
available to fund FTRs. As a result, balancing congestion and M2M payments
are assigned to load, rather than to FTR holders, as of the 2017/2018 planning
period. When combined with the direct assignment of both surplus day-aheadcongestion and surplus FTR auction revenues to FTR holders, the Commission’sorder shifted substantial revenue from load to the holders of FTRs and further
reduced the offset to congestion payments by load. This approach ignores
183 Such subsidies have been suggested repeatedly. See FERC Dockets Nos. EL13-47-000 and EL12-19-000.
184 See 156 FERC ¶ 61,180 (2016), reh’g denied, 156 FERC ¶ 61,093 (2017).

2021 Quarterly State of the Market Report for PJM: January through June 77

2021 Quarterly State of the Market Report for PJM: January through Junethe fact that load pays both day-ahead and balancing congestion, and thatcongestion is defined, in an accounting sense, to equal the sum of day-ahead
and balancing congestion. Eliminating balancing congestion from the FTR
revenue calculation requires load to pay twice for congestion. Load pays total
congestion and pays negative balancing congestion again. The fundamental
reasons that there has been a significant and persistent difference between dayahead and balancing congestion include inadequate transmission modeling in
the FTR auction and the role of UTCs in taking advantage of these modelingdifferences and creating negative balancing congestion. There is no reason to
impose these costs on load.
These changes were made in order to increase the payout to holders of FTRs
who are not loads. Increasing the payout to FTR holders at the expense of
the load is not a supportable market objective. PJM should implement an
FTR design that calculates and assigns congestion rights to load rather thancontinuing to modify the current, fundamentally flawed, design.
Load was made significantly worse off as a result of the changes made to the
FTR/ARR process by PJM based on the FERC order of September 15, 2016.
ARR revenues were significantly reduced for the 2017/2018 FTR Auction,
the first auction under the new rules. ARRs and self scheduled FTRs offset
only 49.5 percent of total congestion costs for the 2017/2018 planning period
rather than the 58.0 percent offset that would have occurred under the priorrules, a difference of $101.4 million.
A subsequent rule change was implemented that modified the allocation of
surplus auction revenue to load. Beginning with the 2018/2019 planning
period, surplus day-ahead congestion and surplus FTR auction revenue areassigned to FTR holders only up total target allocations, and then distributed
to ARR holders.185 ARR holders will only be allocated this surplus after full
funding of FTRs is accomplished. While this rule change increased the level ofcongestion revenues returned to load, the rules do not recognize ARR holders’rights to all congestion revenue. With this rule in effect for the 2020/2021
planning period, ARRs and FTRs offset 46.2 percent of total congestion.
185 163 FERC ¶61,165 (2018).

78

Section 1 Introduction

The complex process related to what is termed the overallocation of Stage 1A
ARRs are entirely an artificial result of reliance on the contract path model in
the assignment of FTRs. For example, there is a reason that transmission is not
built to address the Stage 1A overallocation issue. The Stage 1A overallocation
issue is a fiction based on the use of outdated and irrelevant generation toload contract paths to assign Stage 1A rights that have nothing to do withactual power flows.

Proposed Design
To address the issues with the current contract path based ARR/FTR market
design, the MMU recommends that the current design be replaced with adesign in which the rights to actual congestion paid are assigned directly
to the load that paid that congestion by node. The assigned right would be
the actual difference between load payments, both day-ahead and balancing,and revenues paid to the generation used to serve that load. The load could
retain the right to the network congestion or sell the right through auctions.
The correct assignment of congestion revenues to load is fully consistent
with retaining FTR auctions for the sale by ARR holders of their congestion
revenue rights.
With a network assignment of actual congestion, there would be no crosssubsidies among rights holders and no over or under allocation of rights relative
to actual network market solutions. There would be no revenue shortfalls ascongestion payments equal congestion collected. The risk of default would
be isolated to the buyer and seller of the right, and any default would not besocialized to other right holders. In the case of a defaulting buyer, the rights tothe congestion revenues would revert to the load. There would be no risk of a
network right flipping in value from positive to negative, because congestionis always the positive difference between what load pays for energy, andgeneration is paid for energy as a result of transmission constraints.
The MMU proposal requires the calculation of constraint specific congestion
and the calculation of that specific constraint’s congestion related charges
to each physical load bus downstream of that constraint. Under the MMU
proposal, the constraint specific congestion calculated by hour, from both© 2021 Monitoring Analytics, LLC

Section 1 Introduction

the day-ahead and balancing market would be paid directly to the physicalload as a credit against the associated load serving entity’s (LSE) energy bill.
This right to the congestion is defined as the congestion revenue right (CRR)
that belongs to the physical load at a defined bus, zone or aggregate. The LSE
could choose to sell all or a portion of the CRR through auctions.
A CRR is the right to actual, realized network related congestion that is paidby physical load at a specific bus, zone or aggregate. Under the MMU proposala bus, zone or aggregate specific CRR could be sold as a defined share of theactual congestion. For example, an LSE could sell 50 percent of its congestion
revenue right for the planning period to a third party. The third party buyer
would then be entitled to 50 percent of the congestion that will be credited
to that specific bus, zone or aggregate for the planning period. The remaining
50 percent of the congestion credit for the specified bus, zone or aggregate
would be paid to the LSE along with auction clearing price for the 50 percent
of CRR that was sold to the third party. Depending on actual congestion, an
LSE selling its congestion revenue rights could be better or worse off than if
it retained its rights.
Under the MMU proposal, the LSE would be able to set reservation prices in
the auction for the sale of portions or all of its CRR. Third parties would havean opportunity to bid for the offered portions of the CRR, and the market forthe congestion revenue associated with the specified bus, zone or aggregate
would clear at a price. If the reservation price of an identified portion of theoffered CRR was not met at the clearing price, that portion of the offered CRR
would remain with the load. Auctions could be annual and/or monthly.
Under the MMU proposal, point to point rights (FTRs) could exist as a separate,
self-funded hedging product based on simultaneously feasible prevailing andcounter flows in a PJM managed network based auction. The only supply andthe only source of revenues in the point to point market for prevailing flow
FTRs would be counter flow offers and direct payments for specific rights.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 79

2021 Quarterly State of the Market Report for PJM: January through June

80

Section 1 Introduction© 2021 Monitoring Analytics, LLC

Section 2 Recommendations

Recommendations
In order to perform its role in PJM market design, the MMU evaluates existingand proposed PJM Market Rules and the design of the PJM Markets.1 The MMU
initiates and proposes changes to the design of the markets and the PJM Market
Rules in stakeholder and regulatory proceedings.2 In support of this function,
the MMU engages in discussions with stakeholders, State Commissions, PJM
management, and the PJM Board; participates in PJM stakeholder meetings
and working groups regarding market design matters; publishes proposals,
reports and studies on market design issues; and makes filings with theCommission on market design issues.3 The MMU also recommends changes to
the PJM Market Rules to the staff of the Commission’s Office of Energy Market
Regulation, State Commissions, and the PJM Board.4 The MMU may provide
in its annual, quarterly and other reports “recommendations regarding any
matter within its purview.”5
Priority rankings are relative. The creation of rankings recognizes that there
are limited resources available to address market issues and that problems
must be ranked in order to determine the order in which to address them.
It does not mean that all the problems should not be addressed. Priority
rankings are dynamic and as new issues are identified, priority rankings willchange. The rankings reflect a number of factors including the significanceof the issue for efficient markets, the difficulty of completion and the degree
to which items are already in progress. A low ranking does not necessarilymean that an issue is not important, but could mean that the issue would beeasy to resolve.
There are three priority rankings: High, Medium and Low. High priority
indicates that the recommendation requires action because it addresses
a market design issue that creates significant market inefficiencies and/or long lasting negative market effects. Medium priority indicates that therecommendation addresses a market design issue that creates intermediatemarket inefficiencies and/or near term negative market effects. Low priority
1
2
3
4
5

OATT Attachment M § IV.D.
Id.
Id.
Id.
OATT Attachment M § VI.A.

© 2021 Monitoring Analytics, LLC

indicates that the recommendation addresses a market design issue thatcreates smaller market inefficiencies and/or more limited market effects orthat it could be easily resolved.
The MMU is also tracking PJM’s progress in addressing these recommendations.
The MMU recognizes that part of the process of addressing recommendations
may include discussions in the stakeholder process, FERC decisions and court
decisions and those elements are included in the tracking. The MMU recognizes
that PJM does not have the unilateral authority to implement changes to thetariff but PJM has a significant role in the issues PJM focuses on, in proposedchanges to the PJM manuals, and in the recommendations PJM makes to thestakeholders and to FERC. Each recommendation includes a status. The status
categories are:

• Adopted: PJM has implemented the recommendation made by the MMU.
• Partially adopted: PJM has implemented part of the recommendation
made by the MMU.

• Not adopted: PJM does not plan to implement the recommendation madeby the MMU, or has not yet implemented any part of the recommendation
made by the MMU. Where the subject of the recommendation is pending
stakeholder, FERC, or court action, that status is noted.

New Recommendations
Consistent with its core function to “[e]valuate existing and proposed market
rules, tariff provisions and market design elements and recommend proposed
rule and tariff changes,” the MMU recommends specific enhancements toexisting market rules and implementation of new rules that are required forcompetitive results in PJM markets and for continued improvements in thefunctioning of PJM markets.6
In this 2021 Quarterly State of the Market Report for PJM: January throughJune, the MMU includes two new recommendations.

6 18 CFR § 35.28(g)(3)(ii)(A); see also OATT Attachment M § IV.D.

2021 Quarterly State of the Market Report for PJM: January through June 81

2021 Quarterly State of the Market Report for PJM: January through June

New Recommendation from Section 3, Energy Market• The MMU recommends, if PJM implements extended downward sloping

ORDCs, that PJM calculate the probability of reserves falling below theminimum reserve requirement (MRR) based on ten minute rather than
30 minute forecast error, and on forced outages in the ten minute rather
than the 30 minute look ahead window to model the uncertainty in the
inputs to RT SCED. (Priority: Medium. New recommendation. Status: Not
adopted.)New Recommendation from Section 4, Energy Uplift• The MMU recommends that units not be paid lost opportunity cost

uplift when PJM directs a unit to reduce output based on a transmission
constraint or other reliability issue. There is no lost opportunity because
the unit is required to reduce for the reliability of the unit and the system.
(Priority: High. New recommendation. Status: Not adopted.)

Complete List of Current MMU Recommendations
The recommendations are explained in each section of the report.

Section 3, Energy Market
Market Power• The MMU recommends that the market rules explicitly require thatoffers in the energy market be competitive, where competitive is defined
to be the short run marginal cost of the units. The short run marginal
cost should reflect opportunity cost when and where appropriate. The
MMU recommends that the level of incremental costs includable in costbased offers not exceed the short run marginal cost of the unit. (Priority:
Medium. First reported 2009. Status: Not adopted.)

Fuel Cost Policies• The MMU recommends that PJM require that all fuel cost policies be
algorithmic, verifiable, and systematic, and accurately reflect short82

Section 2 Recommendations

run marginal costs. (Priority: Medium. First reported 2016. Status: Not
adopted.)• The MMU recommends that the tariff be changed to allow units to havefuel cost policies that do not include fuel procurement practices, including
fuel contracts. Fuel procurement practices, including fuel contracts, may
be used as the basis for fuel cost policies but should not be required.
(Priority: Low. First reported 2018. Status: Adopted 2020.)• The MMU recommends that PJM change the fuel cost policy requirement

to apply only to units that will be offered with non-zero cost-based offers.
The PJM market rules should require that the cost-based offers of units
without an approved fuel cost policy be set to zero. (Priority: Low. First
reported 2018. Status: Adopted 2020.)• The MMU recommends that the temporary cost method be removed andthat all units that submit nonzero cost-based offers be required to havean approved fuel cost policy. (Priority: Low. First reported 2020. Status:
Not adopted.)• The MMU recommends that the penalty exemption provision be removed

and that all units that submit nonzero cost-based offers be required tofollow their approved fuel cost policy. (Priority: Medium. First reported
2020. Status: Not adopted.)

Cost-Based Offers• The MMU recommends that Manual 15 (Cost Development Guidelines) be

replaced with a straightforward description of the components of costbased offers based on short run marginal costs and the correct calculationof cost-based offers. (Priority: Medium. First reported 2016. Status: Not
adopted.)• The MMU recommends removal of all use of FERC System of Accounts in
the Cost Development Guidelines. (Priority: Medium. First reported 2016.
Status: Not adopted.)• The MMU recommends the removal of all use of cyclic starting andpeaking factors from the Cost Development Guidelines. (Priority: Medium.
First reported 2016. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Section 2 Recommendations• The MMU recommends the removal of all labor costs from the Cost•

Development Guidelines. (Priority: Medium. First reported 2016. Status:
Not adopted.)
The MMU recommends the removal of all maintenance costs from theCost Development Guidelines. (Priority: Medium. First reported 2019.
Status: Not adopted.)• The MMU recommends that market participants be required to document

the amount and cost of consumables used when operating in order toverify that the total operating cost is consistent with the total quantity
used and the unit characteristics. (Priority: Medium. First reported 2020.
Status: Not adopted.)• The MMU recommends, given that maintenance costs are currently allowedin cost-based offers, that market participants be permitted to include
only variable maintenance costs, linked to verifiable operational eventsand that can be supported by clear and unambiguous documentationof the operational data (e.g. run hours, MWh, MMBtu) that support themaintenance cycle of the equipment being serviced/replaced. (Priority:
Medium. First reported 2020. Status: Not adopted.)• The MMU recommends explicitly accounting for soak costs and changing

the definition of the start heat input for combined cycles to include only
the amount of fuel used from first fire to the first breaker close in the Cost
Development Guidelines. (Priority: Medium. First reported 2016. Status:
Not adopted.)• The MMU recommends the removal of nuclear fuel and nonfuel operations

and maintenance costs that are not short run marginal costs from the Cost
Development Guidelines. (Priority: Medium. First reported 2016. Status:
Not adopted.)• The MMU recommends revising the pumped hydro fuel cost calculation

to include day-ahead and real-time power purchases. (Priority: Low. First
reported 2016. Status: Not adopted.)• The MMU recommends revisions to the calculation of energy market
opportunity costs to incorporate all time based offer parameters and all© 2021 Monitoring Analytics, LLC

limitations that impact the opportunity cost of generating unit output.
(Priority: Medium. First reported 2016. Status: Adopted 2020.)• The MMU recommends removing the catastrophic designation for force

majeure fuel supply limitations in Schedule 2. (Priority: Medium. First
reported 2016. Status: Not adopted.)Market Power: TPS Test and Offer Capping• The MMU recommends that the rules governing the application of the

TPS test be clarified and documented. The TPS test application in the dayahead energy market is not documented. (Priority: High. First reported
2015. Status: Partially adopted.)• The MMU recommends that PJM require every market participant tomake available at least one cost schedule based on the same hourly fueltype(s) and parameters at least as flexible as their offered price schedule.
(Priority: Medium. First reported 2015. Status: Not adopted.)• The MMU recommends, in order to ensure effective market power
mitigation when the TPS test is failed, that markup be constant acrossthe full MWh range of price and cost-based offers. (Priority: High. First
reported 2015. Status: Not adopted.)• The MMU recommends, in order to ensure effective market power

mitigation when the TPS test is failed, that offer capping be applied tounits that fail the TPS test in the real-time market that were not offer
capped at the time of commitment in the day-ahead market or at a priortime in the real-time market. (Priority: High. First reported 2020. Status:
Not adopted.)• The MMU recommends, in order to ensure effective market power
mitigation when the TPS test is failed, and during high load conditions
such as cold and hot weather alerts or more severe emergencies, thatthe operating parameters in the cost-based offer and the price-based
parameter limited schedule (PLS) offer be at least as flexible as theoperating parameters in the available price-based non-PLS offer, and thatthe price-MW pairs in the price-based PLS offer be exactly equal to the2021 Quarterly State of the Market Report for PJM: January through June 83

2021 Quarterly State of the Market Report for PJM: January through June•

price-based non-PLS offer. (Priority: High. First reported 2015. Status:
Not adopted.)
The MMU recommends, in order to ensure effective market power
mitigation, that PJM always enforce parameter limited values bycommitting units only on parameter limited schedules, when the TPS
test is failed or during high load conditions such as cold and hot weather
alerts or more severe emergencies. (Priority: High. First reported 2019.
Status: Not adopted.)• The MMU recommends that PJM retain the $1,000 per MWh offer cap

in the PJM energy market except when cost-based offers exceed $1,000
per MWh, and retain other existing rules that limit incentives to exercise
market power. (Priority: High. First reported 1999. Status: Partiallyadopted, 1999, 2017.)

Capacity Performance Resources• The MMU recommends that capacity performance resources be held to

the OEM operating parameters of the capacity market CONE reference
resource for performance assessment and energy uplift payments and that
this standard be applied to all technologies on a uniform basis. (Priority:
Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that the parameters which determine

nonperformance charges and the amounts of uplift payments shouldreflect the flexibility goals of the capacity performance construct. The
operational parameters used by generation owners to indicate to PJM
operators what a unit is capable of during the operating day should not
determine capacity performance assessment or uplift payments. (Priority:
Medium. First reported 2015. Status: Partially adopted.)• The MMU recommends the elimination of FMU and AU adders. FMU and• The MMU recommends that PJM not include the balancing ratios

Offer Behavior• The MMU recommends that PJM clearly define the business rules that

AU adders no longer serve the purpose for which they were created andinterfere with the efficient operation of PJM markets. (Priority: Medium.
First reported 2012. Status: Partially adopted, 2014.)• The MMU recommends that resources not be allowed to violate the ICAP

must offer requirement. The MMU recommends that PJM enforce the
ICAP must offer requirement by assigning a forced outage to any unitthat is derated in the energy market below its committed ICAP without
an outage that reflects the derate. (Priority: Medium. First reported 2020.
Status: Not adopted.)• The MMU recommends that storage and intermittent resources be subject
to an enforceable ICAP must offer rule that reflects the limitations of theseresources. (Priority: Medium. First reported 2020. Status: Not adopted.)• The MMU recommends that capacity resources not be allowed to offer

any portion of their capacity market obligation as maximum emergency
energy. (Priority: Medium. First reported 2012. Status: Not adopted.)

84

Section 2 Recommendations

calculated for localized Performance Assessment Intervals (PAIs) in thecapacity market default offer cap, and only include those events thattrigger emergencies at a defined zonal or higher level. (Priority: Medium.
First reported 2018. Status: Not adopted.)
apply to the unit specific parameter adjustment process, including PJM’s
implementation of the tariff rules in the PJM manuals to ensure market
sellers know the requirements for their resources. (Priority: Low. First
reported 2018. Status: Not adopted.)• The MMU recommends that PJM update the tariff to clarify that all
generation resources are subject to unit specific parameter limits on
their cost-based offers using the same standard and process as capacity
performance capacity resources. (Priority: Medium. First reported 2018.
Status: Not adopted.)• The MMU recommends that PJM institute rules that would not pay ashare of capacity market revenue to resources that choose to submit realtime values that are less flexible than their unit specific parameter limits
or approved parameter limit exceptions based on tariff defined reasons.
(Priority: Medium. First reported 2018. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Section 2 Recommendations• The MMU recommends that PJM not approve temporary exceptions
that are based on pipeline tariff terms that are not routinely enforced,
and based on inferior transportation service procured by the generator.
(Priority: Medium. First reported 2019. Status: Not adopted.)

Accurate System Modeling• The MMU recommends that PJM approve one RT SCED case for each fiveminute interval to dispatch resources during that interval using a fiveminute ramp time, and that PJM calculate prices using LPC for that fiveminute interval using the same approved RT SCED case. (Priority: High.
First reported 2019. Status: Not adopted.)• The MMU recommends that PJM explicitly state its policy on the use oftransmission penalty factors including: the level of the penalty factors;
the triggers for the use of the penalty factors; the appropriate line ratingsto trigger the use of penalty factors; the allowed duration of the violation;
the use of constraint relaxation logic; and when the transmission penalty
factors will be used to set the shadow price. (Priority: Medium. First
reported 2015. Status: Partially adopted 2020.)• The MMU recommends that PJM routinely review all transmission facility

ratings and any changes to those ratings to ensure that the normal,
emergency and load dump ratings used in modeling the transmission
system are accurate and reflect standard ratings practice. (Priority: Low.
First reported 2013. Status: Partially adopted.)• The MMU recommends that PJM not use closed loop interface or surrogate

constraints to artificially override nodal prices based on fundamental LMP
logic in order to: accommodate rather than resolve the inadequacies of thedemand side resource capacity product; address the inability of the power
flow model to incorporate the need for reactive power; accommodate
rather than resolve the flaws in PJM’s approach to scarcity pricing; orfor any other reason. (Priority: Medium. First reported 2013. Status: Not
adopted.)• The MMU recommends that PJM not use CT price setting logic to modify
transmission line limits to artificially override the nodal prices that are© 2021 Monitoring Analytics, LLC

based on fundamental LMP logic in order to reduce uplift. (Priority:
Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that if PJM believes it appropriate to implement

CT price setting logic, PJM first initiate a stakeholder process to determine
whether such modification is appropriate. PJM should file any proposedchanges with FERC to ensure review. Any such changes should beincorporated in the PJM tariff. (Priority: Medium. First reported 2016.
Status: Partially adopted.)• The MMU recommends that PJM update the outage impact studies,

the reliability analyses used in RPM for capacity deliverability, andthe reliability analyses used in RTEP for transmission upgrades to beconsistent with the more conservative emergency operations (postcontingency load dump limit exceedance analysis) in the energy market
that were implemented in June 2013. (Priority: Low. First reported 2013.
Status: Not adopted.)• The MMU recommends that PJM include in the tariff or appropriate

manual an explanation of the initial creation of hubs, the process formodifying hub definitions and a description of how hub definitions havechanged.7 8 (Priority: Low. First reported 2013. Status: Not adopted.)• The MMU recommends that all buses with a net withdrawal be treated asload for purposes of calculating load and load-weighted LMP, even if the
MW are settled to the generator. The MMU recommends that during hours
when a load bus shows a net injection, the energy injection be treatedas generation, not negative load, for purposes of calculating generationand load-weighted LMP, even if the injection MW are settled to the load
serving entity. (Priority: Low. First reported 2013. Status: Not adopted.)• The MMU recommends that PJM identify and collect data on available
behind the meter generation resources, including nodal location
information and relevant operating parameters. (Priority: Low. First
reported 2013. Status: Partially adopted.)

7 According to minutes from the first meeting of the Energy Market Committee (EMC) on January 28, 1998, the EMC unanimously agreed
to be responsible for approving additions, deletions and changes to the hub definitions to be published and modeled by PJM. Since the
EMC has become the Market Implementation Committee (MIC), the MIC now appears to be responsible for such changes.
8 There is currently no PJM documentation in the tariff or manuals explaining how hubs are created and how their definitions are changed.
The general definition of a hub can be found in the PJM.com Glossary <http://www.pjm.com/Glossary.aspx>.

2021 Quarterly State of the Market Report for PJM: January through June 85

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends that PJM document how LMPs are calculated
when demand response is marginal. (Priority: Low. First reported 2014.
Status: Not adopted.)• The MMU recommends that PJM not allow nuclear generators which do

not respond to prices or which only respond to manual instructions fromthe operator to set the LMPs in the real-time market. (Priority: Low. First
reported 2016. Status: Not adopted.)• The MMU recommends that PJM increase the coordination of outage and••operational restrictions data submitted by market participants via eDART/eGADs and offer data submitted via Markets Gateway. (Priority: Low. First
reported 2017. Status: Not adopted.)
The MMU recommends that PJM model generators’ operating transitions,
including soak time for units with a steam turbine, configurationtransitions for combined cycles, and peak operating modes. (Priority:
Medium. First reported 2019. Status: Not adopted.)
The MMU recommends that PJM clarify, modify and document its process
for dispatching reserves and energy when SCED indicates that supply isless than total demand including forecasted load and reserve requirements.
The modifications should define: a SCED process to economically convert
reserves to energy; a process for the recall of energy from capacity
resources; and the minimum level of synchronized reserves that would
trigger load shedding. (Priority: Medium. First reported 2020. Status: Not
adopted.)• The MMU recommends that PJM stop capping the system marginal pricein RT SCED and instead limit the sum of violated reserve constraint
shadow prices used in LPC to $1,700 per MWh. (Priority: Medium. First
reported Q1, 2021. Status: Not adopted.)• The MMU recommends, if PJM implements extended downward sloping

ORDCs, that PJM calculate the probability of reserves falling below theminimum reserve requirement (MRR) based on ten minute rather than
30 minute forecast error, and on forced outages in the ten minute rather
than the 30 minute look ahead window to model the uncertainty in the86

Section 2 Recommendations

inputs to RT SCED. (Priority: Medium. New recommendation. Status: Not
adopted.)Transparency• The MMU recommends that PJM market rules require the fuel type beidentified for every price and cost schedule and PJM market rules remove
nonspecific fuel types such as other or co-fire other from the list of fueltypes available for market participants to identify the fuel type associatedwith their price and cost schedules. (Priority: Medium. First reported 2015.
Status: Adopted 2019.)• The MMU recommends that PJM allow generators to report fuel typeon an hourly basis in their offer schedules and to designate schedule
availability on an hourly basis. (Priority: Medium. First reported 2015.
Status: Partially adopted.)• The MMU recommends that PJM define clear criteria for operator approvalof RT SCED cases, including shortage cases, that are used to send dispatch
signals to resources, and for pricing, to minimize discretion. (Priority:
High. First reported 2018. Status: Partially adopted.)

Virtual Bids and Offers• The MMU recommends eliminating up to congestion (UTC) bidding at
pricing nodes that aggregate only small sections of transmission zones
with few physical assets. (Priority: Medium. First reported 2020. Status:
Not adopted.)• The MMU recommends eliminating INC, DEC, and UTC bidding at pricing

nodes that allow market participants to profit from modeling issues.
(Priority: Medium. First reported 2020. Status: Not adopted.)

Section 4, Energy Uplift• The MMU recommends that uplift be paid only based on operating
parameters that reflect the flexibility of the benchmark new entrant unit

© 2021 Monitoring Analytics, LLC

Section 2 Recommendations(CONE unit) in the PJM Capacity Market. (Priority: High. First reported
2018. Status: Not adopted.)• The MMU recommends that PJM initiate an analysis of the reasons•

why a significant number of combustion turbines and diesels scheduledin the day-ahead energy market are not called in real time when they
are economic. (Priority: Medium. First Reported 2012. Status: Partiallyadopted, 2019.)
The MMU recommends that PJM develop and implement an accurate
metric to define when a unit is following dispatch to determine eligibility
to receive balancing operating reserve credits and for assessing generator
deviations and that PJM not pay uplift to units not following dispatch.
(Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that PJM designate units whose offers are flagged

for fixed generation in Markets Gateway as not eligible for uplift. Units
that are flagged for fixed generation are not dispatchable. Following
dispatch is an eligibility requirement for uplift compensation. (Priority:
Medium. First reported 2020. Status: Not adopted.)• The MMU recommends eliminating intraday segments from the calculationof uplift payments and returning to calculating the need for uplift basedon the entire 24 hour operating day. (Priority: High. First reported 2018.
Status: Not adopted.)• The MMU recommends the elimination of day-ahead uplift to ensure that
units receive an energy uplift payment based on their real-time output andnot their day-ahead scheduled output. (Priority: Medium. First reported
2013. Status: Not adopted.)• The MMU recommends enhancing the current energy uplift allocation•

rules to reflect the recommended elimination of day-ahead uplift, thetiming of commitment decisions and the commitment reasons. (Priority:
High. First reported 2012. Status: Not adopted.)
The MMU recommends that units not be paid lost opportunity cost
uplift when PJM directs a unit to reduce output based on a transmission
constraint or other reliability issue. There is no lost opportunity because© 2021 Monitoring Analytics, LLC

the unit is required to reduce for the reliability of the unit and the system.
(Priority: High. New recommendation. Status: Not adopted.)• The MMU recommends reincorporating the use of net regulation revenues
as an offset in the calculation of balancing operating reserve credits.
(Priority: Medium. First reported 2009. Status: Not adopted.)• The MMU recommends that self scheduled units not be paid energy uplift

for their startup cost when the units are scheduled by PJM to start before
the self scheduled hours. (Priority: Low. First reported 2013. Status: Not
adopted.)• The MMU recommends three modifications to the energy lost opportunity
cost calculations:— The MMU recommends calculating LOC based on 24 hour daily periods

for combustion turbines and diesels scheduled in the day-aheadenergy market, but not committed in real time. (Priority: Medium. First
reported 2014. Status: Not adopted.)— The MMU recommends that units scheduled in the day-ahead energy

market and not committed in real time should be compensated for
LOC based on their real-time desired and achievable output, not theirscheduled day-ahead output. (Priority: Medium. First reported 2015.
Status: Not adopted.)— The MMU recommends that only flexible fast start units (startup
plus notification times of 10 minutes or less) and units with shortminimum run times (one hour or less) be eligible by default for the
LOC compensation to units scheduled in the day-ahead energy market
and not committed in real time. Other units should be eligible for
LOC compensation only if PJM explicitly cancels their day-ahead
commitment. (Priority: Medium. First reported 2015. Status: Not
adopted.)• The MMU recommends that up to congestion transactions be required to

pay energy uplift charges for both the injection and the withdrawal sidesof the UTC. (Priority: High. First reported 2011. Status: Partially adopted.)

2021 Quarterly State of the Market Report for PJM: January through June 87

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends eliminating the use of internal bilateraltransactions (IBTs) in the calculation of deviations used to allocatebalancing operating reserve charges. (Priority: High. First reported 2013.
Status: Adopted 2018.9)• The MMU recommends allocating the energy uplift payments to units• The MMU recommends that PJM revise the current uplift (operating

reserve) confidentiality rules in order to allow the disclosure of complete
information about the level of uplift (operating reserve charges) by unit
and the detailed reasons for the level of operating reserve credits by unit
in the PJM region. (Priority: High. First reported 2013. Status: Partiallyadopted.10)

scheduled as must run in the day-ahead energy market for reasons otherthan voltage/reactive or black start services as a reliability charge to realtime load, real-time exports and real-time wheels. (Priority: Medium. First
reported 2014. Status: Not adopted. Stakeholder process.)• The MMU recommends that PJM pay uplift based on the offer at the lower

be categorized and allocated as reactive services. Reactive services credits
should be calculated consistent with the balancing operating reserve
credit calculation. (Priority: Medium. First reported 2012. Status: Not
adopted. Stakeholder process.)resources (CTs and diesels) from the requirement to follow dispatch.
The performance of these resources should be evaluated in a mannerconsistent with all other resources (Priority: Medium. First reported 2018.
Status: Not adopted.)of the actual unit output or the dispatch signal MW. (Priority: Medium.
First reported 2018. Status: Not adopted.)• The MMU recommends that the total cost of providing reactive support• The MMU recommends that PJM eliminate the exemption for fast start• The MMU recommends including real-time exports and real-time wheels

Section 5, Capacity Market

in the allocation of the cost of providing reactive support to the 500
kV system or above, in addition to real-time load. (Priority: Low. First
reported 2013. Status: Not adopted.)Definition of Capacity• The MMU recommends modifications to the calculation of lost opportunity• The MMU recommends the enforcement of a consistent definition of• The MMU recommends that PJM clearly identify and classify all reasons• The MMU recommends that DR providers be required to have a signed

costs credits paid to wind units. The lost opportunity costs credits paid
to wind units should be based on the lesser of the desired output, theestimated output based on actual wind conditions and the capacity
interconnection rights (CIRs). The MMU recommends that PJM allow
wind units to request CIRs that reflect the maximum output wind units
want to inject into the transmission system at any time. (Priority: Low.
First reported 2012. Status: Not adopted.)for incurring uplift in the day-ahead and the real-time energy markets
and the associated uplift charges in order to make all market participants
aware of the reasons for these costs and to help ensure a long term solution
to the issue of how to allocate the costs of uplift. (Priority: Medium. First
reported 2011. Status: Partially adopted.)

9 As of November 1, 2018, internal bilateral transactions are no longer used for the calculation of deviations for purposes of allocatingbalancing operating reserve charges. See the 2018 State of the Market Report for PJM, Volume II, Section 3: “Energy Market” at “Internal
Bilateral Transactions” for an analysis of the impact of this change on virtual bidding activity.

88

Section 2 Recommendations

capacity resource. The MMU recommends that the requirement to be aphysical resource be enforced and enhanced. The requirement to be aphysical resource should apply at the time of auctions and should also
constitute a commitment to be physical in the relevant delivery year. The
requirement to be a physical resource should be applied to all resource
types, including planned generation, demand resources and imports.11 12(Priority: High. First reported 2013. Status: Not adopted.)
contract with specific customers for specific facilities for specific levels of
DR at least six months prior to any capacity auction in which the DR isoffered. (Priority: High. First reported 2016. Status: Not adopted.)

10 On September 7, 2018, PJM made a compliance filing for FERC Order No. 844 to publish unit specific uplift credits. The compliance filing
was accepted by FERC on March 21, 2019. 166 FERC ¶ 61,210. PJM began posting unit specific uplift reports on May 1, 2019. 167 FERC ¶61,280 (2019).
11 See also Comments of the Independent Market Monitor for PJM, Docket No. ER14-503-000 (December 20, 2013).
12 See “Analysis of Replacement Capacity for RPM Commitments: June 1, 2007 to June 1, 2019,” <http://www.monitoringanalytics.com/
reports/Reports/2019/IMM_Analysis_of_Replacement_Capacity_for_RPM_Commitments_June_1_2007_to_June_1_2019_20190913.
pdf> (September 13, 2019).

© 2021 Monitoring Analytics, LLC

Section 2 Recommendations

Market Design and Parameters• The MMU recommends that the test for determining modeled Locational

Deliverability Areas (LDAs) in RPM be redefined. A detailed reliability
analysis of all at risk units should be included in the redefined model.
(Priority: Medium. First reported 2013. Status: Not adopted.)• The MMU recommends that the net revenue calculation used by PJM

to calculate the net Cost of New Entry (CONE) VRR parameter reflect
the actual flexibility of units in responding to price signals rather thanusing assumed fixed operating blocks that are not a result of actual unit
limitations.13 14 The result of reflecting the actual flexibility is higher
net revenues, which affect the parameters of the RPM demand curveand market outcomes. (Priority: High. First reported 2013. Status: Not
adopted.)• The MMU recommends that energy efficiency resources (EE) not be

included on the supply side of the capacity market, because PJM’s load
forecasts now account for future EE, unlike the situation when EE wasfirst added to the capacity market. However, the MMU recommends that
the PJM load forecast method should be modified so that EE impacts
immediately affect the forecast without the long lag times incorporated
in the current forecast method. If EE is not included on the supply side,
there is no reason to have an add back mechanism. If EE remains on the
supply side, the implementation of the EE add back mechanism should be
modified to ensure that market clearing prices are not affected. (Priority:
Medium. First reported 2016. Status: Not adopted.)• The MMU recommends that PJM reduce the number of incremental

auctions to a single incremental auction held three months prior to
the start of the delivery year and reevaluate the triggers for holding
conditional incremental auctions. (Priority: Medium. First reported 2013.
Status: Not adopted.)• The MMU recommends that PJM offer to sell back capacity in incremental

auctions only at the BRA clearing price for the relevant delivery year.
(Priority: Medium. First reported 2017. Status: Not adopted.)

13 See PJM Interconnection, L.L.C., Docket No. ER12-513-000 (December 1, 2011) (“Triennial Review”).
14 See the 2019 State of the Market Report for PJM, Volume 2, Section 7: Net Revenue.

© 2021 Monitoring Analytics, LLC• The MMU recommends changing the RPM solution method to explicitly
incorporate the cost of make whole payments in the objective function.
(Priority: Medium. First reported 2014. Status: Not adopted.)• The MMU recommends that PJM clear the capacity market based on nodal

capacity resource locations and the characteristics of the transmission
system consistent with the actual electrical facts of the grid. The current
nested LDA structure used in the capacity market does not adequately
represent all the capacity transfers that are feasible among LDAs. Absent
a fully nodal capacity market clearing process, the MMU recommends that
PJM use a nonnested model for all LDAs and specify a VRR curve for each
LDA separately. Each LDA requirement should be met with the capacity
resources located within the LDA and exchanges from neighboring
LDAs up to the transmission limit. LDAs should price separate if thatis the result of the LDA supply curves and the transmission constraints.
(Priority: Medium. First reported 2017. Status: Not adopted.)• The MMU recommends that the maximum price on the VRR curve bedefined as net CONE. (Priority: Medium. First reported 2019. Status: Not
adopted.)• The MMU recommends that the Fixed Resource Requirement (FRR) rules,

including obligations and performance requirements, be revised andupdated to ensure that the rules reflect current market realities and that
FRR entities do not unfairly take advantage of those customers paying
for capacity in the PJM capacity market. (Priority: Medium. First reported
2019. Status: Not adopted.)Offer Caps, Offer Floors, and Must Offer• The MMU recommends use of the Sustainable Market Rule (SMR) in orderto protect competition in the capacity market from nonmarket revenues.15(Priority: High. First reported 2016. Status: Not adopted.)• The MMU recommends that, as part of the MOPR unit specific standardof review, all projects be required to use the same basic modelingassumptions. That is the only way to ensure that projects compete on the

15 Brief of the Independent Market Monitor for PJM, Docket No. EL16-49, ER18-1314-000,-001; EL18-178 (October 2, 2018).

2021 Quarterly State of the Market Report for PJM: January through June 89

2021 Quarterly State of the Market Report for PJM: January through June

basis of actual costs rather than on the basis of modeling assumptions.16(Priority: High. First reported 2013. Status: Not adopted.)• The MMU recommends that modifications to existing resources not betreated as new resources for purposes of market power related offer caps
or MOPR offer floors. (Priority: Low. First reported 2012. Status: Not
adopted.)• The MMU recommends that the RPM market power mitigation rule be••modified to apply offer caps in all cases when the three pivotal supplier
test is failed and the sell offer is greater than the offer cap. This will
ensure that market power does not result in an increase in make whole
payments. (Priority: Medium. First reported 2017. Status: Not adopted.)
The MMU recommends that the offer cap for capacity resources be definedas the net avoidable cost rate (ACR) of each unit so that the clearing
prices are a result of such net ACR offers, consistent with the fundamental
economic logic for a competitive offer of a CP resource. (Priority: High.
First reported 2017. Status: Not adopted.)
The MMU recommends that PJM develop a process for calculating
a forward looking estimate for the expected number of Performance
Assessment Intervals (H) to use in calculating the Market Seller Offer Cap(MSOC). The MMU recommends that the Nonperformance Charge Ratebe left at its current level. The MMU recommends that PJM develop a
forward looking estimate for the Balancing Ratio (B) during Performance
Assessment Intervals (PAIs) to use in calculating the MSOC. Both H
and B parameters should be included in the annual review of planningparameters for the Base Residual Auction, and should incorporate theactual observed reserve margins, and other assumptions consistent withthe annual IRM study. (Priority: High. First reported 2017. Status: Not
adopted.)16 See 143 FERC ¶ 61,090 (2013) (“We encourage PJM and its stakeholders to consider, for example, whether the unit-specific review
process would be more effective if PJM requires the use of common modeling assumptions for establishing unit-specific offer floors
while, at the same time, allowing sellers to provide support for objective, individual cost advantages. Moreover, we encourage PJM and its
stakeholders to consider these modifications to the unit-specific review process together with possible enhancements to the calculationof Net CONE.”); see also, Comments of the Independent Market Monitor for PJM, Docket No. ER13-535-001 (March 25, 2013); Complaintof the Independent Market Monitor for PJM v. Unnamed Participant, Docket No. EL12-63-000 (May 1, 2012); Motion for Clarificationof the Independent Market Monitor for PJM, Docket No. ER11-2875-000, et al. (February 17, 2012); Protest of the Independent Market
Monitor for PJM, Docket No. ER11-2875-002 (June 2, 2011); Comments of the Independent Market Monitor for PJM, Docket Nos. EL11-20
and ER11-2875 (March 4, 2011).

90

Section 2 Recommendations• The MMU recommends that capacity market sellers be required to request

the use of minimum MW quantities greater than 0 MW (inflexible selloffer segments) and that the requests should only be permitted for defined
physical reasons. (Priority: Medium. First reported 2018. Status: Not
adopted.)• The MMU recommends that PJM update the values in the CRF table in thetariff when the components change. (Priority: High. First reported 2020.
Status: Not adopted.)

Performance Incentive Requirements of RPM• The MMU recommends that any unit which is not capable of supplying

energy consistent with its day-ahead offer which should equal its ICAP,
reflect an appropriate outage. (Priority: Medium. First reported 2009.
Status: Not adopted.)• The MMU recommends that retroactive replacement transactions

associated with a failure to perform during a PAI not be allowed andthat, more generally, retroactive replacement capacity transactions not be
permitted. (Priority: Medium. First reported 2016. Status: Not adopted.)• The MMU recommends that there be an explicit requirement that capacity
resource offers in the day-ahead energy market be competitive, wherecompetitive is defined to be the short run marginal cost of the units.
(Priority: Low. First reported 2013. Status: Not adopted.)• The MMU recommends that Capacity Performance resources be required
to perform without excuses. Resources that do not perform should not be
paid regardless of the reason for nonperformance. (Priority: High. First
reported 2019. Status: Not adopted.)• The MMU recommends that the market data posting rules be modified

to allow the disclosure of expected performance, actual performance,
shortfall and bonus MW during a PAI by area without the requirementthat more than three market participants’ data be aggregated for posting.
(Priority: Low. First reported 2019. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Section 2 Recommendations

Capacity Imports and Exports• The MMU recommends that all capacity imports be required to bedeliverable to PJM load prior to the relevant delivery year to ensure thatthey are full substitutes for internal, physical capacity resources. Pseudoties alone are not adequate to ensure deliverability. (Priority: High. First
reported 2016. Status: Not adopted.)• The MMU recommends that all costs incurred as a result of a pseudo tiedunit be borne by the unit itself and included as appropriate in unit offers
in the capacity market. (Priority: High. First reported 2016. Status: Not
adopted.)• The MMU recommends clear, explicit and detailed rules that define theconditions under which PJM will and will not recall energy from PJM
capacity resources and prohibit new energy exports from PJM capacity
resources. The MMU recommends that those rules define the conditions
under which PJM will purchase emergency energy while at the sametime not recalling energy exports from PJM capacity resources. PJM
has modified these rules, but the rules need additional clarification andoperational details. (Priority: Low. First reported 2010. Status: Partiallyadopted.)

Deactivations/Retirements• The MMU recommends that the notification requirement for deactivations

be extended from 90 days prior to the date of deactivation to 12 months
prior to the date of deactivation and that PJM and the MMU be provided
60 days rather than 30 days to complete their reliability and market
power analyses. (Priority: Low. First reported 2012. Status: Not adopted.)• The MMU recommends that RMR units recover all and only theincremental costs, including incremental investment costs, required by
the RMR service that the unit owner would not have incurred if the unit
owner had deactivated its unit as it proposed. Customers should bear no
responsibility for paying previously incurred costs, including a return on
or of prior investments. (Priority: Low. First reported 2010. Status: Not
adopted.)© 2021 Monitoring Analytics, LLC• The MMU recommends elimination of the cost of service recovery rate in
OATT Section 119, and that RMR service should be provided under thedeactivation avoidable cost rate in Part V. The MMU also recommends
specific improvements to the DACR provisions. (Priority: Medium. First
reported 2017. Status: Not adopted.)

Section 6, Demand Response• The MMU recommends, as a preferred alternative to including demand

resources as supply in the capacity market, that demand resources be on
the demand side of the markets, that customers be able to avoid capacityand energy charges by not using capacity and energy at their discretion,that customer payments be determined only by metered load, and thatPJM forecasts immediately incorporate the impacts of demand side
behavior. (Priority: High. First reported 2014. Status: Not adopted.)• The MMU recommends that the option to specify a minimum dispatch price(strike price) for demand resources be eliminated and that participating
resources receive the hourly real-time LMP less any generation componentof their retail rate. (Priority: Medium. First reported 2010. Status: Not
adopted.)• The MMU recommends that the maximum offer for demand resources

be the same as the maximum offer for generation resources. (Priority:
Medium. First reported 2013. Status: Not adopted.)• The MMU recommends that the demand resources be treated as economic

resources, responding to economic price signals like other capacity
resources. The MMU recommends that demand resources not be treatedas emergency resources, not trigger a PJM emergency and not trigger
a Performance Assessment Interval. (Priority: High. First reported 2012.
Status: Not adopted.)• The MMU recommends that the Emergency Program Energy Only option

be eliminated because the opportunity to receive the appropriate energy
market incentive is already provided in the economic program. (Priority:
Low. First reported 2010. Status: Not adopted.)

2021 Quarterly State of the Market Report for PJM: January through June 91

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends that, if demand resources remain in the capacity

market, a daily energy market must offer requirement apply to demand
resources, comparable to the rule applicable to generation capacity
resources.17 (Priority: High. First reported 2013. Status: Not adopted.)• The MMU recommends that demand resources be required to provide••

their nodal location, comparable to generation resources. (Priority: High.
First reported 2011. Status: Not adopted.)
The MMU recommends that PJM require nodal dispatch of demand
resources with no advance notice required or, if nodal location is not
required, subzonal dispatch of demand resources with no advance noticerequired. (Priority: High. First reported 2015. Status: Not adopted.)
The MMU recommends that PJM not remove any defined subzones andmaintain a public record of all created and removed subzones. (Priority:
Low. First reported 2016. Status: Not adopted.)• The MMU recommends that PJM eliminate the measurement of•compliance across zones within a compliance aggregation area (CAA).
The multiple zone approach is less locational than the zonal and subzonal
approach and creates larger mismatches between the locational need forthe resources and the actual response. (Priority: High. First reported 2015.
Status: Not adopted.)
The MMU recommends that measurement and verification methods fordemand resources be modified to reflect compliance more accurately.
(Priority: Medium. First reported 2009. Status: Not adopted.)• The MMU recommends that compliance rules be revised to include

submittal of all necessary hourly load data, and that negative values
be included when calculating event compliance across hours andregistrations. (Priority: Medium. First reported 2012. Status: Not adopted.)• The MMU recommends that PJM adopt the ISO-NE five-minute metering

requirements in order to ensure that operators have the necessary
information for reliability and that market payments to demand resources

17 See “Complaint and Motion to Consolidate of the Independent Market Monitor for PJM,” Docket No. EL14-20-000 (January 27, 2014) at 1.

92

Section 2 Recommendations

be calculated based on interval meter data at the site of the demand
reductions.18 (Priority: Medium. First reported 2013. Status: Not adopted.)• The MMU recommends demand response event compliance be calculated

on a five minute basis for all capacity performance resources and that thepenalty structure reflect five minute compliance. (Priority: Medium. First
reported 2013. Status: Partially adopted.)• The MMU recommends that load management testing be initiated by PJM

with limited warning to CSPs in order to more accurately represent theconditions of an emergency event. (Priority: Low. First reported 2012.
Status: Not adopted.)• The MMU recommends that shutdown cost be defined as the cost to curtailload for a given period that does not vary with the measured reduction or,
for behind the meter generators, be the start cost defined in Manual 15
for generators. (Priority: Low. First reported 2012. Status: Not adopted.)• The MMU recommends that the Net Benefits Test be eliminated and thatdemand response resources be paid LMP less any generation componentof the applicable retail rate. (Priority: Low. First reported 2015. Status:
Not adopted.)• The MMU recommends that the tariff rules for demand response clarify

that a resource and its CSP, if any, must notify PJM of material changes
affecting the capability of the resource to perform as registered and mustterminate or modify registrations that are no longer capable of responding
to PJM dispatch directives at defined levels because load has been reduced
or eliminated, as in the case of bankrupt and/or out of service facilities.
(Priority: Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that there be only one demand response productin the capacity market, with an obligation to respond when called forany hour of the delivery year. (Priority: High. First reported 2011. Status:
Partially adopted.19)

18 See ISO-NE Tariff, Section III, Market Rule 1, Appendix E1 and Appendix E2, “Demand Response,” <http://www.iso-ne.com/regulatory/
tariff/sect_3/mr1_append-e.pdf>. (Accessed October 17, 2017) ISO-NE requires that DR have an interval meter with five-minute datareported to the ISO and each behind the meter generator is required to have a separate interval meter. After June 1, 2017, demand
response resources in ISO-NE must also be registered at a single node.
19 PJM’s Capacity Performance design requires resources to respond when called for any hour of the delivery year, but demand resources
still have a limited mandatory compliance window.

© 2021 Monitoring Analytics, LLC

Section 2 Recommendations• The MMU recommends that the lead times for demand resources be•

shortened to 30 minutes with an hour minimum dispatch for all resources.
(Priority: Medium. First reported 2013. Status: Partially adopted.)

The MMU recommends setting the baseline for measuring capacity
compliance under winter compliance at the customers’ PLC, similar
to GLD, to avoid double counting. (Priority: High. First reported 2010.
Status: Partially adopted.)• The MMU recommends the Relative Root Mean Squared Test be required
for all demand resources with a CBL. (Priority: Low. First reported 2017.
Status: Partially adopted.)• The MMU recommends that PRD be required to respond during a PAI to
be consistent with all CP resources. (Priority: High. First reported 2017.
Status: Not adopted.)• The MMU recommends that the limits imposed on the pre-emergency andemergency demand response share of the synchronized reserve market beeliminated. (Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that 30 minute pre-emergency and emergency
demand response be considered to be 30 minute reserves. (Priority:
Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that energy efficiency MW not be included in the

PJM Capacity Market and that PJM should ensure that the impact of EE
measures on the load forecast is incorporated immediately rather thanwith the existing lag. (Priority: Medium. First reported 2018. Status: Not
adopted.)• The MMU recommends that demand reductions based entirely on behindthe meter generation be capped at the lower of economic maximum or
actual generation output. (Priority: High. First reported 2019. Status: Not
adopted.)• The MMU recommends that all demand resources register as PreEmergency Load Response and that the Emergency Load Response
Program be eliminated. (Priority: High. First reported Q1 2020. Status:
Not adopted.)© 2021 Monitoring Analytics, LLC

Section 7, Net Revenue• The MMU recommends that the net revenue calculation used by PJM tocalculate the net Cost of New Entry (CONE) and net ACR be based on a
forward looking estimate of expected energy and ancillary services net
revenues using forward prices for energy and fuel. (Priority: Medium.
First reported 2019. Status: Adopted 2020.)

Section 8, Environmental and Renewables• The MMU recommends that renewable energy credit markets based onstate renewable portfolio standards be brought into PJM markets as they
are an increasingly important component of the wholesale energy market.
(Priority: Medium. First reported 2010. Status: Not adopted.)• The MMU recommends that the Commission reconsider its disclaimer
of jurisdiction over RECs markets because, given market changes sincethat decision, it is clear that RECs materially affect jurisdictional rates.
(Priority: High. First reported 2018. Status: Not adopted.)• The MMU recommends that PJM provide a full analysis of the impact

of carbon pricing on PJM generating units and carbon pricing revenues
to the PJM states in order to permit the states to consider a potential
agreement on the development of a multistate framework for carbon
pricing and the distribution of carbon revenues. (Priority: High. First
reported 2018. Status: Not adopted.)• The MMU recommends that jurisdictions with a renewable portfolio
standard make the price and quantity data on supply and demand moretransparent. (Priority: Low. First reported 2018. Status: Not adopted.)• The MMU recommends that load and generation located at separate

nodes be treated as separate resources in order to ensure that load andgeneration face consistent incentives throughout the markets. (Priority:
High. First reported 2019. Status: Not adopted.)• The MMU recommends that emergency stationary RICE be prohibitedfrom participation as DR either when registered individually or as part ofa portfolio if it cannot meet the capacity market requirements to be DR

2021 Quarterly State of the Market Report for PJM: January through June 93

2021 Quarterly State of the Market Report for PJM: January through June

as a result of emissions standards that impose environmental run hour
limitations. (Priority: Medium. First reported 2019. Status: Not adopted.)

Section 9, Interchange Transactions• The MMU recommends that PJM implement rules to prevent shamscheduling. The MMU recommends that PJM apply after the fact market
settlement adjustments to identified sham scheduling segments to ensurethat market participants cannot benefit from sham scheduling. (Priority:
High. First reported 2012. Status: Not adopted.)• The MMU recommends that PJM implement a validation method for• The MMU recommends that PJM eliminate the IMO interface pricing point,

and assign the transactions that originate or sink in the IESO balancing
authority to the MISO interface pricing point. (Priority: Medium. First
reported 2013. Status: Not adopted.)• The MMU recommends that PJM monitor, and adjust as necessary, theweights applied to the components of the interfaces to ensure that theinterface prices reflect ongoing changes in system conditions. The MMU
also recommends that PJM review the mappings of external balancing
authorities to individual interface pricing points to reflect changes to theimpact of the external power source on PJM tie lines as a result of system
topology changes. The MMU recommends that this review occur at least
annually. (Priority: Low. First reported 2009. Status: Not adopted.)

submitted transactions that would prohibit market participants frombreaking transactions into smaller segments to defeat the interface pricing
rule by concealing the true source or sink of the transaction. (Priority:
Medium. First reported 2013. Status: Not adopted.)• The MMU recommends that, in order to permit a complete analysis ofsubmitted transactions that would require market participants to submit
transactions on paths that reflect the expected actual power flow in orderto reduce unscheduled loop flows. (Priority: Medium. First reported 2013.
Status: Not adopted.)• The MMU recommends that PJM explore an interchange optimization• The MMU recommends that PJM implement a validation method for• The MMU recommends that PJM end the practice of maintaining outdated

definitions of interface pricing points, eliminate the NIPSCO, Southeast
and Southwest interface pricing points from the day-ahead and real-timeenergy markets and, with VACAR, assign the transactions created under
the reserve sharing agreement to the SOUTH interface pricing point.
(Priority: High. First reported 2013. Status: Partially adopted, Q2 2020.)20• The MMU recommends that transactions sourcing in the Western

loop flow, FERC and NERC ensure that the identified data are madeavailable to market monitors as well as other industry entities determined
appropriate by FERC. (Priority: Medium. First reported 2003. Status: Not
adopted.)solution with its neighboring balancing authorities that would remove
the need for market participants to schedule physical transactions across
seams. Such a solution would include an optimized, but limited, joint
dispatch approach that uses supply curves and treats seams between
balancing authorities as constraints, similar to other constraints within an
LMP market. (Priority: Medium. First reported 2014. Status: Not adopted.)• The MMU recommends that PJM permit unlimited spot market imports aswell as unlimited nonfirm point to point willing to pay congestion imports
and exports at all PJM interfaces in order to improve the efficiency of themarket. (Priority: Medium. First reported 2012. Status: Not adopted.)

Interconnection be priced at either the MISO interface pricing point or
the SOUTH interface pricing point based on the locational price impact
of flows between the DC tie line point of connection with the EasternInterconnection and PJM. (Priority: High. First reported Q1, 2020. Status:
Not adopted.)• The MMU recommends that the emergency interchange cap be replaced

20 The grandfathered agreements associated with the Southwest interface pricing point expired in 2012. The Southwest interface pricing
point is no longer an eligible pricing point in the day-ahead or real-time energy markets. Effective June 1, 2020, PJM retired the NIPSCO
interface pricing point.

dispatchable transactions be modified from 1800 on the day prior, to94

Section 2 Recommendations

with a market based solution. (Priority: Low. First reported 2015. Status:
Not adopted.)• The MMU recommends that the submission deadline for real-time© 2021 Monitoring Analytics, LLC

Section 2 Recommendations

three hours prior to the requested start time, and that the minimum
duration be modified from one hour to 15 minutes. These changes would
give PJM a more flexible product that could be used to meet load in themost economic manner. (Priority: Medium. First reported 2014. Status:
Partially adopted, 2015.)• The MMU recommends modifications to the FFE calculation to ensurethat FFE calculations reflect the current capability of the transmission
system as it evolves. The MMU recommends that the Commission set a
deadline for PJM and MISO to resolve the FFE freeze date and related
issues. (Priority: Medium. First reported 2019. Status: Not adopted.)

Section 10, Ancillary Services

scheduled to run in the energy market. (Priority: High. First reported 2010.
Status: Not adopted.22 FERC rejected.23)• The MMU recommends that the lost opportunity cost calculation usedin the regulation market be based on the resource’s dispatched energy
offer schedule, not the lower of its price or cost offer schedule. (Priority:
Medium. First reported 2010. Status: Not adopted. FERC rejected.24)• The MMU recommends that, to prevent gaming, there be a penalty

enforced in the regulation market as a reduction in performance score
and/or a forfeiture of revenues when resource owners elect to deassign
assigned regulation resources within the hour. (Priority: Medium. First
reported 2016. Status: Not adopted. FERC rejected.25)• The MMU recommends that all data necessary to perform the regulation• The MMU recommends enhanced documentation of the implementation• The MMU recommends that the total regulation (TReg) signal sent on a

• The MMU recommends that PJM be required to save data elements

market three pivotal supplier test be saved by PJM so that the test can be
replicated. (Priority: Medium. First reported 2016. Status: Not adopted.)of the regulation market design. (Priority: Medium. First reported 2010.
Status: Not adopted. FERC rejected.26)
necessary for verifying the performance of the regulation market.
(Priority: Medium. First reported 2010. Status: Not adopted.)

fleet wide basis be eliminated and replaced with individual regulation
signals for each unit. (Priority: Low. First reported 2019. Status: Not
adopted.)• The MMU recommends that the $12.00 margin adder be eliminated fromas both a RegA and a RegD resource in the same market hour) be removed
from the regulation market. (Priority: High. First reported 2019. Status:
Not adopted.)• The MMU recommends that PJM replace the static MidAtlantic/Dominion• The MMU recommends that the ability to make dual offers (to make offers• The MMU recommends that the regulation market be modified toincorporate a consistent application of the marginal benefit factor (MBF)
throughout the optimization, assignment and settlement process. The
MBF should be defined as the Marginal Rate of Technical Substitution(MRTS) between RegA and RegD. (Priority: High. First reported 2012.
Status: Not adopted. FERC rejected.21)• The MMU recommends that the lost opportunity cost in the ancillary
services markets be calculated using the schedule on which the unit was

21 162 FERC ¶ 61,295 (2018), reh’g denied, 170 FERC ¶ 61,259 (2020).

© 2021 Monitoring Analytics, LLC

the definition of the cost based regulation offer because it is a markup
and not a cost. (Priority: Medium. First reported Q1, 2021. Status: Not
adopted.)Reserve Subzone with a reserve zone structure consistent with the actual
deliverability of reserves based on current transmission constraints.
(Priority: High. First reported 2019. Status: Not adopted.)• The MMU recommends that the $7.50 margin be eliminated from thedefinition of the cost of tier 2 synchronized reserve because it is amarkup and not a cost. (Priority: Medium. First reported 2018. Status:
Not adopted.)

22 This recommendation was adopted by PJM for the energy market. Lost opportunity costs in the energy market are calculated using theschedule on which the unit was scheduled to run. In the regulation market, this recommendation has not been adopted, as the LOC
continues to be calculated based on the lower of price or cost in the energy market offer.
23 162 FERC ¶ 61,295 (2018), reh’g denied, 170 FERC ¶ 61,259 (2020).
24 Id.
25 Id.
26 Id.

2021 Quarterly State of the Market Report for PJM: January through June 95

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends that the variable operating and maintenance cost••be eliminated from the definition of the cost of tier 2 synchronized reserveand that the calculation of synchronized reserve variable operations andmaintenance costs be removed from Manual 15. (Priority: Medium. First
reported 2019. Status: Not adopted.)
The MMU recommends that the components of the cost-based offers forproviding regulation and synchronous condensing be defined in Schedule
2 of the Operating Agreement. (Priority: Low. First reported 2019. Status:
Not adopted.)
The MMU recommends that the rule requiring that tier 1 synchronizedreserve resources be paid the tier 2 price when the nonsynchronizedreserve price is above zero be eliminated immediately and that, under
the current rule, tier 1 synchronized reserve resources not be paid the tier2 price when they do not respond. (Priority: High. First reported 2013.
Status: Not adopted.)• The MMU recommends that the tier 2 synchronized reserve must

offer requirement be enforced on a daily and hourly basis. The MMU
recommends that PJM define a set of acceptable reasons why a unit canbe made unavailable daily or hourly and require unit owners to select areason in Markets Gateway whenever making a unit unavailable either
daily or hourly or setting the offer MW to 0 MW. (Priority: Medium. First
reported 2013. Status: Partially adopted.)

improve the actual tier 1 estimate. If PJM continues to use DGP, DGP
should be documented in PJM’s manuals. (Priority: Medium. First reported
2018. Status: Not adopted.)• The MMU recommends that the details of VACAR Reserve Sharing
Agreement (VRSA) be made public, including any responsibilities assigned
to PJM and including the amount of reserves that Dominion commits tomeet its obligations under the VRSA. (Priority: Medium. First reported
2020. Status: Not adopted.)• The MMU recommends that the VRSA be terminated and, if necessary,

replaced by a reserve sharing agreement between PJM and VACAR South,
similar to agreements between PJM and other bordering areas. (Priority:
Medium. First reported 2020. Status: Not adopted.)• The MMU recommends that a reason code be attached to every hourin which PJM market operations adds additional DASR MW. (Priority:
Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that PJM modify the DASR market to ensure that
all resources cleared incur a real-time performance obligation. (Priority:
Low. First reported 2013. Status: Not adopted.)• The MMU recommends that, in order to mitigate market power, offers in

the DASR market be based on opportunity cost only. (Priority: Low. First
reported 2009. Modified, 2018. Status: Not adopted.)• The MMU recommends that, for calculating the penalty for a tier 2• The MMU recommends that all resources, new and existing, have a• The MMU recommends that aggregation not be permitted to offset unit

• The MMU recommends that new CRF rates for black start units,

resource failing to meet its scheduled obligation during a spinning event,the penalty should be based on the actual time since the last spinning
event of 10 minutes or longer during which the resource performed
because performance is only measured for events 10 minutes or longer.
(Priority: Medium. First reported 2018. Status: Not adopted.)
specific penalties for failure to respond to a synchronized reserve event.
(Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that PJM eliminate the use of Degree of Generator
Performance (DGP) in the synchronized reserve market solution and

96

Section 2 Recommendations

requirement to include and maintain equipment for primary frequency
response capability as a condition of interconnection service. The PJM
capacity and energy markets already compensate resources for frequency
response capability and any marginal costs. (Priority: Medium. First
reported 2018. Status: Not adopted.)
incorporating current tax code changes, be implemented immediately.
The new CRF rates should apply to all black start units. The black start
units should be required to commit to providing black start service for thelife of the unit. (Priority: High. First reported 2020. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Section 2 Recommendations• The MMU recommends for oil tanks shared with other resources that

only a proportionate share of the minimum tank suction level (MTSL) be
allocated to black start service. The MMU further recommends that the
PJM tariff be updated to clearly state how the MTSL will be calculated forblack start units sharing oil tanks. (Priority: Medium. First reported 2017.
Status: Not adopted.)• The MMU recommends that separate cost of service payments for reactive
capability be eliminated and the cost of reactive capability be recoveredin the capacity market. (Priority: Medium. First reported 2016. Status: Not
adopted.)• The MMU recommends that payments for reactive capability, if continued,
be based on the 0.90 power factor that PJM has determined is necessary.
(Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that, if payments for reactive are continued,

fleet wide cost of service rates used to compensate resources for reactive
capability be eliminated and replaced with compensation based on unit
specific costs. (Priority: Low. First reported 2019.27 Status: Partiallyadopted.)• The MMU recommends that Schedule 2 to OATT be revised to state

explicitly that only generators that provide reactive capability to thetransmission system that PJM operates and has responsibility for are
eligible for reactive capability compensation. Specifically, such eligibility
should be determined based on whether a generation facility’s point ofinterconnection is on a transmission line that is a Monitored Transmission
Facility as defined by PJM and is on a Reportable Transmission Facility
as defined by PJM.28 (Priority: Medium. First reported 2020. Status: Not
adopted.)Section 11, Congestion and Marginal Losses
There are no recommendations in this section.
27 The MMU has discussed this recommendation in state of the market reports since 2016 but Q3, 2019 was the first time it was reported asa formal MMU recommendation.
28 See PJM Transmission Facilities (note that this requires you first log into a PJM Tools account. If you do not, then the link sends you to an
Access Request page, <https://pjm.com/markets-and-operations/ops-analysis/transmission-facilities>.

© 2021 Monitoring Analytics, LLC

Section 12, Planning
Generation Retirements• The MMU recommends that the question of whether Capacity

Interconnection Rights (CIRs) should persist after the retirement of a unit
be addressed. The rules need to ensure that incumbents cannot exploit
control of CIRs to block or postpone entry of competitors.29 (Priority: Low.
First reported 2013. Status: Partially adopted, 2012.)

Generation Queue• The MMU recommends that barriers to entry be addressed in a timely

manner in order to help ensure that the capacity market will result in theentry of new capacity to meet the needs of PJM market participants andreflect the uncertainty and resultant risks in the cost of new entry used toestablish the capacity market demand curve in RPM. (Priority: Low. First
reported 2012. Status: Not adopted.)• The MMU recommends improvements in queue management includingthat PJM establish a review process to ensure that projects are removed
from the queue if they are not viable, as well as a process to allow
commercially viable projects to advance in the queue ahead of projects
which have failed to make progress, subject to rules to prevent gaming.
(Priority: Medium. First reported 2013. Status: Partially adopted.)• The MMU recommends continuing analysis of the study phase of PJM’stransmission planning to reduce the need for postponements of study
results, to decrease study completion times, and to improve the likelihoodthat a project at a given phase in the study process will successfully
go into service. (Priority: Medium. First reported 2014. Status: Partiallyadopted.)• The MMU recommends outsourcing interconnection studies to anindependent party to avoid potential conflicts of interest. Currently,
these studies are performed by incumbent transmission owners under
PJM’s direction. This creates potential conflicts of interest, particularly

29 See “Comments of the Independent Market Monitor for PJM,” Docket No. ER12-1177-000 (March 12, 2012) <http://www.
monitoringanalytics.com/Filings/2012/IMM_Comments_ER12-1177-000_20120312.PDF>.

2021 Quarterly State of the Market Report for PJM: January through June 97

2021 Quarterly State of the Market Report for PJM: January through June

when transmission owners are vertically integrated and the owner oftransmission also owns generation. (Priority: Low. First reported 2013.
Status: Not adopted.)Market Efficiency Process• The MMU recommends that the market efficiency process be eliminatedbecause it is not consistent with a competitive market design. (Priority:
Medium. First reported 2019. Status: Not adopted.)• The MMU recommends that, if the market efficiency process is retained,
PJM modify the rules governing benefit/cost analysis, the evaluation
process for selecting among competing market efficiency projects andcost allocation for economic projects in order to ensure that all costs,
including increased congestion costs and the risk of project cost increases,
in all zones are included in order to ensure that the correct metrics areused for defining benefits. (Priority: Medium. First reported 2018. Status:
Not adopted.)Comparative Cost Framework• The MMU recommends that PJM modify the project proposal templates

to include data necessary to perform a detailed project lifetime financial
analysis. The required data includes, but is not limited to: capital
expenditure; capital structure; return on equity; cost of debt; tax
assumptions; ongoing capital expenditures; ongoing maintenance; andexpected life. (Priority: Medium. First reported 2020. Status: Not adopted.)Transmission Competition• The MMU recommends, to increase the role of competition, that theexemption of supplemental projects from the Order No. 1000 competitive
process be terminated and that the basis for all such exemptions bereviewed and modified to ensure that the supplemental project designation
is not used to exempt transmission projects from a transparent, robust andclearly defined mechanism to permit competition to build such projects or

98

Section 2 Recommendations

to effectively replace the RTEP process. (Priority: Medium. First reported
2017. Status: Not adopted. Rejected by FERC.)30• The MMU recommends, to increase the role of competition, that theexemption of end of life projects from the Order No. 1000 competitive
process be terminated and that end of life transmission projects be
included in the RTEP process and should be subject to a transparent,robust and clearly defined mechanism to permit competition to build
such projects. (Priority: Medium. First reported 2019. Status: Not adopted.
Rejected by FERC.)31• The MMU recommends that PJM enhance the transparency and queue
management process for nonincumbent transmission investment. Issues
related to data access and complete explanations of cost impacts should
be addressed. The goal should be to remove barriers to competition fromnonincumbent transmission providers. (Priority: Medium. First reported
2015. Status: Not adopted.)• The MMU recommends that PJM continue to incorporate the principlethat the goal of transmission planning should be the incorporation oftransmission investment decisions into market driven processes as muchas possible. (Priority: Low. First reported 2001. Status: Not adopted.)• The MMU recommends the creation of a mechanism to permit a directcomparison, or competition, between transmission and generation
alternatives, including which alternative is less costly and who bears therisks associated with each alternative. (Priority: Low. First reported 2013.
Status: Not adopted.)• The MMU recommends that PJM establish fair terms of access to rights of

way and property, such as at substations, in order to remove any barriers toentry and permit competition between incumbent transmission providers
and nonincumbent transmission providers in the RTEP. (Priority: Medium.
First reported 2014. Status: Not adopted.)

30 The FERC accepted tariff provisions that exclude supplemental projects from competition in the RTEP. 162 FERC ¶ 61,129 (2018), reh’gdenied, 164 FERC ¶ 61,217 (2018).
31 In recent decisions addressing competing proposals on end of life projects, the Commission accepted a transmission owner proposal
excluding end of life projects from competition in the RTEP process, 172 FERC ¶ 61,136 (2020), reh’g denied, 173 FERC ¶ 61,225 (2020),
and rejected a proposal from PJM stakeholders that would have included end of life projects in competition in the RTEP process, 173
FERC ¶ 61,242 (2020).

© 2021 Monitoring Analytics, LLC

Section 2 Recommendations• The MMU recommends that rules be implemented to permit competition

to provide financing for transmission projects. This competition could
reduce the cost of capital for transmission projects and significantly
reduce total costs to customers. (Priority: Low. First reported 2013. Status:
Not adopted.)• The MMU recommends that rules be implemented to require that project

cost caps on new transmission projects be part of the evaluation ofcompeting projects. (Priority: Medium. First reported 2015. Status:
Adopted 2020.)• The MMU recommends that storage resources not be includable astransmission assets for any reason. (Priority: High. First reported 2020.
Status: Not adopted.)

Cost Allocation• The MMU recommends a comprehensive review of the ways in which thesolution based dfax is implemented. The goal for such a process would beto ensure that the most rational and efficient approach to implementing
the solution based dfax method is used in PJM. Such an approach shouldallocate costs consistent with benefits and appropriately calibrate the
incentives for investment in new transmission capability. No replacement
approach should be approved until all potential alternatives, including
the status quo, are thoroughly reviewed. (Priority: Medium. First reported
2020. Status: Not adopted.)• The MMU recommends consideration of changing the minimum
distribution factor in the allocation from 0.01 to 0.00 and adding athreshold minimum usage impact on the line.32 (Priority: Medium. First
reported 2015. Status: Not adopted.)Transmission Line Ratings• The MMU recommends that all PJM transmission owners use the same

methods to define line ratings, subject to NERC standards and guidelines,
subject to review by NERC and approval by FERC. (Priority: Medium. First
reported 2019. Status: Not adopted.)Transmission Facility Outages• The MMU recommends that PJM reevaluate all transmission outage

tickets as on time or late as if they were new requests when an outage
is rescheduled, and apply the standard rules for late submissions to any
such outages. (Priority: Low. First reported 2014. Status: Not adopted.)• The MMU recommends that PJM draft a clear definition of the congestion

analysis required for transmission outage requests to include in Manual
3 after appropriate review. (Priority: Low. First reported 2015. Status: Not
adopted.)• The MMU recommends that PJM modify the rules to reduce or eliminate
the approval of late outage requests submitted or rescheduled after the
FTR auction bidding opening date. (Priority: Low. First reported 2015.
Status: Not adopted.)• The MMU recommends that PJM not permit transmission owners to divide

long duration outages into smaller segments to avoid complying withthe requirements for long duration outages. (Priority: Low. First reported
2015. Status: Not adopted.)

Section 13, FTRs and ARRs
Market Design• The MMU recommends that the current ARR/FTR design be replacedwith defined congestion revenue rights (CRRs). A CRR is the right toactual congestion that is paid by physical load at a specific bus, zone oraggregate. (Priority: High. First reported 2015. Status: Not adopted.)

32 See the 2015 State of the Market Report for PJM, Volume II, Section 12: Generation and Transmission Planning, at p. 463, Cost Allocation
Issues.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 99

2021 Quarterly State of the Market Report for PJM: January through June

ARR•

The MMU recommends that the ARR/FTR design be modified to ensurethat the rights to all congestion revenues are assigned to load. (Priority:
High. First reported 2015. Status: Not adopted.)• The MMU recommends that all historical generation to load paths be••eliminated as a basis for assigning ARRs. The MMU recommends thatthe current design be replaced with a design in which the rights to actual
congestion paid are assigned directly to the load that paid that congestion
by node. (Priority: High. First reported 2015. Status: Partially adopted.)

The MMU recommends that, under the current FTR design, the rights to allcongestion revenue be allocated as ARRs prior to sale as FTRs. Reductions
for outages and increased system capability should be reserved for ARRs
rather than sold in the Long Term FTR Auction. (Priority: High. First
reported 2017. Status: Not adopted.)
The MMU recommends that IARRs be eliminated from PJM’s tariff, butthat if IARRs are not eliminated, IARRs should be subject to the sameproration rules that apply to all other ARR rights. (Priority: Low. First
reported 2018. Status: Not adopted.)

FTR• The MMU recommends that FTR funding be based on total congestion,

including day-ahead and balancing congestion. (Priority: High. First
reported 2017. Status: Not adopted.)• The MMU recommends that PJM enforce the FTR auction bid limits at theparent company level starting immediately. (Priority: High. First reported
2020. Status: Adopted 2021.)• The MMU recommends a requirement that the details of all bilateral FTR•

transactions be reported to PJM. (Priority: High. First reported 2020.
Status: Not adopted.)
The MMU recommends that PJM continue to evaluate the bilateralindemnification rules and any asymmetries they may create. (Priority:
Low. First reported 2018. Status: Not adopted.)• The MMU recommends that PJM reduce FTR sales on paths withpersistent overallocation of FTRs, including a clear definition of persistentoverallocation and how the reduction will be applied. (Priority: High. First
reported 2013. Status: Partially adopted, 2014/2015 planning period.)• MMU recommends that PJM eliminate generation to generation paths
and all other paths that do not represent the delivery of power to load.
(Priority: High. First reported 2018. Status: Not adopted.)• The MMU recommends that the Long Term FTR product be eliminated. If
the Long Term FTR product is not eliminated, the Long Term FTR Market
should be modified so that the supply of prevailing flow FTRs in the Long
Term FTR Market is based solely on counter flow offers in the Long Term
FTR Market. (Priority: High. First reported 2017. Status: Not adopted.)• The MMU recommends that PJM improve transmission outage modelingin the FTR auction models, including the use of probabilistic outage
modeling. (Priority: Low. First reported 2013. Status: Not adopted.)• The MMU recommends that the forfeiture amount from the FTR forfeiturerule be based on the correct hourly cost of an FTR, rather than a simple
daily price divided by 24. (Priority: High. First reported 2018. Status:
Adopted 2019.)

Surplus• The MMU recommends that all FTR auction revenue be distributed to ARR
holders monthly, regardless of FTR funding levels. (Priority: High. First
reported 2015. Status: Not adopted.)• The MMU recommends that, under the current FTR design, all congestion

revenue in excess of FTR target allocations be distributed to ARR holders
on a monthly basis. (Priority: High. First reported 2018. Status: Not
adopted.)• The MMU recommends that FTR auction revenues not be used by PJM tobuy counter flow FTRs for the purpose of improving FTR payout ratios.33(Priority: High. First reported 2015. Status: Not adopted.)

33 See “PJM Manual 6: Financial Transmission Rights,” Rev. 26 (Jan. 27, 2021).

100

Section 2 Recommendations© 2021 Monitoring Analytics, LLC

Section 2 Recommendations

FTR Subsidies• The MMU recommends that PJM eliminate portfolio netting to eliminate

cross subsidies among FTR market participants. (Priority: High. First
reported 2012. Status: Not adopted. Rejected by FERC.)• The MMU recommends that PJM eliminate subsidies to counter flow

FTRs by applying the payout ratio to counter flow FTRs in the same way
the payout ratio is applied to prevailing flow FTRs. (Priority: High. First
reported 2012. Status: Not adopted.)• The MMU recommends that PJM eliminate geographic cross subsidies.
(Priority: High. First reported 2013. Status: Not adopted.)• The MMU recommends that PJM examine the mechanism by which selfscheduled FTRs are allocated when load switching among LSEs occurs
throughout the planning period. (Priority: Low. First reported 2011.
Status: Not adopted.)

FTR Liquidation• The MMU recommends that the FTR portfolio of a defaulted member becanceled rather than liquidated or allowed to settle as a default cost on
the membership. (Priority: High. First reported 2018. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 101

2021 Quarterly State of the Market Report for PJM: January through June

102

Section 2 Recommendations© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Energy Market
The PJM energy market comprises all types of energy transactions, including
the sale or purchase of energy in PJM’s Day-Ahead and Real-Time Energy
Markets, bilateral and forward markets and self supply. Energy transactions
analyzed in this report include those in the PJM Day-Ahead and Real-Time
Energy Markets. These markets provide key benchmarks against which market
participants may measure results of transactions in other markets.
The Market Monitoring Unit (MMU) analyzed measures of market structure,
participant conduct and market performance, including market size,
concentration, pivotal suppliers, offer behavior, markup, and price. The MMU
concludes that the PJM energy market results were competitive in the first six
months of 2021.
Table 3-1 The energy market results were competitive
Market Element
Market Structure: Aggregate Market
Market Structure: Local Market
Participant Behavior
Market Performance

Evaluation
Partially Competitive
Not Competitive
Competitive
Competitive

Market Design

Effective• The aggregate market structure was evaluated as partially competitive

because the aggregate market power test based on pivotal suppliers
indicates that the aggregate day-ahead market structure was notcompetitive on every day. The hourly HHI (Herfindahl-Hirschman Index)
results indicate that the PJM aggregate energy market in the first six
months of 2021 was, on average, unconcentrated by FERC HHI standards.
Average HHI was 751 with a minimum of 574 and a maximum of 1118 in
the first six months of 2021. The peaking segment of supply was highly
concentrated. The fact that the average HHI is in the unconcentrated
range does not mean that the aggregate market was competitive in all
hours. As demonstrated for the day-ahead market, it is possible to havepivotal suppliers in the aggregate market even when the HHI level is notin the highly concentrated range. It is possible to have an exercise of
market power even when the HHI level is not in the highly concentrated© 2021 Monitoring Analytics, LLC

range. The number of pivotal suppliers in the energy market is a more
precise measure of structural market power than the HHI. The HHI is nota definitive measure of structural market power.

• The local market structure was evaluated as not competitive due to thehighly concentrated ownership of supply in local markets created bytransmission constraints and local reliability issues. The results of the threepivotal supplier (TPS) test, used to test local market structure, indicate
the existence of market power in local markets created by transmission
constraints. The local market performance is competitive as a result of
the application of the TPS test. While transmission constraints create thepotential for the exercise of local market power, PJM’s application of thethree pivotal supplier test identified local market power and resulted inoffer capping to force competitive offers, correcting for structural issues
created by local transmission constraints. There are, however, identified
issues with the definition of cost-based offers and the application ofmarket power mitigation to resources whose owners fail the TPS test thatneed to be addressed because unit owners can exercise market power evenwhen they fail the TPS test.

• Participant behavior was evaluated as competitive because the analysis ofmarkup shows that marginal units generally make offers at, or close to,their marginal costs in both the day-ahead and real-time energy markets,
although the behavior of some participants both routinely and during
periods of high demand represents economic withholding. The ownershipof marginal units is concentrated. The markups of pivotal suppliers in theaggregate market and of many pivotal suppliers in local markets remain
unmitigated due to the lack of aggregate market power mitigation and theflawed implementation of offer caps for resources that fail the TPS test.
The markups of those participants affected LMP.

• Market performance was evaluated as competitive because market resultsin the energy market reflect the outcome of a competitive market, as PJM
prices are set, on average, by marginal units operating at, or close to, their
marginal costs in both day-ahead and real-time energy markets, althoughhigh markups for some marginal units did affect prices.

2021 Quarterly State of the Market Report for PJM: January through June 103

2021 Quarterly State of the Market Report for PJM: January through June

• Market design was evaluated as effective because the analysis showsthat the PJM energy market resulted in competitive market outcomes. In
general, PJM’s energy market design provides incentives for competitive
behavior and results in competitive outcomes. In local markets, where
market power is an issue, the market design identifies market power andcauses the market to provide competitive market outcomes in most cases
although issues with the implementation of market power mitigationand development of cost-based offers remain. The role of UTCs in the
day-ahead energy market continues to cause concerns. Market design
implementation issues, including inaccuracies in modeling of thetransmission system and of generator capabilities as well as inefficiencies
in real-time dispatch and price formation, undermine market efficiency
in the energy market. PJM plans to resolve the problems with real time
dispatch and pricing in November 2021, but the implementation of fast
start pricing and the extended ORDC in September 2021 and March 2022
will undermine market efficiency by setting inefficient prices that areinconsistent with the dispatch signals.

• PJM markets are designed to promote competitive outcomes derived fromthe interaction of supply and demand in each of the PJM markets. Market
design itself is the primary means of achieving and promoting competitive
outcomes in PJM markets. One of the MMU’s core functions is to identify
actual or potential market design flaws.1 The approach to market power
mitigation in PJM has focused on market designs that promote competition(a structural basis for competitive outcomes) and on mitigating market
power in instances where the market structure is not competitive and thus
where market design alone cannot mitigate market power. FERC relies
on effective market power mitigation when it approves market sellers toparticipate in the PJM market at market based rates.2 In the PJM energy
market, market power mitigation occurs primarily in the case of local
market power. When a transmission constraint creates the potential for
local market power, PJM applies a structural test to determine if the local
market is competitive, applies a behavioral test to determine if generator
offers exceed competitive levels and applies a market performance test to

1 OATT Attachment M (PJM Market Monitoring Plan).
2 See Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System
Operator Markets, Order No. 861, 168 FERC ¶ 61,040 (July 18, 2019); order on reh’g, Order No. 861-A; 170 FERC ¶ 61,106 (2020).

104

Section 3 Energy Market

determine if such generator offers would affect the market price.3 There
are, however, identified issues with the application of market power
mitigation to resources whose owners fail the TPS test that can result in
the exercise of local market power even when market power mitigation
rules are applied. These issues need to be addressed. FERC recognized theseissues in its June 17, 2021 order.4 Some units with market power havepositive markups and some have inflexible parameters, which means thatthe cost-based offer was not used and that the process for offer capping
units that fail the TPS test does not consistently result in competitivemarket outcomes in the presence of market power. There are issues related
to the definition of gas costs includable in energy offers that need to beaddressed. There are issues related to the level of maintenance expense
includable in energy offers that need to be addressed. There are currently
no market power mitigation rules in place that limit the ability to exercise
market power when aggregate market conditions are tight and there arepivotal suppliers in the aggregate market. Aggregate market power needs
to be addressed. Market design must reflect appropriate incentives forcompetitive behavior, the application of local market power mitigationneeds to be fixed, the definition of a competitive offer needs to be fixed,
and aggregate market power mitigation rules need to be developed. The
importance of these issues is amplified by the rules permitting cost-based
offers in excess of $1,000 per MWh.

Overview
Supply and DemandMarket Structure• Supply. The average on-peak hourly day-ahead supply was 151,999 MW

for spring 2020, and 151,376 MW for spring 2021. The average on-peakhourly offered real-time supply was 123,217 MW for spring 2020, and121,843 MW for spring 2021. In the first six months of 2021, 1,538.8 MW

3 The market performance test means that offer capping is not applied if the offer does not exceed the competitive level and therefore
market power would not affect market performance.
4 PJM Interconnection, L.L.C., Order to Show Cause, (June 17, 2021) 175 FERC ¶ 61,231.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Marketof new resources were added in the energy market, and 1,251.4 MW ofresources were retired.

• PJM average hourly real-time cleared generation in the first six monthsof 2021 increased by 5.5 percent from the first six months of 2020, from87,044 MWh to 91,798 MWh• PJM average hourly day-ahead supply in the first six months of 2021,
including INCs and UTCs, decreased by 6.7 percent from the first six
months of 2020, from 109,126 MWh to 101,836 MWh.

• Demand. The PJM system real-time hourly peak load plus exports in thefirst six months of 2021 was 148,667 MWh (143,559 MW of load plus
5,108 MW of gross exports) in the HE 1700 on June 29, 2021, which was
12,767 MWh, 9.4 percent, higher than the PJM peak load plus exports inthe first six months of 2020, which was 135,900 MWh in the HE 1600 on
June 10, 2020.
PJM average hourly real-time load in the first six months of 2021
increased by 5.8 percent from the first six months of 2020, from 81,255
MWh to 85,958 MWh.
PJM average hourly day-ahead demand in the first six months of 2021,
including DECs and UTCs, decreased by 6.8 percent from the first six
months of 2020, from 104,164 MWh to 97,083 MWh.

Market Behavior• Generator Offers. In the day-ahead market in the first six months of 2021,

19.6 percent of MW were offered as must run, 28.0 percent were theeconomic minimum MW for dispatchable units, 51.7 percent were offered
as a dispatchable range, and 0.6 percent were offered as emergency
maximum MW.

• Virtual Offers and Bids. Any market participant in the PJM Day-Ahead

Energy Market can use increment offers, decrement bids, up to congestiontransactions, import transactions and export transactions as financial
instruments that do not require physical generation or load. The hourly
average submitted increment offer MW decreased by 13.2 percent and© 2021 Monitoring Analytics, LLC

cleared MW decreased by 4.9 percent in the first six months of 2021
compared to the first six months of 2020. The hourly average submitted
decrement bid MW increased by 29.3 percent and cleared MW increased
by 17.5 percent in the first six months of 2021 compared to the first six
months of 2020. The hourly average submitted up to congestion bid MW
decreased by 50.1 percent and cleared MW decreased by 59.8 percent in
the first six months of 2021 compared to the first six months of 2020.

Market Performance• Generation Fuel Mix. In the first six months of 2021, coal units provided

23.5 percent, nuclear units 33.0 percent and natural gas units 35.6
percent of total generation. Compared to the first six months of 2020,
the generation from coal units increased 39.7 percent, from nuclear units
decreased 2.2 percent and from natural gas units decreased 4.6 percent.

• Fuel Diversity. The fuel diversity of energy generation for the first six
months of 2021, measured by the fuel diversity index for energy (FDIe),
increased 2.8 percent compared to the first six months of 2020.

• Marginal Resources. In the PJM Real-Time Energy Market in the firstsix months of 2021, coal units were 16.8 percent and natural gas units
were 68.7 percent of marginal resources. In the first six months of 2020,
coal units were 16.4 percent and natural gas units were 74.3 percent ofmarginal resources.
In the PJM Day-Ahead Energy Market in the first six months of 2021,
UTCs were 36.5 percent, INCs were 17.7 percent, DECs were 25.1 percent,and generation resources were 20.4 percent of marginal resources. In thefirst six months of 2020, UTCs were 52.3 percent, INCs were 14.3 percent,DECs were 14.2 percent, and generation resources were 19.2 percent ofmarginal resources.

• Prices. PJM load-weighted, average, real-time LMP in the first six monthsof 2021 increased 57.8 percent from the first six months of 2020, from
$19.40 per MWh to $30.62 per MWh.

2021 Quarterly State of the Market Report for PJM: January through June 105

2021 Quarterly State of the Market Report for PJM: January through JunePJM load-weighted, average day-ahead LMP in the first six months of2021 increased 61.2 percent from the first six months of 2020, from
$19.23 per MWh to $31.00 per MWh.

• Components of LMP. In the PJM Real-Time Energy Market in the first six

months of 2021, 14.0 percent of the load-weighted LMP was the result ofcoal costs, 51.7 percent was the result of gas costs and 3.2 percent was theresult of the cost of emission allowances. In the first six months of 2021,
11.2 percent of load-weighted LMP was the result of the transmission
constraint violation penalty factor due to an increased frequency oftransmission constraint violations, especially on the 500 kV system.
In the PJM Day-Ahead Energy Market, in the first six months of 2021,
27.7 percent of the load-weighted LMP was the result of gas costs, 28.3
percent was the result of DEC bids, 14.3 percent was the result of coal
costs, 12.4 percent was the result of INC offers, 0.7 percent was the resultof markup, and 2.2 percent was the result of UTCs.

• Price Convergence. Hourly and daily price differences between the
day-ahead and real-time energy markets fluctuate continuously andsubstantially from positive to negative. The difference between average
day-ahead and real-time prices was -$0.29 per MWh in the first six
months of 2021, and $0.15 per MWh in the first six months of 2020. The
difference between average day-ahead and real-time prices, by itself, is
not a measure of the competitiveness or effectiveness of the day-aheadenergy market.

Scarcity• There were ten intervals with five minute shortage pricing in the firstsix months of 2021. There were no emergency actions that resulted in
Performance Assessment Intervals in the first six months of 2021.

• There were 1,301 five minute intervals, or 2.5 percent of all five minuteintervals in the first six months of 2021 for which at least one RT SCED
solution showed a shortage of reserves, and 333 five minute intervals, or
0.6 percent of all five minute intervals in the first six months of 2021 for

106

Section 3 Energy Market

which more than one RT SCED solution showed a shortage of reserves.
PJM triggered shortage pricing for ten five minute intervals.

Competitive Assessment
Market Structure• Aggregate Pivotal Suppliers. The PJM energy market, at times, requires

generation from pivotal suppliers to meet load, resulting in aggregate
market power even when the HHI level indicates that the aggregate
market is unconcentrated.

• Local Market Power. In the first six months of 2021, 12 control zones

experienced congestion resulting from one or more constraints bindingfor 50 or more hours. For four out of the top 10 congested facilities (byreal-time binding hours) in the first six months of 2021, the average
number of suppliers providing constraint relief was three or less. There isa high level of concentration within the local markets for providing relief
to the most congested facilities in the PJM Real-Time Energy Market. The
local market structure is not competitive.

Market Behavior• Offer Capping for Local Market Power. PJM offer caps units when thelocal market structure is noncompetitive. Offer capping is an effectivemeans of addressing local market power when the rules are designed andimplemented properly. Offer capping levels have historically been low
in PJM. In the day-ahead energy market, for units committed to provide
energy for local constraint relief, offer-capped unit hours increased from
1.2 percent in the first six months of 2020 to 1.3 percent in the firstsix months of 2021. In the real-time energy market, for units committed
to provide energy for local constraint relief, offer-capped unit hours
increased from 0.9 percent in the first six months of 2020 to 1.3 percent
in the first six months of 2021. While overall offer capping levels havebeen low, there are a significant number of units with persistent structural
local market power that would have a significant impact on prices in theabsence of local market power mitigation.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

The analysis of the application of the TPS test to local markets demonstrates
that it is working to identify pivotal owners when the market structure isnoncompetitive and to ensure that owners are not subject to offer capping
when the market structure is competitive. There are, however, identified
issues with the application of market power mitigation to resources whose
owners fail the TPS test that can result in the exercise of local market
power. These issues need to be addressed.

• Offer Capping for Reliability. PJM also offer caps units that are committed

for reliability reasons, including for reactive support. In the day-aheadenergy market, for units committed for reliability reasons, offer-capped
unit hours increased from 0.00 percent in the first six months of 2020
to 0.02 percent in the first six months of 2021. In the real-time energy
market, for units committed for reliability reasons, offer-capped unit
hours remained at 0.01 percent in the first six months of 2020 and 2021.
The low offer cap percentages do not mean that units manually committed
for reliability reasons do not have market power. All units manuallycommitted for reliability have market power and all are treated as if they
had market power. These units are not capped to their cost-based offers
because they tend to offer with a negative markup in their price-based
offers, particularly at the economic minimum level, which means that
PJM’s offer capping process results in the use of the price-based offer forcommitment even if it has less flexible operating parameters.

• Parameter Mitigation. In the first six months of 2021, 35.1 percent ofunit hours for units that failed the TPS test in the day-ahead market
were committed on price-based schedules that were less flexible thantheir cost-based schedules. In the first six months of 2021, on days when
hot weather and cold weather alerts were declared, 31.8 percent of unit
hours in the day-ahead energy market were committed on price-basedschedules that were less flexible than their price PLS schedules.

• Frequently Mitigated Units (FMU) and Associated Units (AU). In 2020, fiveunits qualified for an FMU adder in at least one month. In the first six
months of 2021, one unit qualified for an FMU adder in January.

• Markup Index. The markup index is a summary measure of participant

offer behavior for individual marginal units. While the average markup
index in the real-time market was -0.02 in the first six months of 2021,
some marginal units did have substantial markups. The highest markup
for any marginal unit in the real-time market in the first six months of2021 was more than $400 per MWh when using unadjusted cost-based
offers.
While the average markup index in the day-ahead market was 0.04 in
the first six months of 2021, some marginal units did have substantial
markups. The highest markup for any marginal unit in the day-aheadmarket in the first six months of 2021 was more than $120 per MWhwhen using unadjusted cost-based offers.

• Markup. The markup frequency distributions show that a significant

proportion of units make price-based offers less than the cost-based
offers permitted under the PJM market rules. This behavior means thatcompetitive price-based offers reveal actual unit marginal costs and that
PJM market rules permit the inclusion of costs in cost-based offers thatare not short run marginal costs.
The markup behavior shown in the markup frequency distributions also
shows that a substantial number of units were offered with high markups,
consistent with the exercise of market power.

Market Performance• Markup. The markup conduct of individual owners and units has an

identifiable impact on market prices. Markup is a key indicator of thecompetitiveness of the energy market.
In the PJM Real-Time Energy Market in the first six months of 2021,
the unadjusted markup component of LMP was -$0.13 per MWh or -0.4
percent of the PJM load-weighted, average LMP. June had the highest
peak markup component, $2.76 per MWh, or 6.9 percent of the real-time,
peak hour load-weighted, average LMP for June.
In the PJM Day-Ahead Energy Market, INCs, DECs and UTCs have zero
markups. In the first six months of 2021, the markup component of LMP© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 107

2021 Quarterly State of the Market Report for PJM: January through June

was $0.22 per MWh or 0.7 percent of the PJM day-ahead load-weighted,
average LMP. February had the highest unadjusted peak markup
component, $2.13 per MWh.
Participant behavior was evaluated as competitive because the analysis
of markup shows that marginal units generally make offers at, or close
to, their marginal costs in both the day-ahead and real-time energy
markets, although the behavior of some participants represents economic
withholding.

• Markup and Local Market Power. Comparison of the markup behavior of

marginal units with TPS test results shows that for 3.8 percent of all realtime marginal unit intervals in the first six months of 2021, the marginalunit had both local market power as determined by the TPS test and apositive markup. The fact that units with market power had a positive
markup means that the cost-based offer was not used, that a higher pricebased offer was used, and that the process for offer capping units that failthe TPS test does not consistently result in competitive market outcomesin the presence of market power.

• Markup and Aggregate Market Power. In the first six months of 2021,

pivotal suppliers in the aggregate market set prices with high markups forsome real-time market intervals.

Recommendations
Market Power• The MMU recommends that the market rules explicitly require thatoffers in the energy market be competitive, where competitive is defined
to be the short run marginal cost of the units. The short run marginal
cost should reflect opportunity cost when and where appropriate. The
MMU recommends that the level of incremental costs includable in costbased offers not exceed the short run marginal cost of the unit. (Priority:
Medium. First reported 2009. Status: Not adopted.)

Fuel Cost Policies• The MMU recommends that PJM require that all fuel cost policies be
algorithmic, verifiable, and systematic, and accurately reflect short
run marginal costs. (Priority: Medium. First reported 2016. Status: Not
adopted.)• The MMU recommends that the tariff be changed to allow units to havefuel cost policies that do not include fuel procurement practices, including
fuel contracts. Fuel procurement practices, including fuel contracts, may
be used as the basis for fuel cost policies but should not be required.
(Priority: Low. First reported 2018. Status: Adopted 2020.)• The MMU recommends that PJM change the fuel cost policy requirement

to apply only to units that will be offered with non-zero cost-based offers.
The PJM market rules should require that the cost-based offers of units
without an approved fuel cost policy be set to zero. (Priority: Low. First
reported 2018. Status: Adopted 2020.)• The MMU recommends that the temporary cost method be removed andthat all units that submit nonzero cost-based offers be required to havean approved fuel cost policy. (Priority: Low. First reported 2020. Status:
Not adopted.)• The MMU recommends that the penalty exemption provision be removed

and that all units that submit nonzero cost-based offers be required tofollow their approved fuel cost policy. (Priority: Medium. First reported
2020. Status: Not adopted.)

Cost-Based Offers• The MMU recommends that Manual 15 (Cost Development Guidelines) be

replaced with a straightforward description of the components of costbased offers based on short run marginal costs and the correct calculationof cost-based offers. (Priority: Medium. First reported 2016. Status: Not
adopted.)• The MMU recommends removal of all use of FERC System of Accounts in
the Cost Development Guidelines. (Priority: Medium. First reported 2016.
Status: Not adopted.)

108

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market• The MMU recommends the removal of all use of cyclic starting andpeaking factors from the Cost Development Guidelines. (Priority: Medium.
First reported 2016. Status: Not adopted.)• The MMU recommends the removal of all labor costs from the Cost

Development Guidelines. (Priority: Medium. First reported 2016. Status:
Not adopted.)• The MMU recommends the removal of all maintenance costs from theCost Development Guidelines. (Priority: Medium. First reported 2019.
Status: Not adopted.)• The MMU recommends that market participants be required to document

the amount and cost of consumables used when operating in order toverify that the total operating cost is consistent with the total quantity
used and the unit characteristics. (Priority: Medium. First reported 2020.
Status: Not adopted.)• The MMU recommends, given that maintenance costs are currently allowedin cost-based offers, that market participants be permitted to include
only variable maintenance costs, linked to verifiable operational eventsand that can be supported by clear and unambiguous documentationof the operational data (e.g. run hours, MWh, MMBtu) that support themaintenance cycle of the equipment being serviced/replaced. (Priority:
Medium. First reported 2020. Status: Not adopted.)• The MMU recommends explicitly accounting for soak costs and changing

the definition of the start heat input for combined cycles to include only
the amount of fuel used from first fire to the first breaker close in the Cost
Development Guidelines. (Priority: Medium. First reported 2016. Status:
Not adopted.)• The MMU recommends the removal of nuclear fuel and nonfuel operations

and maintenance costs that are not short run marginal costs from the Cost
Development Guidelines. (Priority: Medium. First reported 2016. Status:
Not adopted.)• The MMU recommends revising the pumped hydro fuel cost calculation

to include day-ahead and real-time power purchases. (Priority: Low. First
reported 2016. Status: Not adopted.)© 2021 Monitoring Analytics, LLC• The MMU recommends revisions to the calculation of energy market

opportunity costs to incorporate all time based offer parameters and all
limitations that impact the opportunity cost of generating unit output.
(Priority: Medium. First reported 2016. Status: Adopted 2020.)• The MMU recommends removing the catastrophic designation for force

majeure fuel supply limitations in Schedule 2. (Priority: Medium. First
reported 2016. Status: Not adopted.)Market Power: TPS Test and Offer Capping• The MMU recommends that the rules governing the application of the

TPS test be clarified and documented. The TPS test application in the dayahead energy market is not documented. (Priority: High. First reported
2015. Status: Partially adopted.)• The MMU recommends that PJM require every market participant tomake available at least one cost schedule based on the same hourly fueltype(s) and parameters at least as flexible as their offered price schedule.
(Priority: Medium. First reported 2015. Status: Not adopted.)• The MMU recommends, in order to ensure effective market power
mitigation when the TPS test is failed, that markup be constant acrossthe full MWh range of price and cost-based offers. (Priority: High. First
reported 2015. Status: Not adopted.)• The MMU recommends, in order to ensure effective market power

mitigation when the TPS test is failed, that offer capping be applied tounits that fail the TPS test in the real-time market that were not offer
capped at the time of commitment in the day-ahead market or at a priortime in the real-time market. (Priority: High. First reported 2020. Status:
Not adopted.)• The MMU recommends, in order to ensure effective market power
mitigation when the TPS test is failed, and during high load conditions
such as cold and hot weather alerts or more severe emergencies, thatthe operating parameters in the cost-based offer and the price-based
parameter limited schedule (PLS) offer be at least as flexible as theoperating parameters in the available price-based non-PLS offer, and that2021 Quarterly State of the Market Report for PJM: January through June 109

2021 Quarterly State of the Market Report for PJM: January through June•

the price-MW pairs in the price-based PLS offer be exactly equal to theprice-based non-PLS offer. (Priority: High. First reported 2015. Status:
Not adopted.)
The MMU recommends, in order to ensure effective market power
mitigation, that PJM always enforce parameter limited values bycommitting units only on parameter limited schedules, when the TPS
test is failed or during high load conditions such as cold and hot weather
alerts or more severe emergencies. (Priority: High. First reported 2019.
Status: Not adopted.)• The MMU recommends that PJM retain the $1,000 per MWh offer cap•

in the PJM energy market except when cost-based offers exceed $1,000
per MWh, and retain other existing rules that limit incentives to exercise
market power. (Priority: High. First reported 1999. Status: Partiallyadopted, 1999, 2017.)
The MMU recommends the elimination of FMU and AU adders. FMU and
AU adders no longer serve the purpose for which they were created andinterfere with the efficient operation of PJM markets. (Priority: Medium.
First reported 2012. Status: Partially adopted, 2014.)

Offer Behavior• The MMU recommends that resources not be allowed to violate the ICAP

must offer requirement. The MMU recommends that PJM enforce the
ICAP must offer requirement by assigning a forced outage to any unitthat is derated in the energy market below its committed ICAP without
an outage that reflects the derate. (Priority: Medium. First reported 2020.
Status: Not adopted.)• The MMU recommends that storage and intermittent resources be subject
to an enforceable ICAP must offer rule that reflects the limitations of theseresources. (Priority: Medium. First reported 2020. Status: Not adopted.)• The MMU recommends that capacity resources not be allowed to offer

any portion of their capacity market obligation as maximum emergency
energy. (Priority: Medium. First reported 2012. Status: Not adopted.)

110

Section 3 Energy Market

Capacity Performance Resources• The MMU recommends that capacity performance resources be held to

the OEM operating parameters of the capacity market CONE reference
resource for performance assessment and energy uplift payments and that
this standard be applied to all technologies on a uniform basis. (Priority:
Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that the parameters which determine

nonperformance charges and the amounts of uplift payments shouldreflect the flexibility goals of the capacity performance construct. The
operational parameters used by generation owners to indicate to PJM
operators what a unit is capable of during the operating day should not
determine capacity performance assessment or uplift payments. (Priority:
Medium. First reported 2015. Status: Partially adopted.)• The MMU recommends that PJM not include the balancing ratios

calculated for localized Performance Assessment Intervals (PAIs) in thecapacity market default offer cap, and only include those events thattrigger emergencies at a defined zonal or higher level. (Priority: Medium.
First reported 2018. Status: Not adopted.)• The MMU recommends that PJM clearly define the business rules that

apply to the unit specific parameter adjustment process, including PJM’s
implementation of the tariff rules in the PJM manuals to ensure market
sellers know the requirements for their resources. (Priority: Low. First
reported 2018. Status: Not adopted.)• The MMU recommends that PJM update the tariff to clarify that all
generation resources are subject to unit specific parameter limits on
their cost-based offers using the same standard and process as capacity
performance capacity resources. (Priority: Medium. First reported 2018.
Status: Not adopted.)• The MMU recommends that PJM institute rules that would not pay ashare of capacity market revenue to resources that choose to submit realtime values that are less flexible than their unit specific parameter limits
or approved parameter limit exceptions based on tariff defined reasons.
(Priority: Medium. First reported 2018. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Section 3 Energy Market• The MMU recommends that PJM not approve temporary exceptions
that are based on pipeline tariff terms that are not routinely enforced,
and based on inferior transportation service procured by the generator.
(Priority: Medium. First reported 2019. Status: Not adopted.)

Accurate System Modeling• The MMU recommends that PJM approve one RT SCED case for each fiveminute interval to dispatch resources during that interval using a fiveminute ramp time, and that PJM calculate prices using LPC for that fiveminute interval using the same approved RT SCED case. (Priority: High.
First reported 2019. Status: Not adopted.)• The MMU recommends that PJM explicitly state its policy on the use oftransmission penalty factors including: the level of the penalty factors;
the triggers for the use of the penalty factors; the appropriate line ratingsto trigger the use of penalty factors; the allowed duration of the violation;
the use of constraint relaxation logic; and when the transmission penalty
factors will be used to set the shadow price. (Priority: Medium. First
reported 2015. Status: Partially adopted 2020.)• The MMU recommends that PJM routinely review all transmission facility

ratings and any changes to those ratings to ensure that the normal,
emergency and load dump ratings used in modeling the transmission
system are accurate and reflect standard ratings practice. (Priority: Low.
First reported 2013. Status: Partially adopted.)• The MMU recommends that PJM not use closed loop interface or surrogate

constraints to artificially override nodal prices based on fundamental LMP
logic in order to: accommodate rather than resolve the inadequacies of thedemand side resource capacity product; address the inability of the power
flow model to incorporate the need for reactive power; accommodate
rather than resolve the flaws in PJM’s approach to scarcity pricing; orfor any other reason. (Priority: Medium. First reported 2013. Status: Not
adopted.)• The MMU recommends that PJM not use CT price setting logic to modify
transmission line limits to artificially override the nodal prices that are© 2021 Monitoring Analytics, LLC

based on fundamental LMP logic in order to reduce uplift. (Priority:
Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that if PJM believes it appropriate to implement

CT price setting logic, PJM first initiate a stakeholder process to determine
whether such modification is appropriate. PJM should file any proposedchanges with FERC to ensure review. Any such changes should beincorporated in the PJM tariff. (Priority: Medium. First reported 2016.
Status: Partially adopted.)• The MMU recommends that PJM update the outage impact studies,

the reliability analyses used in RPM for capacity deliverability, andthe reliability analyses used in RTEP for transmission upgrades to beconsistent with the more conservative emergency operations (postcontingency load dump limit exceedance analysis) in the energy market
that were implemented in June 2013. (Priority: Low. First reported 2013.
Status: Not adopted.)• The MMU recommends that PJM include in the tariff or appropriate

manual an explanation of the initial creation of hubs, the process formodifying hub definitions and a description of how hub definitions havechanged.5 6 (Priority: Low. First reported 2013. Status: Not adopted.)• The MMU recommends that all buses with a net withdrawal be treated asload for purposes of calculating load and load-weighted LMP, even if the
MW are settled to the generator. The MMU recommends that during hours
when a load bus shows a net injection, the energy injection be treatedas generation, not negative load, for purposes of calculating generationand load-weighted LMP, even if the injection MW are settled to the load
serving entity. (Priority: Low. First reported 2013. Status: Not adopted.)• The MMU recommends that PJM identify and collect data on available
behind the meter generation resources, including nodal location
information and relevant operating parameters. (Priority: Low. First
reported 2013. Status: Partially adopted.)

5 According to minutes from the first meeting of the Energy Market Committee (EMC) on January 28, 1998, the EMC unanimously agreed
to be responsible for approving additions, deletions and changes to the hub definitions to be published and modeled by PJM. Since the
EMC has become the Market Implementation Committee (MIC), the MIC now appears to be responsible for such changes.
6 There is currently no PJM documentation in the tariff or manuals explaining how hubs are created and how their definitions are changed.
The general definition of a hub can be found in the PJM.com Glossary <http://www.pjm.com/Glossary.aspx>.

2021 Quarterly State of the Market Report for PJM: January through June 111

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends that PJM document how LMPs are calculated
when demand response is marginal. (Priority: Low. First reported 2014.
Status: Not adopted.)• The MMU recommends that PJM not allow nuclear generators which do

not respond to prices or which only respond to manual instructions fromthe operator to set the LMPs in the real-time market. (Priority: Low. First
reported 2016. Status: Not adopted.)• The MMU recommends that PJM increase the coordination of outage and••operational restrictions data submitted by market participants via eDART/eGADs and offer data submitted via Markets Gateway. (Priority: Low. First
reported 2017. Status: Not adopted.)
The MMU recommends that PJM model generators’ operating transitions,
including soak time for units with a steam turbine, configurationtransitions for combined cycles, and peak operating modes. (Priority:
Medium. First reported 2019. Status: Not adopted.)
The MMU recommends that PJM clarify, modify and document its process
for dispatching reserves and energy when SCED indicates that supply isless than total demand including forecasted load and reserve requirements.
The modifications should define: a SCED process to economically convert
reserves to energy; a process for the recall of energy from capacity
resources; and the minimum level of synchronized reserves that would
trigger load shedding. (Priority: Medium. First reported 2020. Status: Not
adopted.)• The MMU recommends that PJM stop capping the system marginal pricein RT SCED and instead limit the sum of violated reserve constraint
shadow prices used in LPC to $1,700 per MWh. (Priority: Medium. First
reported Q1, 2021. Status: Not adopted.)• The MMU recommends, if PJM implements extended downward sloping

ORDCs, that PJM calculate the probability of reserves falling below theminimum reserve requirement (MRR) based on ten minute rather than
30 minute forecast error, and on forced outages in the ten minute rather
than the 30 minute look ahead window to model the uncertainty in the112

Section 3 Energy Market

inputs to RT SCED. (Priority: Medium. New recommendation. Status: Not
adopted.)Transparency• The MMU recommends that PJM market rules require the fuel type beidentified for every price and cost schedule and PJM market rules remove
nonspecific fuel types such as other or co-fire other from the list of fueltypes available for market participants to identify the fuel type associatedwith their price and cost schedules. (Priority: Medium. First reported 2015.
Status: Adopted 2019.)• The MMU recommends that PJM allow generators to report fuel typeon an hourly basis in their offer schedules and to designate schedule
availability on an hourly basis. (Priority: Medium. First reported 2015.
Status: Partially adopted.)• The MMU recommends that PJM define clear criteria for operator approvalof RT SCED cases, including shortage cases, that are used to send dispatch
signals to resources, and for pricing, to minimize discretion. (Priority:
High. First reported 2018. Status: Partially adopted.)

Virtual Bids and Offers• The MMU recommends eliminating up to congestion (UTC) bidding at
pricing nodes that aggregate only small sections of transmission zones
with few physical assets. (Priority: Medium. First reported 2020. Status:
Not adopted.)• The MMU recommends eliminating INC, DEC, and UTC bidding at pricing

nodes that allow market participants to profit from modeling issues.
(Priority: Medium. First reported 2020. Status: Not adopted.)Conclusion
The MMU analyzed key elements of PJM energy market structure, participant
conduct and market performance in the first six months of 2021, including
aggregate supply and demand, concentration ratios, aggregate pivotal© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

supplier results, local three pivotal supplier test results, offer capping, markup,
marginal units, participation in demand response programs, virtual bids andoffers, loads and prices.
PJM average hourly real-time load in the first six months of 2021 increased
by 5.8 percent from the first six months of 2020, from 81,255 MWh to 85,958
MWh. The relationship between supply and demand, regardless of the specificmarket, along with market concentration and the extent of pivotal suppliers,
is referred to as the supply-demand fundamentals or economic fundamentals
or market structure. The market structure of the PJM aggregate energy market
is partially competitive because aggregate market power does exist for asignificant number of hours. The HHI is not a definitive measure of structural
market power. The number of pivotal suppliers in the energy market is amore precise measure of structural market power than the HHI. It is possible
to have pivotal suppliers in the aggregate market even when the HHI levelis not in the highly concentrated range. Even a low HHI may be consistent
with the exercise of market power with a low price elasticity of demand. The
current market power mitigation rules for the PJM energy market rely on
the assumption that the ownership structure of the aggregate market ensurescompetitive outcomes. This assumption requires that the total demand forenergy can be met without the supply from any individual supplier or without
the supply from a small group of suppliers. This assumption is not correct.
There are pivotal suppliers in the aggregate energy market at times. High
markups for some units demonstrate the potential to exercise market powerboth routinely and during high demand conditions. The existing market
power mitigation measures do not address aggregate market power. The MMU
is developing an aggregate market power test and will propose market power
mitigation rules to address aggregate market power.
The three pivotal supplier test is applied by PJM on an ongoing basis for local
energy markets in order to determine whether offer capping is required fortransmission constraints.7 However, there are some issues with the applicationof market power mitigation in the day-ahead energy market and the real-time
7 The MMU reviews PJM’s application of the TPS test and brings issues to the attention of PJM.

© 2021 Monitoring Analytics, LLC

energy market when market sellers fail the TPS test. Many of these issues canbe resolved by simple rule changes.
The enforcement of market power mitigation rules is undermined if thedefinition of a competitive offer is not correct. A competitive offer is equal toshort run marginal costs. The significance of competition metrics like markup
is also undermined if the definition of a competitive offer is not correct. The
definition of a competitive offer, under the PJM Market Rules, is not currently
correct. The definition, that all costs that are related to electric production are
short run marginal costs, is not clear or correct. All costs and investmentsfor power generation are related to electric production. Under this definition,some unit owners include costs that are not short run marginal costs inoffers, especially maintenance costs. This issue can be resolved by simple rulechanges to incorporate a clear and accurate definition of short run marginal
costs.
Prices are a key outcome of markets. Prices vary across hours, days and years
for multiple reasons. Price is an indicator of the level of competition in amarket. In a competitive market, prices are directly related to the marginal
cost to serve load at a given time. The pattern of prices within days and acrossmonths and years illustrates how prices are directly related to supply anddemand conditions and thus also illustrates the potential significance of the
impact of the price elasticity of demand on prices. Energy market results inthe first six months of 2021 generally reflected supply-demand fundamentals,
although the behavior of some participants both routinely and during highdemand periods represents economic withholding. Economic withholding
occurs when generator offers are greater than competitive levels. There are
additional issues in the energy market including the uncertainties about
the pricing and availability of natural gas, the way that generation owners
incorporate natural gas costs in offers, and the lack of adequate incentives forunit owners to take all necessary actions to acquire fuel, staff their units, andoperate rather than economically withhold or physically withhold.
Prices in PJM are not too low. Prices in PJM are the result of input prices,consistent with a competitive market. Low natural gas prices have been a2021 Quarterly State of the Market Report for PJM: January through June 113

2021 Quarterly State of the Market Report for PJM: January through June

primary cause of low PJM energy market prices. There is no evidence tosupport the need for a significant change to the calculation of LMP, such as
fast start pricing or the extended ORDC. Fast start pricing and the extended
ORDC will disconnect pricing from dispatch instructions and create greater
reliance on uplift as an incentive to follow PJM’s instructions. The extended
ORDCs will create shortage pricing when no reserve shortages exist. Rather
than undercutting the basic LMP logic that is core to market efficiency, it
would make more sense to directly address the design of RT SCED/LPC,
scarcity pricing, operator actions and the design of reserve markets. PJM has
made progress in addressing the timing of RT SCED and LPC and accepting
shortage pricing in some cases when SCED shows a shortage, but moreprogress is needed.
The PJM defined inputs to the dispatch tools, particularly the RT SCED, havesubstantial effects on energy market outcomes. Transmission line ratings,
transmission penalty factors, load forecast bias, hydro resource schedules, andunit ramp rate adjustments change the dispatch of the system, affect prices,and can create significant price increases through transmission line limit
violations or restrictions on the resources available to resolve constraints.
The automated adjustment of ramp rates by PJM, called Degree of Generator
Performance (DGP), modifies the values offered by generators and limits
the MW available to the RT SCED. Rather than sending dispatch signals
consistent with resource offers and holding resources accountable when they
fail to follow them, DGP accommodates resources that do not follow dispatch.
PJM operator interventions to reduce line ratings unnecessarily trigger
transmission constraint penalty factors and significantly increase prices.
PJM should evaluate its interventions in the market, consider whether theinterventions are appropriate, and provide greater transparency to enhancemarket efficiency.
The objective of efficient short run price signals is to minimize systemproduction costs, not to minimize uplift. Repricing the market to reflectcommitment costs prioritizes minimizing uplift over minimizing production
costs. The tradeoff exists because when commitment costs are included inprices, the price signal no longer equals the short run marginal cost and114

Section 3 Energy Market

therefore no longer provides the correct signal for efficient behavior formarket participants making decisions on the margin, whether resources, load,interchange transactions, or virtual traders. This tradeoff will be created by
PJM’s fast start pricing proposal as approved by FERC and would be createdin a much more extensive form by PJM’s pending extended ORDC pricing
changes.8
Units that start in one hour are not actually fast start units, and theircommitment costs are not marginal in a five minute market. The differences
between the actual LMP and the fast start LMP will distort the incentive formarket participants to behave competitively and to follow PJM’s dispatch
instructions. PJM will pay new forms of uplift in an attempt to counter the
distorted incentives. The magnitude of the new payments and their effects on
behavior are not well understood.
PJM’s arguments for changing energy market price formation asserted thatfast start pricing and the extended ORDC would price flexibility in the market,
but instead they will benefit inflexible units. The fast start pricing extended
ORDC solutions would undercut LMP logic rather than directly addressing theunderlying issues. The solution is not to accept that the inflexible CT shouldbe paid or set price based on its commitment costs rather than its short run
marginal costs. The question of why units make inflexible offers should be
addressed directly. Are units inflexible because they are old and inefficient,because owners have not invested in increased flexibility or because they
serve as a mechanism for the exercise of market power? The question of
why the unit was built, whether it was built under cost of service regulation
and whether it is efficient to retain the unit should be answered directly. The
question of how to provide market incentives for investment in flexible units,
for investment in increased flexibility of existing units, and for operating at
the full extent of existing flexibility should be addressed directly. The questionof whether inflexible units should be paid uplift at all should be addressed
directly. Marginal cost pricing without paying excess uplift to inflexible units
would create incentives for market participants to provide flexible solutions
including replacing inefficient units with flexible, efficient units.
8

See 173 FERC ¶ 61,244 (2020).

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

With or without a capacity market, energy market design must permit scarcity
pricing when such pricing is consistent with market conditions and constrainedby reasonable rules to ensure that market power is not exercised and ensure no
scarcity pricing when such pricing is not consistent with market conditions.
Scarcity pricing can serve two functions in wholesale power markets:
revenue adequacy and price signals. Scarcity pricing for revenue adequacy,
as in PJM’s ORDC proposal, is not required in PJM. Scarcity pricing for pricesignals that reflect market conditions during periods of scarcity is requiredin PJM. Scarcity pricing is also part of an appropriate incentive structure
facing both load and generation owners in a working wholesale electric power
market design. Scarcity pricing must be designed to ensure that market prices
reflect actual market conditions, that scarcity pricing occurs with transparent
triggers based on measured reserve levels and transparent prices, that scarcity
pricing only occurs when scarcity exists, and that there are strong incentives
for competitive behavior and strong disincentives to exercise market power.
Such administrative scarcity pricing is a key link between energy and capacity
markets. Administrative scarcity pricing that establishes scarcity pricing in
about 85 percent of hours, as PJM’s ORDC proposal would, is not scarcity
pricing but simply a revenue enhancement mechanism, which could haveunintended consequences in an emergency, as was the case in ERCOT in
February 2021. PJM’s pending ORDC changes are not consistent with efficient
market design and are just a revenue enhancement mechanism.
The PJM Capacity Market is explicitly designed to provide revenue adequacy
and the resultant reliability. However, the explicit balancing mechanism that
included net revenues directly in unit offers in the prior capacity market design
is not present in the Capacity Performance design. The nature of a direct andexplicit energy pricing net revenue true up mechanism in the capacity market
should be addressed if energy revenues are expected to increase as a result of
scarcity events, as a result of increased demand for reserves, or as a result of
PJM’s inappropriate proposals related to fast start pricing and the inclusionof maintenance expenses as short run marginal costs. The true up mechanism
must address both cleared auctions and subsequent auctions. There are alsosignificant issues with PJM’s scarcity pricing rules, including the absence of aclear trigger based on measured reserve levels (the current triggers are based© 2021 Monitoring Analytics, LLC

on estimated reserves) and the lack of adequate locational scarcity pricing
options.
The overall energy market results support the conclusion that energy prices
in PJM are set, generally, by marginal units operating at, or close to, their
marginal costs, although this was not always the case in the first six monthsof 2021 or prior years. In the first six months of 2021, marginal units werepredominantly combined cycle gas generators. The frequency of combined
cycle gas units as the marginal unit type has risen rapidly, from 31.5 percent
in the first six months of 2016 to 61.1 percent in the first six months of 2021.
Overdue improvements in generator modeling in the energy market would
allow PJM to more efficiently commit and dispatch combined cycle plants
and to fully reflect the flexibility of these units. New combined cycle units
have placed competitive pressure on less efficient generators, and the market
has reliably served load with less congestion, less uplift, and less markup asa result. This is evidence of generally competitive behavior and competitivemarket outcomes, although the behavior of some participants represents
economic withholding. Given the structure of the energy market which
can permit the exercise of aggregate and local market power, the change
in some participants’ behavior is a source of concern in the energy market
and provides a reason to use correctly defined short run marginal cost as thesole basis for cost-based offers and a reason for implementing an aggregate
market power test and correcting the offer capping process for resources withlocal market power. The MMU concludes that the PJM energy market results
were competitive in the first six months of 2021.

2021 Quarterly State of the Market Report for PJM: January through June 115

2021 Quarterly State of the Market Report for PJM: January through June

Supply and Demand

Figure 3-2 shows the typical dispatch range.

Market Structure

Figure 3-2 Typical dispatch range of supply curves

Supply$100

Supply includes physical generation, imports and virtual transactions.

$90

2020 Spring Real-Time Peak-Hour Supply

Price ($/MWh)Figure 3-1 Hourly real-time and aggregate day-ahead supply curve
comparison: Spring of 2020 and 2021
$2,000$1,900$1,800$1,700$1,600$1,500$1,400$1,300$1,200$1,100$1,000
$900
$800
$700
$600
$500
$400
$300
$200
$100
$0
-$100
-$200
-$300

2021 Spring Real-Time Peak-Hour Supply
2021 Spring Day-Ahead Peak-Hour Supply
2020 Spring Real-Time Peak-Hour Load Plus Exports
2020 Spring Day-Ahead Peak-Hour Load Plus Exports
2021 Spring Real-Time Peak-Hour Load Plus Exports
2021 Spring Day-Ahead Peak-Hour Load Plus Exports

$60
$50
$40
$30
$20
$10

2020 Spring Real-Time Peak-Hour Supply
2020 Spring Day-Ahead Peak-Hour Supply$02021 Spring Real-Time Peak-Hour Supply
2021 Spring Day-Ahead Peak-Hour Supply
2020 Spring Real-Time Peak-Hour Load Plus Exports
2020 Spring Day-Ahead Peak-Hour Load Plus Exports
2021 Spring Real-Time Peak-Hour Load Plus Exports

Quantity (MW)2021 Spring Day-Ahead Peak-Hour Load Plus Exports

Table 3-2 shows the price elasticity of the real-time supply curve for the on
peak hours in the spring of 2019 to 2021 by load level.
The price elasticity of the supply curve measures the responsiveness of thequantity supplied (GW) to a change in price:

Quantity (MW)
9 Real-time supply includes real-time generation offers and import MWh.
10 The supply curve period is from March 1 to May 31

116

$70

Price ($/MWh)In the first six months of 2021, 1,538.8 MW of new resources were addedin the energy market, and 1,251.4 MW of resources were retired. Figure 3-1
shows the average real-time and day-ahead supply curves in spring 2020 and
2021.9 10 The real-time supply curve includes average on peak hourly offers.
The real-time supply curve includes available MW from units that are online
or have a notification plus start time that is no more than one hour. The dayahead supply curve shows the average of all available peak hourly offers.

$80

2020 Spring Day-Ahead Peak-Hour Supply

Section 3 Energy Market

The supply curve is elastic when elasticity is greater than 1.0. The supply
curve is more sensitive to changes in price the higher the elasticity. Although
the aggregate supply curve may appear flat as a result of the wide range inprices and quantities, the calculated elasticity is low throughout.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-2 Price elasticity of the supply curve

PJM Real-Time Supply Frequency
Figure 3-3 shows the hourly distribution of PJM real-time generation plus
imports for the first six months of 2020 and 2021.
Figure 3-3 Distribution of real-time generation plus imports: January throughJune, 2020 and 202112
900

Real-Time Supply

from another balancing authority. A real-time import must have a valid
OASIS reservation when offered, must have available ramp room tosupport the import, must be accompanied by a NERC Tag, and must pass
the neighboring balancing authority checkout process.

11 Generation data are the net MWh injections and withdrawals MWh at every generation bus in PJM.

© 2021 Monitoring Analytics, LLC

235-240225-230

215-220205-210

195-200

185-190

175-180

165-170

155-160

145-150

135-1400125-130100

115-120• Import. An import is an external energy transaction scheduled to PJM

200

105-110corresponding offer prices from a specific unit.

300

85-90

• Dispatchable Generation Offer. Offer to supply a schedule of MW and400

95-100a price taker, from a unit that may also have a dispatchable component
above the fixed MW.

500

75-80

• Self Scheduled Generation Offer. Offer to supply a fixed block of MW, as

600

65-70

In the PJM Real-Time Energy Market, there are three types of supply offers:

2021 Jan - Jun

700

Hours

PJM average hourly real-time cleared supply including imports in the first six
months of 2021 increased by 5.5 percent from the first six months of 2020,
from 87,861 MWh to 92,655 MWh.

2020 Jan - Jun

800

PJM average hourly real-time cleared generation in the first six months of2021 increased by 5.5 percent from the first six months of 2020, from 87,044
MWh to 91,798 MWh.11

55-60

2021
0.021
0.148
0.111
0.004

0-50

GW
Min - 75
75 - 95
95 - 115
115 - Max

Elasticity of Spring Supply Curve
2019
2020
0.015
0.032
0.200
0.317
0.271
0.105
0.003
0.003

Range (GWh)

12 Each range on the horizontal axis excludes the start value and includes the end value.

2021 Quarterly State of the Market Report for PJM: January through June 117

2021 Quarterly State of the Market Report for PJM: January through JunePJM Real-Time, Average Supply

PJM Real-Time, Monthly Average Generation

Table 3-3 shows real-time hourly supply for the first six months of each year
from 2001 through 2021.

Figure 3-4 compares the real-time, monthly average hourly generation in2020 and the first six months of 2021 with the historic five year range. In
February and June 2021, the monthly average hourly generation was higher
than the maximum of the past five years, primarily as a result of weather
related demand.

JanJun
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

PJM Real-Time Supply (MWh)Generation Plus
Generation
Imports
Standard
Standard
Generation Deviation
Supply Deviation
29,4284,679
32,412
4,813
30,9675,770
34,7306,238
36,034
6,008
39,644
6,021
41,4309,435
45,597
9,699
74,365
12,661
79,693
13,24280,24911,011
84,819
11,574
83,478
12,10588,15013,192
83,294
12,45888,824
12,77877,508
12,961
82,92813,58080,702
13,96885,575
14,455
81,483
13,677
86,26814,42886,31013,69591,526
14,27987,974
13,52893,166
14,27792,45815,722
98,186
16,71090,097
16,02896,626
17,16886,335
14,576
91,21815,231
88,66913,528
91,10814,02991,631
14,82894,091
15,312
91,613
14,403
92,947
14,73587,044
13,30887,861
13,453
91,79815,382
92,655
15,620Year-to-Year Change
Generation Plus
Generation
Imports
Standard
Standard
Generation Deviation
Supply Deviation
NA
NA
NA
NA
5.2%
23.3%
7.2%
29.6%
16.4%
4.1%
14.1%
(3.5%)
15.0%
57.0%
15.0%
61.1%
79.5%
34.2%
74.8%
36.5%
7.9%
(13.0%)
6.4%(12.6%)
4.0%
9.9%
3.9%
14.0%
(0.2%)
2.9%
0.8%(3.1%)(6.9%)
4.0%(6.6%)
6.3%
4.1%
7.8%
3.2%
6.4%
1.0%
(2.1%)
0.8%(0.2%)
5.9%
0.1%
6.1%
(1.0%)
1.9%(1.2%)
1.8%(0.0%)
5.1%
16.2%
5.4%
17.0%
(2.6%)
1.9%(1.6%)
2.7%(4.2%)(9.1%)(5.6%)(11.3%)
2.7%(7.2%)(0.1%)(7.9%)
3.3%
9.6%
3.3%
9.1%
(0.0%)(2.9%)(1.2%)(3.8%)(5.0%)(7.6%)(5.5%)(8.7%)
5.5%
15.6%
5.5%
16.1%

Figure 3-4 Real-time monthly average hourly generation: 2020 through June
2021
160,000

Section 3 Energy Market

2020
2021

140,000
130,000
120,000
110,000
100,000

90,00080,00070,00060,000118

Max - Min 2016 - 2020

150,000

Generation (MWh)Table 3-3 Average hourly real-time generation and real-time generation plus
imports: January through June, 2001 through 2021

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Day-Ahead Supply

PJM Day-Ahead Supply Duration

PJM average hourly day-ahead cleared supply in the first six months of 2021,
including INCs and up to congestion transactions, decreased by 6.7 percent
from the first six months of 2020, from 109,126 MWh to 101,836 MWh. When
imports are added, PJM average hourly, day-ahead cleared supply in the firstsix months of 2021 decreased by 6.7 percent from the first six months of
2020, from 109,369 MWh to 102,057 MWh. The decrease of day-ahead supply
was a result of a decrease in UTCs.

Figure 3-5 shows the hourly distribution of PJM day-ahead cleared supply,
including increment offers, up to congestion transactions, and imports in thefirst six months of 2020 and 2021.
Figure 3-5 Distribution of day-ahead cleared supply plus imports: January
through June, 2020 and 202113
900

amount scheduled to PJM from another balancing authority. An importmust have a valid willing to pay congestion (WPC) OASIS reservation
when offered. An import energy transaction that clears the day-aheadenergy market is financially binding. There is no link between transactions
submitted in the PJM Day-Ahead Energy Market and the PJM Real-Time
Energy Market, so an import energy transaction approved in the dayahead energy market will not physically flow in real time unless it is also
submitted through the real-time energy market scheduling process.

235-240225-230

215-220205-210

195-200

185-190

175-180

165-170

155-160

145-150

135-140

125-130

115-120105-110095-100100

85-90• Import. An import is an external energy transaction for a specific MW

200

75-80

Up to Congestion Transaction (UTC). Conditional transaction that permits
a market participant to specify a maximum price spread for a specificamount of MW between the transaction source and sink. An up tocongestion transaction is a matched pair of an injection and a withdrawal.

300

65-70

•

offer prices. INCs can be submitted by any market participant.

400

0-50

• Increment Offer (INC). Financial offer to supply MW and corresponding

500

55-60

corresponding offer prices from a unit.

600

Hours

• Dispatchable Generation Offer. Offer to supply a schedule of MW and2021 Jan - Jun

700• Self Scheduled Generation Offer. Offer to supply a fixed block of MW, asa price taker, from a unit that may also have a dispatchable component
above the minimum.

2020 Jan - Jun

800

In the PJM Day-Ahead Energy Market, there are five types of financiallybinding supply offers:

Range (GWh)

13 Each range on the horizontal axis excludes the start value and includes the end value.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 119

2021 Quarterly State of the Market Report for PJM: January through JunePJM Day-Ahead, Average Supply

PJM Day-Ahead, Monthly Average Cleared Supply

Table 3-4 presents day-ahead hourly cleared supply summary statistics for the
first six months of each year from 2001 through 2021.

Figure 3-6 compares the day-ahead, monthly average hourly cleared supply,
including increment offers and up to congestion transactions for the first six
months of 2020 and 2021 with the historic five year range. The average supply
was lower than the minimum of the previous five years in most months as aresult of the decrease in UTCs.

JanJun
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

PJM Day-Ahead Supply (MWh)SupplySupply Plus Imports
Standard
Standard
Supply Deviation
Supply Deviation
26,796
4,305
27,5404,382
25,84010,011
26,39810,021
36,4207,000
36,994
7,023
50,08910,10850,836
10,17187,855
14,36589,382
14,39595,562
12,62097,796
12,615
106,470
14,522
108,815
14,772
104,705
14,124
107,169
14,19097,607
16,283100,076
16,342
102,626
18,206
105,463
18,378108,143
16,666110,656
16,926132,326
15,710134,747
15,841
148,381
15,606
150,554
15,830165,620
13,930167,939
14,119115,150
18,851
117,613
18,996
127,715
20,380129,798
20,518
133,601
19,109134,433
19,293113,028
21,246
113,493
21,258
115,511
16,792
115,896
16,811109,126
16,253
109,369
16,248101,836
17,741102,057
17,778Year-to-Year Change
SupplySupply Plus Imports
Standard
Standard
Supply Deviation
Supply Deviation
NA
NA
NA
NA
(3.6%)
132.5%(4.1%)
128.7%
40.9%(30.1%)
40.1%(29.9%)
37.5%
44.4%
37.4%
44.8%
75.4%
42.1%
75.8%
41.5%
8.8%
(12.1%)
9.4%(12.4%)
11.4%
15.1%
11.3%
17.1%
(1.7%)(2.7%)(1.5%)(3.9%)(6.8%)
15.3%(6.6%)
15.2%
5.1%
11.8%
5.4%
12.5%
5.4%
(8.5%)
4.9%(7.9%)
22.4%(5.7%)
21.8%(6.4%)
12.1%(0.7%)
11.7%(0.1%)
11.6%(10.7%)
11.5%(10.8%)(30.5%)
35.3%(30.0%)
34.5%
10.9%
8.1%
10.4%
8.0%
4.6%
(6.2%)
3.6%(6.0%)(15.4%)
11.2%(15.6%)
10.2%
2.2%(21.0%)
2.1%(20.9%)(5.5%)(3.2%)(5.6%)(3.3%)(6.7%)
9.2%(6.7%)
9.4%

Figure 3-6 Day-ahead monthly average cleared hourly supply: January 2020
through June 2021
160,000

Max - Min 2016 - 2020

2020

2021

150,000
140,000
130,000
Generation (MWh)Table 3-4 Average hourly day-ahead cleared supply and day-ahead cleared
supply plus imports: January through June, 2001 through 2021

120,000
110,000
100,000
90,00080,00070,00060,000120

Section 3 Energy Market

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Real-Time and Day-Ahead Supply
Table 3-5 presents summary statistics for the first six months of 2020 and 2021, for day-ahead cleared supply and real-time supply. The last two columns ofTable 3-5 are the day-ahead supply minus the real-time supply. The first column is the total physical day-ahead generation less the total physical real-time
generation and the second column is the total day-ahead supply less the total real-time supply.
Table 3-5 Day-ahead and real-time supply (MWh): January through June, 2020 and 2021
JanJunAverage
2020
2021
Median
2020
2021
Standard Deviation
2020
2021
Peak Average
2020
2021
Peak Median
2020
2021
Peak Standard Deviation
2020
2021
Off-Peak Average
2020
2021
Off-Peak Median
2020
2021
Off-Peak Standard Deviation 2020
2021

© 2021 Monitoring Analytics, LLC

Generation
87,01391,55884,93489,785
14,237
15,954
94,576
98,96093,02597,444
12,87914,16080,33585,05078,68082,851
11,838
14,544

Day-Ahead
Up to
INC Offers Congestion
2,562
19,551
2,423
7,855
2,513
19,408
2,320
7,663
762
3,687
1,000
2,835
2,818
20,509
2,895
8,918
2,787
20,287
2,893
8,668
771
3,786
994
2,613
2,336
18,705
2,007
6,920
2,274
18,521
1,906
6,632
677
3,379
800
2,691

Day-Ahead Less
Real-Time

Real-Time
Imports
243
221
225
150
167
265
217
199
200
136
160
235
265
241
245
165
169
288

Total
Supply109,369
102,057
107,105
100,194
16,248
17,778118,121110,972
115,771
109,026
15,074
15,214
101,640
94,218100,599
91,43313,006
16,100Generation
87,044
91,79884,89489,987
13,30815,38293,707
98,78092,211
97,13912,323
13,965
81,16085,65879,81383,596
11,207
13,880

Total
Supply87,861
92,65585,59890,713
13,453
15,62094,552
99,71893,12597,762
12,497
14,213
81,951
86,44580,667
84,107
11,335
14,090Generation
(31)
(240)
40
(202)
929
571
869
180
814
305
556
195
(825)
(609)
(1,132)
(745)
631
664

Supply21,508
9,402
21,507
9,481
2,795
2,158
23,568
11,25522,646
11,264
2,577
1,001
19,6897,773
19,932
7,327
1,671
2,010

2021 Quarterly State of the Market Report for PJM: January through June 121

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-7 shows the average cleared volumes of day-ahead supply and realtime supply by hour of the day for the first six months of 2021. The day-ahead
supply consists of cleared MW of physical generation, imports, increment
offers and up to congestion transactions. The real-time supply consists ofcleared MW of physical generation and imports.

Figure 3-8 shows the difference between the day-ahead and real-time average
daily supply in 2020 and the first six months of 2021.
Figure 3-8 Difference between cleared day-ahead and real-time supply(Average daily volumes): January 2020 through June 2021
50,000Figure 3-7 Day-ahead and real-time supply (Average volumes by hour of theday): January through June, 2021

40,000140,000
30,000Volume (MWh)120,000

Volume (MWh)100,000
80,00060,00020,00010,000040,000-10,000

20,0000-20,000
Jan-20

1

2

3

4

5

6

7

8

9

Real-time cleared generation
Day-ahead cleared generation
Day-ahead cleared INC

122

Section 3 Energy Market

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour Ending (EPT)

Apr-20Jul-20

Oct-20Jan-21

Apr-21

Total Day-Ahead Supply Minus Total Real-Time Supply
Total Physical Day-Ahead Generation Minus Total Physical Real-Time Generation

Real-time imports
Day-ahead imports
Day-ahead cleared up to congestion transactions© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Demand includes physical load and exports and virtual transactions.

Peak Demand
In this section, demand refers to accounting load and exports and, in the dayahead energy market, includes virtual transactions.14

Figure 3-9 compares prices and demand on the peak load days in the first six
months of 2020 and 2021. The average, real-time LMP for June 10, 2021, peakload hour was $31.56 and for June 29, 2021 peak load hour it was $61.71.
Figure 3-9 Peak load and export day comparison: Wednesday, June 10, 2020and Tuesday, June 29, 2021
29-Jun-2021 Load and Export

The PJM system real-time hourly peak load plus exports in the first six
months of 2021 was 148,667 MWh in the HE 1700 on June 29, 2021, which
was 12,767 MWh, 9.4 percent, higher than the PJM peak load plus exports
in the first six months of 2020, which was 135,900 MWh in the HE 1600 on
June 10, 2020.

Table 3-6 Actual footprint peak loads plus export: January through June,2009 through 202115 16(Jan - Jun)
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Date
Fri, January 16
Wed, June 23
Wed, June 08
Fri, June 29Tue, June 25Tue, June 17
Fri, February 20
Mon, June 20
Mon, June 12
Mon, June 18
Wed, January 30
Wed, June 10
Tue, June 29

Hour Ending PJM Load Plus Export
(EPT)
(MWh)
9
128,31017
136,847
18
153,559
17
156,66416
140,22118
142,4288
144,850
18
137,16218
142,63317
150,23420
140,037
16
135,900
17
148,667

Annual Change
(MWh)
NA
8,538
16,712
3,105(16,443)
2,206
2,422
(7,688)5,471
7,601(10,197)(4,137)
12,767

Annual Change
(%)
NA
6.7%
12.2%
2.0%
(10.5%)
1.6%
1.7%(5.3%)
4.0%
5.3%(6.8%)(3.0%)
9.4%

29-Jun-2021 1700 ET - PJM 148,667 MWh

10-Jun-2020 1600 ET - PJM 135,900 MWh

10-Jun-2020 Load and Export

160,000$180

29-Jun-2021 LMP

10-Jun-2020 LMP$160

140,000$140
120,000
Load (MW)Table 3-6 shows the peak loads plus export for the first six months of 2009
through 2021.

$200

180,000

Real-time LMP ($\MWh)

Demand$120

100,000$100$80

80,000$60
60,000$40
40,00020,000

$20

1

2

3

4

5

6

7

8

9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour Ending (EPT)$0

14 PJM reports peak load including accounting load plus an addback equal to PJM’s estimated load drop from demand side resources. This
will generally result in PJM reporting peak load values greater than accounting load values. PJM’s load drop estimate is based on PJM
Manual 19: Load Forecasting and Analysis,” Attachment A: Load Drop Estimate Guidelines.
15 Peak loads shown are Power accounting load. See the MMU Technical Reference for the PJM Markets, at “Load Definitions,” for detailed
definitions of load. <http://www.monitoringanalytics.com/‌reports/Technical_References/references.shtml>.
16 Peak loads shown have been corrected to reflect the accounting load value excluding PJM loss adjustment. The values presented in thistable do not include settlement adjustments made prior to January 1, 2017.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 123

2021 Quarterly State of the Market Report for PJM: January through June

900

400
300

200

235-240225-230

215-220205-210

195-200

185-190

175-180

165-170

155-160

145-150

135-140

125-130

115-120105-11085-90

095-100100

75-80

Figure 3-10 shows the distribution of hourly PJM real-time load plus exports
in the first six months of 2020 and 2021.18

500

65-70

PJM Real-Time Demand Duration

600

Hours

to another balancing authority. A real-time export must have a valid
OASIS reservation when offered, must have available ramp room tosupport the export, must be accompanied by a NERC Tag, and must pass
the neighboring balancing authority’s checkout process.

2021 Jan - Jun

700

In the PJM Real-Time Energy Market, there are two types of demand:• Load. The actual MWh level of energy used by load within PJM.
• Export. An export is an external energy transaction scheduled from PJM

2020 Jan - Jun

800

55-60

PJM average hourly real-time load in the first six months of 2021 increased
by 5.8 percent from the first six months of 2020, from 81,255 MWh to 85,958
MWh.17 PJM average hourly real-time demand including exports in the firstsix months of 2021 increased by 5.3 percent from the first six months of 2020,
from 86,344 MWh to 90,960 MWh.

Figure 3-10 Distribution of real-time accounting load plus exports: January
through June, 2020 and 202119

0-50

Real-Time Demand

Range (GWh)

17 Load data are the net MWh injections and withdrawals MWh at every load bus in PJM.
18 All real-time load data in Section 3, “Energy Market,” “Market Performance: Load and LMP,” are based on PJM accounting load. See theTechnical Reference for PJM Markets, “Load Definitions,” for detailed definitions of accounting load. <http://www.monitoringanalytics.
com/reports/‌Technical_References/references.shtml>.

124

Section 3 Energy Market

19 Each range on the horizontal axis excludes the start value and includes the end value.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

PJM Real-Time, Average LoadPJM Real-Time, Monthly Average Load

Table 3-7 presents real-time hourly demand summary statistics for the firstsix months of each year from 2001 through 2021.20

Figure 3-11 compares the real-time, monthly average load plus exports in2020 and the first six months of 2021, with the historic five year range. The
February and June monthly average load plus exports in 2021 are higher thanthe maximum of the past five years.

Jan-Jun
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

PJM Real-Time Demand (MWh)Load
Load Plus Exports
Standard
Standard
Load Deviation
Demand Deviation
30,1805,274
32,041
5,103
32,6786,457
33,9696,557
36,727
6,428
38,775
6,554
41,787
8,999
44,80810,03371,93913,60378,745
13,79877,232
12,003
83,606
12,377
81,11013,49986,557
13,81978,685
12,81985,81913,24275,991
12,89981,062
13,253
78,106
13,64383,75814,22778,823
13,931
84,28814,046
84,946
13,941
89,638
13,84886,897
13,871
91,19913,84890,52916,26696,18916,147
90,586
16,192
94,782
16,58985,80014,51789,746
14,79884,56913,67089,477
13,63888,847
14,68392,352
14,81886,297
14,03891,262
14,303
81,255
13,191
86,344
13,13385,95814,26990,96015,221

Year to Year Change
Load
Load Plus Exports
Standard
Standard
Load Deviation
Demand Deviation
NA
NA
NA
NA
8.3%
22.4%
6.0%
28.5%
12.4%
(0.4%)
14.1%(0.0%)
13.8%
40.0%
15.6%
53.1%
72.2%
51.2%
75.7%
37.5%
7.4%
(11.8%)
6.2%(10.3%)
5.0%
12.5%
3.5%
11.6%
(3.0%)(5.0%)(0.9%)(4.2%)(3.4%)
0.6%(5.5%)
0.1%
2.8%
5.8%
3.3%
7.3%
0.9%
2.1%
0.6%
(1.3%)
7.8%
0.1%
6.3%
(1.4%)
2.3%(0.5%)
1.7%
0.0%
4.2%
17.3%
5.5%
16.6%
0.1%
(0.5%)(1.5%)
2.7%(5.3%)(10.3%)(5.3%)(10.8%)(1.4%)(5.8%)(0.3%)(7.8%)
5.1%
7.4%
3.2%
8.7%
(2.9%)(4.4%)(1.2%)(3.5%)(5.8%)(6.0%)(5.4%)(8.2%)
5.8%
8.2%
5.3%
15.9%

Figure 3-11 Real-time monthly average hourly load plus exports: January
2020 through June 2021
160,000
Max - Min 2016 - 2020

150,000

2020
2021

140,000
130,000

Demand (MWh)Table 3-7 Real-time average hourly load and load plus exports: January
through June, 2001 through 2021

120,000
110,000
100,000

90,00080,00070,00060,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

20 Accounting load is used because accounting load is the load customers pay for in PJM settlements. The use of accounting load withlosses before June 1, and without losses after June 1, 2007, is consistent with PJM’s calculation of LMP. Before June 1, 2007, transmission
losses were included in accounting load. After June 1, 2007, transmission losses were excluded from accounting load and losses wereaddressed through the incorporation of marginal loss pricing in LMP.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 125

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-12 compares the real-time, average daily load in 2020 and the firstsix months of 2021, with the historic five year range.
Figure 3-12 Real-time daily load: January 2020 through June 2021
4,000,000
Max-Min 2016-2020

2020

2021

Q2 Cumulative Change in PJM Load: 2020 to 2021: 5.9%
Peak Hour Load Change: 5.7%
Off Peak Hour Load Change: 6.2%

3,500,000

Load (MWh)3,000,000

2,500,000

2020
2021
Percent Change
Heating Degree Cooling Degree Heating Degree Cooling Degree Heating Degree Cooling Degree
Days
Days
Days
Days
Days
Days
Jan
698
0
816
0
16.9%
0.0%
Feb
652
0
822
0
26.1%
0.0%
Mar
385
0
405
0
5.3%
0.0%
Apr
279
0
203
8
(27.2%)
0.0%
May
105
59
77
82
(26.7%)
37.8%
Jun
0
262
0
283
0.0%
8.1%
Jul
0
464
Aug
0
342
Sep
13
120
Oct
139
1
Nov
313
0
Dec
719
0
Jan-Jun
2,118
321
2,323
373
9.7%
16.1%

Figure 3-13 shows the real-time daily load and the weather normalized loadfor 2020 through the first six months of 2021.

2,000,000

1,500,000

1,000,000

Table 3-8 Heating and cooling degree days: January 2020 through June 2021

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Weather normalized load is calculated using the historic relationship between
PJM daily load and HDD, CDD, and time of year for 2015 through 2018.
Figure 3-13 shows that from March through May 2020, the actual load wassignificantly less than the weather normalized load. The difference was a
result of changes in the pattern and level of activity due to COVID-19 andassociated policy responses.

PJM real-time load is significantly affected by weather conditions. Table 3-8
compares the PJM monthly heating and cooling degree days in 2020 and thefirst six months of 2021.21 Heating degree days increased 9.7 percent, andcooling degree days increased 16.1 percent compared to the first six monthsof 2020.
21 A heating degree day is defined as the number of degrees that a day’s average temperature is below 65 degrees F (the temperature below
which buildings need to be heated). A cooling degree day is the number of degrees that a day’s average temperature is above 65 degrees
F (the temperature when people will start to use air conditioning to cool buildings). PJM uses 60 degrees F for a heating degree day asstated in Manual 19.
Heating and cooling degree days are calculated by weighting the temperature at each weather station in the individual transmission
zones using weights provided by PJM in Manual 19. Then the temperature is weighted by the real-time zonal accounting load for eachtransmission zone. After calculating an average hourly temperature across PJM, the heating and cooling degree formulas are used to
calculate the daily heating and cooling degree days, which are summed for monthly reporting. The weather stations that provided thebasis for the analysis are ABE, ACY, AVP, BWI, CAK, CLE, CMH, CRW, CVG, DAY, DCA, ERI, EWR, FWA, IAD, ILG, IPT, LEX, ORD, ORF, PHL, PIT,
RIC, ROA, TOL and WAL.

126

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Figure 3-13 Real-time daily load and weather normalized load: January 2020
through June 2021
3,500,000
Actual Load

Weather Normalized Load

3,000,000

Load (MWh)2,500,000

Table 3-9 Actual load and weather normalized load: January 2020 throughJune 2021

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan - Jun

2,000,000

1,500,000

1,000,000
Jan-20

Table 3-9 compares the total monthly actual load and weather normalized
load. The gap between actual load and weather normalized load in the first six
months of 2021 is significantly smaller than in the first six months of 2020.

Mar-20May-20Jul-20

Sep-20Nov-20Jan-21

Mar-21

Actual Load
66,905,774
61,717,353
58,258,178
50,864,950
53,430,088
63,666,037
78,749,183
72,425,029
58,683,018
55,061,813
55,993,432
67,232,280
354,842,381

2020
Weather
Normalized
Load
68,256,113
62,471,212
60,459,812
55,116,626
57,904,128
67,406,845
80,856,404
74,173,773
60,988,913
56,572,150
57,678,640
67,074,317
371,614,736

Percent
Difference(2.0%)(1.2%)(3.6%)(7.7%)(7.7%)(5.5%)(2.6%)(2.4%)(3.8%)(2.7%)(2.9%)
0.2%(4.5%)

Actual Load
69,303,496
64,761,103
60,002,018
54,010,529
57,460,157
67,779,457

2021
Weather
Normalized
Load69,689,108
64,275,946
61,459,726
55,580,210
59,183,412
68,488,450

Percent
Difference(0.6%)
0.8%(2.4%)(2.8%)(2.9%)(1.0%)

373,316,760

378,676,852(1.4%)

May-21

Day-Ahead Demand
PJM average hourly day-ahead demand in the first six months of 2021,
including DECs and UTCs, decreased by 6.8 percent from the first six monthsof 2020, from 104,164 MWh to 97,083 MWh. When exports are added, PJM
average hourly day-ahead demand in the first six months of 2021 decreased
by 6.7 percent from the first six months of 2020, from 107,293 MWh to
100,060 MWh.
In the PJM Day-Ahead Energy Market, there are five types of financiallybinding demand bids:• Fixed-Demand Bid. Bid to purchase a defined MWh level of energy,
regardless of LMP.

• Price-Sensitive Bid. Bid to purchase a defined MWh level of energy only
up to a specified LMP, above which the load bid is zero.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 127

2021 Quarterly State of the Market Report for PJM: January through June

• Decrement Bid (DEC). Financial bid to purchase a defined MWh level ofenergy up to a specified LMP, above which the bid is zero.

• Up to Congestion Transaction (UTC). A conditional transaction that permits

a market participant to specify a maximum price spread between thetransaction source and sink. An up to congestion transaction is evaluatedas a matched pair of an injection and a withdrawal.

PJM Day-Ahead Demand Duration
Figure 3-14 shows the hourly distribution of PJM day-ahead demand for the
first six months of 2020 and 2021.
Figure 3-14 Distribution of day-ahead demand plus exports: January throughJune, 2020 and 202122• Export. An external energy transaction scheduled from PJM to another

PJM day-ahead demand is the total of the five types of cleared demand bids.

2020 Jan - Jun

800

2021 Jan - Jun

700
600

Hours

balancing authority. An export must have a valid willing to pay
congestion (WPC) OASIS reservation when offered. There is no link
between transactions submitted in the PJM Day-Ahead Energy Market
and the PJM Real-Time Energy Market, so an export energy transaction
approved in the day-ahead energy market will not physically flow inreal time unless it is also submitted through the real-time energy market
scheduling process.

900

500
400
300
200

235-240225-230

215-220205-210

195-200

185-190

175-180

Range (GWh)

165-170

155-160

145-150

135-140

125-130

115-12095-100105-110

85-90

75-80

65-70

0-50

0

55-60

100

22 Each range on the horizontal axis excludes the start value and includes the end value.

128

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

PJM Day-Ahead, Average Demand

PJM Day-Ahead, Monthly Average Demand

Table 3-10 shows day-ahead hourly demand for the first six months of 2001
through 2021. The monthly average hourly demand in first six months of2021, with and without exports, is lower than any year since 2010, as a resultof the reduction in UTC transaction volumes.

Figure 3-15 compares the day-ahead, monthly average hourly demand,
including decrement bids and up to congestion transactions in 2020 and firstsix months of 2021 with the historic five-year range.

Jan-Jun
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

PJM Day-Ahead Demand (MWh)DemandDemand Plus Exports
Standard
Standard
Demand Deviation
Demand Deviation
32,425
6,014
33,075
5,857
37,561
8,293
37,607
8,311
44,391
7,717
44,503
7,704
50,161
10,30450,596
10,55786,89014,67789,38814,827
94,47012,92597,46013,303
104,737
15,019107,647
15,269100,948
14,255
104,499
14,461
95,13015,87898,001
15,972
99,691
18,097
103,573
18,366
105,071
16,452
108,756
16,578129,881
15,268133,046
15,436145,280
15,552
148,414
15,588160,805
13,872
164,740
13,800111,750
18,076
115,117
18,477
124,542
19,750127,461
19,991
128,690
18,440131,976
18,746108,950
20,548111,451
20,718110,890
15,994
113,738
16,323
104,164
15,680107,293
15,84597,083
16,637100,060
17,277© 2021 Monitoring Analytics, LLC

Year to Year Change
DemandDemand Plus Exports
Standard
Standard
Demand Deviation
Demand Deviation
NA
NA
NA
NA
15.8%
37.9%
13.7%
41.9%
18.2%
(6.9%)
18.3%(7.3%)
13.0%
33.5%
13.7%
37.0%
73.2%
42.4%
76.7%
40.4%
8.7%
(11.9%)
9.0%(10.3%)
10.9%
16.2%
10.5%
14.8%
(3.6%)(5.1%)(2.9%)(5.3%)(5.8%)
11.4%(6.2%)
10.4%
4.8%
14.0%
5.7%
15.0%
5.4%
(9.1%)
5.0%(9.7%)
23.6%(7.2%)
22.3%(6.9%)
11.9%
1.9%
11.6%
1.0%
10.7%
(10.8%)
11.0%(11.5%)(30.5%)
30.3%(30.1%)
33.9%
11.4%
9.3%
10.7%
8.2%
3.3%
(6.6%)
3.5%(6.2%)(15.3%)
11.4%(15.6%)
10.5%
1.8%(22.2%)
2.1%(21.2%)(6.1%)(2.0%)(5.7%)(2.9%)(6.8%)
6.1%(6.7%)
9.0%

Figure 3-15 Day-ahead monthly average hourly demand plus exports: January
2020 through June 2021
160,000
Max - Min 2016 - 2020

150,000

2020
2021

140,000
130,000

Demand (MWh)Table 3-10 Average hourly day-ahead demand and day-ahead demand plus
exports: January through June, 2001 through 2021

120,000
110,000
100,000

90,00080,00070,00060,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

2021 Quarterly State of the Market Report for PJM: January through June 129

2021 Quarterly State of the Market Report for PJM: January through June

Real-Time and Day-Ahead Demand
Table 3-11 presents summary statistics for the first six months of 2020 and 2021 day-ahead and real-time demand. The last two columns of Table 3-11 are
the day-ahead demand minus the real-time demand: the first column is the total physical day-ahead load (fixed demand plus price-sensitive demand) less thephysical real-time load; and the second column is the total day-ahead demand less the total real-time demand. The data show the impact of the reduction in
UTC bids on day-ahead demand.
Table 3-11 Cleared day-ahead and real-time demand (MWh): January through June, 2020 and 2021
Day-Ahead
Jan-JunAverage
MedianStandard Deviation
Peak Average
Peak MedianPeak Standard Deviation
Off-Peak Average
Off-Peak Median
Off-Peak Standard Deviation

130

Year
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021

Section 3 Energy Market

Fixed
Demand79,90883,61778,27682,387
12,832
13,49286,65390,361
86,061
89,582
11,337
11,522
73,95077,68872,54675,54010,997
12,258

Price
Sensitive
1,099
1,393
1,112
1,408
226
250
1,199
1,537
1,233
1,560
247
222
1,011
1,267
1,027
1,291
161
200

DEC Bids
3,606
4,218
3,186
3,758
1,864
1,878
4,277
4,774
3,878
4,406
2,038
1,879
3,014
3,729
2,721
3,317
1,458
1,737

Up-to
Congestion
19,551
7,855
19,408
7,663
3,687
2,835
20,5098,918
20,287
8,668
3,786
2,613
18,705
6,920
18,521
6,632
3,379
2,691

Real-Time
Exports
3,129
2,977
3,121
2,661
687
1,123
3,225
3,192
3,200
2,828
682
1,228
3,044
2,787
3,044
2,565
681
984

Total
Demand107,293
100,060
105,117
98,24915,845
17,277
115,864
108,782
113,650
106,857
14,672
14,75399,724
92,391
98,77489,72812,672
15,619Load81,25585,95879,05984,601
13,191
14,26987,79092,59786,85591,304
12,12012,77375,48480,121
74,111
78,191
11,26812,901

Total
Demand86,34490,96084,15189,037
13,133
15,221
92,884
97,89391,47996,03012,195
13,82380,56784,864
79,27582,624
11,061
13,712

Day-Ahead Less
Real-Time
Load
(248)
(948)
329
(806)
(133)
(527)
62
(699)
438
(162)
(536)
(1,029)(523)(1,167)(538)(1,360)
(111)
(442)

Demand20,950
9,100
20,967
9,212
2,712
2,056
22,98010,88922,172
10,8272,477
930
19,157
7,527
19,500
7,104
1,610
1,906

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Figure 3-16 shows the average hourly cleared volumes of day-ahead demand
and real-time demand for the first six months of 2021. The day-ahead demand
includes day-ahead load, decrement bids, up to congestion transactions, andday-ahead exports. The real-time demand includes real-time load and realtime exports.

Figure 3-17 shows the difference between the day-ahead and real-time
average daily demand for 2020 and the first six months of 2021.
Figure 3-17 Difference between day-ahead and real-time demand (Average
daily volumes): January 2020 through June 2021
50,000Figure 3-16 Day-ahead and real-time demand (Average hourly volumes):
January through June, 2021

40,000140,000
30,000Volume (MWh)120,000

Volume (MWh)100,000
80,00020,00010,00060,000040,000-10,000

20,0000-20,000
Jan-20

1

2

3

4

5

6

7

8

9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour Ending (EPT)

Real-time load
Day-ahead fixed demand plus price sensitive demand
Day-ahead DEC bids

© 2021 Monitoring Analytics, LLC

May-20

Sep-20Jan-21

May-21

Total Day-Ahead Demand Minus Total Real-Time Demand
Total Physical Day-Ahead Load Minus Total Physical Real-Time Load

Real-time exports
Day-ahead exports
Day-ahead up to congestion transactions

2021 Quarterly State of the Market Report for PJM: January through June 131

2021 Quarterly State of the Market Report for PJM: January through June

Market Behavior
Generator Offers
Generators indicate the commitment status and the dispatch status of their units in the day-ahead through their offers. For example, units that select must run
status in the offer will run the unit in the day-ahead market regardless of market signals. Units may commit at economic minimum and permit the balance tobe dispatchable or block load the full output of the unit. If units do not select must run status, the day-ahead market will commit and dispatch them based on
their offers.
The Must Run column in Table 3-12 is the economic minimum MW of units offering with must run commitment status. The Eco Min column in Table 3-12
is the economic minimum MW of units offering with economic commitment status. The dispatchable range of Table 3-12 shows the percent of MW offeredby price range, between the economic minimum MW and economic maximum MW. Units can designate all or a portion of their capacity as emergency MW.
Table 3-12 shows that 0.6 percent of offered MW are emergency MW. In some cases, higher shares of emergency MW is a result of offer behavior and does notnecessarily represent the actual availability of the emergency MW in real time. Some units, like wind and solar, offer a dispatchable range in the day-aheadmarket although their availability in real time is determined by the presence of sun and wind and are therefore generally not capable of following dispatch
across the entire range in real-time.
In the day-ahead market in the first six months of 2021, 19.6 percent of MW were offered as must run, 28.0 percent were the economic minimum MW for
dispatchable units, 51.7 percent were offered as a dispatchable range, and 0.6 percent were offered as emergency maximum MW.
Table 3-12 Dispatchable status of day-ahead energy offers: January through June, 2021
Unit TypeCCCT
DieselHydro
Nuclear
Solar
Steam - Coal
Steam - Other
Wind
Other
Total

132

Must
Run
6.7%
0.3%
0.0%
89.9%
83.2%
18.0%
20.5%
4.1%
6.3%
18.3%
19.6%

Eco Min
30.5%
53.4%
100.0%
0.0%
6.3%
0.1%
19.2%
22.8%
0.9%
41.7%
28.0%

($300) $0
0.0%
0.0%
0.0%
6.8%
4.1%
62.5%
0.0%
1.1%
84.3%
2.9%
2.1%

Section 3 Energy Market$0 $25
32.5%
3.4%
0.0%
3.3%
6.4%
18.4%
30.9%
3.5%
7.0%
7.6%
19.3%

$25 $50
20.3%
18.9%
0.0%
0.0%
0.0%
0.2%
24.7%
32.9%
1.3%
3.0%
18.6%

$50 $75
3.2%
4.4%
0.0%
0.0%
0.0%
0.3%
2.3%
1.9%
0.2%
3.1%
2.6%

Dispatchable Range$75 $100 $100
$200
1.7%
3.7%
1.6%
12.5%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.5%
0.5%
0.2%
1.0%
23.9%
0.0%
0.0%
1.2%
15.0%
1.1%
6.0%

$200 $400
0.7%
3.9%
0.0%
0.0%
0.0%
0.0%
0.1%
8.3%
0.0%
3.4%
1.8%

$400 $600
0.0%
0.4%
0.0%
0.0%
0.0%
0.0%
1.0%
0.0%
0.0%
0.0%
0.3%

$600 $800
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

$800 - Emergency
$1000
MW
0.0%
0.6%
0.0%
1.2%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.6%
0.0%
0.4%
0.0%
0.0%
0.0%
3.8%
0.0%
0.6%

Dispatchable
Percent
62.2%
45.1%
0.0%
10.1%
10.5%
81.9%
59.6%
72.8%
92.8%
36.2%
51.7%

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Hourly Offers and Intraday Offer Updates
All participants may make hourly offers. Participants must opt in on a monthly
basis to make intraday offer updates. Participants that have opted in can makeupdates only based on the process defined in their fuel cost policies. Table
3-13 shows the daily average number of units that make hourly offers, that
opted in to intraday offer updates and that make intraday offer updates. In thefirst six months of 2021, an average of 318 units per day made hourly offers,
an increase of 18 units from 2020. In the first six months of 2021, 425 units
opted in for intraday offer updates, an increase of 30 units from 2020. In thefirst six months of 2021, an average of 134 units made intraday offer updates
each day, an increase of six units from 2020.
Table 3-13 Daily average number of units making hourly offers, opted in for
intraday offers and making intraday offer updates: January through June,
2020 and 2021
Hourly Offers

Opt InIntraday Offer Updates

Fuel Type
Natural Gas
Other Fuels
Total
Natural Gas
Other Fuels
Total
Natural Gas
Other Fuels
Total

2020
283
17
300
347
48
395
123
5
128

2021
296
22
318
362
63
425
129
5
134

Difference
13
5
18
15
15
30
6
0
6

ICAP Must Offer Requirement
Generation capacity resources are required to offer their full ICAP MW into
the day-ahead and real-time energy market, or report an outage for thedifference.23 The full installed capacity (ICAP) is the ICAP of the resourcesthat cleared in the capacity market. This is known as the ICAP must offer
requirement.
Solar, wind, landfill gas, hydro and batteries can satisfy the must offer
requirement by self scheduling or offering as dispatchable. There is no defined
amount of capacity that these resources must offer. The must offer requirement
23 OA Schedule 1 § 1.10.1A(d).

© 2021 Monitoring Analytics, LLC

is thus not applied to these intermittent resource types and compliance is notenforceable.
The current enforcement of the ICAP must offer requirement is inadequate.
The problem is a complex combination of generator behavior, and inadequate
and inconsistent reporting tools that are not synchronized. Compliance issubject to mistakes and susceptible to manipulation.
Resources are required to submit their available capacity in three different
systems. Resources are required to make offers in the energy market. Resources
are required to report outages in the Dispatch Application Reporting Tool(eDART) in advance or in real time. Resources are required to report outages
in the Generator Availability Data System (eGADS) after the fact. The three
applications are not linked in a systematic way to ensure consistency.
Ambient derates are an example issue. When the weather is hotter than test
conditions, the capacity of some units is reduced below the ICAP levels. While
this fact may be reported by unit owners in eDART and reflected in lower
offered MW in the energy market, the derates are never reported as outages in
eGADS and are therefore not outages for purposes of defining capacity using
EFORd.
The MMU recommends that PJM enforce the ICAP must offer requirementby assigning a forced outage to any unit that is derated in the energy market
below its committed ICAP without an outage that reflects the derate.
The MMU recommends that intermittent resources be subject to an enforceable
ICAP must offer rule that reflects the limitations of these resources.
Table 3-14 shows average hourly MW, for each month, that violated the ICAP
must offer requirement in the first six months of 2021. On average for all
hours, 1,759 MW did not meet the ICAP must offer requirement, but for 10
percent of the hours 3,805 MW did not meet the must offer requirement. These
MW levels are larger than the reserve shortages that triggered scarcity pricing
in the first six months of 2021 and larger than most supply contingencies that
led to synchronized reserve events in the first six months of 2021.
2021 Quarterly State of the Market Report for PJM: January through June 133

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-14 Average hourly estimated capacity (MW) failing the ICAP must
offer requirement: January through June, 2021
Month
Jan-21
Feb-21
Mar-21
Apr-21
May-21
Jun-21
2021

90th Percentile
958
1,139
2,194
5,160
3,347
1,949
3,805

Average
494
683
1,491
4,040
2,575
1,221
1,759

10th Percentile
97
242
554
2,772
1,986
628
311

The outage data reported in eGADS do not exactly match the Energy Market
data submitted in Markets Gateway. For example, economic maximum MW
levels submitted in Markets Gateway that reflect expected ambient conditions(including ambient derates) can be inconsistent with the maximum capability
submitted in eGADS. Another example is the start and end times of planned
outages in the shoulder months. In many situations units are derated inMarkets Gateway to reflect an upcoming planned outage for which the unit
must ramp down over an extended period but in eGADS the outage start time
is not reported until the unit is completely unavailable. These differences canresult in units not meeting their ICAP must offer requirement.

Emergency Maximum MW
Generation resources are offered with economic maximum MW and emergency
maximum MW. The economic maximum MW is the output level the resource
can achieve following economic dispatch. The emergency maximum MW
is the output level the resource can achieve when emergency conditions
are declared by PJM. The MW difference between the two ratings equals
emergency maximum MW. The PJM market rules allow generators to include
emergency maximum MW as part of ICAP offered in the capacity market.24
Generation resources have to meet one of four conditions to offer any MW as
emergency in the energy market: environmental limits imposed by a federal,state or other governmental agency that significantly limit availability; fuellimits beyond the control of the generation owner; temporary emergency
24 See 151 FERC ¶ 61, 208 at P 476 (2015).

134

Section 3 Energy Market

conditions that significantly limit availability; or temporary MW additions
not ordinarily available.25
The MMU recommends that capacity resources not be allowed to offer any
portion of their capacity market obligation as maximum emergency energy.26
Capacity resources should offer their full output in the energy market andsubject to economic dispatch. The result will be incentives for correct reportingof ICAP, more efficient energy market pricing, and a reduction in the need for
manual overrides by PJM dispatchers during emergency conditions. Resourcesthat do have capacity that can only be achieved with extraordinary measures
could offer such capacity in the energy market but should not take on acapacity market obligation. The capacity performance rules in the capacity
market provide incentives for such output during PAI.
Table 3-15 shows average hourly maximum emergency MW, for each month.
The levels of maximum emergency MW change hourly, daily and seasonally.
For example, 10 percent of hours in January 2021 had maximum emergency
MW greater than or equal to 2,966 MW while 10 percent of hours in January
2021 had maximum emergency MW less than 1,778 MW. The hourly average,in the first six months of 2021, was 2,115 MW offered as maximum emergency,
6.3 percent lower than in 2020.
Table 3-15 Maximum emergency MW by month: January through June, 2021
Month
Jan-21
Feb-21
Mar-21
Apr-21
May-21
Jun-21
2021

90th Percentile
2,966
2,887
2,999
2,678
2,345
2,737
2,830

Average
2,310
2,304
2,262
2,049
1,793
1,985
2,115

10th Percentile
1,778
1,765
1,638
1,556
1,306
1,517
1,536

25 OA Schedule 1 § 1.10.1A (d)26 This recommendation was accepted by PJM and filed with FERC in 2014 as part of the capacity performance updates to the RPM. See
PJM Filing, Attachment A (Redlines of OA Schedule 1 § 1.10.1A(d), EL15-29-000 (December 12, 2014). FERC rejected the proposed change.
See 151 FERC ¶ 61,208 at P 476 (2015).

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Parameter Limited Schedules
Cost-Based Offers
All resources in PJM are required to submit at least one cost-based offer.
For the 2020/2021 Delivery Year, PJM procured only capacity performance
resources. Cost-based offers, submitted by capacity resources for a defined setof technologies, are parameter limited based on unit specific parameter limits.
Nuclear, wind, solar and hydro units are not subject to parameter limits.

Price-Based Offers
All capacity resources that choose to offer price-based offers are required tomake available at least one price-based parameter limited offer (referred toas price-based PLS). For resources that are not capacity resources, the pricebased parameter limited schedule is used by PJM for committing generation
resources when a maximum emergency generation alert is declared. For
capacity performance resources, the price-based parameter limited schedule
is used by PJM for committing generation resources when hot weather alerts
and cold weather alerts are declared.
The MMU recommends that in order to ensure effective market power
mitigation, PJM always enforce parameter limited values when the TPS test is
failed and during high load conditions such as cold and hot weather alerts andemergency conditions.27 Instead of ensuring that parameter limits apply, PJM
chooses the lower of the price-based schedule and the price-based parameter
limited schedule during hot and cold weather alerts. Instead of ensuring thatparameter limits apply, PJM chooses the lower of the price-based scheduleand the cost-based parameter limited schedule when a resource fails the TPS
test. The current implementation is not consistent with the goal of having
parameter limited schedules, which is to prevent the use of inflexible operating
parameters to exercise market power. The Commission recognized this flaw in
the implementation of market power mitigation in its order to show cause,issued June 17, 2021.28
27 See Protest of the Independent Market Monitor for PJM, Docket No. ER20-995 (February 25, 2020).
28 See 175 FERC ¶ 61,231 (June 17, 2021).

© 2021 Monitoring Analytics, LLC

The MMU analyzed the extent of parameter mitigation in the day-ahead energy
market when units are committed after failing the TPS test for transmission
constraints in the first six months of 2021. The analysis includes units withtechnologies that are subject to parameter limits and offer both price-basedand cost-based schedules.29 Table 3-16 shows the number and percentage ofday-ahead unit run hours that failed the TPS test but were committed on priceschedules. Table 3-16 shows that 35.1 percent of unit hours for units thatfailed the TPS test were committed on price-based schedules that were lessflexible than their cost-based schedules. For effective market power mitigation
there would be zero units that fail the TPS test committed with parameters lessflexible than their cost-based schedules.
Table 3-16 Parameter mitigation for units failing TPS test: January throughJune, 2021
Day-ahead Commitment For Units That Failed TPS Test
Committed on price schedule less flexible than cost
Committed on price schedule as flexible as cost
Total committed on price schedule without parameter limits
Committed on cost (cost capped)
Committed on price PLS
Total committed on PLS schedules (cost or price PLS)

Day-ahead Unit
Hours
15,744
3,926
19,67024,952
185
25,137

Percent Day-ahead
Unit Hours
35.1%
8.8%
43.9%
55.7%
0.4%
56.1%

The MMU analyzed the extent of parameter mitigation in the day-aheadenergy market for units in regions where a cold weather alert or a hot weather
alert was declared in the first six months of 2021. PJM declared cold weather
alerts on six days and hot weather alerts on six days in the first six monthsof 2021.30 The analysis includes units with technologies that are subject toparameter limits, with a CP commitment, in the zones where the cold or hot
weather alerts were declared. Table 3-17 shows that 31.8 percent of unit hours
in the day-ahead energy market were committed on price-based schedules
that were less flexible than their price PLS schedules.31 For effective market
power mitigation there would be zero units committed during cold and hot
weather alerts with parameters less flexible than their price PLS schedules.
29 Nuclear, wind, solar and hydro units are not subject to parameter limits.
30 2021 Quarterly State of the Market Report for PJM: January through June, Section 3: Energy Market, at Emergency Procedures.
31 Nuclear, wind, solar and hydro units are not subject to parameter limits.

2021 Quarterly State of the Market Report for PJM: January through June 135

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-17 Parameter mitigation during weather alerts: January throughJune, 2021
Day-ahead Commitment During Hot And Cold Weather
AlertsCommitted on price schedule less flexible than PLS
Committed on price schedule as flexible as PLS
Total committed on price schedule without parameter limits
Committed on cost (cost capped)
Committed on price PLS
Total committed on PLS schedules (cost or price PLS)

Day-ahead Unit
Hours
9,796
2,058
11,854573
18,39918,972

Percent Day-ahead
Unit Hours
31.8%
6.7%
38.5%
1.9%
59.7%
61.5%

Currently, there are no rules in the PJM tariff or manuals that limit the markup
attributes of price-based PLS offers. The intent of the price-based PLS offer
is to prevent the exercise of market power during high demand conditions
by preventing units from offering inflexible operating parameters in order
to extract higher market revenues or higher uplift payments. However, agenerator can include a higher markup in the price-based PLS offer than in
the price-based non-PLS schedule. The result is that the offer is higher andmarket prices are higher as a result of the exercise of market power using the
PLS offer. This defeats the purpose of requiring price-based PLS offers.
The MMU recommends that in order to ensure effective market power mitigation
when the TPS test is failed and during high load conditions such as cold andhot weather alerts or more severe emergencies, the operating parameters in
the cost-based offer and the price-based parameter limited schedule (PLS)
offer be at least as flexible as the operating parameters in the available nonPLS price-based offer, and that the price-MW pairs in the price-based PLS
offer be exactly equal to the price-based non-PLS offer. This recommendation
would ensure that market power that results from inflexible parameters is
mitigated during high load conditions and when a market seller fails the TPS
test, consistent with the goal of having parameter limited schedules.

Parameter Limits
Beginning June 1, 2020, all capacity resources, including resources in
FRR capacity plans, are capacity performance resources. The unit specificparameter limits for capacity performance resources are based on default

136

Section 3 Energy Market

minimum operating parameter limits posted by PJM by technology type,and any adjustments based on a unit specific review process. These default
parameters were based on analysis by the MMU.
The PJM tariff specifies that all generation capacity resources, regardless of thecurrent commitment status, are subject to parameter limits on their cost-based
offers. However, the tariff currently does not make it clear what parameter
limit values are applicable for resources without a capacity commitment. The
MMU recommends that PJM update the tariff to clarify that all generation
resources are subject to unit specific parameter limits on their cost-based
offers using the same standard and process as capacity performance resources.

Unit Specific Adjustment Process
Market participants can request an adjustment to the default values ofparameter limits for capacity performance resources by submitting supporting
documentation which is reviewed by PJM and the MMU. The default minimum
operating parameter limits or approved adjusted values are used by capacity
performance resources for their parameter limited schedules.
PJM has the authority to approve adjusted parameters with input from the
MMU. PJM has inappropriately applied different review standards to coal units
than to CTs and CCs despite the objections of the MMU. PJM has approved
parameter limits for boiler based steam units based on historical performanceand existing equipment while holding CTs and CCs to higher standards basedon OEM documentation and a best practices equipment configuration.
The PJM process for the review of unit specific parameter limit adjustments
is generally described in Manual 11: Energy and Ancillary Services Market
Operations. The standards used by PJM to review the requests are currently
not described in the tariff or PJM manuals. The MMU recommends that PJM
clearly define the business rules that apply to the unit specific parameter
adjustment process, including PJM’s implementation of the tariff rules in
the PJM manuals to ensure market sellers know the requirements for theirresources.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Only certain technology types are subject to limits on operating parametersin their parameter limited schedules.32 Solar units, wind units, run of riverhydro units, and nuclear units are currently not subject to parameter limits.
The MMU analyzed, for the units that are subject to parameter limits, theproportion of units that use the default limits published by PJM and the
proportion of units that have been provided unit specific adjustments forsome of the parameters. Table 3-18 shows, for the delivery year beginning
June 1, 2021, the number of units that submitted and had approved unit
specific parameter limit adjustments, and the number of units that used thedefault parameter limits published by PJM.
Table 3-18 Adjusted unit specific parameter limit statistics: 2021/2022
Delivery Year
Technology Classification
Aero CT
Frame CT
Combined Cycle
Reciprocating Internal Combustion Engines
Solid Fuel NUG
Oil and Gas Steam
Subcritical Coal SteamSupercritical Coal Steam
Pumped Storage

Units Using
Default Parameter
Limits
126
171
87
68
35
8
7
3
8

Units with One
or More Adjusted
Parameter Limits
40
102
32
4
6
13
57
38
0

Percent of Units with
One or More Adjusted
Parameter Limits
24.1%
37.4%
26.9%
5.6%
14.6%
61.9%
89.1%
92.7%
0.0%

Real-Time Values
The Commission rejected PJM’s proposed revisions to add RTV rules to thetariff in an order issued on May 28, 2021. In its order, the Commission
recognized that RTVs can be used to exercise market power by withholding
generation and avoiding market power mitigation.33
The real-time values submittal process was never defined in the PJM Operating
Agreement. The process was defined only in PJM Manual 11. While there are
32 For the default parameter limits by technology type, see PJM. “Unit-Specific Minimum Operating Parameters for Capacity Performanceand Base Capacity Resources,” which can be accessed at <https://www.pjm.com/~/media/committees-groups/committees/elc/
postings/20150612-june-2015-capacity-performance-parameter-limitations-informational-posting.ashx>.
33 175 FERC ¶ 61,171 (2021).

© 2021 Monitoring Analytics, LLC

a number of options for providing real time unit status to PJM operators, PJM
created a mechanism for the submission of such values called real-time values(RTVs). Unlike parameter exceptions, the use of real-time values made a unit
ineligible for make whole payments, unless the market seller could justify
such operation based on an actual constraint.34 In the case of the notification
time parameter, start time parameter, minimum run time and minimum downtime parameters, a longer real-time value decreases the likelihood of theunit being committed, making the RTV a mechanism for exercising market
power through withholding and for failing to meet the obligations of capacity
resources. There were no defined negative consequences to market sellers forthe use of real time values to withhold generation in the PJM market rules.
Currently, a resource that is staffed or has remote start capability and offers
according to its physical capability, and a resource that makes the economic
choice not to staff or invest in remote start and economically or physicallywithholds to decrease the likelihood of commitment, are compensatedidentically in the capacity market. If a market seller makes an economic
decision to not staff the unit or to not have remote start capability, and uses
real-time values to communicate the longer time to start to PJM, the unit’s
actual parameters are not recognized as inconsistent with its obligations
as a capacity resource, not reflected in forced outages, and not reflected ineligibility for uplift payments. The market seller is able to withhold the unit
in the energy market with no defined consequence, while other similarly
situated units incur the costs associated with meeting their obligations. Suchwithholding is an exercise of market power.
PJM’s proposed RTV mechanism was rejected by the Commission because
it would weaken the existing market power mitigation rules including
parameter limited schedules.35 PJM’s practice of allowing units to use real timevalues, which was not a tariff defined mechanism, continued to undermine
parameter mitigation by allowing resources to use inflexible parameters on
their parameter limited schedules, for economic reasons, without any definedconsequence. PJM’s practice of units using real time values to increase theirnotification time continued to allow physical withholding and avoiding
34 See OA Schedule 1 § 3.2.3(e).
35 Id. at P 36.

2021 Quarterly State of the Market Report for PJM: January through June 137

2021 Quarterly State of the Market Report for PJM: January through June

commitment. The MMU recommends that PJM institute rules that would not
pay a share of capacity market revenue to resources that choose to submit
real-time values that are less flexible than their unit specific parameter limits
or approved parameter limit exceptions based on tariff defined reasons.

Generator Flexibility Incentives under Capacity Performance
In its June 9, 2015, order on capacity performance, the Commission determinedthat capacity performance resources should be able to reflect actual constraints
based on not just the resource physical constraints, but also other constraints,
such as contractual limits that are not based on the physical characteristicsof the generator.36 The Commission directed that capacity performance
resources with parameters based on nonphysical constraints should receive
uplift payments.37 The Commission directed PJM to submit tariff language
to establish a process through which capacity performance resources that
operate outside the defined unit specific parameter limits can justify suchoperation and therefore remain eligible for make whole payments.38
A primary goal of the capacity performance market design is to assign
performance risk to generation owners and to ensure that capacity prices
reflect underlying supply and demand conditions, including the cost of taking
on performance risk. The June 9th Order’s determination on parameters is
not consistent with that goal. By permitting generation owners to establish
unit parameters based on nonphysical limits, the June 9th Order weakened
the incentives for units to be flexible and weakened the assignment of
performance risk to generation owners. Contractual limits, unlike generating
unit operational limits, are a function of the interests and incentives of theparties to the contracts. If a generation owner expects to be compensatedthrough uplift payments for running for 24 hours regardless of whether theenergy is economic or needed, that generation owner has no incentive to pay
more to purchase the flexible gas service that would permit the unit to beflexible in response to dispatch.

36 151 FERC ¶ 61,208 at P 437 (2015) (June 9th Order).
37 Id at P 439.
38 Id at P 440.

138

Section 3 Energy Market

The fact that a contract may be entered into by two willing parties does notmean that is the only possible arrangement between the two parties or that
it is consistent with an efficient market outcome or that such a contract canreasonably impose costs on customers who were not party to the contract. The
actual contractual terms are a function of the incentives and interests of theparties, who may be affiliates or have market power. The fact that a just andreasonable contract exists between a generation owner and a gas supplier does
not mean that it is appropriate or efficient to impose the resultant costs onelectric customers or that it incorporates an efficient allocation of performancerisk between the generation owner and other market participants.
The approach to parameters defined in the June 9th Order will increase energy
market uplift payments substantially. While some uplift is necessary andefficient in an LMP market, this uplift is not. Electric customers are not ina position to determine the terms of the contracts that resources enter into.
Customers rely on the market rules to create incentives that protect themby assigning operational risk to generators, who are in the best position toefficiently manage those risks.
The MMU recommends that capacity performance resources be held to the
OEM operating parameters of the capacity market reference resource used for
the Cost of New Entry (CONE) calculation for performance assessment andenergy uplift payments and that this standard be applied to all technologies
on a uniform basis. This solution creates the incentives for flexibility andpreserves, to the extent possible, the incentives to follow PJM’s dispatch
instructions during high demand conditions. The proposed operating
parameters should be based on the physical capability of the Reference
Resource used in the Cost of New Entry, currently two GE Frame 7FA turbineswith dual fuel capability. All resources that are less flexible than the reference
resource are expected to be scheduled and running during high demandconditions anyway, while the flexible CTs that are used as peaking plants
would still have the incentive to follow LMP and dispatch instructions. CCs
would also have the capability to be as flexible as the reference resource.
These units will be exempt from nonperformance charges and made whole aslong as they perform in accordance with their parameters. This ensures that© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

all the peaking units that are needed by PJM for flexible operation do notself schedule at their maximum output, and follow PJM dispatch instructions
during high demand conditions. If any of the less flexible resources need to bedispatched down by PJM for reliability reasons, they would be exempt from
nonperformance charges.
Such an approach is consistent with the Commission’s no excuses policy for
nonperformance because the flexibility target is set based on the optimal
OEM-defined capability for the marginal resource that is expected to meetpeak demand, which is consistent with the level of performance that customers
are paying for in the capacity market. Any resource that is less flexible is not
excused for nonperformance and any resource that meets the flexibility target
is performing according to the commitments made in the capacity market.
The June 9th Order pointed out that the way to ensure that a resource’s
parameters are exposed to market consequences is to not allow any parameter
limitations as an excuse for nonperformance. The same logic should apply
to energy market uplift rules. A resource’s parameters should be exposed
to market consequences and the resource should not be made whole if it
is operating less flexibly than the reference resource. Paying energy market
uplift on the basis of parameters consistent with the flexibility goals of thecapacity performance construct would ensure that performance incentives are
consistent across the capacity and energy markets and ensure that performancerisk is appropriately assigned to generation owners.

Parameter Impacts of Gas Pipeline Conditions
During extreme cold weather conditions, and recently, during hot weather
conditions, a number of gas fired generators request temporary exceptions
to parameter limits for their parameter limited schedules due to restrictions
imposed by natural gas pipelines. The parameters affected include notification
time, minimum run time (MRT) and turn down ratio (TDR, the ratio of economic
maximum MW to economic minimum MW). When pipelines issue critical
notices and enforce ratable take requirements, generators may, depending on
the nature of the transportation service purchased, be forced to nominate an© 2021 Monitoring Analytics, LLC

equal amount of gas for each hour in a 24 hour period, with penalties for
deviating from the nominated quantity. This leads to requests for 24 hour
minimum run times and turn down ratios close to 1.0, to avoid deviations
from the hourly nominated quantity. Table 3-19 shows the number of units,
and the installed capacity MW that submitted parameter exception requests
for a 24 hour minimum run time due to gas pipeline restrictions. In the firstsix months of 2021, there were 54 units in PJM, with a total installed capacityof 7,196 MW that requested a 24 hour minimum run time on their parameter
limited schedules based on pipeline restrictions.
Table 3-19 Units with 24 hour minimum run times due to gas pipeline
restrictions: January through June, 2017 to 202139
Year(Jan - Jun)
2017
2018
2019
2020
2021

Number of Units With 24 Hour Minimum
Run Time Exceptions
25
37
8
54

Installed Capacity (MW) With 24 Hour
Minimun Run Time Exceptions
3,627
5,616
3,448
7,196

Key parameters like startup and notification time were not included in the PLS
matrix in 2017 and prior periods, even though other parameters were subject
to parameter limits. Some resource owners notified PJM that they needed
extended notification times based on the claimed necessity for generation
owners to nominate gas prior to gas nomination cycle deadlines.
The MMU observed instances when generators submitted temporary
parameter exceptions based on claimed pipeline constraints even thoughthese constraints are based on the nature of the transportation service thatthe generator procured from the pipeline. In some instances, generators
requested temporary exceptions based on ratable take requirements stated inpipeline tariffs, even though the requirement is not enforced by the pipelines
on a routine basis. If a unit were to be dispatched uneconomically using
the inflexible parameters, the unit would receive make whole payments
based on these temporary exceptions. The MMU recommends that PJM not
39 The units that requested 24 hour minimum run time on their parameter limited schedules in 2017 belonged to less than four owners.
Aggregated data consisting of three or fewer owners is considered confidential and cannot be published. See PJM Manual 31, Section 3.1.

2021 Quarterly State of the Market Report for PJM: January through June 139

2021 Quarterly State of the Market Report for PJM: January through June

approve temporary exceptions that are based on pipeline tariff terms that are
not routinely enforced or on inferior transportation service chosen by thegenerator.

Figure 3-18 Day-ahead aggregate supply curves: 2021 example day$1,000Virtual Offers and Bids
There is a substantial volume of virtual offers and bids in the PJM Day-Ahead
Energy Market and such offers and bids may be marginal.

Day-Ahead Supply Without INCs and Imports$800

Imports$700

Day-Ahead Supply with INCs and Imports

INCs
Day-Ahead Supply with INCs

$600
$500
Price ($/MWh)Any market participant in the PJM Day-Ahead Energy Market can use
increment offers, decrement bids, up to congestion transactions, importtransactions and export transactions as financial instruments that do not
require physical generation or load. Because virtual positions do not requirephysical generation or load, participants must buy or sell out of their virtual
positions at real-time energy market prices. On February 20, 2018, FERC issued
an order limiting the eligible bidding points for up to congestion transactions
to hubs, interfaces and residual aggregate metered load nodes, and limiting
the eligible bidding points for INCs and DECs to the same nodes plus active
generation and load nodes.40 Up to congestion transactions may be submitted
between any two buses on a list of 47 buses eligible for up to congestiontransaction bidding.41 Import and export transactions may be submitted at
any interface pricing point, where an import is equivalent to a virtual offerthat is injected into PJM and an export is equivalent to a virtual bid that iswithdrawn from PJM.

$900

$400
$300
$200
$100
$0
-$100

-$200
-$300

Quantity (MW)Figure 3-18 shows the PJM day-ahead daily aggregate supply curve of
increment offers, the system aggregate supply curve of imports, the systemaggregate supply curve without increment offers and imports, the systemaggregate supply curve with increment offers, and the system aggregate
supply curve with increment offers and imports for an example day in 2021.

40 162 FERC ¶ 61,139.
41 Prior to November 1, 2012, market participants were required to specify an interface pricing point as the source for imports, an interface
pricing point as the sink for exports or an interface pricing point as both the source and sink for transactions wheeling through PJM. For
the list of eligible sources and sinks for up to congestion transactions, see www.pjm.com “OASIS-Source-Sink-Link.xls,”<http://www.pjm.
com/~/‌media/etools/oasis/references/oasis-source-sink-link.ashx>.

140

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-20 shows the hourly average number of cleared and submitted
increment offers and decrement bids by month for 2020 and the first six
months of 2021. The hourly average submitted increment MW decreased by
13.2 percent and cleared increment MW decreased by 4.9 percent in the firstsix months of 2021 compared to the first six months of 2020. The hourly
average submitted decrement MW increased by 29.3 percent and cleared
decrement MW increased by 17.5 percent in the first six months of 2021
compared to the first six months of 2020.
Table 3-20 Average hourly number of cleared and submitted INCs and DECsby month: January 2020 through June 2021

Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Annual
Jan
Feb
Mar
Apr
May
Jun
Jan-JunIncrement Offers
Average
Average Average
Average
Cleared Submitted Cleared Submitted
MW
MW Volume
Volume
2,684
6,395
261
1,063
2,544
7,043
233
1,046
2,435
7,119
258
1,069
2,655
7,738
299
1,167
2,695
6,931
254
1,050
2,353
7,185
235
1,011
2,247
6,936
252
1,071
1,915
6,084
209
973
2,472
6,486
254
1,150
2,492
6,086
309
1,084
2,505
7,000
277
1,125
2,141
5,911
241
974
2,427
6,737
257
1,065
2,208
6,221
259
1,068
2,078
5,476
264
972
2,838
6,524
273
947
3,053
6,998
297
974
2,431
6,036
259
885
1,898
5,290
180
726
2,423
6,100
255
929

© 2021 Monitoring Analytics, LLC

Average
Cleared
MW
2,547
2,990
3,203
3,400
4,361
5,140
5,515
5,148
5,217
4,884
4,612
4,746
4,318
3,916
5,123
4,406
3,569
3,415
4,971
4,218

Decrement Bids
Average Average
Average
Submitted Cleared Submitted
MW Volume
Volume
5,856
187
662
6,653
222
702
7,688
251
762
8,312
261
840
8,257
307
814
9,843
404
1,083
11,233436
1,293
10,165
451
1,217
9,414
468
1,156
9,696
392
1,229
9,570
335
1,037
10,450
321
1,190
8,937
337
1,000
10,076297
1,194
11,556280
1,303
10,063
280
1,149
9,188
223
928
8,363
187
862
10,854
197
1,024
9,991
244
1,074

Table 3-21 shows the average hourly number of up to congestion transactions
and the average hourly MW from by month in 2020 and the first six monthsof 2021. The hourly average submitted up to congestion bid MW decreased by
50.1 percent and cleared MW decreased by 59.8 percent in the first six monthsof 2021 compared to the first six months of 2020.
Table 3-21 Average hourly cleared and submitted up to congestion bids bymonth: January 2020 through June 2021
Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Annual
Jan
Feb
Mar
Apr
May
Jun
Jan-JunAverage ClearedMW
19,106
19,415
19,513
18,26718,02823,03821,01422,47822,90019,587
8,667
7,156
18,257
7,277
10,354
8,776
6,770
6,976
7,163
7,855

Up to Congestion
Average Submitted
MW
37,53340,281
40,99837,29841,50359,52064,37663,36865,86655,904
21,141
17,96845,501
20,412
23,732
24,571
21,293
20,67417,80821,396

Average Cleared
Volume
1,127
1,100
990
955
1,122
1,403
1,227
1,159
1,136
933
578
526
1,021
546
691
548
495
585
621
579

Average Submitted
Volume
2,087
2,133
1,970
1,859
2,425
2,726
2,539
2,306
2,315
1,957
1,053
942
2,026
1,062
1,227
1,087
1,033
1,164
1,132
1,116

2021 Quarterly State of the Market Report for PJM: January through June 141

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-22 shows the average hourly number of day-ahead import and export transactions and the average hourly MW from January 2020 through June 2021.
In the first six months of 2021, the average hourly submitted import transaction MW increased by 2.1 percent and the average hourly cleared import transaction
MW decreased by 2.8 percent compared to the first six months of 2020. The average hourly submitted and cleared export transaction MW decreased by 3.6 and4.4 percent compared to the first six months of 2020.
Table 3-22 Hourly average day-ahead number of cleared and submitted import and export transactions by month: January 2020 through June 2021
Imports
Average
Average
Cleared Submitted
MW
MW
427
445
324
346
254
269
173
188
207
231
159
152
83
112
100
128
118
115
171
164
189
199
173
180
215
223
389
408
267
285
250
266
214
249
217
268
155
177
249
276

Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2021
2021
2021
2021
2021
2021
2021

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Annual
Jan
Feb
Mar
Apr
May
Jun
Jan-Jun142

Section 3 Energy Market

Average
Average
Cleared Submitted
VolumeVolume
5
6
4
5
3
4
2
3
3
4
2
2
2
2
2
2
2
2
2
2
2
2
2
2
3
3
4
4
3
4
2
3
3
3
2
3
2
2
3
3

Exports
Average
Average
Average
Average
Cleared Submitted
Cleared Submitted
MW
MW
VolumeVolume
3,034
3,041
28
28
2,737
2,742
29
29
3,084
3,085
27
27
3,057
3,062
25
25
3,075
3,080
23
23
3,782
3,798
31
31
3,907
3,922
31
31
3,909
3,920
29
29
3,424
3,448
28
28
3,268
3,231
26
26
3,158
3,182
32
32
3,106
3,113
31
31
3,298
3,304
28
28
2,854
2,862
30
30
4,581
4,658
41
42
2,493
2,542
27
28
2,364
2,376
24
24
2,255
2,279
21
21
3,463
3,489
30
30
2,977
3,008
29
29

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-23 shows the frequency with which generation offers, import or export transactions, up to congestion transactions, decrement bids, increment offers
and price-sensitive demand were marginal in January 2020 through June 2021. The frequency of marginal up to congestion transactions deceased significantly
in November 2020, due to decreased UTC activity beginning November 1, 2020, when FERC required UTCs to pay uplift.42
Table 3-23 Type of day-ahead marginal resources: January 2020 through June 2021

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
AnnualGeneration
27.7%
20.7%
19.5%
18.2%
16.6%
14.1%
11.8%
10.5%
13.1%
14.7%
21.0%
20.8%
16.5%

Dispatchable
Transaction
0.1%
0.1%
0.0%
0.0%
0.1%
0.0%
0.1%
0.0%
0.1%
0.2%
0.1%
0.2%
0.1%

2020
Up to
Congestion Decrement Increment
Transaction
Bid
Offer
44.7%
10.6%
16.9%
48.5%
12.5%
18.2%
52.2%
14.7%
13.6%
49.3%
16.6%
15.9%
55.2%
15.2%
13.0%
60.8%
15.5%
9.6%
57.4%
20.4%
10.3%
55.3%
24.9%
9.2%
54.8%
21.9%
10.1%
58.2%
15.0%
12.0%
27.6%
27.1%
24.2%
32.7%
30.7%
15.5%
51.4%
18.8%
13.2%

Price
Sensitive
Demand
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

Generation
23.1%
20.3%
18.9%
19.4%
20.6%
21.3%

Dispatchable
Transaction
0.1%
0.4%
0.1%
0.2%
0.2%
0.2%

20.4%

0.2%

2021
Up to
Congestion Decrement Increment
Transaction
Bid
Offer
35.7%
24.2%
16.9%
45.1%
23.1%
11.1%
33.9%
26.5%
20.6%
34.4%
21.6%
24.5%
35.5%
24.5%
19.1%
35.8%
30.4%
12.3%

36.5%

25.1%

17.7%

Price
Sensitive
Demand
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

0.0%

42 172 FERC ¶ 61,046 (2020).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 143

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-19 shows the monthly volume of bid and cleared INC, DEC and up tocongestion bids by month from 2005 through June 2021.

Figure 3-20 shows the daily volume of bid and cleared INC, DEC and up tocongestion bids from January 2020 through June 2021.

Figure 3-19 Monthly bid and cleared INCs, DECs and UTCs (GWh): January2005 through June 2021

Figure 3-20 Daily bid and cleared INCs, DECs, and UTCs (GWh): January 2020
through June 2021

300

100
INC Average Cleared GWh
INC Average Bid GWh
DEC Average Cleared GWh
DEC Average Bid GWh
Up to Congestion Average Cleared GWh
Up to Congestion Average Bid GWh250

INC Average Bid GWh
DEC Average Cleared GWh80

DEC Average Bid GWh
Up to Congestion Average Cleared GWh
Up to Congestion Average Bid GWh

70
Average Hourly GWh

200
Average Hourly GWh

INC Average Cleared GWh

90

150

100

60
50

40
30
20

50

Jun-21

May-21

Apr-21

Mar-21

Feb-21

Jan-21

Dec-20Nov-20

Oct-20

Sep-20Aug-20Jul-20Jun-20May-20

Apr-20Mar-20Feb-20Jan-20Jan-21

Jan-20Jan-19Jan-18Jan-17Jan-16

Jan-15Jan-14Jan-13Jan-12

Jan-11

Jan-10

Jan-09

Jan-08Jan-07

Jan-060
Jan-050

10In order to evaluate the ownership of virtual bids, the MMU categorizes
all participants making virtual bids in PJM as either physical or financial.
Physical entities include utilities and customers which primarily take physicalpositions in PJM markets. Financial entities include banks and hedge funds
which primarily take financial positions in PJM markets. International market
participants that primarily take financial positions in PJM markets are
generally considered to be financial entities even if they are utilities in theirown countries.

144

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-24 shows, in the first six months of 2020 and 2021, the total increment
offers and decrement bids and cleared MW by type of parent organization.
Table 3-24 INC and DEC bids and cleared MWh by type of parent organization(MWh): January through June, 2020 and 2021

Category
Financial
Physical
Total

Total
Virtual Bid
MWh55,146,844
9,565,968
64,712,812

2020 (Jan-Jun)Total Virtual
Cleared
Percent
MWh85.2% 21,943,638
14.8%
4,950,243
100.0% 26,893,881

Percent
81.6%
18.4%
100.0%

Total
Virtual Bid
MWh63,304,886
6,521,335
69,826,221

2021 (Jan-Jun)Total Virtual
Cleared
Percent
MWh90.7% 23,770,687
9.3%
5,024,155
100.0% 28,794,842

Percent
82.6%
17.4%
100.0%

Table 3-26 shows, in the first six months of 2020 and 2021, the total importand export transactions by whether the parent organization was financial or
physical.
Table 3-26 Import and export transactions by type of parent organization(MWh): January through June, 2020 and 2021

Day-Ahead

Real-Time

Table 3-25 shows, in the first six months of 2020 and 2021, the total up tocongestion bids and cleared MWh by type of parent organization.

Category
Financial
Physical
Total
Financial
Physical
Total

2020 (Jan-Jun)Total Import andExport MWh
5,177,737
9,547,594
14,725,330
7,716,943
18,067,743
25,784,687

Percent
35.2%
64.8%
100.0%
29.9%
70.1%
100.0%

2021 (Jan-Jun)Total Import andExport MWh
5,217,416
8,669,810
13,887,226
7,204,786
18,239,479
25,444,265

Percent
37.6%
62.4%
100.0%
28.3%
71.7%
100.0%

Table 3-25 Up to congestion transactions by type of parent organization(MWh): January through June, 2020 and 2021

Category
Financial
Physical
Total

Total Up toCongestion
Bid MWh
169,950,493
17,057,937
187,008,431

2020 (Jan-Jun)Total Up toCongestion
Percent Cleared MWh
90.9%
76,974,619
9.1%
8,403,870
100.0%
85,378,488© 2021 Monitoring Analytics, LLC

Percent
90.2%
9.8%
100.0%

Total Up toCongestion
Bid MWh
81,851,857
11,072,051
92,923,908

2021 (Jan-Jun)Total Up toCongestion
Percent Cleared MWh
88.1%
29,264,279
11.9%
4,850,465
100.0%
34,114,743

Percent
85.8%
14.2%
100.0%

2021 Quarterly State of the Market Report for PJM: January through June 145

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-27 shows increment offers and decrement bids by top 10 locations in the first six months of 2020 and 2021.
Table 3-27 Virtual offers and bids by top 10 locations (MWh): January through June, 2020 and 2021
Aggregate/Bus NameMISO
WESTERN HUB
AEP-DAYTON HUB
BGE_RESID_AGG
DOM_RESID_AGG
PECO_RESID_AGG
NORTHWESTN ILLINOIS HUB
NYIS
PPL_RESID_AGG
Top ten total
PJM total
Top ten total as percent of PJM total

146

2020 (Jan-Jun)
Aggregate/Bus Type
INTERFACE
HUB
HUB
RESIDUAL METERED EDC
RESIDUAL METERED EDC
RESIDUAL METERED EDC
INTERFACE
HUB
INTERFACERESIDUAL METERED EDC

Section 3 Energy Market

INC MWh26,971
369,326
161,857
156,360
94,861
389,685
364,381
171,493394,017330,291
2,459,242
11,188,379
22.0%

DEC MWh
3,560,904
1,083,234
620,286
609,870
632,232
99,669105,376
260,760
31,66575,8097,079,805
15,748,543
45.0%

Total MWh Aggregate/Bus Name
3,587,875 MISO
1,452,560 WESTERN HUB
782,144 LINDENVFT
766,230 DOM_RESID_AGG
727,092 AEP-DAYTON HUB
489,354 BGE_RESID_AGG
469,758 NYIS
432,253 N ILLINOIS HUB
425,681 COMED_RESID_AGG
406,100 HUDSONTP
9,539,047
26,936,922
35.4%

2021 (Jan-Jun)
Aggregate/Bus Type
INTERFACE
HUB
INTERFACERESIDUAL METERED EDC
HUB
RESIDUAL METERED EDC
INTERFACEHUB
RESIDUAL METERED EDC
INTERFACE

INC MWh
104,469
421,138
29,49591,306
171,086
98,065328,968
216,552
194,003
25,3081,680,391
10,521,283
16.0%

DEC MWh
3,312,282
946,818
861,018
753,826
595,111572,407339,596
399,859
306,048461,869
8,548,835
18,319,319
46.7%

Total MWh
3,416,752
1,367,956
890,513845,133
766,197
670,472
668,564
616,411500,052
487,177
10,229,226
28,840,602
35.5%© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-28 shows up to congestion transactions for the top 10 source and sink pairs and associated source, sink and overall gross revenues before operating
reserve charges on each path in the first six months of 2020 and 2021. While the total cleared MWh were much lower in the first six months of 2021 comparedto the first six months of 2020, total revenues were higher in the first six months of 2021. The NIPSCO Interface was eliminated effective June 1, 2020. The
NORTHWEST Interface was eliminated effective October 1, 2020. Before the elimination of these interface, trades located at these two nodes were among thelargest sources of revenue for up to congestion transactions in 2020.43
Table 3-28 Cleared up to congestion bids by top 10 source and sink pairs (MWh): January through June, 2020 and 2021
2020 (Jan-Jun)
Top 10 Paths by Cleared MWh
SourceNORTHWESTAEP GEN HUB
NORTHWESTSMECO_RESID_AGG
COMED_RESID_AGG
NORTHWESTAEP GEN HUB
N ILLINOIS HUBNORTHWESTOVEC_RESID_AGG
Top ten total
PJM total
Top ten total as percent of PJM total

Source Type
INTERFACE
HUB
INTERFACE
AGGREGATEAGGREGATEINTERFACE
HUB
HUB
INTERFACE
AGGREGATESink
N ILLINOIS HUB
AEPOHIO_RESID_AGG
COMED_RESID_AGG
BGE_RESID_AGG
NIPSCOCHICAGO GEN HUB
EKPC_RESID_AGG
AEPIM_RESID_AGG
MISO
DAY_RESID_AGG

Sink TypeHUB
AGGREGATEAGGREGATEAGGREGATEINTERFACEHUB
AGGREGATEAGGREGATEINTERFACE
AGGREGATE

Cleared MW
2,520,539
2,269,083
2,231,016
2,213,226
1,565,759
1,389,204
1,328,174
1,262,526
1,244,193
1,195,478
17,219,198
82,425,058
20.9%

SourceSink
UTC
Revenue
Revenue
Revenue$2,127,741 ($1,137,955)$989,785($61,990)$292,072$230,082$1,459,200($191,668) $1,267,532$223,583($163,412)$60,170$1,394,315($951,202)$443,113$1,246,554($870,092)$376,461$248,162$70,501$318,663$63,265$367,843$431,108$1,121,893 ($440,648)$681,245($5,065)($75,227)($80,292)$7,817,658 ($3,099,788) $4,717,870$5,683,587 $7,696,122 $13,379,709
137.5%(40.3%)
35.3%

2021 (Jan-Jun)
Top 10 Paths by Cleared MWh
SourceCOMED_RESID_AGG
AEP GEN HUB
SMECO_RESID_AGG
CHICAGO GEN HUB
MISO
CHICAGO GEN HUB
N ILLINOIS HUB
CHICAGO GEN HUB
AEP GEN HUB
COMED_RESID_AGG
Top ten total
PJM total
Top ten total as percent of PJM total

Source TypeAGGREGATEHUB
AGGREGATEHUB
INTERFACE
HUB
HUB
HUB
HUB
HUB

Sink
AEPIM_RESID_AGG
EKPC_RESID_AGG
BGE_RESID_AGG
AEPIM_RESID_AGG
AEPIM_RESID_AGG
MISO
AEPIM_RESID_AGG
EKPC_RESID_AGG
AEPOHIO_RESID_AGG
DEOK_RESID_AGG

Sink TypeAGGREGATEAGGREGATEAGGREGATEAGGREGATEAGGREGATEINTERFACE
AGGREGATEAGGREGATEAGGREGATEAGGREGATE

ClearedSourceMWhRevenue
1,621,626 $1,483,213
1,420,390 $1,407,848
771,915 $1,058,271
657,011$597,719
570,105$936,452
551,742 ($559,479)
542,750$414,036
518,374$126,149
505,486$182,672
440,675$480,842
7,600,075 $6,127,722
34,114,743 $29,709,923
22.3%
20.6%

Sink
UTC
Revenue
Revenue($106,309) $1,376,904($400,780) $1,007,068($637,060)$421,211($2,309)$595,410($108,918)$827,534$804,059$244,580$94,011$508,047$132,148$258,297$122,386$305,057($227,364)$253,478($330,137) $5,797,585$2,199,009 $31,908,932(15.0%)
18.2%

43 The source and sink aggregates in these tables refer to the name and location of a bus and do not include information about the behavior of any individual market participant.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 147

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-29 shows the average daily number of source-sink pairs that were
offered and cleared each month from January 2020 through June 2021. Since
November 2020, there has been a decrease in the average number of paths
with submitted and cleared bids.
Table 3-29 Number of offered and cleared source and sink pairs: January
2020 through June 2021
Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2021
2021
2021
2021
2021
2021
2021

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Annual
Jan
Feb
Mar
Apr
May
Jun
Jan-JunAverage Offered
1,658
1,710
1,789
1,804
1,913
1,974
1,886
1,760
1,656
1,544
1,306
1,305
1,692
1,286
1,303
1,314
1,309
1,329
1,291
1,301

Daily Number of Source-Sink Pairs
Max Offered
Average Cleared
1,942
1,523
1,975
1,568
2,013
1,591
1,978
1,567
2,126
1,681
2,111
1,803
2,085
1,749
1,993
1,575
1,851
1,498
1,689
1,358
1,497
1,203
1,508
1,184
1,897
1,525
1,470
1,132
1,514
1,210
1,542
1,189
1,559
1,146
1,540
1,176
1,412
1,161
1,509
1,177

Max Cleared
1,857
1,725
1,832
1,760
1,900
2,020
1,970
1,854
1,641
1,525
1,387
1,359
1,736
1,302
1,449
1,386
1,388
1,395
1,289
1,379

Table 3-30 and Figure 3-21 show total cleared up to congestion transactions
and share of the top ten up to congestion paths by transaction type (import,
export, or internal) in the first six months of 2020 and 2021. Total cleared up
to congestion transactions decreased by 60.0 percent from 85.4 million MWhin the first six months of 2020 to 34.1 million MWh in the first six monthsof 2021. Internal up to congestion transactions in the first six months of2021 were 80.2 percent of all up to congestion transactions compared to 65.5
percent in the first six months of 2020.

Table 3-30 Cleared up to congestion transactions and share of top 10 pathsby type (MW): January through June, 2020 and 2021

Top ten total (MW)PJM total (MW)Top ten total as percent of PJM total
PJM total as percent of all up to congestion transactions

Import
9,910,974
16,364,450
60.6%
19.2%

Top ten total (MW)PJM total (MW)Top ten total as percent of PJM total
PJM total as percent of all up to congestion transactions

Import
1,751,494
3,104,438
56.4%
9.1%

2020 (Jan-Jun)
Cleared Up to Congestion Bids
Export
Wheel
Internal
5,790,483 4,162,158 13,050,899
8,519,048 4,542,415 55,952,575
68.0%
91.6%
23.3%
10.0%
5.3%
65.5%
2021 (Jan-Jun)
Cleared Up to Congestion Bids
Export
Wheel
Internal
1,972,647
359,089 7,321,612
3,201,002
445,873 27,363,431
61.6%
80.5%
26.8%
9.4%
1.3%
80.2%

Total
32,914,514
85,378,488
38.6%
100.0%

Total
11,404,843
34,114,743
33.4%
100.0%

Figure 3-21 shows the initial increase and continued increase in internal up
to congestion transactions by month following the November 1, 2012, rulechange permitting such transactions, until September 8, 2014. The reduction
in up to congestion transactions (UTC) that followed a FERC order setting
September 8, 2014, as the effective date for any uplift charges subsequently
assigned to UTCs, was reversed.44 There was an increase in up to congestion
volume as a result of the expiration of the 15 month refund period for theproceeding related to uplift charges for UTC transactions. In 2018, total UTC
activity and the percent of marginal up to congestion transactions again
decreased significantly as the result of a FERC order issued on February
20, 2018, and implemented on February 22, 2018.45 The order limited UTC
trading to hubs, residual metered load, and interfaces. UTC activity increased
following that reduction. UTC activity decreased again beginning November
1, 2020, after a FERC order requiring UTCs to pay day-ahead and balancing
operating reserve charges equivalent to a DEC at the UTC sink point became
effective on that date.46

44 See 162 FERC ¶ 61,139 (2018).
45 Id.
46 See 172 FERC ¶ 61,046 (2020).

148

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Figure 3-21 Monthly cleared up to congestion transactions by type (MW):January 2005 through June 2021
60,000
Import50,000

ExportFigure 3-22 shows the daily cleared up to congestion MW by transaction typefrom January 1, 2020 through June 30, 2021.
Figure 3-22 Daily cleared up to congestion transaction by type (MW): January
2020 through June 2021
800

Wheel

700

40,00030,00020,00010,000Up to Congestion Cleared GWh

Up to Congestion Cleared GWh

Internal

600

ImportExport
Wheel
Internal

500
400
300
200

0

100
0

One of the goals of the February 2018 FERC order accepting PJM’s proposal
limiting UTC bidding to hubs, interfaces and residual aggregate meteredload nodes, and limiting INC and DEC bidding to the same nodes plus active
generation nodes, was to limit the opportunities for traders to profit from
opportunities for false arbitrage in which price spreads between the day-ahead
and real-time energy markets result from differences in the models used tooperate each market that cannot be corrected through virtual bidding.47

47 PJM Interconnection, LLC, “Proposed Revisions To Reduce Bidding Points for Virtual Transactions,” Docket No. ER18-88, October 17,
2017 at 9–10: “Discrepancies between the models can occur for various reasons despite PJM’s best attempts to minimize them…Because
individual nodes are more highly impacted by modeling discrepancies than aggregated locations due to averaging, they are often
locations where Virtual Transactions can profit. Profits collected by Virtual Transactions in these cases lead to additional costs for PJM
members without any benefits.”© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 149

2021 Quarterly State of the Market Report for PJM: January through June

A key assumption underlying the February 2018 order is that the limited set ofnodes available for virtual trading is sufficiently protected from false arbitrage
trades because price spreads resulting from modeling differences between the
day-ahead and real-time markets are mitigated by the averaging of prices
over a large number of buses at aggregate nodes.48 This assumption is notcorrect, given the large share of INC, DEC, and UTC profits still attributable tomodeling or operational differences between day-ahead and real-time since
the February 2018 order.
The assumption that modeling differences are averaged out over aggregate
nodes does not hold for multiple nodes in the current list of available up
to congestion bidding nodes. The MMU recommends eliminating up tocongestion (UTC) bidding at pricing nodes that aggregate only small sectionsof transmission zones with few physical assets. For this reason, the MMU
recommends eliminating UTC bidding at the following nodes: DPLEASTON_RESID_AGG, PENNPOWER_RESID_AGG, UGI_RESID_AGG, SMECO_RESID_
AGG, AEPKY_RESID_AGG, and VINELAND_RESID_AGG.
Prices at larger aggregate nodes can also be affected by transmission
constraints, especially when constraints are violated and transmission penalty
factors are applied in the real-time energy market. Even when the same
constraints are modeled in day ahead and real time, constraint violations
in real time may result from differences in the day ahead and real time
operational environments such as intra hourly ramping limitations, changes
to constraint limits, and unit commitments and decommitments. Price spreads
due to modeling or operational differences can be in the tens to hundredsof dollars, even when averaged over an aggregate node, and may persist fordays or weeks. Virtual traders can often identify and profit from price spreads
resulting from systematic modeling and operational differences between day
ahead and real time affecting specific generators or aggregate nodes. The
MMU recommends eliminating INC, DEC, and UTC bidding at pricing nodes
that allow market participants to profit from modeling issues.
48 162 FERC ¶ 61,139 at PP 35–36 (“We accept PJM’s proposal to limit eligible bidding points for UTCs to hubs, residual metered load, andinterfaces. First, we agree with the IMM’s statement that PJM’s proposal to limit the UTC bid locations to interfaces, zones, and hubs
will minimize false arbitrage opportunities for UTCs currently being pursued through penny bids, as the effect of modeling differences
between the day-ahead and real-time markets are minimized at these aggregates.”).

150

Section 3 Energy Market

Market Performance
PJM locational marginal prices (LMPs) are a direct measure of market
performance. The market performs optimally when the market structure
provides incentives for market participants to behave competitively. In a
competitive market, prices equal the short run marginal cost of the marginalunit of output and reflect the most efficient and least cost allocation of
resources to meet demand.

LMP
The behavior of individual market entities within a market structure is reflected
in market prices. PJM locational marginal prices (LMPs) are a direct measureof market performance. Price level is a good, general indicator of market
performance, although overall price results must be interpreted carefully
because of the multiple factors that affect them. Among other things, overall
average prices reflect changes in supply and demand, generation fuel mix,
the cost of fuel, emission related expenses, markup and local price differences
caused by congestion. PJM also may administratively set prices with thecreation of a closed loop interface related to demand side resources, surrogate
constraints for reactive power and generator stability, or influence prices
through manual interventions such as load biasing, changing constraint limits
and penalty factors, and committing reserves beyond the requirement.
Real-time and day-ahead energy market load-weighted prices were 57.8
percent and 61.2 percent higher in the first six months of 2021 compared tothe same time period of 2020.
The average real-time LMP in the first six months of 2021 increased 56.0
percent from the first six months of 2020, from $18.70 per MWh to $29.17
per MWh. The load-weighted average real-time LMP in the first six months of2021 increased 57.8 percent from the first six months of 2020, from $19.40
per MWh to $30.62 per MWh.
The, load-weighted, average, real-time LMP for the first six months of 2021
was 50.6 percent lower than the fuel-cost adjusted, load-weighted, average,© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

real-time LMP for the first six months of 2021. If fuel and emission costs inthe first six months of 2021 had been the same as in the first six months of
2020, holding everything else constant, the load-weighted LMP would havebeen lower, $20.33 per MWh instead of the observed $30.62 per MWh.
The average day-ahead LMP in the first six months of 2021 increased 58.8
percent from the first six months of 2020, from $18.55 per MWh to $29.46
per MWh. The load-weighted average day-ahead LMP increased 61.2 percent
from the first six months of 2020, from $19.23 per MWh to $31.00 per MWh.
Occasionally, in a constrained market, the LMPs at some pricing nodes canexceed the offer price of the highest cleared generator in the supply curve.49 In
the nodal pricing system, the LMP at a pricing node is the total cost of meeting
incremental demand at that node. When there are binding transmission
constraints, satisfying the marginal increase in demand at a node may require
increasing the output of some generators while simultaneously decreasing
the output of other generators, such that the transmission constraints are
not violated. The total cost of redispatching multiple generators can at times
exceed the cost of marginally increasing the output of the most expensive
generator offered. Thus, the LMPs at some pricing nodes exceed $1,000 per
MWh, the cap on the generators’ offer price in the PJM market.50
LMP may, at times, be set by transmission penalty factors, which exceed$1,000 per MWh. When a transmission constraint is binding and there are no
generation alternatives to resolve the constraint, the transmission limits may
be violated in the market dispatch solution. When this occurs, the shadow
price of the constraint is set by transmission penalty factors. The shadow pricedirectly affects the LMP. Transmission penalty factors are administratively
determined and can be thought of as a form of locational scarcity pricing.

49 See O’Neill R. P, Mead D. and Malvadkar P. “On Market Clearing Prices Higher than the Highest Bid and Other Almost Paranormal
Phenomena.” The Electricity Journal 2005; 18(2) at 19–27.
50 The offer cap in PJM was temporarily increased to $1,800 per MWh prior to the winter of 2014/2015. A new cap of $2,000 per MWh, only
for offers with costs exceeding $1,000 per MWh, went into effect on December 14, 2015. See 153 FERC ¶ 61,289 (2015).

© 2021 Monitoring Analytics, LLC

Real-Time Average LMP
Real-time, average LMP is the hourly average LMP for the PJM Real-Time
Energy Market.51

PJM Real-Time, Average LMP
Table 3-31 shows the PJM real-time, average LMP for the first six months of1998 through 2021.52
Table 3-31 Real-time, average LMP (Dollars per MWh): January through June,
1998 through 2021
Real-Time LMP
Jan-Jun
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Average$20.13$22.94$25.38$33.10$24.10$41.31$44.99$45.71$49.36$55.03$70.19$40.12$43.27$45.51$29.74$36.56$62.14$38.87$25.84$28.72$38.82$26.41$18.70$29.17

Median$15.90$17.84$18.03$25.69$19.64$33.74$40.75$39.80$43.46$48.05$59.53$35.42$37.11$37.40$28.32$32.79$39.69$29.04$23.17$25.76$27.21$23.81$17.54$23.89Year to Year ChangeStandard
Deviation$15.59$41.16$25.65$21.11$13.21$27.81$22.97$23.51$25.26$31.42$41.77$19.30$22.20$32.52$16.10$17.18$88.87$34.04$13.61$12.03$38.76$15.75$8.46$21.30

Average
NA
14.0%
10.6%
30.4%
(27.2%)
71.4%
8.9%
1.6%
8.0%
11.5%
27.6%
(42.8%)
7.9%
5.2%(34.6%)
22.9%
69.9%(37.4%)(33.5%)
11.1%
35.2%(32.0%)(29.2%)
56.0%

Median
NA
12.2%
1.1%
42.5%
(23.6%)
71.8%
20.8%(2.3%)
9.2%
10.6%
23.9%
(40.5%)
4.8%
0.8%(24.3%)
15.8%
21.0%(26.8%)(20.2%)
11.2%
5.6%(12.5%)(26.3%)
36.2%

Standard
DeviationNA
164.0%(37.7%)(17.7%)(37.4%)
110.6%(17.4%)
2.3%
7.5%
24.4%
33.0%
(53.8%)
15.0%
46.5%(50.5%)
6.7%
417.4%(61.7%)(60.0%)(11.6%)
222.3%(59.4%)(46.3%)
151.8%

51 See the Technical Reference for PJM Markets, at “Calculating Locational Marginal Price,” p 16-18 for detailed definition of Real-Time
LMP. <http://www.monitoringanalytics.com/‌reports/Technical_References/references.shtml>.
52 The system average LMP is the average of the hourly LMP without any weighting. The only exception is that market-clearing prices(MCPs) are included for January to April 1998. MCP was the single market-clearing price calculated by PJM prior to implementation of
LMP.

2021 Quarterly State of the Market Report for PJM: January through June 151

2021 Quarterly State of the Market Report for PJM: January through JunePJM Real-Time Average LMP Duration

Real-Time, Load-Weighted, Average LMP

Figure 3-23 shows the hourly distribution of PJM real-time, average LMP for
the first six months of 2020 and 2021. There were 2,910 hours with an average
LMP between the $10 to $20 per MWh in the first six months of 2020, but
only 1,029 hours were in the same range in the first six months of 2021.

Higher demand (load) generally results in higher prices, all else constant. As aresult, load-weighted, average prices are generally higher than average prices.
Load-weighted LMP reflects the average LMP paid for actual MWh consumed
during a year. Load-weighted, average LMP is the average of PJM hourly LMP,
each weighted by the PJM total hourly load.

Figure 3-23 Average LMP for the real-time energy market: January throughJune, 2020 and 2021
3,500

Table 3-32 shows the PJM real-time, load-weighted, average LMP for the firstsix months of 1998 through 2021.

2020 Jan - Jun

3,000

2021 Jan - Jun

Table 3-32 Real-time, load-weighted, average LMP (Dollars per MWh):
January through June, 1998 through 2021

2,500

Hours

2,000

1,500

1,000

Range ($/MWh)152

Section 3 Energy Market

1,800-2,000

1,000-1,800

200-1,000

100-200

90-100

80-90

70-80

60-70

50-60

40-50

30-40

20-30

10-20

0-10

-200-0500

0PJM Real-Time, Load-Weighted, Average LMP

Jan-Jun
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Real-Time, Load-Weighted,
Average LMP
Standard
Average
MedianDeviation$21.66$16.80$18.39$25.34$18.59$52.06$27.76$18.91$29.69$35.27$27.88$22.12$25.93$20.67$14.62$44.43$37.98$28.55$47.62$43.96$23.30$48.67$42.30$24.81$51.83$45.79$26.54$58.32$52.52$32.39$74.77$64.26$44.25$42.48$36.95$20.61$45.75$38.78$23.60$48.47$38.63$37.59$31.21$28.98$17.69$37.96$33.58$18.54$69.92$42.61$103.35$42.30$30.34$37.85$27.09$23.82$14.49$29.81$26.47$12.88$42.44$28.36$43.68$27.49$24.40$16.38$19.40$18.13$8.93$30.62$24.61$22.60Year to Year Change
Average
NA
17.0%
9.5%
27.0%
(26.5%)
71.4%
7.2%
2.2%
6.5%
12.5%
28.2%
(43.2%)
7.7%
5.9%(35.6%)
21.6%
84.2%(39.5%)(36.0%)
10.1%
42.4%(35.2%)(29.4%)
57.8%

Median
NA
10.7%
1.7%
47.4%
(25.9%)
83.8%
15.8%(3.8%)
8.3%
14.7%
22.4%
(42.5%)
5.0%(0.4%)(25.0%)
15.9%
26.9%(28.8%)(21.5%)
11.1%
7.1%(14.0%)(25.7%)
35.7%

Standard
Deviation
NA
183.1%(43.0%)(25.5%)(33.9%)
95.2%(18.4%)
6.5%
7.0%
22.1%
36.6%
(53.4%)
14.5%
59.3%(52.9%)
4.8%
457.6%(63.4%)(61.7%)(11.1%)
239.1%(62.5%)(45.5%)
153.2%© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

PJM Real-Time, Monthly, Load-Weighted, Average LMP

PJM Real-Time, Daily, Load-Weighted, Average LMP

Figure 3-24 shows the PJM real-time monthly and annual load-weighted LMP
for January 1999 through June 2021.

Figure 3-25 shows the PJM real-time, daily, load-weighted LMP for 2020
through the first six months of 2021.

Figure 3-24 Real-time, monthly and annual, load-weighted, average LMP:
January 1999 through June 2021

Figure 3-25 Real-time, daily, load-weighted, average LMP: January 2020
through June 2021

$140

250
Max-Min 2016-2020

Yearly Average Load-Weighted LMP

$120

2020

2021

Year to Date PJM Real Time Load Weighted Daily LMP:
Change in Real Time Daily Load-Weighted LMP for Q2: $11.26, 58.1%
2020 through 2021

Monthly Average Load-Weighted LMP

Peak: $13.27, 60.8%
Off Peak: $9.22, 54.7%

200

LMP ($/MWh)

LMP ($/MWh)

$100

$80

$60

150

100

$40

50

© 2021 Monitoring Analytics, LLC

2021

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

2009

2008

2007

2006

2005

2004

2003

2002

2001

2000

$0

1999

$20

0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

2021 Quarterly State of the Market Report for PJM: January through June 153

2021 Quarterly State of the Market Report for PJM: January through JunePJM Real-Time, Monthly, Inflation Adjusted Load-Weighted, Average
LMP
Figure 3-26 shows the PJM real-time, monthly, load-weighted, average LMP
and inflation adjusted, monthly, load-weighted, average LMP from January
1998 through June 2021.53 Table 3-33 shows the PJM real-time, loadweighted, average LMP and inflation adjusted load-weighted, average LMP
for the first six months of every year from 1998 through 2021. The PJM realtime inflation adjusted, load-weighted, average LMP for the first six monthsof 2021 was the fourth lowest value since PJM real-time markets started on
April 1, 1999 at $18.59 per MWh. The real-time, inflation adjusted, monthly,load-weighted, average LMP for April 2020 was the lowest monthly value
since PJM markets started in April 1999 at $11.08 per MWh.
Figure 3-26 Real-time, monthly, load-weighted, average LMP unadjusted andadjusted for inflation: January 1998 through June 2021
$140
Monthly Average Inflation Adjusted RT Load-Weighted LMP
Monthly Average RT Load-Weighted LMP$120

LMP ($/MWh)

$100

$80

$40

Jan-21

Jan-20Jan-19Jan-18Jan-17Jan-16

Jan-15Jan-14Jan-13Jan-12

Jan-11

Jan-10

Jan-09

Jan-08Jan-07

Jan-06

Jan-05Jan-04Jan-03Jan-02Jan-01

Jan-00Jan-99Jan-98$20

53 To obtain the inflation adjusted, monthly, load-weighted, average LMP, the PJM system-wide load-weighted average LMP is deflatedusing the US Consumer Price Index for all items, Urban Consumers (base period: January 1998), published by Bureau of Labor Statistics.
<http://download.bls.gov/pub/time.series/cu/cu.data.1.AllItems> (Accessed July 13, 2021)

154

1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Load-Weighted, Average LMP
Jan-Jun$21.66$25.34$27.76$35.27$25.93$44.43$47.62$48.67$51.83$58.32$74.77$42.48$45.75$48.47$31.21$37.96$69.92$42.30$27.09$29.81$42.44$27.49$19.40$30.62

Inflation Adjusted Load-Weighted, Average LMP
Jan-Jun$21.54$24.74$26.25$32.27$23.40$39.18$41.02$40.71$41.78$45.83$56.29$32.26$33.99$35.04$22.05$26.40$47.96$28.98$18.34$19.74$27.48$17.48$12.17$18.59Real-Time Dispatch and Pricing

$60

$0

Table 3-33 Real-time, load-weighted, average LMP unadjusted and adjusted
for inflation: January through June, 1998 through 2021

Section 3 Energy Market

Currently, real-time dispatch and pricing are not temporally aligned. The PJM
Real-Time Energy Market consists of a series of applications that produce
the generator dispatch for energy and reserves, and five minute locational
marginal prices (LMPs). These applications include the ancillary services
optimizer (ASO), real-time security constrained economic dispatch (RT SCED),
and the locational pricing calculator (LPC).54 The final real-time LMPs andancillary service clearing prices are determined for every five minute interval
by LPC.

54 See PJM. “Manual 11: Energy & Ancillary Services Market Operations,” Rev. 115 (June 1, 2021)© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Real-Time SCED and LPC
LPC uses data from an approved RT SCED solution that was used to dispatch
the resources in the system. RT SCED solves to meet load and reserve
requirements forecast at a future point in time, called the target time. Prior to2021, on average, PJM operators approved more than one RT SCED solution
per five minute target time to send dispatch signals to resources. In thefirst six months of 2021, on average, PJM operators approved one RT SCED
solution per five minute target time to send dispatch signals to resources.
PJM uses a subset of these approved RT SCED solutions in LPC to calculate
real-time LMPs every five minutes. Prior to October 15, 2020, LPC used thelatest available approved RT SCED solution to calculate prices, regardless ofthe target dispatch time of the RT SCED solution, but LPC assigned the prices
to a five minute interval that did not contain the target time of the RT SCED
case it used. On October 15, 2020, PJM updated its pricing process to use anapproved RT SCED solution that solves for the same target time as the endof each five minute pricing interval to calculate LMPs applicable for thatfive minute interval, although the SCED cases are still for 10 minutes ahead
while the LPC cases are for each five minute interval. As a result, under thedefault timing of case approvals, resources follow the dispatch signal in thefirst five minutes after the RT SCED case approval and the corresponding
pricing occurs five minutes after the same case approval, when resources arefollowing a new dispatch signal.
Table 3-34 shows, on a monthly basis in the first six months of 2021, thenumber of RT SCED case solutions, the number of solutions that wereapproved and the number and percent of approved solutions used in LPC. Until
February 24, 2020, RT SCED was automatically executed every three minuteswith operators having the ability to execute additional cases in between theautomatically executed cases. Beginning February 24, 2020, PJM changed
the RT SCED automatic execution frequency to once every four minutes. On
June 22, 2020, PJM changed the RT SCED execution frequency to once every
five minutes. PJM operators continue to have the ability to execute additional
RT SCED cases. PJM retains the discretion to change the automatic RT SCED
execution frequency at any time, as the frequency is not documented in the© 2021 Monitoring Analytics, LLC

PJM market rules. Prior to June 3, 2021, each execution of RT SCED produced
three solutions, using three different levels of load bias. Beginning June 3,
2021, each execution of RT SCED produces five solutions, using five different
levels of load bias. Since prices are calculated every five minutes while five
SCED solutions are produced every five minutes, there is, by definition, alarger number of SCED solutions than there are five minute intervals in any
given period.
Table 3-34 shows that in the first six months of 2021, 92.5 percent of approved
RT SCED solutions that were used to send dispatch signals to generators wereused in calculating real-time energy market prices. The percent of approved
solutions used for pricing increased in 2020 with the decrease in the frequencyof executed RT SCED cases.
Figure 3-27 shows the daily number of RT SCED cases approved by PJM
operators to send dispatch signals to resources and the subset of approved RT
SCED cases that were used in LPC to calculate LMPs in 2020 and the first six
months of 2021, and the dates when the frequency of RT SCED auto execution
was changed in 2020. Figure 3-27 shows that changing the auto execution
frequency of RT SCED from once every three minutes to once every four
minutes on February 24, 2020 and to five minutes on June 22, 2020 reduced
the number of approved RT SCED cases used to send dispatch signals in 2020.
This change in the frequency of approved solutions reduced the difference
between the number of approved solutions and the number of solutions usedin pricing in the first six months of 2021 relative to the first six months of
2020.

2021 Quarterly State of the Market Report for PJM: January through June 155

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-34 RT SCED cases solved, approved and used in pricing: January
through June, 2021
Month
(2021)
Jan
Feb
Mar
Apr
May
Jun
Total

Number of RT SCED
Solutions
31,39530,48932,456
29,58630,43846,184
200,548

Number of Approved
RT SCED Solutions
9,022
7,888
9,069
8,798
9,124
8,847
52,748

Number of Approved
RT SCED Solutions
Used in LPC
8,276
7,308
8,372
8,220
8,468
8,133
48,777

RT SCED Solutions
Used in LPC as
Percent of Approved
RT SCED Solutions
91.7%
92.6%
92.3%
93.4%
92.8%
91.9%
92.5%

Figure 3-27 Daily RT SCED solutions approved for dispatch signals andsolutions used in pricing: January 2020 through June 2021
600

Number of RT SCED Solutions

500

400

300

200

0

6/22/2020: Auto
execution changed
to once every 5
minutes

2/24/2020: Auto
execution changed
to once every 4
minutes

100

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Approved RT SCED Solutions, 2020

RT SCED Solutions Used in LPC, 2020

Approved RT SCED Solutions, 2021

RT SCED Solutions Used in LPC, 2021

Nov

Dec

PJM’s process for solving and approving RT SCED cases, and selecting
approved RT SCED cases to use in LPC to calculate LMPs has inconsistencies
that lead to downstream impacts for energy and reserve dispatch andsettlements. PJM does not link dispatch and settlement intervals. RT SCED
moved from automatically executing a case every three minutes to every fiveminutes in 2020, while settlements are linked to five minute intervals. In thefirst six months of 2021, the frequency of automatic execution of RT SCED
cases was one every five minutes. RT SCED solves the dispatch problem fora target time that is generally 14 minutes in the future. An RT SCED case isapproved and sends dispatch signals to generators based on a 10 minute ramp
time. The look ahead time for the load forecast and the look ahead time for the
resource dispatch target do not match, and a new RT SCED case overrides thepreviously approved case before resources have time to achieve the previous
target dispatch. Prior to October 15, 2020, the interval that was priced in
LPC was consistently before the target time from the RT SCED case used forthe dispatch signal. LPC took the most recently approved RT SCED case to
calculate LMPs for the present five minute interval. For example, the LPC casethat calculated prices for the interval ending 10:05 EPT used an approved RT
SCED case that sent MW dispatch signals for the target time of 10:10 EPT.
This discrepancy created a mismatch between the MW dispatch and real-time
LMPs and undermined generators’ incentive to follow dispatch. Under new
RT SCED changes that were implemented on October 15, 2020, PJM resolved
the mismatch between LPC and the RT SCED target time, but prices no longer
apply at the time when resources receive and follow that dispatch signal.55
For example, the LPC case that calculates prices for the interval ending 10:05
EPT uses an approved RT SCED case that sent MW dispatch signals at 9:55
EPT which are no longer effective from 10:00 to 10:05 EPT. There is still amismatch between the MW dispatch and real-time LMPs that undermines
generators’ incentive to follow dispatch. The timing remains incorrect until all
three (the pricing interval, the dispatch interval, and the RT SCED target time)
all correspond to one another.
The extent to which dispatch instructions from approved SCED solutions arereflected in concurrent prices in the PJM Real-Time Energy Market can be
55 See Docket No. ER19-2573-000.

156

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

measured by comparing the start and end times when the dispatch instructions
from the RT SCED solution were effective with the start and end times when
the corresponding prices applied. The start time for a dispatch instructionis the time at which PJM approves the RT SCED solution, which triggers
sending the resulting dispatch instructions to resources. The end time for adispatch instruction is the time when the next RT SCED solution is approved.
Dispatch and pricing would be perfectly aligned if the start and end times ofthe dispatch instructions from an approved RT SCED solution matched withthe start and end times of the LPC pricing interval that used the same RT SCED
solution. In a perfectly aligned five minute market, these times would both befive minutes in duration. However, RT SCED uses a 10 minute ramp time todispatch resources, while LPC applies prices to five minute intervals.
Table 3-35 shows the average duration of the period when dispatch instructions
corresponded to the prevailing prices in the first six months of 2021. Prior to
October 15, 2020, PJM used the latest approved RT SCED solution available
at the time of LPC execution, regardless of the SCED target time, to calculate
prices for the current five minute pricing interval. The average duration ofcorrespondence ranged from 3 minutes 11 seconds to 3 minutes 37 seconds
from January through October 15, 2020, varying with changes to thefrequency of automatic RT SCED execution. The percent of time that prices
were consistent with the dispatch instructions was 67.2 to 69.9 percent, on
average. This is far from the goal of 100 percent correspondence between
five minute dispatch instructions and prices. With the short term changes to
RT SCED that were implemented on October 15, 2020, the prices no longer
correspond to the dispatch instructions. Table 3-35 shows that during thefirst six months of 2021, the dispatch instructions were consistent withprevailing prices for only 34 seconds. During this period, the percent of timethat prices were consistent with the dispatch instructions was 9.0 percent. Thisis because by the time LMPs reflect the dispatch signals from an approved RT
SCED solution, dispatchers have approved a new solution, and resources are
instructed to follow new dispatch signals that do not align with the LMPs used
to settle the current five minute interval. In other words, prices consistently
lag dispatch instructions by five minutes, except in cases where dispatchers© 2021 Monitoring Analytics, LLC

have not approved a new SCED solution five minutes after a previously
approved solution.
Table 3-35 Dispatch instructions reflected in prices: January through June,
2021
PeriodJan 1, 2020 - Feb 23, 2020
Feb 24, 2020 - Jun 22, 2020
Jun 23, 2020 - Oct 14, 2020
Oct 15, 2020 - Dec 31, 2020
Jan 1, 2021 - Jun 30, 2021

RT SCED Automatic
Execution Frequency
Every 3 minutes
Every 4 minutes
Every 5 minutes
Every 5 minutes
Every 5 minutes

Dispatch Duration
Reflected in Prices(Minutes:Seconds)
03:11
03:27
03:37
00:39
00:34

Percent Dispatch
Duration Reflected inPrices
67.9%
67.2%
69.9%
9.9%
9.0%

For correct price signals and compensation, energy (LMP) and ancillary
service pricing should align with the dispatch solution that is the basis for
those prices and with the actual physical dispatch period during which that
dispatch solution is realized for each and every real-time market interval.56
This will only happen if RT SCED and LPC both use a five minute ramp time,
consistent with the five minute real-time settlement period in PJM. The MMU
recommends that PJM approve one RT SCED case for each five minute interval
to dispatch resources during that interval using a five minute ramp time, andthat PJM calculate prices using LPC for that five minute interval using thesame approved RT SCED case. This will result in prices used to settle energy
for the five minute interval that ends at the RT SCED dispatch target time.
On May 17, 2021, PJM filed tariff updates to address this issue, and proposed
to update the five minute dispatch and pricing process to use a five minuteramp time beginning November 1, 2021.57 Under this proposal, RT SCED
solves the real time dispatch problem using a five minute ramp time to meetload and reserve requirements at the end of each five minute interval. The RT
SCED case would be approved five minutes prior to the target time, sending
dispatch signals that would be effective for the same duration as modeledin the RT SCED solution. Under this proposal, LPC will use the approved RT
SCED solution that sent dispatch signals for a five minute interval to calculate
56 See Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System
Operators, Order No. 825, 155 FERC ¶ 61,276 (2016).
57 See PJM, “Enhancements to PJM Dispatch and Pricing – The ‘Long-Term’ Reforms,” Docket No. ER21 – 1919 (May 17, 2021).

2021 Quarterly State of the Market Report for PJM: January through June 157

2021 Quarterly State of the Market Report for PJM: January through June

the prices for the same five minute interval. This proposal will ensure that theprices in any interval are consistent with the dispatch signals effective duringthat five minute interval, that five minute LMPs are calculated using the
dispatch solution based on the five minute ramp time, and that LMPs in a fiveminute interval reflect the marginal offer for energy and reserves, consistent
with the economic dispatch that targets the end of that five minute period.58

Recalculation of Five Minute Real-Time Prices
PJM’s five minute interval LMPs are obtained from solved LPC cases. PJM
recalculates five minute interval real-time LMPs as it believes necessary tocorrect errors. To do so, PJM reruns LPC cases with modified inputs. The
PJM OATT allows for posting of recalculated real-time prices no later than
17:00 of the tenth calendar day following the operating day. The OATT also
requires PJM to notify market participants of the underlying error no later
than 17:00 of the second business day following the operating day.59 Table
3-36 shows the number of five minute intervals in each month and numberof five minute intervals in each month for which PJM recalculated real-time
prices in 2020 and the first six months of 2021. In the first six months of2021, PJM recalculated LMPs for 874 five minute intervals or 1.68 percentof the total 52,116 five minute intervals. In February 2021, PJM recalculated
LMPs for several five minute intervals due to a telemetry issue that affected
the calculation of regulation performance scores.

Table 3-36 Number of five minute interval real-time prices recalculated:
January 2020 through June 2021

Month
January
February
March
April
May
June
July
AugustSeptember
OctoberNovember
December
Total

2020
Number of Five Minute
Number of Five
Intervals for which
Minute Intervals LMPs were recalculated
8,928
193
8,352
12
8,916
110
8,640
50
8,928
37
8,640
64
8,928
67
8,928
251
8,640
20
8,928
37
8,652
22
8,928
80
105,408
943

2021
Number of Five Minute
Number of Five
Intervals for which
Minute Intervals LMPs were recalculated
8,928
12
8,064
496
8,916
49
8,640
266
8,928
29
8,640
22
52,116874

58 The implementation of fast start pricing planned for September 1, 2021, will result in much more significant misalignment between priceand dispatch signals.
59 OA Schedule 1 § 1.10.8(e).

158Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Day-Ahead Average LMP

PJM Day-Ahead Average LMP Duration

Day-ahead, average LMP is the hourly average LMP for the PJM Day-Ahead
Energy Market.60

Figure 3-28 shows the hourly distribution of PJM day-ahead, average LMP in
the first six months of 2020 and 2021.

PJM Day-Ahead, Average LMP

Figure 3-28 Average LMP for the day-ahead energy market: January throughJune, 2020 and 2021

Table 3-37 shows the PJM day-ahead, average LMP for the first six monthsof 2001 through 2021.

3,500

2,000
1,500
1,000

1,800-2,000

1,000-1,800

200-1,000

100-200

90-100

80-90

70-80

60-70

50-60

0

40-50

500

30-40

MedianNA(32.1%)
84.1%
10.1%(1.5%)
10.7%
8.5%
29.4%
(43.3%)
8.5%
0.5%(27.4%)
18.7%
26.2%(28.1%)(21.9%)
9.3%
10.3%(15.8%)(28.1%)
40.5%

20-30

AverageNA(29.3%)
73.0%
2.8%
3.7%
5.9%
9.7%
32.2%
(42.9%)
9.5%
2.1%(32.0%)
21.9%
71.2%(37.1%)(34.4%)
10.6%
30.5%(29.1%)(30.9%)
58.8%

10-20

Median$31.34$21.28$39.18$43.14$42.51$47.07$51.08$66.09$37.46$40.64$40.85$29.64$35.19$44.42$31.93$24.95$27.26$30.08$25.31$18.20$25.58

0-10

Average$35.02$24.76$42.83$44.02$45.63$48.33$53.03$70.12$40.01$43.81$44.75$30.44$37.11$63.52$39.98$26.24$29.03$37.90$26.86$18.55$29.46

Standard
Deviation
NA(28.4%)
88.3%(22.0%)
0.1%(12.7%)
43.0%
39.6%(51.9%)
1.8%
24.8%(39.8%)(11.4%)
571.1%(58.9%)(70.3%)
3.9%
228.6%(67.2%)(48.6%)
211.3%-200-0Jan-Jun
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

2,500

Year to Year ChangeStandard
Deviation$17.43$12.49$23.52$18.33$18.35$16.02$22.91$31.98$15.38$15.66$19.53$11.77$10.42$69.93$28.76$8.54$8.87$29.14$9.56$4.92$15.302021 Jan-Jun

Hours

Day-Ahead LMP

2020 Jan-Jun

3,000

Table 3-37 Day-ahead, average LMP (Dollars per MWh): January throughJune, 2001 through 2021

Range ($/MWh)

Day-Ahead, Load-Weighted, Average LMP
Day-ahead, load-weighted LMP reflects the average LMP paid for day-ahead
MWh. Day-ahead, load-weighted LMP is the average of PJM day-ahead,hourly LMP, each weighted by the PJM total cleared day-ahead, hourly load,
including day-ahead fixed load, price-sensitive load, decrement bids and up
to congestion.

60 See the MMU Technical Reference for the PJM Markets, at “Calculating Locational Marginal Price” for a detailed definition of day-ahead
LMP. <http://www.monitoringanalytics.com/‌reports/Technical_References/references.shtml>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 159

2021 Quarterly State of the Market Report for PJM: January through JunePJM Day-Ahead, Load-Weighted, Average LMP

PJM Day-Ahead, Monthly, Load-Weighted, Average LMP

Table 3-38 shows the PJM day-ahead, load-weighted, average LMP in the firstsix months of 2001 through 2021.

Figure 3-29 shows the PJM day-ahead, monthly and annual, load-weighted
LMP from January 2001 through June 2021.

Table 3-38 Day-ahead, load-weighted, average LMP (Dollars per MWh):
January through June, 2001 through 2021

Figure 3-29 Day-ahead, monthly and annual, load-weighted, average LMP:
January 2001 through June 2021

160

Section 3 Energy Market$140

Year to Year Change
AverageNA(27.5%)
69.7%
1.1%
4.3%
4.3%
10.9%
32.3%
(42.7%)
9.3%
2.2%(32.4%)
20.1%
84.8%(38.8%)(36.8%)
9.8%
36.5%(31.7%)(31.3%)
61.2%

MedianNA(32.2%)
82.7%
8.2%(1.3%)
8.5%
11.5%
27.8%
(44.0%)
9.5%
0.2%(28.7%)
19.3%
30.0%(28.9%)(22.5%)
8.8%
11.4%(17.0%)(28.2%)
42.1%

Standard
DeviationNA(20.7%)
66.8%(22.3%)
3.3%(15.7%)
44.7%
44.7%(52.4%)
2.3%
35.1%(37.6%)(20.8%)
623.8%(59.6%)(72.4%)
5.6%
248.5%(67.6%)(51.4%)
225.4%

Yearly Average Load-Weighted LMP$120Monthly Average Load-Weighted LMP$100

LMP ($/MWh)

Jan-Jun
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Day-Ahead, Load-Weighted,
Average LMP
Standard
Average
MedianDeviation$37.08$33.91$18.11$26.88$23.00$14.36$45.62$42.01$23.96$46.12$45.45$18.62$48.12$44.88$19.24$50.21$48.67$16.23$55.70$54.26$23.47$73.71$69.33$33.95$42.21$38.83$16.16$46.12$42.50$16.54$47.12$42.58$22.34$31.84$30.35$13.94$38.23$36.19$11.03$70.67$47.04$79.85$43.26$33.45$32.23$27.33$25.92$8.89$30.02$28.21$9.38$40.96$31.44$32.70$27.97$26.10$10.59$19.23$18.73$5.14$31.00$26.63$16.73

$80

$60

$40

$20

$0

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Figure 3-30 shows the PJM day-ahead daily, load-weighted, LMP in 2020
through the first six months 2021 compared to the historic five year pricerange.
Figure 3-30 Day-ahead, daily, load-weighted, average LMP: January 2020
through June 2021
$250
Max-Min 2016-2020

2020

2021

Change in Day Ahead Daily Load-Weighted LMP for Q2: $11.78, 61.3%
Peak: $13.87, 64.4%
Off Peak: $9.66, 57.5%$200

LMP ($/MWh)$150

PJM Day-Ahead, Monthly, Inflation Adjusted Load-Weighted,
Average LMP
Figure 3-31 shows the PJM day-ahead, monthly, load-weighted, average LMP
and inflation adjusted monthly day-ahead, load-weighted, average LMP for
June 2000 through June 2021.61 Table 3-39 shows the PJM day-ahead, loadweighted, average LMP and inflation adjusted load-weighted, average LMP
for the first six months of every year from 2000 through 2021. The PJM
day-ahead, inflation adjusted, load-weighted, average LMP for the first six
months of 2021 was the fourth lowest ($18.82 per MWh) since PJM dayahead markets started in 2000. The day-ahead inflation adjusted monthlyload-weighted, average LMP for April 2020 ($10.70 per MWh) was the lowest
monthly value since the day-ahead markets started.
Figure 3-31 Day-ahead, monthly, load-weighted, average LMP unadjusted andinflation adjusted: June 2000 through June 2021
$160
Monthly Average Inflation Adjusted DA Load-Weighted LMP$100

Monthly Average DA Load-Weighted LMP

$140
$120

$0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

LMP ($/MWh)

$50
$100
$80
$60
$40

Jun-21

Jun-20Jun-19Jun-18Jun-17

Jun-16Jun-15Jun-14Jun-13Jun-12

Jun-11

Jun-10

Jun-09Jun-08Jun-07

Jun-06

Jun-05

Jun-04

Jun-03Jun-02

Jun-01$0

Jun-00$2061 To obtain the inflation adjusted monthly load-weighted average LMP, the PJM system-wide load-weighted average LMP is deflated using
US Consumer Price Index for all items, Urban Consumers (base period: January 1998), published by Bureau of Labor Statistics. <http://
download.bls.gov/‌pub/time.series/cu/cu.data.1.AllItems> (Accessed July 13, 2021).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 161

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-39 Day-ahead, yearly, load-weighted, average LMP unadjusted andinflation adjusted: January through June, 2001 through 2021
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Load-Weighted, Average LMP
Jan-Jun$34.12$37.08$26.88$45.62$46.12$48.12$50.21$55.70$73.71$42.21$46.12$47.12$31.84$38.23$70.67$43.26$27.33$30.02$40.96$27.97$19.23$31.00Inflation Adjusted Load-Weighted, Average LMP
Jan-Jun$31.98$33.94$24.25$40.23$39.73$40.24$40.47$43.76$55.49$32.06$34.28$34.08$22.49$26.59$48.48$29.64$18.51$19.88$26.52$17.79$12.06$18.82

Price Convergence
The introduction of the PJM Day-Ahead Energy Market with virtuals as partof the design created the possibility that competition, exercised through theuse of virtual offers and bids, could tend to cause prices in the day-ahead andreal-time energy markets to converge more than would be the case without
virtuals. Convergence is not the goal of virtual trading, but it is a possible
outcome.
In practice, virtuals can receive a positive revenue anytime there is a differencein prices at any location in any hour between the day-ahead and real-timeenergy markets. Virtual trading can only result in price convergence at agiven location and market hour if the factors affecting prices at that locationand hour, such as modeled contingencies, transmission constraint limits andsources of flows, are the same in both the day-ahead and real-time models.
162

Section 3 Energy Market

Where arbitrage incentives are created by systematic modeling differences,such as differences between the day-ahead and real-time modeled transmission
contingencies and marginal loss calculations, virtual bids and offers cannot
result in more efficient market outcomes. Such offers may be profitable but
cannot change the underlying reason for the price difference. The virtualtransactions will continue to receive positive revenue from the activity for thatreason regardless of the volume of those transactions and without improving
the efficiency of the energy market. This is termed false arbitrage.
The degree of convergence, by itself, is not a measure of the competitivenessor effectiveness of the day-ahead energy market. Price convergence does notnecessarily mean a zero or even a very small difference in prices between dayahead and real-time energy markets. There may be factors, from uplift charges
to differences in risk that result in a competitive, market-based differential.
In addition, convergence in the sense that day-ahead and real-time prices areequal at individual buses or aggregates on a day to day basis is not a realistic
expectation as a result of uncertainty, lags in response time and modelingdifferences.
INCs, DECs and UTCs allow participants to benefit from price differences between
the day-ahead and real-time energy market. In theory, virtual transactions
receive positive revenues when they contribute to price convergence, but withfalse arbitrage, high revenues result with little or no price convergence. The
seller of an INC must buy energy in the real-time energy market to fulfill thefinancial obligation to provide energy. If the day-ahead price for energy ishigher than the real-time price for energy, the INC receives positive revenue.
The buyer of a DEC must sell energy in the real-time energy market to fulfill
the financial obligation to buy energy. If the day-ahead price for energy islower than the real-time price for energy, the DEC receives positive revenue.
The net revenue of a UTC transaction is the net of the separate revenues of
the component INC and DEC. A UTC can have a net positive revenue if thepositive revenue on one side of the UTC transaction exceeds the losses on theother side.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-40 shows, before uplift charges, the number of cleared UTC transactions, the number of cleared UTCs with positive net revenues, the number of cleared
UTCs with positive revenues at their source point and the number of cleared UTCs with positive revenues at their sink point in the first six months of 2020
and 2021. In the first six months of 2021, 47.6 percent of all cleared UTC transactions received positive net revenues before uplift charges. Of cleared UTC
transactions, 69.5 percent received positive revenues on the source side and 31.2 percent received positive revenues on the sink side, but only 8.0 percent
received positive revenues on both the source and sink side.
Table 3-40 Cleared UTC count with positive revenues by source and sink point before uplift charges: January through June, 2020 and 202162(JanJun)2020
2021

ClearedPositive
UTCs Revenue UTCs
4,872,175
2,540,498
2,516,220
1,196,821

Positive
Revenue atSource3,025,710
1,747,789

Positive Positive Revenue Share Positive Share Positive
Revenue at
at Source andRevenue
Revenue Share Positive
Sink
Sink
Overall
Source Revenue Sink
1,866,187
356,062
52.1%
62.1%
38.3%
785,574
201,425
47.6%
69.5%
31.2%

Share Positive
Revenue Sourceand Sink
7.3%
8.0%

Table 3-41 shows the number of cleared INC and DEC transactions and the number of cleared transactions with positive revenues before uplift charges in thefirst six months of 2020 and 2021. Of cleared INC and DEC transactions in the first six months of 2021, 69.0 percent of INCs had positive revenues and 32.2
percent of DECs had positive revenues.
Table 3-41 Cleared INC and DEC count with positive revenues: January through June, 2020 and 2021
(JanJun)2020
2021

Cleared INC
1,122,070
1,108,541

Positive Positive Revenue
Revenue INC
INC Share
718,460
64.0%
764,682
69.0%

Cleared DEC
1,187,461
1,058,084

Positive Positive Revenue
Revenue DEC
DEC Share
475,21340.0%
340,939
32.2%

62 Calculations exclude PJM administrative charges.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 163

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-32 shows the total daily net revenues of UTCs with positive net
revenues, with negative net revenues, and all UTCs, before uplift charges, inthe first six months of 2021.
Figure 3-32 UTC daily positive, negative, and net revenues before upliftcharges: January through June, 202163

Figure 3-33 shows the cumulative UTC daily total net revenues before operating
reserve charges for each year from 2013 through the first six months of 2021.
Figure 3-33 Cumulative daily UTC net revenues before operating reservecharges: January 2013 through June 2021
$300
2013
2014
2015
2016
2017
2018
2019
2020
2021

$8
Positive Revenues$250

Negative Revenues$6

Net Revenues$4

Revenue (Millions)$200

Revenue (Millions)

$2

$0

$150

$100
-$2

$50

-$4

-$6

-$8

$0

Jan

Feb

Mar

Apr

May

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Jun

63 Calculations exclude PJM administrative charges.

164

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-42 shows UTC revenues before operating reserve charges by month for January 2013 through June 2021. May 2016, September 2016, February 2017,
June 2018 and September 2020 were the only months in this seven year period in which monthly net revenues were negative.
Table 3-42 UTC net revenues before operating reserve charges by month: January 2013 through June 2021
2013
2014
2015
2016
2017
2018
2019
2020
2021

January$17,048,654$148,973,434$16,132,319$8,874,363$5,716,757$13,184,346$574,901$664,972$6,421,567

February$8,304,767$23,235,621$53,830,098$6,118,477($17,860)$506,509$2,407,307$2,497,856$13,241,294

March$5,629,392$39,448,716$44,309,656$1,119,457$3,083,167$3,410,577$5,287,985$1,720,037$1,788,961

April$7,560,773$1,581,786$6,392,939$2,768,591$944,939$688,796$332,036$1,865,139$4,529,921

May$25,219,947$3,851,636$19,793,475($1,333,563)$1,245,988$9,499,735$1,833,879$5,508,276$2,542,898

June$3,484,372$7,353,460$824,817$841,706$868,400($768,614)$3,382,009$1,123,429$3,384,291

July$8,781,526$3,179,356$8,879,275$3,128,346$7,053,390$1,163,380$4,066,461$8,573,276

August$2,327,168$287,824$5,507,608$3,200,573$4,002,063$692,736$2,442,971$3,957,296

September$31,160,618$2,727,763$6,957,012($2,518,408)$10,960,012$2,845,649$12,599,278($141,240)

October$4,393,583$10,889,817$4,852,454$4,216,717$2,360,817$1,452,515$5,914,042$1,628,186

November$8,730,701$11,042,443$392,876$254,684$2,716,950$4,339,363$1,171,145$1,170,367

December$6,793,990$6,191,101$6,620,581$3,271,368$15,936,217$1,358,446$3,722,403$2,319,727

Total$129,435,490$258,762,955$174,493,110$29,942,312$54,870,839$38,373,436$43,734,418$30,887,320$31,908,932

Figure 3-34 shows total INC and DEC daily revenues before uplift charges, gross positive revenues, the sum of all positive revenue transactions, gross negative
revenues, the sum of all negative revenue transactions, and net revenues in the first six months of 2021.
Figure 3-34 INC and DEC daily positive, negative, and total revenues before uplift charges: January through June, 202164$12.0
Positive Revenues$10.0

Negative Revenues
Net Revenues$8.0

Revenue (Millions)

$6.0
$4.0
$2.0
$0.0
-$2.0
-$4.0
-$6.0

Jan

Feb

Mar

Apr

May

Jun

64 Calculations exclude PJM administrative charges.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 165

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-35 shows total INC daily gross positive and negative revenues andnet revenues before uplift charges in the first six months of 2021.

Figure 3-36 shows total DEC daily gross positive and negative revenues andnet revenues before uplift charges in the first six months of 2021.

Figure 3-35 INC daily positive, negative, and total net revenues before upliftcharges January through June, 202165

Figure 3-36 DEC daily positive, negative, and total net revenues before upliftcharges: January through June, 202166

$3.0

$10.0
Positive Revenues

Positive Revenues

Negative Revenues

Negative Revenues$8.0

Net Revenues$2.0

Net Revenues$6.0

Revenue (Millions)

Revenue (Millions)

$1.0

$0.0

$4.0

$2.0

$0.0

-$1.0

-$2.0
-$2.0
-$4.0
-$3.0

Jan

Feb

65 Calculations exclude PJM administrative charges.

166

Section 3 Energy Market

Mar

Apr

May

Jun

-$6.0

Jan

Feb

Mar

Apr

May

Jun

66 Calculations exclude PJM administrative charges.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Figure 3-37 shows the cumulative INC and DEC daily revenues before upliftcharges for the first six months of 2021.
Figure 3-37 Cumulative daily INC and DEC revenues before uplift charges:
January through June, 2021
$40
INC

DEC

$35

INC and DEC$30

Profit (Millions)

$25
$20

There are incentives to use virtual transactions to profit from price differences
between the day-ahead and real-time energy markets, but there is no guaranteethat such activity will result in price convergence and no data to support thatclaim. As a general matter, virtual offers and bids are based on expectations
about both day-ahead and real-time energy market conditions and reflect theuncertainty about conditions in both markets, about modeling differences
and the fact that these conditions change hourly and daily. PJM markets do
not provide a mechanism that could result in immediate convergence after achange in system conditions as there is at least a one day lag after any change
in system conditions before offers could reflect such changes. PJM markets
do not provide a mechanism that could ever result in convergence in thepresence of modeling differences.
Substantial virtual trading activity does not guarantee that market power
cannot be exercised in the day-ahead energy market. Hourly and daily pricedifferences between the day-ahead and real-time energy markets fluctuatecontinuously and substantially from positive to negative. There may besubstantial, persistent differences between day-ahead and real-time prices
even on a monthly basis.

$15
$10
$5
$0

-$5

Jan

Feb

Mar

Apr

May

Jun

Table 3-43 shows INC and DEC revenues before uplift charges by month forthe first six months of 2021.
Table 3-43 INC and DEC revenues before uplift charges by month: January
through June, 2021
INCs
DECs
INCs and DECs

January$116,313$4,506,985$4,623,297© 2021 Monitoring Analytics, LLC

February$6,534,110$3,060,102$9,594,212

March$1,874,664$5,820,332$7,694,996

April$5,140,992($3,623,933)$1,517,059

May$554,421$2,168,601$2,723,022

June$1,767,917$6,490,068$8,257,985

Total$15,988,416$18,422,156$34,410,572

2021 Quarterly State of the Market Report for PJM: January through June 167

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-44 shows that the difference between the average real-time price and the average day-ahead price.
Table 3-44 Day-ahead and real-time average LMP (Dollars per MWh): January through June, 2020 and 202167
2020
Jan-JunAverage
MedianStandard deviation
Peak average
Peak medianPeak standard deviation
Off peak average
Off peak median
Off peak standard deviation

Day-Ahead$18.55$18.20$4.92$21.09$20.07$4.68$16.32$16.03$3.93

Real-Time$18.70$17.54$8.46$21.38$19.35$10.05$16.33$15.74$5.79

Difference$0.15($0.66)$3.54$0.30($0.72)$5.36$0.02($0.29)$1.86

2021
Percent ofReal Time Day-Ahead
0.8%$29.46(3.8%)$25.5841.9%$15.301.4%$34.13
(3.7%)$28.9053.4%$18.290.1%$25.37(1.9%)$22.51
32.1%$10.49Real-Time$29.17$23.89$21.30$33.88$26.48$26.71$25.03$21.65$13.72Difference($0.29)($1.69)$6.00($0.24)($2.42)$8.43($0.33)($0.86)$3.23

Percent ofReal Time(1.0%)(7.1%)
28.2%(0.7%)(9.1%)
31.5%(1.3%)(3.9%)
23.6%

The price difference between the real-time and the day-ahead energy markets results in part, from conditions in the real-time energy market that are difficult,or impossible, to anticipate in the day-ahead energy market.
Table 3-45 shows the difference between the real-time load-weighted and the day-ahead load-weighted energy market prices for the first six months of 2001
through 2021.
Table 3-45 Day-ahead load-weighted and real-time loadeighted, average LMP (Dollars per MWh): January through June, 2001 through 2021
Jan-Jun
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Day-Ahead$35.02$24.76$42.83$44.02$45.63$48.33$53.03$70.12$40.01$43.81$44.75$30.44$37.11$63.52$39.98$26.24$29.03$37.90$26.86$18.55$29.46

Load-Weighted Average LMP
Real-Time
Difference$33.10($1.92)$24.10($0.66)$41.31($1.53)$44.99$0.97$45.71$0.07$49.36$1.03$55.03$2.00$70.19$0.08$40.12$0.11$43.27($0.54)$45.51$0.76$29.74($0.69)$36.56($0.55)$62.14($1.38)$38.87($1.11)$25.84($0.40)$28.72($0.31)$38.82$0.93$26.41($0.45)$18.70$0.15$29.17($0.29)Percent of Real Time
(5.5%)(2.7%)(3.6%)
2.2%
0.2%
2.1%
3.8%
0.1%
0.3%
(1.2%)
1.7%(2.3%)(1.5%)(2.2%)(2.8%)(1.5%)(1.1%)
2.4%(1.7%)
0.8%(1.0%)

67 The averages used are the annual average of the hourly average PJM prices for day-ahead and real-time.

168

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-46 includes frequency distributions of the differences between PJM
real-time, load-weighted, hourly LMP and PJM day-ahead, load-weighted,
hourly LMP for the first six months of 2020 and 2021.
Table 3-46 Frequency distribution by hours of real-time, load-weighted LMP
minus day-ahead, load-weighted LMP (Dollars per MWh): January throughJune, 2020 and 2021
LMP
< ($200)($200) to ($100)($100) to ($50)($50) to $0$0 to $50
$50 to $100
$100 to $200
$200 to $400
$400 to $800>= $800

Frequency
0
0
0
2,759
1,598
8
2
0
0
0

Figure 3-38 Real-time hourly, LMP minus day-ahead hourly LMP: January
through June, 2021
$600

2021(Jan-Jun)
Cumulative
Percent
0.00%
0.00%
0.14%
69.01%
98.92%
99.77%
99.91%
99.98%
100.00%100.00%Frequency
0
0
6
2,991
1,299
37
6
3
1
0

Cumulative
Percent
0.00%
0.00%
0.00%
63.18%
99.77%
99.95%
100.00%100.00%100.00%100.00%

$500

$400

LMP Difference ($/MWh)2020 (Jan-Jun)

Figure 3-38 shows the hourly differences between day-ahead and real-timehourly LMP in the first six months of 2021.

$300

$200

$100

$0

-$100

-$200

© 2021 Monitoring Analytics, LLC

Jan

Feb

Mar

Apr

May

Jun

2021 Quarterly State of the Market Report for PJM: January through June 169

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-39 shows day-ahead and real-time, load-weighted, average hourly
LMP for the first six months of 2020 and 2021.
Figure 3-39 System hourly average LMP: January through June, 2020 and
2021$402021 Real Time
2021 Day Ahead
2020 Real Time
2020 Day Ahead

$35
$30

LMP ($/MWh)

$25
$20
$15
$10
$5
$0

170

1

2

3

4

5

6

7

8

Section 3 Energy Market

9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour Ending (EPT)

Zonal LMP and Dispatch
Table 3-47 shows zonal real-time, and real-time, load-weighted, average LMP
in the first six months of 2020 and 2021.
Table 3-47 Zonal real-time and real-time, load-weighted, average LMP(Dollars per MWh): January through June, 2020 and 2021
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DOM
DPL
DUQ
EKPC
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
PJM

Real-Time Average LMP
2020
2021
Jan-JunJan-Jun$17.31$24.96$19.27$29.82$19.38$28.94$19.54$28.10$20.25$33.60$17.15$27.54$20.14$31.49$19.33$30.64$19.54$32.38$17.38$31.42$19.70$28.06$19.26$29.73$17.71$24.79$17.81$26.89$18.90$28.40$17.04$24.71$18.26$26.94$19.60$31.52$16.95$25.56$17.52$27.70$17.68$30.70$18.70$29.17

Percent
Change
44.2%
54.7%
49.3%
43.8%
65.9%
60.6%
56.4%
58.5%
65.7%
80.8%
42.5%
54.4%
40.0%
51.0%
50.3%
45.0%
47.5%
60.9%
50.8%
58.1%
73.7%
56.0%

Real-Time, Load-Weighted, Average LMP
2020
2021
Percent
Jan-JunJan-JunChange$17.99$26.6147.9%$19.93$31.1256.1%$20.06$30.2650.9%$20.25$29.2944.6%$21.29$35.61
67.3%$18.01$29.22
62.2%$20.96$33.3359.0%$20.08$32.4961.8%$20.35$34.1067.6%$18.10$33.5685.4%$20.47$29.4343.8%$20.10$31.9058.7%$18.53$26.4642.9%$18.57$28.4153.0%$19.08$28.7950.9%$17.64$26.1748.4%$18.81$27.96
48.6%$20.55$33.57
63.4%$17.56$26.7752.5%$18.11$29.3962.3%$18.39$33.02
79.6%$19.40$30.6257.8%© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-48 shows zonal day-ahead, and day-ahead, load-weighted, average
LMP in the first six months of 2020 and 2021.
Table 3-48 Zonal day-ahead and day-ahead, load-weighted, average LMP(Dollars per MWh): January through June, 2020 and 2021
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DOM
DPL
DUQ
EKPC
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
PJM

Day-Ahead Average LMP
2020
2021
Jan-JunJan-Jun$16.94$25.61$19.15$30.02$19.12$29.43$19.39$29.37$20.42$33.76$17.34$27.74$20.13$32.00$19.38$31.32$19.31$32.07$17.30$29.82$19.49$28.94$19.10$29.90$17.16$25.76$17.50$27.67$18.80$29.01$16.67$25.24$18.31$28.11$19.66$31.90$16.70$26.28$17.18$26.99$17.52$29.18$18.55$29.46© 2021 Monitoring Analytics, LLC

Percent
Change
51.2%
56.7%
54.0%
51.5%
65.3%
59.9%
58.9%
61.7%
66.0%
72.4%
48.5%
56.6%
50.1%
58.1%
54.3%
51.4%
53.5%
62.2%
57.3%
57.1%
66.5%
58.8%

Day-Ahead, Load-Weighted, Average LMP
2020
2021
Percent
Jan-JunJan-JunChange$17.53$27.21
55.2%$19.81$31.4858.9%$19.77$30.7355.4%$20.03$30.5352.4%$21.45$35.71
66.5%$18.08$29.3062.1%$20.94$33.82
61.5%$20.15$33.1664.6%$20.14$33.9768.7%$18.17$32.3478.0%$20.21$30.2049.5%$20.09$32.2760.6%$17.85$27.2752.8%$18.19$29.15
60.3%$19.52$31.4361.0%$17.24$26.5654.1%$19.05$29.45
54.6%$20.65$33.8764.0%$17.26$27.4559.1%$17.75$28.5760.9%$18.32$32.2576.1%$19.23$31.0061.2%

2021 Quarterly State of the Market Report for PJM: January through June 171

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-40 is a map of the real-time, load-weighted, average LMP in the first six months of 2021. In the legend, green represents the system marginal price(SMP) and each increment to the right and left of the SMP represents five percent of the pricing nodes above and below the SMP.
Figure 3-40 Real-time, load-weighted, average LMP: January through June, 2021

172

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Transmission Penalty Factors
LMP may, at times, be set by transmission penalty factors. When a transmission
constraint is binding and there are no generation alternatives to resolve theconstraint, system operators may allow the transmission limit to be violated.
When this occurs, the shadow price of the constraint is set by transmission
penalty factors. The shadow price directly affects the LMP. Transmission
penalty factors are administratively determined and can be thought of as aform of locational scarcity pricing.
Table 3-49 shows the frequency and average shadow price of transmission
constraints in PJM. In the first six months of 2021, there were 82,911transmission constraint intervals in the real-time market with a nonzero
shadow price. For nearly seven percent of these transmission constraintintervals, the line limit was violated, meaning that the flow exceeded thefacility limit.68 In the first six months of 2021, the average shadow price oftransmission constraints when the line limit was violated was nearly 12.0
times higher than when the transmission constraint was binding at its limit.

into effect on February 1, 2019. The Commission approved the PJM and MISO
joint filing to remove the constraint relaxation logic for market to market
constraints on March 6, 2020. PJM and MISO implemented the changes totheir dispatch software in the second half of 2020.
PJM continues the practice of discretionary reductions in line ratings. Table
3-50 shows the frequency of changes to the transmission constraints forbinding and violated transmission constraints in the PJM real-time market.
In the first six months of 2021, there were 5,597 or 97 percent of 5,783
internal violated transmission constraint intervals in the real-time market
with constraint limit less than 100 percent of the actual constraint limit. In
the first six months of 2021, among the constraints with reduced constraint
limits, the constraint limit was reduced on average by 7.1 percent.

Table 3-49 Frequency and average shadow price of transmission constraints:
January through June, 2020 and 2021

Description
PJM Internal Violated Transmission Constraints
PJM Internal Binding Transmission Constraints
Market to Market Transmission Constraints
All Transmission Constraints

Frequency(Constraint Intervals)
2020
2021
(Jan - Jun)
(Jan - Jun)
1,289
5,783
64,36451,901
17,59525,227
83,24882,911

Average Shadow Price
2020
2021
(Jan - Jun)
(Jan - Jun)
$1,745.42$1,911.65$63.68$158.99$238.31$394.94$126.63$353.03

Transmission penalty factors should be applied without discretion. PJM
adopted the MMU’s recommendation to remove the constraint relaxation logic
and allow transmission penalty factors to set prices in the day-ahead and realtime markets for all internal transmission constraints. PJM also revised thetariff to list the conditions under which transmission penalty factors would
be changed from their default value of $2,000 per MWh. The new rules went
68 The line limit of a facility associated with a transmission constraint is not necessarily the rated line limit. In PJM, the dispatcher has thediscretion to lower the rated line limit.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 173

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-50 Frequency of reduction in line ratings (constraint intervals):January through June, 2020 and 2021

Description
PJM Internal Violated Transmission Constraints
PJM Internal Binding Transmission Constraints
Market to Market Transmission Constraints
All Transmission Constraints

Frequency(Constraint Intervals)
2020
2021
(Jan - Jun)
(Jan - Jun)
1,289
5,783
64,36451,901
17,59525,227
83,24882,911

Constraints with ReducedLine Limits(Constraint Intervals)
2020
2021
(Jan - Jun)
(Jan - Jun)
1,185
5,597
63,27851,2593,751
11,42968,214
68,285

Table 3-51 shows the frequency of changes to the magnitude of transmission
penalty factors for binding and violated transmission constraints in the PJM
Real-Time Energy Market. In the first six months of 2021, there were 5,161 or
89 percent of internal violated transmission constraint intervals in the realtime market with a transmission penalty factor equal to the default $2,000
per MWh.

PJM uses CT pricing logic to force otherwise uneconomic
resources to be marginal and set price in the dayahead and real-time market solutions. In the event PJMAverage Reduction
commits a resource that is uneconomic and/or offered(Percentage)
with inflexible parameters, PJM uses CT pricing logic to
2020
2021
(Jan - Jun)
(Jan - Jun)model a constraint with a variable flow limit, paired with
14.8%
6.6%
an artificial override of the inflexible resource’s economic
10.7%
7.5%
7.1%
5.6%
minimum, to force the resource to be marginal in the
10.6%
7.1%
PJM market solution.69 Frequently, PJM dispatchers also
manually override the transmission violation penalty
factor of the constraint to match the offer price of the resource to artificiallycontrol the shadow price of the constraint. Table 3-52 shows the frequencyof CT pricing logic used in the PJM Real-Time Energy Market. In the first six
months of 2021, there were 6,421 constraint intervals in the real-time market
where CT pricing logic was used. In the PJM CT pricing logic, there could be
one or multiple resources paired with a constraint.

Table 3-51 Frequency of changes to the magnitude of transmission penalty
factor (constraint intervals): January through June, 2020 and 2021

Description
PJM Internal Violated Transmission Constraints
PJM Internal Binding Transmission Constraints
Market to Market Transmission Constraints
All Transmission Constraints

2020 (Jan - Jun)
$2,000Above
Below
per MWh$2,000$2,000(Default) per MWh per MWh
1,085
204
59,378
4,986
1,430
16,16561,893
21,3552021 (Jan - Jun)
$2,000Above
Below
per MWh$2,000$2,000(Default) per MWh per MWh
5,161
182
440
51,07026
805
3,176
22,051
59,407
208
23,296

Transmission constraint penalty factors frequently set prices when PJM models
a surrogate constraint to limit the dispatch of a generator that would experience
voltage instability at its full output due to a transmission outage. Changes tothe surrogate constraint limit that exceed the unit’s ability to reduce output
cause constraint violations. Constraint violations also occur when the unit
follows the regulation signal or increases its minimum operating parameters
above the surrogate constraint limit. Prices set at the $2,000 per MWh penalty
factor are not useful signals to the market under these conditions and create
false arbitrage opportunities for virtuals.
174

Section 3 Energy Market

PJM’s use of CT pricing logic is inconsistent with the efficient market
dispatch and pricing. For that reason, in 2019 FERC declared CT
pricing logic to be unjust and unreasonable.70 PJM should discontinue
the use of CT pricing logic, regardless of whether the new fast-start
pricing process is in place.

69 PJM dispatchers generally log the resources paired with a constraint in the CT pricing logic. The data presented is based on PJM
dispatcher logs.
70 167 FERC ¶ 61,058 at P 69 (2019).

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-52 Frequency of CT pricing logic used in the real-time market(constraint intervals): January 2020 through June 2021
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

2020
231
167
122
173
632
825
842
1,189
1,982
2,017
956
1,404
10,540Figure 3-41 Map of real-time generation, less real-time load, by zone:
January through June, 202171

2021
783
469
1,186
1,539
1,204
1,240
6,421

Net Generation by Zone
Figure 3-41 shows the difference between the PJM real-time generation
and real-time load by zone in the first six months of 2021. Figure 3-41 iscolor coded using a scale on which red shades represent zones that haveless generation than load and green shades represent zones that have moregeneration than load, with darker shades meaning greater amounts of net
generation or load. Table 3-53 shows the difference between the PJM realtime generation and real-time load by zone in the first six months of 2020
and 2021.

71 Zonal real-time generation data for the map and corresponding table is based on the zonal designation for every bus listed in the mostcurrent PJM LMP bus model, which can be found at <http://www.pjm.com/markets-and-operations/energy/lmp-model-info.aspx>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 175

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-53 Real-time generation less real-time load by zone (GWh): January
through June, 2020 and 2021
Jan-Jun
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DOM
DPL
DUQ
EKPC
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
RECO

Generation
1,647.5
66,795.0
22,273.9
20,277.9
7,529.4
62,501.6
333.0
8,129.8
52,076.6
2,222.6
7,511.6
3,405.3
3,706.6
10,300.9
3,931.6
36,855.0
17,808.6
5,291.3
27,329.1
20,195.4
0.0

Zonal Generation and Load (GWh)
2020
Load
Net
Generation
4,184.7(2,537.2)
1,061.6
58,633.4
8,161.6
69,916.7
22,972.4(698.6)26,435.1
30,114.8(9,836.8)
23,828.9
14,029.0(6,499.6)
8,723.6
43,419.8
19,081.7
63,646.5
7,855.2(7,522.2)
537.0
12,180.4(4,050.6)
7,949.5
46,527.4
5,549.2
48,432.0
8,314.2(6,091.6)
1,706.3
6,095.9
1,415.7
8,003.4
6,037.1(2,631.8)
5,223.6
9,813.1(6,106.5)
2,494.6
7,188.1
3,112.7
8,752.9
57.9
3,873.8
5,201.9
17,642.7
19,212.3
35,169.8
8,063.9
9,744.7
22,205.5
12,832.9(7,541.6)
6,060.3
19,152.1
8,177.0
32,620.2
19,096.2
1,099.1
20,708.5
631.1(631.1)
0.0

2021
Load
4,473.6
61,567.8
23,953.6
31,403.2
14,756.3
44,533.0
8,240.7
12,694.8
51,327.3
8,869.4
6,300.9
6,493.1
10,352.9
7,561.2
58.5
18,510.7
8,260.9
13,397.6
19,976.2
19,921.4
663.5

Net(3,412.0)
8,348.8
2,481.4(7,574.3)(6,032.7)
19,113.6(7,703.7)(4,745.3)(2,895.3)(7,163.1)
1,702.5(1,269.5)(7,858.3)
1,191.7
5,143.4
16,659.1
13,944.5(7,337.3)
12,644.0
787.2(663.5)

withdrawals of energy as generation or load affects PJM’s calculation of zonal
load-weighted LMP.
The MMU recommends that during intervals when a generation bus showsa net withdrawal, the energy withdrawal be treated as load, not negative
generation, for purposes of calculating load and load-weighted LMP. The
MMU also recommends that during intervals when a load bus shows a net
injection, the energy injection be treated as generation, not negative load, forpurposes of calculating generation and load-weighted LMP.

Fuel Prices, LMP, and Dispatch
Energy Production by Fuel Source
Table 3-54 shows PJM generation by fuel source in GWh for the first six
months of 2020 and 2021. In the first six months of 2021, generation fromcoal units increased 39.7 percent, generation from natural gas units decreased
4.6 percent, and generation from oil increased 22.1 percent compared to thefirst six months of 2020. Wind and solar output rose by 12.8 percent comparedto the first six months of 2020, supplying 4.6 percent of PJM energy in thefirst six months of 2021.

Net Generation and LoadPJM sums all negative (injections) and positive (withdrawals) load at each
designated load bus when calculating net load (accounting load). PJM sums
all of the negative (withdrawals) and positive (injections) generation at eachgeneration bus when calculating net generation. Netting withdrawals andinjections by bus type (generation or load) affects the measurement of totalload and total generation. Energy withdrawn at a generation bus to provide,for example, auxiliary/parasitic power or station power, power to synchronous
condenser motors, or power to run pumped storage pumps, is actually load,
not negative generation. Energy injected at load buses by behind the meter
generation is actually generation, not negative load.
The zonal load-weighted LMP is calculated by weighting the zone’s load bus
LMPs by the zone’s load bus accounting load. The definition of injections and176

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-54 Generation (By fuel source (GWh)): January through June, 2020
and 202172 73 74

Coal
Bituminous
Sub Bituminous
Other Coal
NuclearGas
Natural Gas CC
Natural Gas CT
Natural Gas Other Units
Other Gas
Hydroelectric
Pumped Storage
Run of River
Other Hydro
Wind
Waste
Oil
Heavy OilLight Oil
DieselOther Oil
Solar, Net Energy Metering
Battery
BiofuelTotal

2020
Jan - Jun
GWh
67,844.9
62,576.2
2,840.9
2,427.8
136,376.3
151,835.5
143,212.5
5,588.7
1,981.6
1,052.7
9,155.7
2,221.4
6,296.9
637.4
14,497.6
2,145.3
931.5
0.0
55.2
9.5
866.8
1,872.7
17.1
438.3
385,115.0

Percent
17.6%
16.2%
0.7%
0.6%
35.4%
39.4%
37.2%
1.5%
0.5%
0.3%
2.4%
0.6%
1.6%
0.2%
3.8%
0.6%
0.2%
0.0%
0.0%
0.0%
0.2%
0.5%
0.0%
0.1%
100.0%

2021
Jan - Jun
GWh
94,782.2
84,715.1
7,161.9
2,905.2
133,383.6
144,803.0
135,757.2
6,695.6
1,455.9894.3
8,391.0
2,205.8
5,613.2
572.0
15,281.3
2,241.1
1,137.2
0.3
319.9
13.2
803.7
3,183.5
19.9
565.9
403,788.6

Percent
23.5%
21.0%
1.8%
0.7%
33.0%
35.9%
33.6%
1.7%
0.4%
0.2%
2.1%
0.5%
1.4%
0.1%
3.8%
0.6%
0.3%
0.0%
0.1%
0.0%
0.2%
0.8%
0.0%
0.1%
100.0%

Change in
Output39.7%
35.4%
152.1%
19.7%(2.2%)(4.6%)(5.2%)
19.8%(26.5%)(15.0%)(8.4%)(0.7%)(10.9%)(10.3%)
5.4%
4.5%
22.1%
NA
479.9%
38.7%(7.3%)
70.0%
16.6%
29.1%
4.8%

Table 3-55 Monthly generation (By fuel source (GWh)): January through June,
2021
Coal
Bituminous
Sub Bituminous
Other Coal
NuclearGas
Natural Gas CC
Natural Gas CT
Natural Gas Other Units
Other Gas
Hydroelectric
Pumped Storage
Run of River
Other Hydro
Wind
Waste
Oil
Heavy OilLight Oil
DieselOther Oil
Solar, Net Energy Metering
Battery
Biofuel
Total

Jan17,819.0
16,369.6
901.4
548.0
25,133.4
26,011.3
25,125.8
616.1
108.9
160.6
1,481.8
398.4
994.9
88.5
2,507.3
386.1
159.7
0.0
7.0
1.4
151.4
283.1
2.7
97.4
73,881.8

Feb21,469.5
18,774.2
2,124.5
570.7
22,125.3
22,670.8
21,754.8
579.9
198.0
138.1
1,299.8
354.0
847.5
98.3
2,618.9
316.6
254.1
0.0
136.5
2.8
114.8
255.8
3.3
81.4
71,095.4

Mar13,310.1
12,427.5
312.7
570.0
21,217.1
23,925.8
23,076.4
569.5
120.1
159.8
1,682.6
311.9
1,282.8
87.9
3,445.2
391.6
151.5
0.3
23.2
1.2
126.8
532.7
3.2
63.7
64,723.4

Apr
11,172.7
10,305.2
610.2
257.3
19,692.2
21,904.3
20,077.2
1,465.1
221.1
140.8
1,317.5
244.7
1,004.4
68.4
2,746.0
369.1
166.4
0.0
12.2
3.6
150.6
649.8
4.0
72.1
58,094.1

May
12,362.1
10,666.7
1,239.6
455.9
21,841.2
22,545.8
20,964.3
1,131.2
296.3
154.0
1,295.9
357.1
865.0
73.8
2,187.5
389.6
205.6
0.0
51.2
0.2
154.1
737.6
3.7
131.6
61,700.6

Jun18,648.7
16,171.8
1,973.5
503.4
23,374.4
27,745.0
24,758.6
2,333.8
511.5
141.0
1,313.5
539.8
618.6
155.1
1,776.5
388.0
200.0
0.0
89.9
4.0
106.1
724.6
3.0
119.6
74,293.3

Total
94,782.2
84,715.1
7,161.9
2,905.2
133,383.6
144,803.0
135,757.2
6,695.6
1,455.9894.3
8,391.0
2,205.8
5,613.2
572.0
15,281.3
2,241.1
1,137.2
0.3
319.9
13.2
803.7
3,183.5
19.9
565.9
403,788.6

72 All generation is total gross generation output and does not net out the MWh withdrawn at a generation bus to provide auxiliary/parasitic power or station power, power to synchronous condenser motors, power to run pumped hydro pumps or power to charge
batteries.
73 Net Energy Metering is combined with Solar due to data confidentiality reasons.
74 Other Gas includes: Landfill, Propane, Butane, Hydrogen, Gasified Coal, and Refinery Gas. Other Coal includes: Lignite, Liquefied Coal,
Gasified Coal, and Waste Coal. Other oil includes: Gasoline, Jet Oil, Kerosene, and Petroleum-Other.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 177

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-56 shows generation by natural gas, coal, nuclear and other fuel types
in the real-time energy market since 2008.
Table 3-56 Share of generation by fuel source: January 2008 through June
2021
Jan - Jun
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Natural Gas
6.1%
9.1%
9.0%
12.8%
19.4%
16.0%
16.1%
21.0%
25.4%
24.8%
28.2%
33.5%
39.2%
35.6%

Coal
56.0%
51.1%
50.9%
47.5%
40.3%
44.1%
45.8%
38.9%
32.2%
32.4%
29.7%
24.8%
17.6%
23.5%

Nuclear
34.5%
36.1%
35.6%
34.9%
35.3%
35.1%
33.1%
34.6%
36.4%
36.2%
35.0%
34.4%
35.4%
33.0%

Other Fuel Type
3.4%
3.8%
4.5%
4.8%
5.0%
4.8%
5.0%
5.5%
6.0%
6.6%
7.1%
7.3%
7.8%
7.9%

Fuel Diversity
Figure 3-42 shows the fuel diversity index (FDIe) for PJM energy generation.75
The FDIe is defined as, where si is the share of fuel type i. The
minimum possible value for the FDIe is zero, corresponding to all generationfrom a single fuel type. The maximum possible value for the FDIe results wheneach fuel type has an equal share of total generation. For a generation fleet
composed of 10 fuel types, the maximum achievable index is 0.9. The fueltype categories used in the calculation of the FDIe are the 10 primary fuelsources in Table 3-55 with nonzero generation values. As fuel diversity has
increased, seasonality in the FDIe has decreased and the FDIe has exhibited lessvolatility. Since 2012, the monthly FDIe has been less volatile as a result of thedecline in the share of coal from 51.3 percent prior to 2012 to 33.1 percent
from 2012 through June 30, 2021. A significant drop in the FDIe occurred in
the fall of 2004 as a result of the expansion of the PJM market footprint into
ComEd, AEP, and Dayton Power & Light Control Zones and the increased
75 Monitoring Analytics developed the FDI to provide an objective metric of fuel diversity. The FDI metric is similar to the HHI used tomeasure market concentration. The FDI is calculated separately for energy output and for installed capacity.

178

Section 3 Energy Market

shares of coal and nuclear that resulted.76 The increasing trend that began in2008 is a result of decreasing coal generation, increasing gas generation andincreasing wind generation. Coal generation as a share of total generation
was 56.0 percent for for the first six months of 2008 and 23.5 percent for the
first six months of 2021. Natural gas generation as a share of total generation
was 6.1 percent for for the first six months of 2008 and 35.6 percent for the
first six months of 2021. Wind generation as a share of total generation was
0.5 percent for for the first six months of 2008 and 3.8 percent for the firstsix months of 2021.
The FDIe increased 2.8 percent for the first six months of 2021 compared to
first six months of 2020. The increase in FDIe is primarily due to an increasein coal generation in the first six months of 2021 compared to the first six
months of 2020. The FDIe was also used to measure the impact on fuel diversityof potential retirements. A total of 4,763 MW of coal, CT, and other capacity
were identified as being at risk of retirement.77 Generation owners that intend
to retire a generator are required by the tariff to notify PJM at least 90 daysin advance.78 There are 10,161.0 MW of generation that have requested
retirement after June 30, 2021.79 The at risk units and other generators withdeactivation notices generated 25,631.1 GWh in the first six months of 2021.
The dashed line in Figure 3-42 shows a counterfactual result for FDIe assuming
the 25,631.1 GWh of generation from at risk units and other generators withdeactivation notices were replaced by gas, wind and solar generation.80 The
FDIe for the first six months of 2021 under the counterfactual assumption
would have been 0.9 percent lower than the actual FDIe.

76 See the 2019 State of the Market Report for PJM, Volume 2, Appendix A, “PJM Geography” for an explanation of the expansion of the
PJM footprint. The integration of the ComEd Control Area occurred in May 2004 and the integration of the AEP and Dayton control
zones occurred in October 2004.
77 See Table 7-47 in the 2020 State of the Market Report for PJM, Volume 2, Section 7: Net Revenue.
78 See PJM. OATT: § V “Generation Deactivation.”
79 See 2021 State of the Market Report for PJM: January through June, Section 12: Generation and Transmission Planning, Table 12-11.
80 It is assumed that 3,561.2 GWh of the replacement energy is from new wind and solar units. This value represents the increase over 2021
levels in renewable generation through June 30, 2021 that is required by RPS in the first six months of 2022. The split between solar andwind, 874.0 GWh solar and 2,687.2 GWh wind, is based on queue data.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Figure 3-42 Fuel diversity index for monthly generation: June 2000 throughJune 2021
1.0
0.9

0.8

Fuel Diversity Index (FDI)

0.7
0.6
0.5
0.4
0.3
FDI

0.2

Maximum Achievable FDI (10 Fuel Types)

0.1

FDI after replacing generation by at risk resources and announced retirements withgeneration by gas, wind and solar resources

0.0

Natural Gas Supply Issues
A combination of pipeline transportation and natural gas supplies is needed
to deliver natural gas to power plants. A generator could purchase a delivered
service in which the seller bundles both the transportation and fuel to makedeliveries to the plant. The delivered service could be purchased on either aterm contract or a spot basis. A generator could secure pipeline transportation
for part or all of the supplies needed to run the plant and purchase commodity
natural gas separately with a term supply contract or through daily purchasesin the spot market. Other options are also possible.
The increase in natural gas fired capacity in PJM has highlighted issues
with the dependence of the PJM system reliability on the fuel transportation
arrangements entered into by generators. The risks to the fuel supply for gas© 2021 Monitoring Analytics, LLC

generators, including the risk of interruptible supply on cold days and theability to get gas on short notice during times of critical pipeline operations,creates risks for the bulk power system. PJM should collect data on eachindividual generator’s fuel supply arrangements, and analyze the associatedlocational and regional risks to reliability.
In 2020 and the first six months of 2021, a number of interstate gas pipelinesthat supply fuel for generators in the PJM service territory issued restriction
notices limiting the availability of nonfirm transportation services. These
notices include warnings of operational flow orders (OFO) and actual OFOs.
These notices may, depending on the nature of the transportation service
purchased, permit the pipelines to restrict the provision of gas to 24 hour
ratable takes which means that hourly nominations must be the same for eachof the 24 hours in the gas day, with penalties for deviating from the nominatedquantities. Pipelines may also enforce strict balancing constraints which limit
the ability of gas users, depending on the nature of the transportation service
purchased, to deviate from the 24 hour ratable take and which may limit theability of users to have access to unused gas.
Pipeline operators use restrictive and inflexible rules to manage the balanceof supply and demand during constrained operating conditions determinedby the pipeline. The independent operations of geographically overlapping
pipelines during extreme conditions highlights the potential shortcomingsof a gas pipeline network that relies on individual pipelines to manage thebalancing of supply and demand. The independent operational restrictions
imposed by pipelines and the impact on electric generators during extreme
conditions demonstrates the potential benefits to creating a separate gas
ISO/RTO structure to coordinate the supply of gas across pipelines and withthe electric RTOs and to facilitate the interoperability of the pipelines in an
explicit network.

Types of Marginal Resources
LMPs result from the operation of a market based on security-constrained,
least-cost dispatch in which marginal resources determine system LMPs,

2021 Quarterly State of the Market Report for PJM: January through June 179

2021 Quarterly State of the Market Report for PJM: January through June

based on their offers. Marginal resource designation is not limited to physicalresources in the day-ahead energy market. INC offers, DEC bids and up tocongestion transactions are dispatchable injections and withdrawals in the
day-ahead energy market that can set price via their offers and bids.
Table 3-57 shows the type of fuel used and technology by marginal resourcesin the real-time energy market. There can be more than one marginal resourcein any given interval as a result of transmission constraints. In the first six
months of 2021, coal units were 16.8 percent and natural gas units were 68.7
percent of marginal resources. In the first six months of 2021, natural gas
combined cycle units were 61.1 percent of marginal resources. In the first six
months of 2020, coal units were 16.4 percent and natural gas units were 74.3
percent of the total marginal resources. In the first six months of 2020, natural
gas combined cycle units were 70.1 percent of the total marginal resources.
In the first six months of 2021, 87.1 percent of the wind marginal units had
negative offer prices, 12.2 percent had zero offer prices and 0.7 percent of thewind marginal units had positive offer prices. In the first six months of 2020,
95.8 percent of the wind marginal units had negative offer prices, 4.2 percent
had zero offer prices and none had positive offer prices.

Table 3-57 Type of fuel used and technology (By real-time marginal units):
January through June, 2017 through 202181
Fuel
Gas
Coal
Wind
Gas
Other
Uranium
Gas
Oil
Gas
Other
Oil
Oil
Oil
Municipal Waste
Landfill Gas
Municipal Waste
Municipal Waste
Landfill Gas
Gas
Landfill Gas

Technology
CC
Steam
Wind
CT
Solar
Steam
Steam
CT
RICE
Steam
Steam
RICE
CC
Steam
CT
RICE
CT
Steam
Fuel Cell
RICE

2017
44.11%
33.47%
9.81%
3.78%
0.15%
0.96%
2.56%
4.24%
0.30%
0.16%
0.01%
0.37%
0.00%
0.01%
0.00%
0.00%
0.00%
0.02%
0.01%
0.02%

2018
53.21%
29.65%
3.71%
5.85%
0.11%
1.12%
1.34%
3.19%
0.52%
0.23%
0.55%
0.14%
0.25%
0.05%
0.00%
0.05%
0.03%
0.00%
0.00%
0.00%

(Jan - Jun)2019
63.09%
26.57%
3.47%
4.19%
0.07%
0.67%
0.77%
0.43%
0.00%
0.07%
0.01%
0.00%
0.03%
0.03%
0.01%
0.00%
0.00%
0.00%
0.00%
0.00%

2020
70.12%
16.41%
7.36%
2.90%
0.51%
1.29%
0.99%
0.05%
0.25%
0.06%
0.01%
0.02%
0.00%
0.01%
0.01%
0.00%
0.00%
0.00%
0.00%
0.00%

2021
61.12%
16.81%
11.59%
6.50%
1.31%
0.80%
0.76%
0.49%
0.30%
0.13%
0.07%
0.06%
0.04%
0.01%
0.01%
0.00%
0.00%
0.00%
0.00%
0.00%

The proportion of marginal nuclear units decreased from 1.29 percent in thefirst six months of 2020 to 0.80 percent in the first six months of 2021. Most
nuclear units are offered as fixed generation in the PJM market. A small
number of nuclear units were offered with a dispatchable range since 2015.
The dispatchable nuclear units do not always respond to dispatch instructions.

81 The unit type RICE refers to Reciprocating Internal Combustion Engines.

180

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Figure 3-43 shows the type of fuel used by marginal resources in the real-timeenergy market since 2004. The role of coal as a marginal resource has declined
while the role of gas as a marginal resource has increased.
Figure 3-43 Type of fuel used (By real-time marginal units): January throughJune, 2004 through 2021
90%
80%

Table 3-58 Day-ahead marginal resources by type/fuel used and technology:
January through June, 2017 through 2021

Percent of Marginal Fuel

70%
60%
50%
40%
30%
20%
10%

0%

Table 3-58 shows the type of fuel used and technology where relevant, of
marginal resources in the day-ahead energy market. In the first six months of2021, up to congestion transactions were 36.5 percent of marginal resources.
Up to congestion transactions were 52.3 percent of marginal resources in thefirst six months of 2020. In the first six months of 2021, virtual transactions
were 79.3 percent of marginal resources. Virtual transactions were 80.8
percent of marginal resources in the first six months of 2020.

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Gas

Coal

Wind

Other

Uranium

Municipal Waste

Landfill Gas

Interface

Emergency DR

Hydro© 2021 Monitoring Analytics, LLC

Oil

Type/Fuel
Up to Congestion Transaction
DEC
INC
Gas
Coal
Wind
Gas
Dispatchable Transaction
Gas
Gas
Price Sensitive Demand
Other
Municipal Waste
Other
Uranium
Oil
Oil
Oil
Oil
Water
Total

Technology
NA
NA
NA
CC
Steam
Wind
Steam
NA
CT
RICE
NA
Steam
RICE
Solar
Steam
Steam
CT
RICE
CC
Hydro

2017
80.59%
9.63%
5.33%
1.94%
1.61%
0.23%
0.32%
0.03%
0.04%
0.02%
0.00%
0.00%
0.00%
0.00%
0.03%
0.00%
0.21%
0.02%
0.00%
0.00%
100.00%2018
66.89%
14.65%
8.38%
4.91%
4.15%
0.18%
0.26%
0.11%
0.17%
0.04%
0.01%
0.01%
0.00%
0.03%
0.08%
0.05%
0.04%
0.00%
0.03%
0.00%
100.00%(Jan - Jun)2019
57.80%
18.22%
13.33%
5.80%
4.19%
0.11%
0.26%
0.11%
0.07%
0.04%
0.00%
0.01%
0.01%
0.01%
0.02%
0.00%
0.01%
0.00%
0.00%
0.00%
100.00%2020
52.29%
14.21%
14.26%
12.66%
5.32%
0.40%
0.31%
0.07%
0.08%
0.02%
0.00%
0.09%
0.01%
0.02%
0.23%
0.00%
0.03%
0.00%
0.00%
0.00%
100.00%2021
36.46%
25.10%
17.75%
11.90%
6.82%
0.94%
0.38%
0.20%
0.13%
0.07%
0.05%
0.04%
0.04%
0.04%
0.04%
0.02%
0.01%
0.01%
0.01%
0.00%
100.00%2021 Quarterly State of the Market Report for PJM: January through June 181

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-44 shows, for the day-ahead energy market from January 2014
through June 2021, the daily proportion of marginal resources that were up
to congestion transactions and/or generation units. The UTC share decreased
from 52.3 percent in the first six months of 2020 to 36.5 percent in the firstsix months of 2021.
Up to congestion transaction volumes decreased following the allocation of
uplift charges on November 1, 2020.82
Figure 3-44 Day-ahead marginal up to congestion transaction and generation
units: January 2014 through June 2021
100%
90%
80%

Marginal Percent

70%
60%

50%
40%
30%

Generation Unit
Up to Congestion Transaction
September 8, 2014
December 7, 2015
February 22, 2018
November 1, 2020

Fuel Price Trends and LMP
In a competitive market, changes in LMP follow changes in the marginal
costs of marginal units, the units setting LMP. In general, fuel costs make up
between 80 percent and 90 percent of short run marginal cost depending on
generating technology, unit efficiency, unit age and other factors. The impactof fuel cost on marginal cost and on LMP depends on the fuel burned bymarginal units and changes in fuel costs. Changes in emission allowance costs
also contribute to changes in the marginal cost of marginal units.
Figure 3-45 shows fuel prices in PJM for 2012 through June 2021. Natural
gas prices increased in the first six months of 2021 compared to the firstsix months of 2020, as a result of very high gas prices in mid February. Gas
price volatility increased and gas price differences among regions increased.
Western PJM gas prices were much higher in mid February than eastern PJM
gas prices although both increased significantly. The price of natural gas in
the Marcellus Shale production area is lower than in other areas of PJM. A
number of new combined cycle plants have located in the production area
since 2016. In the first six months of 2021, the price of production gas was
55.8 percent higher than in the first six months of 2020, the price of eastern
natural gas was 77.2 percent higher and the price of western natural gas
was 168.1 percent higher. The price of Northern Appalachian coal was 10.4
percent higher; the price of Central Appalachian coal was 32.8 percent higher;
and the price of Powder River Basin coal was 1.2 percent lower.83 The price of
ULSD NY Harbor Barge was 78.6 percent higher.

20%
10%
0%

82 172 FERC ¶ 61,046 (2020).

182

Section 3 Energy Market

83 Eastern natural gas consists of the average of Texas M3, Transco Zone 6 non-NY, Transco Zone 6 NY and Transco Zone 5 daily indices.
Western natural gas prices are the average of Columbia Appalachia and Chicago Citygate daily indices. Production gas prices are theaverage of Dominion South Point, Tennessee Zone 4, and Transco Leidy Line receipts daily indices. Coal prices are the average of daily fuelprices for Central Appalachian coal, Northern Appalachian coal, and Powder River Basin coal. All fuel prices are from Platts.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Figure 3-45 Spot average fuel price comparison: 2012 through June 202184($/MMBtu)$25

Average Monthly Spot Price ($/MMBtu)$20

of 2021 had been the same as in the first six months of 2020, holding themarket dispatch constant, the real-time, load-weighted, average LMP in thefirst six months of 2021 would have been lower, $20.33 per MWh, than theobserved $30.62 per MWh. Almost all, 91.7 percent of the increase in realtime, load-weighted, average LMP, $10.29 per MWh out of $11.22 per MWh,is directly attributable to fuel costs. Contributors to the other $0.93 per MWh
are increased load, adjusted dispatch, including adjustments to dispatch due
to changes in relative fuel costs among units, and lower markups.

$15

Table 3-59 Real-time, fuel-cost adjusted, load-weighted average LMP (Dollars
per MWh): January through June, 2020 and 2021
$102021 Fuel-Cost Adjusted,
Load-Weighted LMP$20.33

Average$52020 Load-Weighted LMP$19.402020 Load-Weighted LMP$19.40

Average

Jan-12
May-12
Sep-12
Jan-13May-13
Sep-13Jan-14May-14
Sep-14Jan-15May-15
Sep-15Jan-16May-16
Sep-16
Jan-17May-17
Sep-17Jan-18May-18
Sep-18Jan-19
May-19Sep-19Jan-20May-20
Sep-20Jan-21
May-21

Average$0

East Gas

West Gas

Production Gas

Northern Appalachian Coal

Central Appalachian Coal

PRB Coal

Table 3-59 compares the PJM real-time fuel-cost adjusted, load-weighted,
average LMP in the first six months of 2021 to the load-weighted, average
LMP in the first six months of 2020.85 The real-time, load-weighted average
LMP in the first six months of 2021 increased by $11.22 or 57.8 percent
from the real-time load-weighted, average LMP in the first six months of2020. The real-time load-weighted, average LMP for the first six months of2021 was 50.6 percent higher than the real-time, fuel-cost adjusted, loadweighted average LMP for the first six months of 2021. The real-time, fuelcost adjusted, load-weighted, average LMP for the first six months of 2021
was 4.8 percent higher than the real-time, load-weighted, average LMP for
the first six months of 2020. If fuel and emissions costs in the first six months
84 This figure is modified from the corresponding figure in the 2020 Quarterly State of the Market Report for PJM: January through June,
which included an error.
85 The fuel-cost adjusted LMP reflects both the fuel and emissions where applicable, including NOx, CO2 and SOx costs.

© 2021 Monitoring Analytics, LLC

2021 Load-Weighted LMP$30.622021 Fuel-Cost Adjusted,
Load-Weighted LMP$20.332021 Load-Weighted LMP$30.62

Change$10.29Change$0.93
Change$11.22

Percent
Change50.6%
Percent
Change4.8%
Change57.8%

Table 3-60 shows the impact of each fuel type on the difference between
the fuel-cost adjusted, load-weighted, average LMP and the load-weighted,
average LMP in the first six months of 2021. Table 3-60 shows that lower
natural gas prices explain 89.7 percent of the fuel-cost related decrease in thereal-time annual, load-weighted, average LMP in the first six months of 2021
from 2020.
Table 3-60 Share of change in fuel-cost adjusted LMP ($/MWh) by fuel type:
January through June, 2021 adjusted to 2020 fuel prices
Fuel Type
Gas
Coal
Oil
Uranium
Municipal Waste
Other
NA
Wind
Total

Share of Change in Fuel Cost Adjusted,
Load Weighted LMP
$9.23
$0.98
$0.08
$0.00
$0.00
$0.00
$0.00
$0.00
$10.29Percent
89.7%
9.5%
0.8%
0.0%
0.0%
0.0%
0.0%
0.0%
100.0%

2021 Quarterly State of the Market Report for PJM: January through June 183

2021 Quarterly State of the Market Report for PJM: January through June

Components of LMP
Components of Real-Time, Load-Weighted, LMP
LMPs result from the operation of a market based on security-constrained,
economic (least cost) dispatch (SCED) in which marginal units determine
system LMPs, based on their offers and up to fourteen minute ahead forecastsof system conditions. Those offers can be decomposed into components
including fuel costs, emission costs, variable operation and maintenance(VOM) costs, markup, FMU adder and the 10 percent cost adder. As a result, it
is possible to decompose LMP by the components of unit offers.
Cost offers of marginal units are separated into their component parts. The
fuel related component is based on unit specific heat rates and spot fuel prices.
Emission costs are calculated using spot prices for NOx, SO2 and CO2 emission
credits, emission rates for NOx, emission rates for SO2 and emission rates forCO2. The CO2 emission costs are applicable to PJM units in the PJM statesthat participate in RGGI: Delaware, Maryland, New Jersey, and Virginia.86 The
FMU adder is the calculated contribution of the FMU and AU adders to LMP
that results when units with FMU or AU adders are marginal.
Since the implementation of scarcity pricing on October 1, 2012, PJM jointly
optimizes the commitment and dispatch of energy and reserves. In periodsof scarcity when generators providing energy have to be dispatched downfrom their economic operating level to meet reserve requirements, the joint
optimization of energy and reserves takes into account the opportunity costof the reduced generation and the associated incremental cost to maintainreserves. If a unit incurring such opportunity costs is a marginal resource inthe energy market, this opportunity cost will contribute to LMP. In addition,in periods when the SCED solution does not meet the reserve requirements,
PJM should invoke shortage pricing. During shortage conditions, the LMPs ofmarginal generators reflect the cost of not meeting the reserve requirements,
the scarcity adder, which is defined by the operating reserve demand curve.

86 New Jersey withdrew from RGGI, effective January 1, 2012, and rejoined RGGI effective January 1, 2020. Virginia joined RGGI effective
January 1, 2021.

184

Section 3 Energy Market

The components of LMP are shown in Table 3-61, including markup using
unadjusted cost-based offers.87 Table 3-61 shows that in the first six months of2021, 14.0 percent of the load-weighted LMP was the result of coal costs, 51.7
percent was the result of gas costs and 2.7 percent was the result of the costof carbon emission allowances. Using unadjusted cost-based offers, negative
markup was -6.3 percent of the load-weighted LMP. Using unadjusted costbased offers, positive markup was 5.9 percent of the load weighted LMP. The
fuel-related components of LMP reflect the degree to which the cost of theidentified fuel affects LMP and does not reflect the other components of theoffers of units burning that fuel. LMP may, at times, be set by transmission
penalty factors. When a transmission constraint is binding and there are nocheaper generation alternatives to resolve the constraint, system operators
may allow the transmission limit to be violated. When this occurs, the shadow
price of the constraint is set by transmission penalty factors. In the first six
months of 2021, 11.2 percent of the load-weighted LMP was the result oftransmission penalty factors affecting LMPs. The percent contribution oftransmission penalty factors was the highest since PJM removed constraint
relaxation logic and allowed penalty factors to affect LMPs in February, 2019.
The component NA is the unexplained portion of load-weighted LMP. For
several intervals, PJM failed to provide all the data needed to accurately
calculate generator sensitivity factors. As a result, the LMP for those intervals
cannot be decomposed into component costs. The NA component is the
cumulative effect of excluding those five minute intervals. The percent column
is the difference (in percentage points) in the proportion of LMP represented
by each component in the first six months of 2021 and 2020.

87 These components are explained in the Technical Reference for PJM Markets, at p 27 “Calculation and Use of Generator Sensitivity/Unit
Participation Factors,” <http://www.monitoringanalytics.com/‌reports/Technical_References/references.shtml>.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-61 Components of real-time (Unadjusted), load-weighted, average
LMP: January through June, 2020 and 2021
Element
Gas
Coal
Constraint Violation Adder
Ten Percent Adder
Positive Markup
Variable MaintenanceNA
Variable Operations
CO2 Cost
LPA-SCED Differential
Ancillary Service Redispatch Cost
Scarcity Adder
Oil
NOx Cost
Opportunity Cost Adder
Increase Generation Adder
Landfill Gas
Market-to-Market Adder
Other
SO2 Cost
Uranium
Renewable Energy Credits
Decrease Generation Adder
LPA Rounding Difference
Negative Markup
Total

2020 (Jan - Jun)
Contribution
to LMP
Percent
$7.94
40.9%
$5.25
27.1%
$0.77
4.0%
$1.58
8.2%
$1.85
9.5%
$1.44
7.4%
$0.53
2.7%
$0.83
4.3%
$0.36
1.8%
$0.01
0.1%
$0.03
0.1%
$0.03
0.2%
$0.03
0.1%
$0.00
0.0%
$0.02
0.1%
$0.06
0.3%
($0.01)(0.1%)
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
($0.01)(0.0%)($0.02)(0.1%)$0.22
1.1%($1.50)(7.7%)$19.40100.0%

2021 (Jan - Jun)
Contribution
to LMP
Percent$15.83
51.7%
$4.30
14.0%
$3.44
11.2%
$2.04
6.6%
$1.81
5.9%
$1.15
3.8%
$0.83
2.7%
$0.83
2.7%
$0.82
2.7%
$0.72
2.3%
$0.33
1.1%
$0.29
1.0%
$0.28
0.9%
$0.16
0.5%
$0.07
0.2%
$0.05
0.2%
$0.01
0.0%
$0.01
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
($0.02)(0.1%)($0.37)(1.2%)($1.93)(6.3%)$30.62100.0%

Change inPercent
10.8%(13.0%)
7.3%(1.5%)(3.6%)(3.7%)(0.0%)(1.6%)
0.8%
2.3%
0.9%
0.8%
0.8%
0.5%
0.1%
(0.2%)
0.1%
0.0%
0.0%
(0.0%)(0.0%)
0.0%
0.0%(2.3%)
1.4%
0.0%

In order to accurately assess the markup behavior of market participants, realtime and day-ahead LMPs are decomposed using two different approaches. In
the first approach (Table 3-61 and Table 3-64) markup is the difference between
the price offer and the cost-based offer (unadjusted markup). In the second
approach (Table 3-62 and Table 3-65), the 10 percent markup is removed fromthe cost-based offers of coal, gas, and oil units (adjusted markup).
The components of LMP are shown in Table 3-62, including markup using
adjusted cost-based offers.

© 2021 Monitoring Analytics, LLC

Table 3-62 Components of real-time (Adjusted), load-weighted, average LMP:
January through June, 2020 and 2021
Element
Gas
Coal
Constraint Violation Adder
Positive Markup
Variable MaintenanceNA
Variable Operations
CO2 Cost
LPA-SCED Differential
Ancillary Service Redispatch Cost
Scarcity Adder
Oil
NOx Cost
Opportunity Cost Adder
Increase Generation Adder
Landfill Gas
Market-to-Market Adder
Other
Ten Percent Adder
SO2 Cost
Uranium
Renewable Energy Credits
Decrease Generation Adder
LPA Rounding Difference
Negative Markup
Total

2020 (Jan - Jun)
Contribution
to LMP
Percent
$7.94
40.9%
$5.25
27.1%
$0.77
4.0%
$2.70
13.9%
$1.44
7.4%
$0.53
2.7%
$0.83
4.3%
$0.36
1.8%
$0.01
0.1%
$0.03
0.1%
$0.03
0.2%
$0.03
0.1%
$0.00
0.0%
$0.02
0.1%
$0.06
0.3%
($0.01)(0.1%)
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
($0.01)(0.0%)($0.02)(0.1%)$0.22
1.1%($0.78)(4.0%)$19.40100.0%

2021 (Jan - Jun)
Contribution
to LMP
Percent$15.83
51.7%
$4.30
14.0%
$3.44
11.2%
$2.84
9.3%
$1.15
3.8%
$0.83
2.7%
$0.83
2.7%
$0.82
2.7%
$0.72
2.3%
$0.33
1.1%
$0.29
1.0%
$0.28
0.9%
$0.16
0.5%
$0.07
0.2%
$0.05
0.2%
$0.01
0.0%
$0.01
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
($0.02)(0.1%)($0.37)(1.2%)($0.93)(3.0%)$30.62100.0%

Change inPercent
10.8%(13.0%)
7.3%(4.7%)(3.7%)(0.0%)(1.6%)
0.8%
2.3%
0.9%
0.8%
0.8%
0.5%
0.1%
(0.2%)
0.1%
0.0%
0.0%
0.0%
(0.0%)(0.0%)
0.0%
0.0%(2.3%)
1.0%
0.0%

Table 3-63 shows the components of the load weighted LMP, using unadjusted
cost based offers, for the seven days between February 13, 2021, and February
18, 2021, when gas prices were high in the PJM region. Table 3-63 showsthat in the seven days of 2021 with the highest gas prices, 1.9 percent of theload-weighted LMP was the result of coal costs, 66.3 percent was the result ofgas costs and 13.6 percent was the result of transmission constraint penalty
factors. The transmission constraints that were violated during this period
included the high voltage constraints: AP South reactive transfer interface;
Broadford 765 kV Transformer; Kyger Creek to Department of Energy, 345 kVtransmission line; and Cedar substation to William, 230 kV transmission line.
Negative markup was -7.5 percent of the load-weighted LMP.
2021 Quarterly State of the Market Report for PJM: January through June 185

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-63 Components of real-time (Unadjusted), load-weighted, average
LMP: February 13, 2021 through February 18, 2021
Gas
Constraint Violation Adder
Positive Markup
Ten Percent AdderOil
Coal
Variable Maintenance
CO2 Cost
Variable Operations
NA
Ancillary Service Redispatch Cost
LPA Rounding Difference
LPA-SCED Differential
Opportunity Cost Adder
Increase Generation Adder
Market-to-Market Adder
NOx Cost
SO2 Cost
Decrease Generation Adder
Negative Markup
Total

13 February - 18 February
Contribution to LMP$50.83$10.42
$5.64
$5.07
$4.73
$1.43
$1.09
$1.03
$0.62
$0.43
$0.42
$0.27
$0.15
$0.15
$0.14
$0.03
$0.00
$0.00
($0.03)($5.72)$76.61

Percent
66.3%
13.6%
7.4%
6.6%
6.2%
1.9%
1.4%
1.3%
0.8%
0.6%
0.6%
0.3%
0.2%
0.2%
0.2%
0.0%
0.0%
0.0%
(0.0%)(7.5%)
100.0%

Components of Day-Ahead, Load-Weighted LMP
LMPs result from the operation of a market based on security-constrained,
least-cost dispatch in which marginal resources determine system LMPs,
based on their offers. For physical units, those offers can be decomposed
into their components including fuel costs, emission costs, variable operationand maintenance costs, markup, day-ahead scheduling reserve (DASR)
adder and the 10 percent cost offer adder. INC offers, DEC bids and up tocongestion transactions are dispatchable injections and withdrawals in the
day-ahead energy market with an offer price that cannot be decomposed.
Using identified marginal resource offers and the components of unit offers,
it is possible to decompose PJM system LMP using the components of unit
offers and sensitivity factors.

186

Section 3 Energy Market

Table 3-64 shows the components of the PJM day-ahead, annual, loadweighted, average LMP. In the first six months of 2021, 27.7 percent of theload-weighted LMP was the result of gas costs, 14.3 percent of the loadweighted LMP was the result of coal costs, 28.3 percent was the result of DEC
bid costs, 12.4 percent was the result of INC bid costs and 2.2 percent was theresult of the up to congestion transaction costs.
Table 3-64 Components of day-ahead, (unadjusted), load-weighted, average
LMP (Dollars per MWh): January through June, 2020 and 2021
Element
DEC
Gas
Coal
INC
Ten Percent Cost Adder
Variable Operating Cost
Variable Maintenance Cost
Up to Congestion Transaction
CO2
Dispatchable Transaction
Price Sensitive DemandMarkupNOx
Municipal Waste
Oil
Constrained Off
DASR Offer Adder
SO2
Other
DASR LOC AdderWind
UraniumNA
Total

2020 (Jan - Jun)
Contribution
to LMP
Percent
$3.55
18.4%
$3.63
18.9%
$5.58
29.0%
$2.69
14.0%
$1.12
5.8%
$0.74
3.9%
$0.99
5.2%
$0.62
3.2%
$0.21
1.1%
$0.09
0.5%
$0.00
0.0%
($0.14)(0.7%)$0.01
0.0%($0.00)(0.0%)($0.01)(0.0%)
$0.07
0.4%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
$0.01
0.0%
($0.00)(0.0%)
$0.00
0.0%
$0.07
0.4%
$19.23100.0%

2021 (Jan - Jun)
Contribution
to LMP
Percent
$8.78
28.3%
$8.59
27.7%
$4.43
14.3%
$3.84
12.4%
$1.52
4.9%
$0.72
2.3%
$0.72
2.3%
$0.67
2.2%
$0.67
2.2%
$0.42
1.4%
$0.23
0.7%
$0.22
0.7%
$0.14
0.5%
$0.10
0.3%
$0.06
0.2%
$0.02
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
($0.02)(0.1%)($0.21)(0.7%)
$0.00
0.0%
$0.10
0.3%
$31.00100.0%

Change inPercent
9.9%
8.9%(14.7%)(1.6%)(0.9%)(1.5%)(2.8%)(1.1%)
1.1%
0.9%
0.7%
1.4%
0.4%
0.3%
0.2%
(0.3%)
0.0%(0.0%)(0.0%)(0.1%)(0.7%)(0.0%)(0.0%)
0.0%© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-65 shows the components of the PJM day-ahead, annual, loadweighted, average LMP including the adjusted markup calculated by excluding
the 10 percent adder from the coal, gas or oil units.
Table 3-65 Components of day-ahead, (adjusted), load-weighted, average
LMP (Dollars per MWh): January through June, 2020 and 2021
Element
DEC
Gas
Coal
INC
MarkupVariable Operating Cost
Variable Maintenance Cost
Up to Congestion Transaction
CO2
Dispatchable Transaction
Price Sensitive Demand
NOx
Municipal Waste
Oil
Constrained Off
DASR Offer Adder
Ten Percent Cost Adder
SO2
Other
DASR LOC AdderWind
UraniumNA
Total

2020 (Jan - Jun)
Contribution
to LMP
Percent
$3.55
18.4%
$3.63
18.9%
$5.58
29.0%
$2.69
14.0%
$0.98
5.1%
$0.74
3.9%
$0.99
5.2%
$0.62
3.2%
$0.21
1.1%
$0.09
0.5%
$0.00
0.0%
$0.01
0.0%
($0.00)(0.0%)($0.01)(0.0%)
$0.07
0.4%
$0.00
0.0%
($0.00)(0.0%)
$0.00
0.0%
$0.00
0.0%
$0.01
0.0%
($0.00)(0.0%)
$0.00
0.0%
$0.07
0.4%
$19.23100.0%

2021 (Jan - Jun)
Contribution
to LMP
Percent
$8.78
28.3%
$8.59
27.7%
$4.43
14.3%
$3.84
12.4%
$1.75
5.6%
$0.72
2.3%
$0.72
2.3%
$0.67
2.2%
$0.67
2.2%
$0.42
1.4%
$0.23
0.7%
$0.14
0.5%
$0.10
0.3%
$0.06
0.2%
$0.02
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
$0.00
0.0%
($0.02)(0.1%)($0.21)(0.7%)
$0.00
0.0%
$0.10
0.3%
$31.00100.0%

Change inPercent
9.9%
8.9%(14.7%)(1.6%)
0.5%(1.5%)(2.8%)(1.1%)
1.1%
0.9%
0.7%
0.4%
0.3%
0.2%
(0.3%)
0.0%
0.0%(0.0%)(0.0%)(0.1%)(0.7%)(0.0%)(0.0%)
0.0%

a Performance Assessment Interval (PAI). The days with shortage pricing
intervals did not correspond to the days with emergency alerts.
Table 3-66 Summary of emergency events declared: January through June,
2020 and 2021

Event Type
Cold Weather Alert
Hot Weather Alert
Maximum Emergency Generation Alert
Primary Reserve Alert
Voltage Reduction Alert
Primary Reserve Warning
Voltage Reduction Warning
Pre Emergency Mandatory Load Management Reduction Action
Emergency Mandatory Load Management Reduction Action (30, 60 or 120 minute lead time)
Maximum Emergency Action
Emergency Energy Bids Requested
Voltage Reduction Action
Shortage Pricing
Energy export recalls from PJM capacity resources

Number of days
events declared
2020
2021
(Jan - (Jan Jun)
Jun)
3
6
2
6
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
7
0
0

Shortage
PJM’s energy market experienced five minute shortage pricing for ten 5
minute intervals on seven days in the first six months of 2021. Table 3-66
shows a summary of the number of days emergency alerts, warnings andactions were declared in PJM in the first six months of 2020 and 2021. In
the first six months of 2021, there were no emergency actions that triggered© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 187

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-46 shows the number of days that weather and capacity emergency
alerts were issued in PJM in the first six months of 2017 through 2021.

Table 3-67 provides a description of PJM declared emergency procedures.88 89 90 91

Figure 3-46 Declared emergency alerts: January through June, 2017 through2021

Emergency Procedure
Cold Weather Alert

14
Cold Weather Alert

Hot Weather Alert

12

Maximum Emergency Generation Alert
Primary Reserve Alert
Voltage Reduction Alert

Number of days alerts issued

10

8

6

4

2

0

2017

2018

2019

2020

2021

Year (January through June)

Emergency Procedures
PJM declares alerts at least a day prior to the operating day to warn membersof possible emergency actions that could be taken during the operating day.
In real time, on the operating day, PJM issues warnings notifying members ofsystem conditions that could result in emergency actions during the operatingday.

Table 3-67 Description of emergency procedures
PurposeTo prepare personnel and facilities for extreme cold weather conditions, generally
when forecast weather conditions approach minimum or temperatures fall below ten
degrees Fahrenheit.
Hot Weather Alert
To prepare personnel and facilities for extreme hot and/or humid weather conditions,generally when forecast temperatures exceed 90 degrees with high humidity.
Maximum Emergency
To provide an early alert at least one day prior to the operating day that system
Generation Alertconditions may require the use of the PJM emergency procedures and resources must
be able to increase generation above the maximum economic level of their offers.
Primary Reserve Alert
To alert members of a projected shortage of primary reserve for a future period. It is
implemented when estimated primary reserve is less than the forecast requirement.
Voltage Reduction Alert To alert members that a voltage reduction may be required during a future critical
period. It is implemented when estimated reserve capacity is less than forecasted
synchronized reserve requirement.
Pre-Emergency LoadTo request load reductions from customers registered in the PJM Demand Response
Management Reduction program that need 30, 60, or 120 minute lead time before declaring emergency load
Actionmanagement reductions
Emergency Mandatory
To request load reductions from customers registered in the PJM Demand Response
Load Management
program that need 30, 60, or 120 minute lead time to provide additional load relief,
Reduction Action
generally declared simultaneously with NERC Energy Emergency Alert Level 2 (EEA2)
Primary Reserve Warning To warn members that available primary reserve is less than required and present
operations are becoming critical. It is implemented when available primary reserve isless than the primary reserve requirement but greater than the synchronized reserve
requirement.
Maximum Emergency
To provide real time notice to increase generation above the maximum economic level.
Generation Action
It is implemented whenever generation is needed that is greater than the maximum
economic level.
Voltage Reduction
To warn members that actual synchronized reserves are less than the synchronized
Warning & Reduction of reserve requirement and that voltage reduction may be required.
Non-Critical Plant Load
Deploy All Resources
For emergency events that do not evolve over time, but rather develop rapidly andActionwithout prior warning, PJM issues this action to instruct all generation resources to beonline immediately and to all load management resources to reduce load immediately.
Manual Load Dump
To warn members of the critical condition of present operations that may require
Warningmanually dumping load. Issued when available primary reserve capacity is less than thelargest operating generator or the loss of a transmission facility jeopardizes reliable
operations after all other possible measures are taken to increase reserve.
Voltage Reduction Action To reduce load to provide sufficient reserve capacity to maintain tie flow schedules
and preserve limited energy sources. It is implemented when load relief is needed tomaintain tie schedules.
Manual Load Dump
To provide load relief when all other possible means of supplying internal PJM RTO
Actionload have been used to prevent a catastrophe within the PJM RTO or to maintain tie
schedules so as not to jeopardize the reliability of the other interconnected regions.
88 See PJM. “Manual 13: Emergency Operations,” Rev. 78 (Jan. 27, 2021), Section 3.3 Cold Weather Alert.
89 See PJM. “Manual 13: Emergency Operations,” Rev. 78 (Jan. 27, 2021), Section 3.4 Hot Weather Alert.
90 See PJM. “Manual 13: Emergency Operations,” Rev. 78 (Jan. 27, 2021), Section 2.3.1 Advanced Notice Emergency Procedures: Alerts.
91 See PJM. “Manual 13: Emergency Operations,” Rev. 78 (Jan. 27, 2021), Section 2.3.2 Real-Time Emergency Procedures (Warnings and Actions).

188

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-68 shows the dates when emergency alerts and warnings were declared and when emergency actions were implemented in the first six months of 2021.
Table 3-68 Declared emergency alerts, warnings and actions: January through June, 2021

Date
2/7/2021
2/8/2021
2/9/2021
2/10/2021
2/14/2021
2/15/2021
5/23/2021
6/6/2021
6/7/2021
6/28/2021
6/29/2021
6/30/2021

Cold Weather Alert
Western except EKPC
Western except EKPC
COMED
COMED
COMED
Western

Hot Weather Alert

Maximum
Emergency
Generation
Alert

Primary
Reserve
Alert

VoltagePrimary
Reduction Reserve
Alert
Warning

Voltage Reduction
Warning andReduction of NonCritical Plant Load

Maximum
Emergency
Generation
ActionPre-Emergency
Mandatory LoadManagement
Reduction

Emergency
Mandatory LoadManagement
Voltage
Reduction
Reduction

ManualLoad
Dump
Warning

ManualLoad
Dump
ActionLoad
Shed
Directive

Mid-Atlantic and Southern
Mid-Atlantic
Mid-Atlantic
RTO except COMEDRTO except COMED
Mid-Atlantic and Southern

Power Balance Constraint Violation
On October 1, 2019, the power balance constraint was violated in 11 approved RT SCED solutions. On February 16, 2020, the power balance constraint was
violated in one approved RT SCED solution which was used to set prices for three five minute intervals. On March 22, 2021, the power balance constraint was
violated in one approved RT SCED solution. In the RT SCED optimization, the power balance constraint enforces the requirement that total dispatched generation(supply) equals the sum total of forecasted load, losses and net interchange (demand). The power balance constraint is violated when supply is less than demand.
In some cases, the power balance constraint is violated while the reserve requirements are satisfied.
The current process for meeting energy and reserve requirements in real time, and pricing the system conditions when RT SCED forecasts that energy supply isless than the demand for energy and reserves, is opaque and not defined in the PJM governing documents. It is unclear whether and how PJM would convert
reserves to energy before violating power balance. It is unclear whether and when PJM would use its authority under the tariff to curtail exports from PJM
capacity resources to meet the power balance constraint. It is unclear whether PJM would maintain a minimum level of synchronized reserves even if that would
result in a controlled load shed. The current RT SCED does not have a mechanism to convert inflexible reserves procured by ASO to energy to satisfy the power
balance constraint.92 SCED solutions from October 1, 2019, February 16, 2020, and April 21, 2020, indicate that the currently defined logic meets transmission
constraint limits and reserve requirements but violates the power balance constraint, and does not reflect this constraint violation in prices. This logic, if
correctly described, is not consistent with basic economics. The overall solution is complex and must be integrated with the approach to shortage pricing.
The MMU recommends that PJM clarify, modify and document its process for dispatching reserves and energy when SCED indicates that supply is less than
total demand including forecasted load and reserve requirements. The modifications should define: a SCED process to economically convert reserves to
92 Inflexible reserves are those reserves that clear in the hour ahead Ancillary Service Optimizer (ASO) but cannot be dispatched in the real time dispatch tool, RT SCED.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 189

2021 Quarterly State of the Market Report for PJM: January through Juneenergy; a process for the recall of energy from capacity resources; and theminimum level of synchronized reserves that would trigger load shedding.The
average energy component of LMP in that 5 minute interval (on March 22)
with artificially increased supply to satisfy the power balance constraint was$3,685.20 per MWh.
Table 3-69 shows the number of five minute intervals for which the RT SCED
solutions used to set prices did not balance demand and supply. PJM reran
the RT SCED with artificially increased supply to satisfy the power balance
constraint. In the first six months of 2021, there was one 5 minute interval
using an RT SCED solution with a violated power balance constraint. The
average energy component of LMP in that 5 minute interval (on March 22)
with artificially increased supply to satisfy the power balance constraint was$3,685.20 per MWh.93
Table 3-69 Number of five minute intervals using RT SCED solutions withviolated power balance constraint by year
Year
2013
2014
2015
2016
2017
2018
2019
2020
2021 (Jan - Jun)

Number of five minute intervals
655
71
42
31
16
36
5
1

Average Energy Component of LMP($/MWh)$0.00$36.29($0.76)$93.06$279.86$268.21$845.48$351.56$3,685.20

Balancing Ratio for Local Emergency Events
The balancing ratio is theoretically defined as the ratio of actual load andreserve requirements in an area during an emergency event to the totalcommitted capacity in the area. In the case of the PAIs declared in 2018 thatwere triggered due to transmission outages in limited locations, if the area isdefined as the location where the load was shed, the balancing ratio is undefined
because there were no committed resources in the area, other than less than93 The energy component of LMP, or the shadow price of the power balance constraint, is the incremental cost of meeting a one MWhincrease in the system load.

190

Section 3 Energy Market

1.0 MW of demand response.94 It is not appropriate or correct to calculate
a balancing ratio as a measure of capacity needed during these events bydefining a wider area to include committed capacity. It is also not appropriate
to use a balancing ratio defined in that way in defining the capacity market
offer cap. PJM calculated the balancing ratio for the localized load shed that
occurred in the AEP Edison area in 2018 and used the average balancing ratio
during the event to calculate the capacity market seller offer cap for all LDAs
for the 2022/2023 Delivery Year.95 These events occurred in a very small local
area where no capacity resources were held to CP performance requirements.
Assessing nonperformance to resources located in the wider area would not beappropriate because their performance would not have helped, and may haveeven exacerbated the transmission issues identified during these events. These
events also do not reflect the type of events that are modeled to define thetarget installed reserve margin in the capacity market. The MMU recommends,
if the capacity market seller offer cap were to be calculated using the historical
average balancing ratio, that PJM not include the balancing ratios calculated
for localized Performance Assessment Intervals (PAIs), and only include those
events that trigger emergencies at a defined zonal or higher level.

Performance Assessment Intervals
PJM currently triggers a PAI any time it declares a pre-emergency load
management reduction action, or a more severe emergency action.96 PJM’s
trigger for PAI is subjective, and it should be based on a quantifiable, transparent
metric of the need for capacity in the PJM system. For example, in ISO New
England, under the Pay for Performance design, resources are assessed for
performance during Capacity Scarcity Conditions (“CSCs”) that occur when thesystem or local area is short on ten and thirty minute nonspinning reserves.97
Reserve shortages are determined based on a predefined reserve requirement,
and the reserve calculation that is embedded in the real-time dispatch tool.

94 See 2018 State of the Market Report for PJM, Volume II, Section 3: Energy Market, at Scarcity, pp. 201 – 202.
95 See PJM, “Capacity Market Seller Offer Cap Values,” (March 15, 2019), which can be accessed at <https://www.pjm.com/-/media/marketsops/rpm/rpm-auction-info/2022-2023/2022-2023-cp-market-seller-offer-cap-values.ashx?la=en?>.
96 OATT Definitions at “Emergency Action”.
97 ISO New England Inc. Internal Market Monitor, “2018 Annual Markets Report,” (May 23, 2019) at 156 (§ 6.2.2 (Pay-for-Performance
Outcomes)).

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

The October 2, 2019, PAI provided actual data and evidence on the issues with
PJM’s triggers, and PJM’s treatment of excused MW. The PAI on October 2,
2019, was triggered when PJM declared a pre-emergency load management
reduction action in the AEP, BGE, Dominion and Pepco Zones based on
anticipated high load relative to the available supply. The actual load wassignificantly lower than forecasted.98
On October 1, 2019, the day before the PAI, PJM did experience high load
relative to the available supply. The system conditions were reflected in themarket outcomes with multiple intervals of high prices, and reserve shortages.99
The decision to declare a pre-emergency load management reduction action
on October 2, 2019, was based on an expectation of the repetition of theevents on October 1, 2019, which did not materialize. This illustrates theshortcomings of triggering PAIs based on PJM operator declared emergency
actions or pre-emergency load management reduction, instead of using aquantitative metric that is readily available to PJM, such as reserves.100 Given
this implementation, it can no longer be assumed that PAI would occur when
the PJM region, or a subset of zones in the PJM region are experiencing
capacity shortage conditions.

Shortage and Shortage Pricing
In electricity markets, shortage means that demand, including reserve
requirements, is nearing the limits of the currently available capacity of thesystem. Shortage pricing is a mechanism for signaling scarcity conditions
through high energy prices. Under the PJM rules that were in place throughSeptember 30, 2012, shortage pricing resulted from the exercise of aggregate
market power by individual generation owners for specific units when thesystem was close to its available capacity. But this was not an efficient way tomanage shortage pricing and made it difficult to distinguish between market
power and shortage pricing. Shortage pricing is an administrative pricing
98 In a report reviewing the PAI, PJM stated: “The most striking anomaly was load levels in the AEP and Mid-Atlantic zones that came insignificantly below forecast.” See PJM, “A Review of the October 2019 Performance Assessment Event,” (2019) at 1, which can be accessedat <https://www.pjm.com/-/media/markets-ops/rpm/review-of-october-2019-performance-assessment-event.ashx>.
99 See Monitoring Analytics, LLC, 2019 State of the Market Report for PJM, Volume 2: Section 3 Energy Market at 176 –180 (Analysis of
October 1 Events).
100 There are existing issues with the accuracy of reserve measurement in PJM, and they should also be resolved by improving generator
modeling in the energy market.

© 2021 Monitoring Analytics, LLC

mechanism in which PJM sets a high energy price at a predetermined level
when the system operates with less real-time reserves than required.
In the first six months of 2021, there were ten 5 minute intervals with shortage
pricing that occurred on seven days in PJM.
With Order No. 825, the Commission required each RTO/ISO to trigger shortage
pricing for any dispatch and pricing interval in which a shortage of energy
or operating reserves is indicated by the RTO/ISO’s software.101 Prior to May
11, 2017, if the dispatch tools (Intermediate-Term SCED and Real-Time SCED)
reflected a shortage of reserves (primary or synchronized) for a time period
shorter than a defined threshold (30 minutes), it was considered a transient
shortage, a shortage event was not declared, and shortage pricing was not
implemented. As of May 11, 2017, the rule requires PJM to trigger shortage
pricing for any five minute interval for which the Real-Time SCED (Security
Constrained Economic Dispatch) indicates a shortage of synchronized reserves
or primary reserves. PJM did not implement the rule as intended in OrderNo. 825, because RT SCED can indicate a shortage that PJM does not use
in pricing. In January 2019, PJM updated its business rules in Manual 11 todescribe PJM’s implementation of the five minute shortage pricing process.
PJM Manual 11 states that shortage pricing is triggered when an approved RT
SCED case that was used in the Locational Pricing Calculator (LPC) indicates ashortage of reserves. Beginning February 24, 2020, PJM changed the RT SCED
automatic execution frequency to once every four minutes, from the previous
three minutes. On June 22, 2020, PJM reduced the frequency of automatic
RT SCED executions to match the frequency of pricing at five minutes, which
reduced the frequency of unpriced shortage solutions.
Voltage reduction actions and manual load dump actions are also triggers for
shortage pricing, reflecting the fact that when operators need to take theseemergency actions to maintain reliability, the system is short reserves andprices should reflect that condition, even if the data do not show a shortageof reserves.102
101 Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System
Operators, Order No. 825, 155 FERC ¶ 61,276 at P 162 (2016).
102 See, e.g., Scarcity and Shortage Pricing, Offer Mitigation and Offer Caps Workshop, Docket No. AD14-14-000, Transcript 29:21–30:14(Oct. 28, 2014).

2021 Quarterly State of the Market Report for PJM: January through June 191

2021 Quarterly State of the Market Report for PJM: January through June

Since July 12, 2017, the PJM synchronized reserve requirement in a reservezone or a subzone is the actual output of the single largest online unit inthat reserve zone or subzone. The primary reserve requirement in a reservezone or a subzone is 150 percent of the actual output of the single largest
online unit in that reserve zone or subzone. The first step of the demand
curves for primary and synchronized reserves are set at the primary andsynchronized reserve requirement. Since the primary and synchronized reserve
requirements are based on the actual output of the largest resource, the MW
value of the first step changes in real time based on the real-time dispatch
solution. The first step is priced at $850 per MWh. The second step of the
primary and synchronized reserve demand curves extends the primary andsynchronized reserve requirements. The extended primary and synchronizedreserve requirements are defined as the primary and synchronized reserve
requirements, plus 190 MW. This 190 MW second step is priced at $300 per
MWh. Figure 3-47 shows an example of the updated synchronized reserve
demand curve when the output of the single largest unit in the region equals
1,000 MW.

Figure 3-47 Synchronized reserve demand curve showing the permanent
second step
1,000
950

Synchronized Reserve Demand Curve

900
850
800
Synchronized Reserve Price ($ per MWh)

Operating Reserve Demand Curves

750
700

650
600
550
500
450
400
350

300
250
200
150
100

Output of Single Largest Online Unit

50

0

0

200

400

600

190 MW
800

1,000

1,200

1,400

Synchronized Reserve Quantity (MW)Shortage Pricing and Energy Price Formation
The current operating reserve demand curves (ORDC) in PJM define anadministrative price for estimated reserves (primary and synchronizedreserves) up to the extended reserve requirement quantities. The demand
curve shown in Figure 3-47 drops to a zero price for quantities above theextended reserve requirement. The price for reserve quantities less than thereserve requirement is $850 per MWh, and the price for reserve quantities
above the reserve requirement to 190 MW above the reserve requirement is$300 per MWh.
The shortage prices set by the ORDC are added to LMP during shortages. Whenmultiple reserve products are short or when reserves are short in multiple
zones, the ORDC prices are additive. Currently, the highest possible shortage

192

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

penalty in LMP is $3,400 per MWh, which is the $850 per MWh price times
four, for two reserve products (synchronized reserve and nonsynchronizedreserve) times two reserve zones, RTO and MAD. However, PJM caps thesystem marginal energy price at $3,750, which is the sum of the highest
possible energy offer, the synchronized reserve penalty factor, the primaryreserve penalty factor, and a $50 per MWh threshold. The current market rules
cap the additive reserve shortage penalty factors for the MAD synchronizedreserve market clearing price to the sum of the synchronized reserve penalty
factor and the primary reserve penalty factor, which is $1,700 per MW.103 The$1,700 per MWh penalty applies any time PJM initiates a manual load dump
action or voltage reduction action.104
Table 3-70 shows six example scenarios, under the current ORDCs, withcombinations of energy offers, reserve shortage penalty factors andtransmission constraint penalty factors that can add up to produce high LMPs
at sample pnodes in the MAD Reserve Subzone and outside the MAD Reserve
Subzone.
In scenario B, there is a reserve shortage for both primary and synchronizedreserves in both MAD and RTO Reserve Zones that results in a $1,700 per
MWh reserve shortage penalty in the RTO zone LMP and a $3,400 per MWh
reserve shortage penalty in the MAD Zone LMP. The marginal resource forenergy is in the RTO Zone, and the RTO to MAD reserve transfer constraint
is not binding, so the higher MAD reserve penalty does not affect the restof RTO LMP. In scenario C, there is a reserve shortage for both primary andsynchronized reserves in both MAD and RTO Reserve Zones and a violatedtransmission constraint that affects the marginal congestion costs in thesystem marginal price.

capping is triggered whether the marginal unit for energy can provide reserves
for the MAD Zone or only the RTO Zone.
In scenario D, with a $1,000 per MWh offer price for the marginal unit forenergy, violation of all four reserve penalty factors only triggers SMP capping
if the marginal unit for energy can serve the MAD reserve requirement.
Scenario E and F show that LMPs can exceed $3,750 per MWh if there is aviolated transmission constraint that is not exacerbated by an increase in loadat the load weighted reference pricing node, which determines the SMP.105
In Scenario F, the energy component of LMP is at its highest level, $2,000
per MWh and there is a reserve shortage for both primary and synchronizedreserves in both MAD and RTO Reserve Zones that results in the $1,700 per
MWh scarcity adder, and a violated transmission constraint with $2,000 per
MWh penalty factor that results in a $5,700 per MWh LMP. The LMPs in
Scenario F are not the highest possible LMPs in the PJM energy market under
the current rules. If there are multiple violated transmission constraints, thecongestion costs contributing to the LMP at a pnode can exceed $2,000 per
MWh resulting in LMPs higher than $5,700 per MWh. The extent to which
each violated transmission penalty factor affects the LMP at a pnode is
directly proportional to the pnode’s distribution factor (dfax) with respect tothat constraint.

In scenario C, the sum of the reserve and transmission constraint penalty
factors equals $5,450 per MWh, which exceeds $3,750 per MWh, so SMP
103 See PJM Operating Agreement, Schedule 1, Section 3.2.3A(d)(ii). The cap on the additive reserve shortage penalty factors in MAD was
not reflected in the prior report and the maximum in MAD was therefore overstated. See: 2020 Quarterly State of the Market Report for
PJM: January through September, p. 192.
104 See PJM. “Manual 11: Energy & Ancillary Services Market Operations,” Rev. 115 (June 1, 2021), 2.8 The Calculation of Locational MarginalPrices (LMPs) During Emergency Procedures.

© 2021 Monitoring Analytics, LLC

105 T he impact of the transmission constraint penalty factor at a pnode depends on its distribution factor (dfax) with respect to theconstraint. The scenarios here assume a single violated transmission constraint with dfax of 1.0. If there are multiple violatedtransmission constraints, the total impact at a pnode is the sum of the product of transmission constraint penalty factors anddistribution factors.

2021 Quarterly State of the Market Report for PJM: January through June 193

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-70 Additive penalty factors under reserve shortage and transmission
constraint violations: Status Quo

to produce LMPs at sample
pnodes in the MAD Reserve
Synchronized Reserve
Primary Reserve
Subzone and outside thePenalty Factor
Penalty Factor
Total LMP
Transmission Constraint System Marginal Price Transmission Constraint
MAD Reserve Subzone.
Marginal Unit
MAD
RTO
MAD
RTO
Penalty Factor
Penalty Factor
In scenario B, there is a
Scenario
Offer Price
RTO
MAD
RTO
MAD
Marginal Marginal
Marginal Marginalin SMPin CLMP
A
$50
$850
$0
$0
$0
$0
$900
$900
$0
$900
$900
reserve shortage for both
B
$50
$850
$850
$850
$850
$0
$3,450$1,750$0$3,450$1,750
primary and synchronized
C
$50
$850
$850
$850
$850
$2,000$3,750$3,750$0$3,750$3,750D$1,000
$850
$850
$850
$850
$0
$3,750$2,700$0$3,750$2,700reserves in both the MAD
E$1,000
$850
$850
$850
$850
$2,000$3,750$3,750$2,000$5,750$5,750and RTO Reserve Zones
F$2,000
$850
$850
$850
$850
$2,000$3,750$3,750$2,000$5,750$5,750and a reserve shortage forsecondary reserve in the
Changes to the ORDC, approved by FERC and planned for implementation
RTO Zone that results in the $10,000 per MWh scarcity adder in MAD. The
in 2022, will increase the price for reserve quantities less than the reserve
full $10,000 per MWh scarcity adder would apply any time PJM initiates arequirement to $2,000 per MWh.106 For each reserve quantity greater than the
manual load dump action or voltage reduction action. In scenario C, there isreserve requirement, PJM will multiply an assumed probability of a reservea reserve shortage for both primary and synchronized reserves in both theshortage, based on historic forecast error, by $2,000 per MWh, creating an
MAD and RTO Reserve Zones, a reserve shortage for secondary reserve in theextended downward sloping ORDC. The extended ORDC is an administratively
RTO Zone, that results in the $10,000 per MWh scarcity adder, and a violated
determined reserve price that will be added to LMP, as a scarcity pricing
transmission constraint with a $2,000 per MWh penalty factor that results inadder, even when no shortage exists. The $2,000 per MWh price is unjustified
a $12,050 per MWh LMP at a pnode in MAD.107
because the highest possible energy offer under most circumstances is only
$1,000 per MWh. Only in the unusual circumstance when short run marginal
In Scenario E, the Energy Component of LMP is at its highest level, $2,000
costs exceed $1,000 per MWh is a higher ORDC price justified. When energy
per MWh and there is a reserve shortage for both primary and synchronizedoffers exceed $1,000 per MWh, they have to be verified and preapproved byreserves in both MAD and RTO Reserve Zones and a secondary reserve
PJM and cannot exceed $2,000 per MWh, to be eligible to set LMP in the PJM
shortage, resulting in the $10,000 per MWh scarcity adder, and a violated
energy market.
transmission constraint with a $2,000 per MWh penalty factor that results in
The highest possible scarcity adder increases under the planned changes to the
ORDC. The highest possible scarcity adder will be $10,000 per MWh, which is
the $2,000 per MWh price times five. The five products are the synchronized
and nonsynchronized reserve products for RTO and MAD Zones plus a new
secondary 30 minute reserve product for the RTO Zone.
Table 3-71 shows example scenarios, under the ORDCs planned for
implementation in 2022, with combinations of energy offers, reserve shortage
penalty factors and transmission constraint penalty factors that can add up
106 See 171 FERC ¶ 61,153 (2020), order on reh’g, 173 FERC ¶ 61,123 (2020).

194

Section 3 Energy Market

a $14,000 per MWh LMP at a pnode in MAD. The LMPs in Scenario E are not
the highest possible LMPs in the PJM energy market under the ORDCs planned
for implementation in 2022. If there are multiple violated transmission
constraints, the transmission constraint penalty factors’ contribution to the
LMP at a pnode can exceed $2,000 per MWh resulting in LMPs higher than
$14,000 per MWh. The extent to which each violated transmission penalty
factor affects the LMP at a pnode is directly proportional to the pnode’s
distribution factor (dfax) with respect to that constraint.
107 The impact of the transmission constraint penalty factor at a pnode depends on its distribution factor (dfax) with respect to theconstraint. The scenarios here assume a single violated transmission constraint with dfax of 1.0. If there are multiple violatedtransmission constraints, the total impact at a pnode is sum of the product of transmission constraint penalty factors and distribution
factors.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-71 Additive penalty factors under shortage conditions andtransmission constraint violations
ScenarioA
B
C
D
E

EnergyComponent of
LMP
$50
$50
$50
$1,000$2,000Synchronized Reserve
Penalty Factor
RTO
MAD$2,000$200$2,000$2,000$2,000$2,000$2,000$2,000$2,000$2,000Primary Reserve
Penalty Factor
RTO
MAD
$200
$200
$2,000$2,000$2,000$2,000$2,000$2,000$2,000$2,000

Secondary Reserve Penalty
FactorRTO$0$2,000$2,000$2,000$2,000minute look ahead windows of the past
three years.
In the real-time energy market, PJM
executes an RT SCED case for every
five minute target time approximately
14 minutes prior to the target time. The
forecasts for the target time used in RT
SCED, including load, solar generation
and wind generation are generated just before the RT SCED case is executed,
approximately fifteen minutes prior to the target time. Beginning November
1, 2021, PJM plans to implement changes that would result in executing
RT SCED approximately ten minutes prior to the target time. Under this
implementation, the look ahead period of the forecasts and generation data
used in RT SCED will be reduced to ten minutes. Generally, the longer the lookahead period for a target time, the greater the forecast errors. Using thirty
minute forecast errors to determine the quantity of reserves to procure in the
ORDCs will inflate the actual uncertainty in the inputs to RT SCED. This willfurther inflate the already overstated ORDC price levels for quantities beyond
the MRR and LMPs. Use of 30 minute forecast errors is not consistent with
PJM’s logic. The MMU recommends, if PJM implements extended downward
sloping ORDCs, that PJM calculate the probability of reserves falling below
the minimum reserve requirement (MRR) based on ten minute rather than 30
minute forecast error, and on forced outages in the ten minute rather than the
30 minute look ahead window to model the uncertainty in the inputs to RT
SCED.

Transmission Constraint
Penalty Factor$0$0$2,000$2,000$2,000Operator Actions
Actions taken by PJM operators to maintain reliability, such as committing
more reserves than required, may suppress reserve prices. The need to commit
more reserves could instead be directly reflected in the ORDC when operational
issues arise, allowing the market to efficiently account for the reliability
commitment in the energy and reserves markets. Instead, the new ORDC will
be inflated at all times based on average historical forecast error that may or
may not have resulted in operator actions to commit additional reserves.
PJM plans to implement the new extended downward sloping ORDCs
beginning May 1, 2022. PJM calculated ORDCs for each reserve product fora 4 hour time block in an operating day, for each of the four seasons. This
results in 24 different ORDCs for each product in a delivery year.108 These
ORDCs were calculated using the reserve penalty factor ($2,000 per MWh)and the probability of reserves being below the minimum reserve requirement(PBMRR) at each quantity above the minimum reserve requirement (MRR). For
synchronized reserves and primary reserves, the PBMRR is calculated using
the 30 minute look ahead uncertainties associated with the load forecast error,
the solar generation forecast error, the wind generation forecast error, and thegeneration forced outages that occurred in 30 minute look ahead windows of
the past three years. For the new secondary reserve product, the PBMRR is
calculated using the 60 minute look ahead uncertainties associated with theload forecast error, the solar generation forecast error, the wind generation
forecast error, and the generation forced outages that occurred in the 60

Total LMP inMAD$2,650$10,050$12,050$13,000$14,000

Total LMP
outside MAD$2,250$6,050$8,050$9,000$10,000

Locational Reserve Requirements
In addition to the construction of the operating reserve demand curves toreflect the value of maintaining reserves and avoiding a loss of load event, themodeling of reserve requirements should reflect locational needs and shouldprice operator actions to, for example, commit more reserves when specificneeds arise.

108 PJM published the ORDCs for all the reserve products to be used beginning May 1, 2022, which can be accessed at: <https://www.pjm.
com/markets-and-operations/ancillary-services>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 195

2021 Quarterly State of the Market Report for PJM: January through June

The current operating reserve demand curves are modeled for reserve
requirements for the RTO level (RTO Reserve Zone) and for the Mid-Atlantic
and Dominion region (MAD Subzone). This was a result of historical congestion
patterns where limits to transmission capacity to deliver power from outside
the MAD Subzone into the MAD Subzone necessitated maintaining reserves in
the MAD area to respond to disturbances within the subzone. On most days,
the MAD Subzone is no longer relevant. PJM may need to maintain or operateresources in other local areas to maintain local reliability. Currently, theseunits are committed out of market for reliability reasons, or the reserve needis modeled as an artificial closed loop interface with limited deliverability
modeled inside the closed loop from resources located outside. The value of
operating these resources, including generators that are manually committed
for reliability and demand resources that may be dispatched inside a closed
loop, is not correctly reflected in prices. A more efficient way to reflect theserequirements would be to have locational reserve requirements that are
adjusted based on PJM forecasts and reliability studies.

Reserve Shortages in 2021
Reserve Shortage in Real-Time SCEDThe MMU analyzed the RT SCED solutions to determine how many of thefive minute target time RT SCED solutions indicated a shortage of any of thereserve products (synchronized reserve and primary reserve at RTO Reserve
Zone and MAD Reserve Subzone), when multiple solutions indicated shortageof reserves, and how many of these resulted in shortage prices in LPC. For
reliability reasons, and to maintain reserves to comply with NERC standards,
reserves are considered short if the quantity (MW) of reserves dispatchedby RT SCED for a five minute interval is less than the minimum reserve
requirement (MRR). To trigger shortage pricing, reserves are considered short
if the quantity (MW) of reserves dispatched by RT SCED for a five minuteinterval is less than the extended reserve requirement.

Until June 2, 2021, PJM generally solved one RT SCED case with threesolutions per case, for each five minute target time.109 110 On June 3, 2021, PJM
updated RT SCED to solve two additional scenarios, or a total of five solutions
per case. In the first six months of 2021, the frequency with which RT SCED
solutions were approved increased to one solution per five minute interval.
This approval frequency increased the proportion of approved SCED solutions
that are reflected in LMPs. However, the process of selecting the SCED solution
to approve, among the solutions available to PJM operators, is subjective andis not based on clearly defined criteria. The criteria are especially importantwhen only some of the SCED solutions reflects shortage pricing, and the restof the solutions do not.
The MMU analyzed the target times for which one or more RT SCED casesolutions indicated a shortage of one or more reserve products. Table 3-72
shows, for each month of 2020 and the first six months of 2021, the total
number of target times, the number of target times for which at least one RT
SCED solution showed a shortage of reserves, the number of target times forwhich more than one RT SCED solution showed a shortage of reserves, and thenumber of five minute pricing intervals for which the LPC solution showed ashortage of reserves. Table 3-72 shows that, in the first six months of 2021,
1,301 target times, or 2.5 percent of all five minute target times, had at least
one RT SCED solution showing a shortage of reserves, and 333 target times,
or 0.6 percent of all five minute target times, had more than one RT SCED
solution showing a shortage of reserves. In the first six months of 2020, there
were 874 target times, or 1.7 percent of all five minute target times, that had
at least one RT SCED solution showing a shortage of reserves, and 364 target
times, or 0.7 percent of all five minute target times, that had more than one
RT SCED solution showing a shortage of reserves.

109 A case is executed when it begins to solve. Most but not all cases are solved. RT SCED cases take about one to two minutes to solve.
110 PJM updated the RT SCED execution frequency to solve one case for each five minute target time beginning June 22, 2020. PJM
dispatchers may solve additional cases at their discretion.

196

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-72 Five minute SCED target times and pricing intervals with shortage: January 2020 through June 2021

Year, Month2020 Jan
2020 Feb
2020 Mar
2020 Apr
2020 May
2020 Jun
2020 Jul
2020 Aug
2020 Sep
2020 Oct
2020 Nov
2020 Dec
2020 Total
2021 Jan
2021 Feb
2021 Mar
2021 Apr
2021 May
2021 Jun
2021 Total

Number of Five
Minute Intervals
8,928
8,352
8,916
8,640
8,928
8,640
8,928
8,928
8,640
8,928
8,652
8,928
105,408
8,928
8,064
8,916
8,640
8,928
8,640
52,116

Number of Target
Percent Target Times
Times With At Least
With At Least One
One SCED Solution SCED Solution Short ofShort of Reserves
Reserves
172
1.9%
94
1.1%
173
1.9%
208
2.4%
113
1.3%
114
1.3%
110
1.2%
95
1.1%
64
0.7%
327
3.7%
181
2.1%
168
1.9%
1,819
1.7%
114
1.3%
108
1.3%
198
2.2%
130
1.5%
235
2.6%
516
6.0%
1,301
2.5%

Number of Target
Times With Multiple
SCED Solutions Shortof Reserves
89
44
66
99
36
30
17
14
21
91
44
41
592
22
28
46
24
48
165
333

Percent Target Times
With Multiple SCED
Solutions Short ofReserves
1.0%
0.5%
0.7%
1.1%
0.4%
0.3%
0.2%
0.2%
0.2%
1.0%
0.5%
0.5%
0.6%
0.2%
0.3%
0.5%
0.3%
0.5%
1.9%
0.6%

Percent RT SCED
Number of Five
Target Times With
Minute Intervals With Reserve Shortage With
Shortage Prices in LPC Shortage Prices in LPC
0
0.0%
0
0.0%
0
0.0%
2
1.0%
0
0.0%
0
0.0%
0
0.0%
0
0.0%
0
0.0%
3
0.9%
3
1.7%
1
0.6%
9
0.5%
0
0.0%
0
0.0%
4
2.0%
0
0.0%
5
2.1%
1
0.2%
10
0.8%

In the first six months of 2021, there were ten 5 minute intervals with shortage pricing, while there were 333 five minute target times for which multiple RT
SCED solutions showed a shortage of reserves. In the first six months of 2020, there were two 5 minute intervals with shortage pricing, while 364 five minutetarget times for which multiple RT SCED solutions showed a shortage of reserves. Clear criteria for approval of shortage cases are needed.
The PJM Real-Time Energy Market produces an efficient outcome only when prices are allowed to reflect the fundamental supply and demand conditions in
the market in real time. While it is appropriate for operators to ensure that cases use data that reflect the actual state of the system, it is essential that operator
discretion not extend beyond what is necessary and that operator discretion not prevent shortage pricing when there are shortage conditions or implement
shortage pricing when there are no shortage conditions. This is a critical issue now that PJM settles all real-time energy transactions on a five minute basis
using the prices calculated by LPC. The MMU recommends that PJM define clear criteria for operator approval of RT SCED cases, including shortage cases, thatare used to send dispatch signals to resources, and for pricing, to minimize discretion. A rule based approach is essential for defining how LMPs are determinedso that all market participants can be confident that energy market pricing is efficient.

Shortage Pricing Intervals in LPC
There were ten 5 minute intervals with shortage pricing in the first six months of 2021, compared to two intervals in the first six months of 2020, in PJM.
Table 3-73 shows the extended synchronized reserve requirement, the total synchronized reserves, the synchronized reserve shortage, and the synchronized© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 197

2021 Quarterly State of the Market Report for PJM: January through June

reserve clearing prices for the RTO Reserve Zone during the ten intervals
with shortage pricing due to synchronized reserve shortage. Table 3-74
shows the extended synchronized reserve requirement, the total synchronizedreserves, the synchronized reserve shortage, and the synchronized reserve
clearing prices for the MAD Reserve Subzone during the ten intervals withshortage pricing due to synchronized reserve shortage. Table 3-75 shows theextended primary reserve requirement, the total primary reserves, the primaryreserve shortage, and the primary reserve clearing prices for the RTO Reserve
Zone during the four intervals with shortage pricing due to primary reserve
shortage. Table 3-76 shows the extended primary reserve requirement, thetotal primary reserves, the primary reserve shortage, and the primary reserve
clearing prices for the MAD Reserve Subzone during the three intervals withshortage pricing due to primary reserve shortage.
PJM enforces an RTO wide reserve requirement and a supplemental reserve
requirement for the MAD region. The MAD Reserve Subzone is nested within
the RTO Reserve Zone. Resources located in the MAD Reserve Subzone cansimultaneously satisfy the synchronized reserve requirement of the RTO
Reserve Zone and the synchronized reserve requirement of the MAD Reserve
Subzone. Resources located outside the MAD Reserve Subzone can satisfy
the synchronized reserve requirement of the RTO Reserve Zone, and subject
to transfer limits defined by transmission constraints, satisfy the reserve
requirement of the MAD Subzone. The synchronized reserve clearing priceof the RTO Reserve Zone is set by the shadow price of the binding reserve
requirement constraint of the RTO Reserve Zone.111 The synchronized reserve
clearing price of the MAD Reserve Subzone, nested within the RTO Reserve
Zone, is set by the sum of the shadow prices of the binding reserve requirement
constraint of the RTO Reserve Zone and the shadow price of the binding
reserve requirement constraint of the MAD Reserve Subzone.

requirement, resulting in an $850 per MWh penalty factor. In six out of theten intervals, the synchronized reserves in the RTO Zone were greater than theminimum reserve requirement but short of the extended reserve requirement(minimum reserve requirement plus 190 MW), resulting in a $300 per MWhpenalty factor. The clearing price for synchronized reserves in the RTO Zone
is the sum of the shadow prices of the synchronized reserve constraint for the
RTO Zone and the primary reserve constraint for the RTO Zone. The clearing
price for synchronized reserves in the MAD Subzone is the sum of the shadow
prices of the synchronized reserve constraints for the RTO Zone and MAD
Subzone and the shadow prices of the primary reserve constraints in the RTO
and MAD Subzone.
Table 3-73 RTO synchronized reserve shortage intervals: January throughJune, 2021
Interval (EPT)
02-Mar-21 06:30
17-Mar-21 10:10
22-Mar-21 19:45
22-Mar-21 19:50
07-May-21 06:30
19-May-21 17:10
19-May-21 17:15
26-May-21 10:25
26-May-21 10:30
02-Jun-21 17:00

RTO Extended
Synchronized Reserve
Requirement (MW)
1,835.0
1,859.0
1,786.0
1,783.0
1,812.0
1,832.0
1,829.0
1,817.0
1,817.0
1,826.0

Total RTO
Synchronized
Reserves (MW)
1,305.6
1,452.1
1,256.5
1,422.9
1,786.5
1,812.8
1,672.4
1,682.5
1,682.5
1,691.3

RTO Synchronized
Reserve Shortage
(MW)
529.4
406.9
529.5
360.1
25.5
19.2
156.6
134.5
134.5
134.7

RTO Synchronized
Reserve Clearing
Price ($/MWh)$1,700.0$1,150.0$1,700.0$1,150.0$300.0$368.1$398.4$300.0$300.0$300.0In all ten intervals in the first six months of 2021 with shortage pricing,both the RTO Zone and the MAD Subzone cleared with synchronized reserves
less than their extended requirement. In four out of the ten intervals, thesynchronized reserves in the RTO Zone were short of the minimum reserve
111 If the reserve requirement cannot be met by the resources located within the reserve zone, the shadow price of the reserve requirement
is set by the applicable operating reserve demand curve.

198

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-74 MAD synchronized reserve shortage intervals: January throughJune, 2021
Interval (EPT)
02-Mar-21 06:30
17-Mar-21 10:10
22-Mar-21 19:45
22-Mar-21 19:50
07-May-21 06:30
19-May-21 17:10
19-May-21 17:15
26-May-21 10:25
26-May-21 10:30
02-Jun-21 17:00

MAD Extended
Synchronized Reserve
Requirement (MW)
1,835.0
1,859.0
1,786.0
1,783.0
1,812.0
1,832.0
1,829.0
1,817.0
1,817.0
1,826.0

Total MAD
Synchronized
Reserves (MW)
1,557.5
1,452.1
1,256.5
1,422.9
1,786.5
1,812.8
1,672.4
1,682.5
1,682.5
1,691.3

MAD Synchronized
Reserve Shortage
(MW)
277.5
406.9
529.5
360.1
25.5
19.2
156.6
134.5
134.5
134.7

MAD Synchronized
Reserve Clearing
Price ($/MWh)$1,700.0$1,700.0$1,700.0$1,700.0$600.0$668.1$698.4$600.0$600.0$600.0

Table 3-75 RTO primary reserve shortage intervals: January through June,
2021
Interval (EPT)
02-Mar-21 06:30
17-Mar-21 10:10
22-Mar-21 19:45
22-Mar-21 19:50

RTO Extended
Primary Reserve
Requirement (MW)2,657.5
2,693.5
2,584.0
2,579.5

Total RTO Primary
Reserves (MW)
2,405.6
2,536.1
2,357.7
2,406.9

RTO Primary
Reserve Shortage
(MW)
251.9
157.4
226.3
172.6

RTO Primary
Reserve Clearing
Price ($/MWh)$850.0$300.0$850.0$300.0

Table 3-76 MAD primary reserve shortage intervals: January through June,
2021
Interval (EPT)
17-Mar-21 10:10
22-Mar-21 19:45
22-Mar-21 19:50

MAD Extended
Primary Reserve
Requirement (MW)2,693.5
2,584.0
2,579.5

Total MAD Primary
Reserves (MW)2,536.1
2,357.7
2,406.9

MAD Primary
Reserve Shortage
(MW)
157.4
226.3
172.6

MAD Primary
Reserve Clearing
Price ($/MWh)$300.0$850.0$600.0On March 17, 2021, for the interval beginning 1010 EPT, both the RTO andMAD primary reserves were short of the extended requirements by 157.4 MW.
The penalty factor for each reserve constraint violation was $300 per MWh.
On March 22, 2021, for the interval beginning 1945 EPT, both the RTO andMAD primary reserves were short of the extended requirements by 226.3 MW.

The penalty factor for each reserve constraint violation was $850 per MWh.
Generally, the market clearing price (MCP) for primary reserves in the MAD
Subzone will equal the sum of the penalty factor for the reserve requirement
constraint of the RTO Reserve Zone and the penalty factor for the reserve
requirement constraint of the MAD Reserve Subzone. Using this logic, theMCPs for primary reserves in the MAD Subzone should have been $600 per
MWh on March 17, 2021, at 1010 EPT, and $1,700 per MWh on March 22, 2021,
at 1945 EPT. However, the MCPs for primary reserves for the MAD subzone
were $300 per MWh and $850 per MWh. This occurred because the MAD
primary reserve requirement constraint was relaxed for both these intervals,
resulting in the shadow price for the MAD primary reserve constraint equal to$0 per MWh. This is a result of the application of PJM’s System Marginal Price(SMP) capping logic. The PJM tariff caps the MCP for primary reserve at one
times the nonsynchronized reserve penalty factor for each zone or subzone,
and caps the MCP for synchronized reserve at the sum of the penalty factor
for synchronized reserve and penalty factor for nonsynchronized reserve, but
the PJM tariff does not specify a cap on the system marginal price, or LMPs.112

System Marginal Price Cap
In the PJM real time market, the SMP is capped at $3,750 per MWh. This cap isthe result of the Energy Offer Cap ($2,000 per MWh), the Synchronous Reserve
Penalty Factor from the first step on the demand curve ($850 per MWh), thePrimary Reserve Penalty Factor from the first step on the demand curve ($850
per MWh) and a threshold ($50 per MWh). The Operating Agreement statesthat only two, of the four, reserve penalty factors may be applied.
If the SMP would otherwise exceed $3,750 per MWh, PJM solves the SCED
optimization by progressively relaxing reserve requirement constraints until
the SMP falls below the cap. For instance, if the original SMP is above $3,750,
PJM would solve the SCED optimization by disabling the subzone (MAD)primary reserve requirement constraint. If the SMP from the relaxed SCED
optimization is still above $3,750, PJM would solve the SCED optimization
by disabling subzone (MAD) primary and synchronized reserve requirement
constraints. If the relaxed SCED optimization is still above $3,750, PJM
112 OA Schedule 1, Section 3.2.3A(d) and Section 3.2.3A.001(c).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 199

2021 Quarterly State of the Market Report for PJM: January through June

would solve the SCED optimization by disabling subzone (MAD) primary andsynchronized reserve requirement constraints and the RTO primary reserve
constraint.

cost was $2,086.15 per MWh. The remaining $3.00 is rounding error.113 The
SMP, without the use of the capping logic, would have been at least $3,965.08
per MWh.114

Since 2018, the SMP has been capped in 95 SCED solutions, of which four
SCED solutions were approved and used in the LPC to set the five minuteLMPs in the PJM real-time market.

The contribution of the transmission penalty factor of a violated transmission
constraint to the SMP depends on the location of the marginal units relative
to the location of the load weighted reference bus. If the marginal unit islocated such that an incremental increase in the load at the load weighted
reference bus results in increased flow on the violated transmission constraint,
the SMP reflects the positive contribution of the transmission penalty factor.
The marginal congestion component, $1,546.98, for the five minute interval
beginning at 10:10 on March 17, 2021, includes the contribution of transmission
constraint penalty factors of two violated transmission constraints.

Table 3-77 shows the shadow price, MCP and SMP for all reserve constraints
for SCED cases that were solved using PJM’s SMP capping logic andset the prices in the PJM real-time market. The shadow price of a reserve
requirement constraint is the marginal cost of satisfying an increase in thereserve requirement. The shadow price equals the penalty factor of the reserve
requirement constraint if the total cleared reserves are below the requirement.
Table 3-78 shows the components of SMP for the five minute intervals thatused SMP capping logic since 2018. The SMP is the marginal cost of satisfying
an increase in load at the load weighted reference bus. That marginal cost
includes the marginal cost of generation, the marginal cost of congestion
and the marginal cost of reserves. By definition, all of these marginal costs
are included in the marginal energy component of LMP at the load weighted
reference bus, which is referred to as the system marginal price (SMP). The
marginal cost of generation is the incremental offer price of the marginal
generation resource adjusted for the marginal cost of losses. The marginal costof congestion reflects the marginal cost of the unit required to meet the load
if there are transmission constraints, including transmission penalty factors
when relevant. If the marginal unit is also providing reserves, the marginal costof reserves reflects the marginal cost incurred to meet the reserve requirement.
The SMP for the five minute interval beginning at 10:10 on March 17, 2021
was $3,653.98 per MWh. The MAD primary reserve constraint was disabled
for this interval. Of the $3,653.98 per MWh, the marginal unit’s incremental
energy cost after accounting for the marginal cost of losses was $17.85 per
MWh, the congestion cost was $1,546.98 per MWh and the reserve opportunity

200

Section 3 Energy Market

Table 3-77 Five minute intervals based on approved SCED cases that used
SMP capping logic: January 2018 through June 2021
Five Minute Interval
01OCT2019:15:00:00
01OCT2019:15:00:00
01OCT2019:15:00:00
01OCT2019:15:00:00
13NOV2020:18:00:00
13NOV2020:18:00:00
13NOV2020:18:00:00
13NOV2020:18:00:00
02MAR2021:06:30:00
02MAR2021:06:30:00
02MAR2021:06:30:00
02MAR2021:06:30:00
17MAR2021:10:10:00
17MAR2021:10:10:00
17MAR2021:10:10:00
17MAR2021:10:10:00

Reserve Constraint
MAD Primary Reserve
MAD Synchronized Reserve
RTO Synchronized Reserve
RTO Primary Reserve
MAD Primary Reserve
MAD Synchronized Reserve
RTO Primary Reserve
RTO Synchronized Reserve
MAD Synchronized Reserve
MAD Primary Reserve
RTO Primary Reserve
RTO Synchronized Reserve
MAD Synchronized Reserve
RTO Primary Reserve
RTO Synchronized Reserve
MAD Primary Reserve

Disabled
No
Yes
No
No
Yes
No
No
No
Yes
No
No
No
No
No
No
Yes

Shadowprice($/MWh)$0.00$0.00$850.00$300.00$0.00$850.00$850.00$850.00$0.00$149.36$850.00$1,782.86$850.00$300.00$850.00$0.00

MCP($/MWh)$300.00$1,150.00$1,150.00$300.00$850.00$2,550.00$850.00$1,700.00$2,782.22$999.36$850.00$2,632.86$2,000.00$300.00$1,150.00$300.00

SMP($/MWh)$3,651.02$3,651.02$3,651.02$3,651.02$3,166.28$3,166.28$3,166.28$3,166.28$2,994.68$2,994.68$2,994.68$2,994.68$3,653.98$3,653.98$3,653.98$3,653.98

113 The final SMP does not precisely match the sum of components due to rounded network parameters such as distribution factors and loss
penalty factors used for deriving the components of the SMP. This difference is shown as rounding error.
114 The original SMP shown in the table represents the lower bound of the uncapped SMP. PJM does not report the segment of the disabledreserve constraint. To derive the original SMP, the lowest priced segment that results in the SMP exceeding the cap was used.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-78 Components of SMP for five minute intervals based on approved
SCED cases that used SMP capping logic: January 2018 through June 2021
Lower bound of
Five Minute Interval
Original SMP
October 01,2019 15:00:00$3,950.36
November 13,2020 18:00:00$4,049.76
March 02,2021 06:30:00$3,891.21
March 17,2021 10:10:00$3,965.08

Final
SMP
$3,651.02$3,166.28$2,994.68$3,653.98

Components of Final SMP
Marginal Cost Marginal Cost Marginal Costof Generation of Congestionof Reserves$33.88$2,436.47$1,173.81$520.20$0.00$2,645.22$30.51$181.10$2,780.81$17.85$1,546.98$2,086.15

The MMU recommends that PJM cease the practice of capping the system
marginal price in the RT SCED and instead limit the sum of violated reserve
constraint shadow prices used in LPC to $1,700 per MWh.

Accuracy of Reserve Measurement
The definition of a shortage of synchronized and primary reserves is based on
the measured and estimated levels of load, generation, interchange, demand
response, and reserves from the real-time SCED software. The definition ofsuch shortage also includes discretionary operator inputs to the ASO (Ancillary
Service Optimizer) or RT SCED software, such as tier 1 bias or operator loadbias. For shortage pricing to be accurate, there must be accurate measurementof real-time reserves. That does not appear to be the case at present in PJM,
but there does not appear to be any reason that PJM cannot accurately
measure reserves. Without accurate measurement of reserves on a minuteby minute basis, system operators cannot know with certainty that there isa shortage condition and a reliable trigger for five minute shortage pricing
does not exist. The benefits of five minute shortage pricing are based on
the assumption that a shortage can be precisely and transparently defined.115
PJM cannot accurately measure or price reserves due to the inaccuracy of its
generator models. PJM’s commitment and dispatch models rely on generator
data to properly commit and dispatch generators. Generator data includes
offers and parameters. When the models do not properly account for thedifferent generator characteristics, both PJM dispatchers and generators haveto make simplifications and assumptions using the tools available. Most of theseactions taken by generators and by PJM dispatchers are not transparent. PJM
115 See Comments of the Independent Market Monitor for PJM, Docket No. RM15-24-000 (December 1, 2015) at 9.

© 2021 Monitoring Analytics, LLC

Rounding
Error
$6.87
$0.86
$2.26
$3.00

manuals do not provide clarity regarding what actions generators cantake when the PJM models and tools do not reflect their operational
characteristics and PJM manuals do not provide sufficient clarity
regarding the actions PJM dispatchers can take when generators do
not follow dispatch.

In the energy and reserve markets, the actions that both generators
and PJM dispatchers take have a direct impact on the amount of
supply available for energy and reserves and the prices for energy
and reserves. These flaws in PJM’s models do not allow PJM to accurately
calculate the amount of reserves available. PJM does not accurately model
discontinuities in generator ramp rates, such as duct burners on combined
cycle plants. PJM’s generator models do not account for the complexities that
may result in generators underperforming their submitted ramp rates. Insteadof addressing these complexities through generator modeling improvements,
PJM relies on a nontransparent method of adjusting generator parameters,
called Degree of Generator Performance (DGP).116 117 PJM also fails to accurately
model unit starts. The market software does not account for the energy output
a resource produces prior to reaching its economic minimum output level,
during its soak time.
PJM adjusts ramp rates using DGP, deselects specific units from providing
reserves, and overrides the dispatch signal to certain units to set the dispatch
signal equal to actual resource output. These manual interventions are, atbest, rough approximations of the capability of generators and result in an
inaccurate measurement of reserves.

116 See “PJM Manual 12: Balancing Operations,” Rev. 42 (Jan. 27, 2021) Attachment A, P78. “PJM Manual 11: Energy and Ancillary Services
Market Operations,” does not mention the use of DGP in the market clearing engine.
117 PJM published a whitepaper that defines DGP and describes its use, which can be accessed at <http://www.pjm.com/~/media/etools/
oasis/system-information/generation-performance-monitor-and-degree-of-generator-performance-white-paper.ashx> (July 2, 2020).

2021 Quarterly State of the Market Report for PJM: January through June 201

2021 Quarterly State of the Market Report for PJM: January through June

Competitive Assessment
Market StructureMarket Concentration
The Herfindahl-Hirschman Index (HHI) concentration ratio is the sum of thesquares of the market shares of all firms in a market. Hourly PJM energy
market HHIs are based on the real-time energy output of generators adjustedwith scheduled imports. Hourly HHIs for the baseload, intermediate andpeaking segments of generation supply are based on hourly energy market
shares, unadjusted for imports.
The HHI may not accurately capture market power issues in situations where,
for example, there is moderate concentration in all on line resources but there
is a high level of concentration in resources needed to meet increases in load.
An aggregate pivotal supplier test is required to accurately measure the abilityof incremental resources to exercise market power.
FERC’s Merger Policy Statement defines levels of concentration by HHI level.
The market is unconcentrated if the market HHI is below 1000, the HHI if
there were 10 firms with equal market shares. The market is moderately
concentrated if the market HHI is between 1000 and 1800. The market ishighly concentrated if the market HHI is greater than 1800, the HHI if there
were between five and six firms with equal market shares.118

cheaper of the cost and price schedules and the lack of rules requiring that
cost-based offers equal short run marginal costs.

PJM HHI Results
Hourly HHIs indicate that by FERC standards, the PJM energy market
during the first six months of 2021 was unconcentrated on average (Table
3-79).119 The fact that the average HHI is in the unconcentrated range and the
maximum hourly HHI is in the moderately concentrated range does not meanthat the aggregate market was competitive in all hours. It is possible to havepivotal suppliers in the aggregate market even when the HHI level does notindicate a highly concentrated market structure. Given the low responsivenessof consumers to prices (inelastic demand), it is possible to have high markup
even when HHI is low. It is possible to have an exercise of market power evenwhen the HHI level does not indicate a highly concentrated market structure.
Table 3-79 Hourly energy market HHI: January through June, 2020 and 2021
By offering supplier
Average
Minimum
Maximum
Highest market share (One hour)
Average of the highest hourly market share# Hours# Hours HHI > 1800
% Hours HHI > 1800

Hourly Market HHI(Jan - Jun, 2020)
788
567
1126
28%
20%

Hourly Market HHI(Jan - Jun, 2021)
751
574
1118
27%
19%

4,367
0
0%

4,343
0
0%

When transmission constraints exist, local markets are created with ownershipthat is typically significantly more concentrated than the overall energy
market. PJM offer capping rules that limit the exercise of local market power
were generally effective in preventing the exercise of market power in the firstsix months of 2021, although there are issues with the application of market
power mitigation for resources whose owners fail the TPS test that permit
local market power to be exercised even when mitigation rules are applied.
These issues include the lack of a method for consistently determining theTable 3-80 includes HHI values by supply curve segment, including base,intermediate and peaking plants for the first six months of 2020 and 2021.
On average, ownership in the baseload segment was unconcentrated, in
the intermediate segment was moderately concentrated, and in the peaking
segment was highly concentrated.120 High concentration levels, particularly inthe peaking segment, increase the probability that a generation owner will bepivotal in the aggregate market.

118 See Inquiry Concerning the Commission’s Merger Policy under the Federal Power Act: Policy Statement, 77 FERC ¶ 61,263 mimeo at 80(1996).

119 The HHI calculations use actual real time settled generation data for each unit in PJM. Each unit’s output is assigned to the supplier thatis responsible for offering the unit in the energy market.
120 A unit is classified as base load if it runs for more than 50 percent of hours, as intermediate if it runs for less than 50 percent but greaterthan 10 percent of hours, and as peak if it runs for less than 10 percent of hours.

202

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-80 Generation segment HHI: January through June, 2020 and 2021
2020 (Jan - Jun)
Minimum
Average
Maximum
645
827
1181
698
1791
9222
646
5798
10000

By offering supplier
Base
IntermediatePeak2021 (Jan - Jun)
Minimum
Average
Maximum
634
799
1131
665
1384
9067
722
5727
10000

Figure 3-48 shows the total installed capacity (ICAP) MW of units in thebaseload, intermediate and peaking segments by fuel source in the first six
months of 2021.121
Figure 3-48 Fuel source distribution in unit segments: January through June,
2021122

Figure 3-49 shows the ICAP of coal fired and gas fired units in PJM thatare classified as baseload, intermediate and peaking in the first six months
from 2017 through 2021. Figure 3-49 shows that the total ICAP of coal fired
units in PJM classified as baseload generally decreased from 2017 through2021, and the total ICAP of gas fired units in PJM classified as baseload
generally increased from 2017 through 2021. In 2019, the ICAP of gas fired
units classified as baseload exceeded the ICAP of coal fired units classified asbaseload for the first time.
Figure 3-49 Unit segment classification by fuel: January through June, 2017
through 2021
50,00050,000GASNUCLEAR35,000

ICAP (MW)COAL

30,00020,00015,00010,000MID
Unit Segment

5,000
HYDRO
NUCLEAR
OIL
SOLAR
WASTE
WIND

BATTERY
COAL
DISTRIBUTED GEN

HYDRO
NUCLEAR
OIL
SOLAR
WASTE
WIND

DISTRIBUTED GEN

BATTERY

WIND
SOLAR
WASTE

OIL

DISTRIBUTED GEN

BATTERY

HYDRO

BASE

25,00020,000GAS

COAL

ICAP MWGAS

30,00010,000GAS ICAP MW

40,00040,0000

COAL ICAP MW

45,000PEAKER

0

2017

2018

2019
BASE

2020

2021

2017

2018

2019

2020

MID
January through June

2021

2017

2018

2019

2020

2021

PEAKER

121 The installed capacity (ICAP) used for wind and solar units here is their nameplate capacity in MW. In PJM’s Capacity Market, the ICAP
value of wind and solar units is derated from the nameplate capacity to reflect their effective load carrying capability.
122 The units classified as Distributed Gen are buses within Electric Distribution Companies (EDCs) that are modeled as generation buses
to accurately reflect net energy injections from distribution level load buses. The modeling change was the outcome of the Net Energy
Metering Task Force stakeholder group in July, 2012. See PJM. “Net Energy Metering Senior Task Force (NEMSTF) 1st Read - Final
Report and Proposed Manual Revisions,” (June 28, 2012) <http://www.pjm.com/~/media/committees-groups/task-forces/nemstf/
postings/‌20120628-first-read-item-04-nemstf-report-and-proposed-manual-revisions.ashx>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 203

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-50 presents the hourly HHI values in chronological order and an
HHI duration curve for the first six months of 2021. The hours when the HHI
increased above 1000 all occurred between May 29, 2021 through June 1,
2021, during the Memorial Day weekend.
Figure 3-50 Hourly energy market HHI: January through June, 2021
1800

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

1600
1400
1200
1000
800
HHI

600

HHI RANK

400

200
0

0

730

1,460

2,190

2,920

3,650

4,380

5,110

5,840

6,570

7,300

8,030

8,760

Hours

Market-Based Rates
Participation in the PJM market using offers that exceed costs requires marketbased rate approval from FERC, which reviews the market-based rate authority
of PJM market sellers on a triennial schedule to ensure that market sellers do
not have market power or that market power is appropriately mitigated. The
entire PJM Region is included in the Northeast Region for purposes of thetriennial review schedule. The most recent triennial review filing period forthe December 1, 2017 – November 30, 2018 study period for nontransmission
owning utilities in the Northeast Region was in June 2020. The next triennial
review filing period for the December 1, 2020 – November 30, 2021 study

204

Section 3 Energy Market

period for transmission owners in the Northeast Region will be in December
2022.
With Order No. 861, FERC no longer requires structural market powerassessments to determine whether sellers have market power in the PJM
markets. Instead, sellers may rely on a rebuttable presumption that market
monitoring and market power mitigation are sufficient to ensure competitivemarket outcomes.123
The MMU has recommended since 2015 that changes to the offer capping
process for the energy market are needed to ensure effective market power
mitigation of units that fail the TPS test. The MMU has found that the capacity
market is not competitive because the default Market Seller Offer Cap (MSOC)
is inflated due to the use of an inaccurate estimate for the expected numberof Performance Assessment Intervals (PAIs).124 With these results and the
supporting evidence, the MMU has challenged the rebuttable presumption of
sufficient market power mitigation for the June 2020 triennial review filings
by unit generating unit owners in PJM and recommended that conditions
limiting sellers to cost-based energy offers and a revised capacity market offer
cap be required until improvements are made to the offer capping processes
in the energy and capacity markets so that suppliers cannot exercise market
power.125 In the first six months of 2021, FERC issued orders requiring reviewof the adequacy of the market power mitigation rules and their implementationin the capacity and energy markets.126 127

Merger Reviews
FERC reviews contemplated dispositions, consolidations, acquisitions,and changes in control of jurisdictional generating units and transmission
facilities under section 203 of the Federal Power Act to determine whether
such transactions are “consistent with the public interest.”128
123 Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System
Operator Markets, Order No. 861, 168 FERC ¶ 61,040 (2019) (“Order No. 861”).
124 See Complaint of the Independent Market Monitor for PJM, Docket No. EL19-47, (February 21, 2019), which can be accessed at <https://www.monitoringanalytics.com/‌Filings/2019/IMM_Complaint_Docket_No_EL19-XXX_20190221.pdf>.
125 See, e.g., Protest of the Independent Market Monitor for PJM, Docket No. ER10-1556 (August 28, 2020).
126 See 175 FERC ¶ 61,231 (June 17, 2021).
127 See 174 FERC ¶ 61,212 (March 18, 2021).
128 18 U.S.C. § 824b.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

FERC applies tests set forth in the 1996 Merger Policy Statement.129 130
The 1996 Merger Policy Statement provides for review of jurisdictionaltransactions based on “(1) the effect on competition; (2) the effect on rates;and (3) the effect on regulation.” FERC adopted the 1992 Department of Justice
Guidelines and the Federal Trade Commission Horizontal Merger Guideline(1992 Guidelines) to evaluate the effect on competition. Following the 1992
Guidelines, FERC applies a five step framework, which includes: (1) defining
the market; (2) analyzing market concentration; (3) analyzing mitigative
effects of new entry; (4) assessing efficiency gains; and (5) assessing viabilityof the parties without a merger. FERC also evaluates a Competitive Analysis
Screen.131

The MMU also reviews transactions that involve ownership changes of PJM
generation resources that are submitted to the Commission pursuant to section
203 of the Federal Power Act. Table 3-81 shows transactions that involved
an entire generation unit or unit owner that were completed in the first six
months of 2021, as reported to the Commission. Table 3-82 shows transactions
that involved transfers of partial unit ownership that were completed in thefirst six months of 2021, as reported to the Commission.135

The MMU reviews proposed mergers based on analysis of the impact of themerger or acquisition on market power given actual market conditions. The
analysis includes use of the three pivotal supplier test results in the real-timeenergy market. The MMU’s review ensures that mergers are evaluated basedon their impact on local market power in the PJM energy market using actual
observed market conditions, actual binding constraints and actual congestion
results. This is in contrast to the typical merger filing that uses predefined
local markets rather than the actual local markets. The MMU routinely files
comments including such analyses.132 The MMU has proposed that FERC
adopt this approach when evaluating mergers in PJM.133 FERC has considered
the MMU’s analysis in reviewing mergers.134

129 See Order No. 592, FERC Stats. & Regs. ¶ 31,044 (1996) (1996 Merger Policy Statement), reconsideration denied, Order No. 592-A,
79 FERC ¶ 61,321 (1997). See also FPA Section 203 Supplemental Policy Statement, FERC Stats. & Regs. ¶ 31,253 (2007), order onclarification and reconsideration, 122 FERC ¶ 61,157 (2008).
130 FERC has an open but inactive docket where the guidelines are under review. See 156 FERC ¶ 61,214 (2016); FERC Docket No. RM16-21000.
131 In February 2019, in response to 2017 amendments to Section 203 of the Federal Power Act, the Commission issued Order No. 855,
implementing a $10,000,000 minimum value for transactions requiring the Commission’s review. See 166 FERC ¶ 61,120 (2019)132 See, e.g., Comments of the Independent Market Monitor for PJM, FERC Docket No. EC14-141-000 (Nov. 10, 2014); Comments of the
Independent Market Monitor for PJM, FERC Docket No. EC14-96-000 (July 21, 2014) Comments of the Independent Market Monitor for
PJM, FERC Docket No. EC11-83-000 (July 21, 2011); Comments of the Independent Market Monitor for PJM, FERC Docket No. EC14-14(Dec. 9, 2013); Comments of the Independent Market Monitor for PJM, FERC Docket No. EC14-112-000 (Sept. 15, 2014); Comments of
the Independent Market Monitor for PJM, FERC Docket No. EC20-49 (June 1, 2020).
133 See Comments of the Independent Market Monitor for PJM, Docket No. RM16-21 (Dec. 12, 2016).
134 See Dynegy Inc., et al., 150 FERC ¶ 61, 231 (2015); Exelon Corporation, Constellation Energy Group, Inc., 138 FERC ¶ 61,167 (2012); NRG
Energy Holdings, Inc., Edison Mission Energy, 146 FERC ¶ 61,196 (2014); see also Analysis of Horizontal Market Power under the Federal
Power Act, 138 FERC ¶ 61,109 (2012).

© 2021 Monitoring Analytics, LLC

135 The transaction completion date is based on the notices of consummation submitted to the Commission.

2021 Quarterly State of the Market Report for PJM: January through June 205

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-81 Completed transfers of entire resources: January through June, 2021
Generator or Generation
Owner NameLES Landfill Units
Big Sky Wind
Mount Storm Wind

From
LES Manager LLC
Blackrock Inc
Castleton Commodities International

To
Energy Power Investment Company
Vitol
Clearway Energy Group LLC

Transaction
Completion Date
June 10, 2021
April 15, 2021
April 23, 2021

DocketEC21-61
EC21-53
EC21-52

generation at a similar price. This assumption requires thatthe total demand for energy can be met without the supply
from any individual supplier or without the supply froma small group of suppliers. This assumption is not always
correct, as demonstrated by these results. There are pivotal
suppliers in the aggregate energy market.

Table 3-82 Completed transfers of partial ownership of resources: January
through June, 2021

The existing market power
mitigation measures do not
Transaction
address
aggregate
marketGenerator or Generation Owner Name
From
To
Completion Date Docket
137
Competitive Power Ventures: Fairview (25%), Maryland (25%), Shore (37.5%) Global Infrastructure Partners
OPC Energy
January 25, 2021
EC21-16
power.
The
MMU
is
Yards Creek (50%)
JCPL
LS Power Development LLC
March 5, 2021
EC20-65
developing
anaggregate
Hamilton Liberty, Hamilton Patriot (50%)
EIG Management
The Carlyle Group
June 9, 2021
EC21-54
Old Trail Wind Farm (49%)
OMERS Administration Corporation Algonquin Power & Utilities Corp
June 16, 2021
EC21-78
market power test for the dayahead and real-time energy
markets based on pivotal suppliers and will propose appropriate market power
The MMU has also facilitated settlements for mitigation of market power, in
mitigation rules to address aggregate market power.
136
cases where market power concerns have been identified. Such mitigation
is designed to mitigate behavior over the long term, in addition to or insteadof imposing short term asset divestiture requirements.

Aggregate Market Pivotal Supplier Results
Notwithstanding the HHI level, a supplier may have the ability to raise energy
market prices. If reliably meeting the PJM system load requires energy froma single supplier, that supplier is pivotal and has monopoly power in theaggregate energy market. If a small number of suppliers are jointly required
to meet load, those suppliers are jointly pivotal and have oligopoly power. The
number of pivotal suppliers in the energy market is a more precise measure ofstructural market power than the HHI. The HHI is not a definitive measure ofstructural market power.
The current market power mitigation rules for the PJM energy market relyon the assumption that the aggregate market includes sufficient competing
sellers to ensure competitive market outcomes. With sufficient competition,
any attempt to economically or physically withhold generation would not
result in higher market prices, because another supplier would replace the136 See 138 FERC ¶ 61,167 at P 19.

206

Section 3 Energy Market

Day-Ahead Energy Market Aggregate Pivotal Suppliers
To assess the number of pivotal suppliers in the day-ahead energy market,
the MMU determined, for each supplier, the MW available for economic
commitment that were already running or were available to start between
the close of the day-ahead energy market and the peak load hour of theoperating day. The available supply is defined as MW offered at a price lessthan 150 percent of the applicable LMP because supply available at higher
prices is not competing to meet the demand for energy.138 Generating units,
import transactions, economic demand response, and INCs, are included foreach supplier. Demand is the total MW required by PJM to meet physicalload, cleared load bids, export transactions, and DECs. A supplier is pivotal if
PJM would require some portion of the supplier’s available economic capacity
in the peak hour of the operating day in order to meet demand. Suppliers
are jointly pivotal if PJM would require some portion of the joint suppliers’
137 One supplier, Exelon, is partially mitigated for aggregate market power through its merger agreement. The agreement is not part of thePJM market rules. See Monitoring Analytics, LLC, Letter attaching Settlement Terms and Conditions, FERC Docket No. EC11-83-000 andMaryland PSC Case No. 9271 (October 11, 2011).
138 Each LMP is scaled by 150 percent to determine the relevant supply, resulting in a different price threshold for each LMP value. The
analysis does not solve a redispatch of the PJM market.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

available economic capacity in the peak hour of the operating day in order tomeet demand.
Figure 3-51 shows the number of days in 2020 and the first six months of2021 with one pivotal supplier, two jointly pivotal suppliers, and three jointly
pivotal suppliers for the day-ahead energy market. One supplier was singly
pivotal on the summer peak days in 2020 and on February 15, 2021. Two
suppliers were jointly pivotal on 128 days in 2020 and on 60 days in thefirst six months of 2021. Three suppliers were jointly pivotal on 301 days in2020 and on 150 days in the first six months of 2021, despite average HHIs
at persistently unconcentrated levels. In 2020, the highest levels of aggregate
market power occurred in the third quarter, PJM’s summer peak load season.
Outside the summer months, the frequency of pivotal suppliers increased onhigh demand days in January 2020 and in February 2021.
Figure 3-51 Days with pivotal suppliers and numbers of pivotal suppliers in
the day-ahead energy market by quarterQ1 202080

Q2 2020
Q3 2020

Table 3-83 provides the frequency with which each of the top 10 pivotal
suppliers was singly or jointly pivotal for the day-ahead energy market in thefirst six months of 2021. The largest pivotal supplier was singly pivotal on one
day in the first six months of 2021. All of the top 10 suppliers were one of two
pivotal suppliers on at least seven days in the first six months of 2021. All of
the top 10 suppliers were one of three pivotal suppliers on at least 88 days inthe first six months of 2021.
Table 3-83 Day-ahead market pivotal supplier frequency: January throughJune, 2021
Pivotal Supplier
Rank
1
2
3
4
5
6
7
8
9
10

Days Singly
Pivotal
1
0
0
0
0
0
0
0
0
0

Days Jointly
Percent of Pivotal with One
Days
Other Supplier
0.6%
57
0.0%
56
0.0%
46
0.0%
32
0.0%
24
0.0%
12
0.0%
11
0.0%
9
0.0%
7
0.0%
7

Days Jointly
Percent of Pivotal with Two
Days Other Suppliers
31.5%
150
30.9%
149
25.4%
150
17.7%
143
13.3%
134
6.6%
120
6.1%
105
5.0%
103
3.9%
94
3.9%
88

Percent of
Days
82.9%
82.3%
82.9%
79.0%
74.0%
66.3%
58.0%
56.9%
51.9%
48.6%

Q4 2020
Q1 2021Market Behavior

Q2 2021

Local Market Power

60

Days

In the PJM energy market, market power mitigation rules currently apply
only for local market power. Local market power exists when transmission
constraints or reliability issues create local markets that are structurally
noncompetitive. If the owners of the units required to solve the constraint
or reliability issue are pivotal or jointly pivotal, they have the ability to
set the price. Absent market power mitigation, unit owners that submit
noncompetitive offers, or offers with inflexible operating parameters, could
exercise market power. This could result in LMPs being set at higher thancompetitive levels, or could result in noncompetitive uplift payments.

40

20

0

Singly Pivotal© 2021 Monitoring Analytics, LLC

Two Jointly Pivotal

Three Jointly Pivotal

2021 Quarterly State of the Market Report for PJM: January through June 207

2021 Quarterly State of the Market Report for PJM: January through June

The three pivotal supplier (TPS) test is the test for local market power in theenergy market.139 If the TPS test is failed, market power mitigation is applied byoffer capping the resources of the owners who have been identified as having
local market power. Offer capping is designed to set offers at competitive
levels. Competitive offers are defined to be cost-based energy offers. In the
PJM energy market, units are required to submit cost-based energy offers,
defined by fuel cost policies, and have the option to submit market-based,also called price-based, offers. Units are committed and dispatched on pricebased offers, if offered, as the default offer. When a unit that submits bothcost-based and price-based offers is mitigated to its cost-based offer by PJM,
it is considered offer capped. A unit that submits only cost-based offers, orthat requests PJM to dispatch it on its cost-based offer, is not considered offer
capped.
Local market power mitigation is implemented in both the day-ahead andreal-time energy markets. However, the implementation of the TPS test andoffer capping differ in the day-ahead and real-time energy markets.

TPS Test Statistics for Local Market PowerThe TPS test in the energy market defines whether one, two or three suppliers
are jointly pivotal in a defined local market. The TPS test is applied when thesystem solution indicates that out of merit resources are needed to relievea transmission constraint. The TPS test result for a constraint for a specificinterval indicates whether a supplier failed or passed the test for that constraint
for that interval. A failed test indicates that the resource owner has structural
market power.
A metric to describe the number of local markets created by transmission
constraints and the applicability of the TPS is the number of hours that eachtransmission constraint was binding in the real-time energy market over a
period, by zone.
In the first six months of 2021, the 500 kV system, 12 zones, and MISO
experienced congestion resulting from one or more constraints binding for139 See the MMU Technical Reference for PJM Markets, at “Three Pivotal Supplier Test” for a more detailed explanation of the three pivotal
supplier test. <http://www.‌monitoringanalytics.com/reports/Technical_References/references.shtml>.

208

Section 3 Energy Market

50 or more hours, or resulting from a binding interface constraint (Table
3-84).140 Table 3-84 shows that the 500 kV system, three zones and MISO
experienced congestion resulting from one or more constraints binding for 50
or more hours or resulting from a binding interface constraint in every year
from January through June, 2009 through 2021. Three control zones did notexperience congestion resulting from one or more constraints binding for 50
or more hours or resulting from any binding interface constraint in any year
from January through June, 2009 through 2021.
Table 3-84 Congestion hours resulting from one or more constraints bindingfor 50 or more hours or from an interface constraint: January through June,2009 through 2021
500 kV System
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DLCO
DOM
DPL
DUKE
DUQ
EKPC
EXT
JCPLC
MEC
MISO
NYISO
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC

2009
2,026
149
932
198
101
90
576
0
156
310
0
0
0
0
0
0
0
3,554
0
0
55
59
0
176
438
0

2010
2,861
69
355
410
0
154
1,406
0
342
589
0
0
0
0
0
0
0
1,879
0
0
0
0
0
0
479
0

2011
2,650
88
1,409
52
0
184
153
0
0
659
0
0
0
0
0
0
0
3,749
0
0
0
130
59
52
605
0

2012
369
0
322
113
1
1,556
845
0
209
200
126
58
0
0
0
0
68
7,080
0
0
0
53
203
146
316
0

(Jan - Jun)
2013 2014 2015 2016
720 1,370
722
700
0
0
0
383
811 1,773 1,902
471
51
170
451
79
70
403
464
0
316 1,142 3,079 4,923
1,678 1,729 1,727 2,910
0
0
0
0
0
281
747
0
0
52 1,422759
142
560 1,199 1,399
0
0
69
0
0
0
0
0
0
65
0
0
0
0
0
0
0
0
79
0
73
0
182
0
8,549 10,367 6,570 7,191
167
121
149 1,374
00000 1,441 1,385
551
256
944
485
732
85
39
0
0
188
147
0
0
1,462 2,023 2,591
220
0
0
0
0

2017
341
0
456
0
483
772
748
0
0
80
326
0
0
0
743
0
0
3,871
332
0
1,537
852
0
741
159
0

2018
458
0
1,020
81
1,866
1,861
564
0
57
136
295
68
0
159
0
0
1,235
4,224
0
0
1,127
130
0
177
334
0

2019
1,216
136
137
0
237
205
283
0
0
0
0
0
0
0
56
0
182
3,058
0
0
1,009
187
0
682
248
0

2020
1,767
0
739
333
263
2,458
923
0
0
584
0
0
0
0
53
0
564
2,194
0
0
1,940
0
0
836
0
0

140 A constraint is mapped to the 500 kV system if its voltage is 500 kV and it is located in one of the control zones including AECO, BGE,
DPL, JCPLC, MEC, PECO, PENELEC, PEPCO, PPL and PSEG. All PJM/MISO reciprocally coordinated flowgates (RCF) are mapped to MISO
regardless of the location of the flowgates. All PJM/NYISO RCF are mapped to NYISO as location regardless of the location of theflowgates.

© 2021 Monitoring Analytics, LLC

2021
1,116
0
1,370
111
460
1,572
897
0
0
498
144
174
0
0
0
0
295
2,158
0
0
52
0
0
921
1,506
0

Section 3 Energy Market

In the PJM Day-Ahead Energy Market, the TPS test is performed in PROBE, aspart of the unit commitment process. Table 3-85 shows the average constraint
relief required on the constraint, the average effective supply available torelieve the constraint, the average number of owners with available relief inthe defined market and the average number of owners passing and failing the
TPS test for the transfer interface constraints in the PJM Day-Ahead Energy
Market.
Table 3-85 Day-ahead three pivotal supplier test details for interface
constraints: January through June, 2021
Constraint
BC Pepco
5004/5005
AEP - DOM

PeriodPeak
Off PeakPeak
Off PeakPeak
Off PeakAverage
Constraint
Relief (MW)
187
1,061
108
NA
332
NA

Average
Effective
Supply (MW)
1,129
1,189
512
NA
542
NA

Average
Average
Average
NumberNumberNumberOwners Owners Passing Owners Failing
21
18
3
15
0
15
29
29
0
NA
NA
NA
21
7
14
NA
NA
NA

Table 3-86 shows the average constraint relief required on the constraint,
the average effective supply available to relieve the constraint, the average
number of owners with available relief in the defined market and the average
number of owners passing and failing the TPS test for the 10 constraints thatwere binding for the most hours in the PJM Day-Ahead Energy Market. In the
PJM Day-Ahead Energy Market, the TPS test evaluates each constraint thatwas binding for each hour during the operating day.

Table 3-86 Day-ahead three pivotal supplier test details for top 10 congested
constraints: January through June, 2021

Constraint
Berwick - Koonsville

PeriodPeak
Off PeakCedar Grove Sub - William
Peak
Off PeakBagley - Raphael RoadPeak
Off PeakNottingham
Peak
Off PeakEast Lima - Haviland
Peak
Off PeakThree Mile Island
Peak
Off PeakHarwood - Susquehanna
Peak
Off PeakFace RockPeak
Off PeakViennaPeak
Off PeakRamapo (ConEd) - S Mahwah (RECO) Peak
Off PeakAverage
Constraint
Relief
(MW)
3
5
209
167
322
250
285
167
103
101
349
242
120
119
125
74
291
327
21
NA

Average
Effective
Supply
(MW)
12
15
156
72
421
341
274
218
148
129
229
172
189
143
133
97
263
285
2
NA

Average
NumberOwners
3
3
8
7
22
22
21
19
11
10
18
15
10
9
10
8
6
5
2
NA

Average
NumberOwnersPassing
0
0
0
0
6
8
6
8
1
0
1
1
1
0
1
0
0
0
0
NA

Average
NumberOwnersFailing
3
3
8
7
17
13
15
11
10
9
17
14
9
9
9
8
6
5
2
NA

The local market structure in the real-time energy market associated with eachof the frequently binding constraints was analyzed using the three pivotal
supplier results in 2020.141 While the real-time constraint hours include
constraints that were binding in the five minute real-time pricing solution(LPC), IT SCED, the software that performs the TPS test, may contain different
binding constraints because IT SCED looks ahead to target times that are in
the near future to solve for constraints that could be binding, using the load
forecast for those times. IT SCED solves for target times that occur at 15
minute time increments, unlike RT SCED that solves for every five minutetime increment. The TPS statistics shown in this section present the data fromthe IT SCED TPS solution. The results of the TPS test are shown for tests that
could have resulted in offer capping and tests that resulted in offer capping.
141 See the MMU Technical Reference for PJM Markets, p. 38 “Three Pivotal Supplier Test” for a more detailed explanation of the threepivotal supplier test. <http://www.monitoringanalytics.com/reports/Technical_References/references.shtml>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 209

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-87 shows the average constraint relief required on the constraint,
the average effective supply available to relieve the constraint, the average
number of owners with available relief in the defined market and the average
number of owners passing and failing for the transfer interface constraints in
the PJM Real-Time Energy Market. Table 3-88 shows the average constraint
relief required on the constraint, the average effective supply available torelieve the constraint, the average number of owners with available relief inthe defined market and the average number of owners passing and failing forthe 10 constraints that were binding for the most hours in the PJM Real-Time
Energy Market. Table 3-87 and Table 3-88 include analysis of all the tests forevery target time where IT SCED determined that constraint relief was neededfor each of the constraints shown. The same target time can be evaluated bymultiple IT SCED cases at different look ahead times. Each 15 minute target
time is solved by 12 different IT SCED cases at different look ahead times. The
set of binding constraints for a target time may be different in 12 look ahead
IT SCED solutions.

Table 3-88 Three pivotal supplier test details for top 10 congested
constraints: January through June, 2021

Constraint
Bagley - Raphael Road
Cedar Grove Sub - William
Brighton
Northwest Tap - Purdue
Nottingham
East Lima - Haviland
Harwood - Susquehanna
North Coulterville
Sandburg

Table 3-87 Three pivotal supplier test details for interface constraints:
January through June, 2021

Constraint
5004/5005 Interface
AP South
East
PA Central

PeriodPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakAverage
Constraint
Relief (MW)
328
146
327
388
409
NA
32
14

Average
Effective
Supply (MW)
421
548
717
387
468
NA
81
154

Average
NumberOwners
19
21
20
10
18
NA
5
5

Average
NumberOwnersPassing
5
15
10
5
2
NA
1
1

Bagley - Graceton
Average
NumberOwnersFailing
14
6
10
4
16
NA
5
4

PeriodPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakAverage
Constraint
Relief (MW)
86
70
79
56
187
127
35
25
71
51
27
27
33
20
26
18
25
23
105
81

Average
Effective
Supply
(MW)
170
139
98
93
330
230
50
42
108
84
32
28
38
30
16
13
12
13
210
150

Average
NumberOwners
12
11
6
5
19
16
2
2
10
9
1
1
4
3
3
2
3
3
11
10

Average
NumberOwnersPassing
6
5
0
0
10
7
0
0
2
1
0
0
0
0
0
0
0
0
6
4

Average
NumberOwnersFailing
6
6
6
5
8
9
2
2
8
7
1
1
4
3
3
2
3
3
6
6

The three pivotal supplier test is applied every time the IT SCED solution
indicates that incremental relief is needed to relieve a transmission constraint.
While every system solution that requires incremental relief to transmission
constraints will result in a test, not all tested providers of effective supply
are eligible for offer capping. Steam unit offers that are offer capped in the
day-ahead energy market continue to be offer capped in the real-time energy
market regardless of their inclusion in the TPS test in real time or the outcomeof the TPS test in real time. Steam unit offers that are not offer capped in the
day-ahead energy market continue to not be offer capped in the real-timeenergy market regardless of their inclusion in the TPS test in real time or theoutcome of the TPS test in real time.142 Offline units that are committed toprovide relief for a transmission constraint, whose owners fail the TPS test,
are committed on the cheaper of their cost or price-based offers. Beginning
November 1, 2017, with the introduction of hourly offers and intraday offer
142 If a steam unit were to lower its cost-based offer in real time, it would become eligible for offer capping based on the online TPS test.

210

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

updates, certain online units whose commitment is extended beyond the day-ahead or real-time commitment, whose owners fail the TPS test, are also switchedto the cost-based offer if it is cheaper than the price-based offer.
Units committed in the day-ahead market often fail the TPS test in the real-time market when they are redispatched to provide relief to transmission constraints,
even though they did not fail the TPS test in the day-ahead market. These units are able to set prices with a positive markup in the real-time market. Units thatcleared the day-ahead market on their price based schedule were evaluated to identify the units whose offers were mitigated in real-time and the units thatcleared on price offers in real-time despite failing the real-time TPS test. Table 3-89 shows that 0.9 percent of unit hours that cleared the day-ahead market on
their price based offer were switched to cost in real-time. Table 3-89 shows that 7.9 percent of unit hours that cleared the day-ahead market on their price based
offer cleared on their price based offer in real-time despite failing the real-time TPS test.
Table 3-89 Day-ahead committed units that cleared real-time: January through June, 2020 and 2021
(Jan - Jun)
2020
2021

Day Ahead Price Based Unit Hours
That Cleared Real-Time on Cost
3,528
11,404

Day Ahead Price Based Unit Hours
That Cleared Real-Time on Price
1,233,994
1,284,844

Day Ahead Price Based Unit Hours
That Failed Real-Time TPS andCleared Real-Time on Price
80,764102,382

Percent Day Ahead Price Based Percent Day Ahead Price Based Unit
Unit Hours That Cleared Real-Time
Hours That Failed Real-Time TPS
on Costand Cleared Real-Time on Price
0.3%
6.5%
0.9%
7.9%

The MMU recommends, in order to ensure effective market power mitigation when the TPS test is failed, that offer capping be applied to units that fail the TPS
test in the real-time market that were not offer capped at the time of commitment in the day-ahead market or at a prior time in the real-time market.
Table 3-90 and Table 3-91 provide, for the identified constraints, information on total tests applied, the subset of three pivotal supplier tests that could haveresulted in offer capping and the portion of those tests that did result in offer capping. Tests where there was at least one offline unit or an online unit eligible
for offer capping are considered tests that could have resulted in offer capping. PJM operators also manually commit units for reliability reasons other thanproviding relief to a binding constraint. Manual commitments are offer capped along with resources that fail the TPS test.
Table 3-90 Summary of three pivotal supplier tests applied for interface constraints: January through June, 2021
Constraint
5004/5005
AP South
Eastern
PA Central

PeriodPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakTotal Tests that Could Percent Total Tests that
Total Tests
Total Tests Have Resulted in Offer Could Have Resulted in Resulted in Offer
Applied
Capping
Offer Capping
Capping
223
223
100%
1
30
30
100%
0
109
109
100%
1
58
34
59%
0
48
48
100%
0
0
0
NA
0
104
102
98%
4
205
177
86%
3

© 2021 Monitoring Analytics, LLC

Percent Total Tests
Resulted in Offer
Capping
0%
0%
1%
0%
0%
NA
4%
1%

Tests Resulted in Offer Capping
as Percent of Tests that Could
Have Resulted in Offer Capping
0%
0%
1%
0%
0%
NA
4%
2%

2021 Quarterly State of the Market Report for PJM: January through June 211

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-91 Summary of three pivotal supplier tests applied for top 10 congested constraints: January through June, 2021
Constraint
Bagley - Raphael Road
Cedar Grove Sub - William
Brighton
Northwest Tap - Purdue
Nottingham
East Lima - Haviland
Harwood - Susquehanna
North Coulterville
Sandburg
Bagley - Graceton

PeriodPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakPeak
Off PeakTotal Tests that Could Percent Total Tests that
Total Tests
Total Tests Have Resulted in Offer Could Have Resulted in Resulted in Offer
Applied
Capping
Offer Capping
Capping
13,762
13,450
98%
76
7,954
7,891
99%
38
10,235
9,423
92%
84
6,282
5,353
85%
55
8,137
8,134
100%
279
8,053
8,053
100%
113
11,943
1,503
13%
0
6,444
591
9%
0
8,060
7,877
98%
62
5,211
5,034
97%
43
4,868
34
1%
0
4,861
18
0%
0
3,663
2,863
78%
17
2,183
1,384
63%
3
140
2
1%
0
1,177
54
5%
0
2,665
263
10%
0
2,658
427
16%
8
5,178
5,107
99%
33
4,262
4,219
99%
29

Percent Total Tests
Resulted in Offer
Capping
1%
0%
1%
1%
3%
1%
0%
0%
1%
1%
0%
0%
0%
0%
0%
0%
0%
0%
1%
1%

Tests Resulted in Offer Capping
as Percent of Tests that Could
Have Resulted in Offer Capping
1%
0%
1%
1%
3%
1%
0%
0%
1%
1%
0%
0%
1%
0%
0%
0%
0%
2%
1%
1%

Offer Capping for Local Market PowerIn the PJM energy market, offer capping occurs as a result of structurally noncompetitive local markets and noncompetitive offers in the day-ahead and realtime energy markets. PJM also uses offer capping for units that are committed for reliability reasons, specifically for providing black start and reactive service
as well as for conservative operations. There are no explicit rules governing market structure or the exercise of market power in the aggregate energy market.
There are some issues with the application of mitigation in the day-ahead energy market and the real-time energy market when market sellers fail the TPS test.
There is no tariff or manual language that defines in detail the application of the TPS test and offer capping in the day-ahead energy market and the real-timeenergy market.
In both the day-ahead and real-time energy markets, generators with market power have the ability to evade mitigation by using varying markups in their pricebased offers, offering different operating parameters in their price-based and cost-based offers, and using different fuels in their price-based and cost-based
offers. These issues can be resolved by simple rule changes.
When an owner fails the TPS test, the units offered by the owner that are committed to provide relief are committed on the cheaper of cost-based or price-based
offers. In the day-ahead energy market, PJM commits a unit on the schedule that results in the lower overall system production cost. This is consistent withthe day-ahead energy market objective of clearing resources (including physical and virtual resources) to meet the total demand (including physical and virtual

212

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

demand) at the lowest bid production cost for the system over the 24 hour
period. In the real-time energy market, PJM uses a dispatch cost formula tocompare price-based offers and cost-based offers to select the cheaper offer.143

Figure 3-52 Offers with varying markups at different MW output levels
45
40
35

30
Offer ($/MWh)where the hourly dispatch cost is calculated for each hour using the offers
applicable for that hour as:

25
20
15

Given the ability to submit offer curves with different markups at different
output levels in the price-based offer, unit owners with market power canevade mitigation by using a low markup at low output levels and a highmarkup at higher output levels. Figure 3-52 shows an example of offers froma unit that has a negative markup at the economic minimum MW level anda positive markup at the economic maximum MW level. The result would bethat a unit that failed the TPS test would be committed on its price-based offerthat has a lower dispatch cost, even though the price-based offer is higher
than cost-based offer at higher output levels and includes positive markups,
inconsistent with the explicit goal of local market power mitigation.

143 See OA Schedule 1

10
5
0

30

40
Cost-Based Offer

50
Price-Based Offer

60
MW

70
Economic Minimum MW

80

90

Economic Maximum MW§ 6.4.1(g).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 213

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-92 shows the number and percent of unit schedule hours, by month, when unit offers included crossing curves in the PJM Day-Ahead and Real-Time
Energy Markets, in the first six months of 2021. The analysis only includes units that offer both price-based and cost-based offers. Units in PJM are only required
to submit cost-based offers, and they may elect to offer price-based offers, but are not required to do so.
Table 3-92 Units offered with crossing curves in the day-ahead and real-time energy markets: January through June, 2021

2021
Jan
Feb
Mar
Apr
May
Jun
Total

Number of Schedule
Hours with Crossing
Curves61,326
56,10070,11073,78591,452
103,578456,351

Day-Ahead
Total Number of Cost
Schedule Hours Offeredby Price Based Units
838,152
750,072
844,732
805,512842,592822,216
4,903,276

Percent of Schedule
Hours with Crossing
Curves
7.3%
7.5%
8.3%
9.2%
10.9%
12.6%
9.3%

Number of Schedule
Hours with Crossing
Curves60,55750,86758,436
58,64977,648
97,130403,287

Real-Time
Total Number of Cost
Schedule Hours Offeredby Price Based Units
779,014687,184
722,456
651,693
715,547
768,461
4,324,355

Percent of Schedule
Hours with Crossing
Curves
7.8%
7.4%
8.1%
9.0%
10.9%
12.6%
9.3%

Offering a different economic minimum MW level, different minimum run times, or different start up and notification times in the cost-based and price-based
offers can also be used to evade mitigation. For example, a unit may offer its price-based offer with a positive markup, but have a shorter minimum run time(MRT) in the price-based offer resulting in a lower dispatch cost for the price-based offer but setting prices at a level that includes a positive markup. Table 3-93
shows the number and percent of unit schedule hours when units offered lower minimum run times in price-based offers than in cost-based offers while having
a positive markup in the price based offer.
Table 3-93 Units offered with lower minimum run time on price compared to cost but with positive markup in the day-ahead and real-time energy markets:
January through June, 2021144
Day-Ahead

2021
Jan
Feb
Mar
Apr
May
Jun
Total

Number of Schedule
Hours with Lower
Min Run Time in Price
Compared to Cost
13,151
12,162
11,513
8,220
6,489
6,367
57,902

Total Number of Cost
Schedule Hours Offeredby Price Based Units
838,152
750,072
844,732
805,512842,592822,216
4,903,276

Real-Time
Percent of Schedule
Hours with Lower
Min Run Time in Price
Compared to Cost
1.6%
1.6%
1.4%
1.0%
0.8%
0.8%
1.2%

Number of Schedule
Hours with Lower
Min Run Time in Price
Compared to Cost
7,779
7,800
8,376
6,759
5,331
5,439
41,484

Total Number of Cost
Schedule Hours Offeredby Price Based Units
779,014687,184
722,456
651,693
715,547
768,461
4,324,355

Percent of Schedule
Hours with Lower
Min Run Time in Price
Compared to Cost
1.0%
1.1%
1.2%
1.0%
0.7%
0.7%
1.0%

144 In the previous version of this report, all the schedule hours with a lower minimum run time in their price-based offer compared to the cost-based offer in the first three months of 2021 were incorrectly included, regardless of the markup in the price-based offer. This table is corrected
to include only those schedule hours with lower minimum run time in their price-based offer compared to the cost-based offer while offering a positive markup in the price-based offer.

214

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

A unit may offer a lower economic minimum MW level on the price-based
offer than the cost-based offer. Such a unit may appear to be cheaper tocommit on the price-based offer even with a positive markup. A unit witha positive markup can have lower dispatch cost with the price-based offerwith a lower economic minimum level compared to cost-based offer. Figure3-53 shows an example of offers from a unit that has a positive markup anda price-based offer with a lower economic minimum MW than the cost-based
offer. Keeping the startup cost, Minimum Run Time and no load cost constant
between the price-based offer and cost-based offer, the dispatch cost for thisunit is lower on the price-based offer than on the cost-based offer. However,the price-based offer includes a positive markup and could result in setting
the market price at a noncompetitive level even after the resource owner fails
the TPS test.
Figure 3-53 Offers with a positive markup but different economic minimum MW
45
40
35

Offer ($/MWh)

30

25
20
15
10
5
0

0

10

20

30

Offer@Ecomin times Ecomin MW Price Offer
Cost-Based Offer
Price Economic Minimum MW
Economic Maximum MW© 2021 Monitoring Analytics, LLC

40 MW

50

60

70

80

90

Offer@Ecomin times Ecomin MW Cost Offer
Price-Based Offer
Cost Economic Minimum MW

2021 Quarterly State of the Market Report for PJM: January through June 215

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-94 shows the number and percent of unit schedule hours when units offered lower economic minimum MW in price-based offers than in cost-based
offers while having a positive markup in the price-based offer.
Table 3-94 Units offered with lower economic minimum MW on price compared to cost but with positive markup in the day-ahead and real-time energy
markets: January through June, 2021145
Day-Ahead

2021
Jan
Feb
Mar
Apr
May
Jun
Total

Number of Schedule
Hours with Lower
Economic Minimum MW
in Price Compared to Cost
0
216
1,486
1,440
1,488
1,440
6,070

Total Number of Cost
Schedule Hours Offeredby Price Based Units
838,152
750,072
844,732
805,512842,592822,216
4,903,276

Real-Time
Percent of Schedule Hours
Number of Schedulewith Lower Economic
Hours with Lower
Minimum MW in Price Economic Minimum MW
Compared to Cost in Price Compared to Cost
0.0%
0
0.0%
194
0.2%
1,174
0.2%
1,440
0.2%
456
0.2%
1,128
0.1%
4,392

Total Number of Cost
Schedule Hours Offeredby Price Based Units
779,014687,184
722,456
651,693
715,547
768,461
4,324,355

Percent of Schedule Hours
with Lower Economic
Minimum MW in Price
Compared to Cost
0.0%
0.0%
0.2%
0.2%
0.1%
0.1%
0.1%

In case of dual fuel units, if the price-based offer uses a cheaper fuel and the cost-based offer uses a more expensive fuel, the price-based offer will appear to belower cost even when it includes a markup. Figure 3-54 shows an example of offers by a dual fuel unit, where the active cost-based offer uses a more expensive
fuel and the price-based offer uses a cheaper fuel and includes a markup. Table 3-95 shows the number and percent of dual fuel unit hours where the price-based
offer does not have a comparable cost-based offer with a matching fuel, and contains a negative markup. The analysis includes only those units that offeredmultiple offers (cost or price) with different fuels in the first six months of 2021.

145 In the previous version of this report, all the schedule hours with a lower economic minimum MW in their price-based offer compared to the cost-based offer in the first three months of 2021 were incorrectly included, regardless of the markup in the price-based offer. This table iscorrected to include only those schedule hours with lower economic minimum MW in their price-based offer compared to the cost-based offer while offering a positive markup in the price-based offer.

216

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Figure 3-54 Dual fuel unit offers

These issues can be solved by simple rule changes.146 The MMU recommends
that markup of price-based offers over cost-based offers be constant acrossthe offer curve, that there be at least one cost-based offer using the same fuelas the available price-based offer, and that operating parameters on parameter
limited schedules (PLS) be at least as flexible as price-based non-PLS offers.

160
140

Offer ($/MWh)

120
100
80
60
40
20
0

30

40

50

Cost-Based Offer (Cheaper Fuel)

60
MW

70

Price-Based Offer (Cheaper Fuel)80

90

Cost-Based Offer (Expensive Fuel)

Table 3-95 Dual fuel unit offers with negative markup but different fuel:January through June, 2021

Levels of offer capping have historically been low in PJM, as shown in
Table 3-97. But offer capping remains a critical element of PJM market rules
because it is designed to prevent the exercise of local market power. While
overall offer capping levels have been low, there are a significant numberof units with persistent structural local market power that would have asignificant impact on prices in the absence of local market power mitigation.
Until November 1, 2017, only uncommitted resources, started to relieve atransmission constraint, were subject to offer capping. Beginning November
1, 2017, under certain circumstances, online resources that are committed
beyond their original commitment (day-ahead or real-time) can be offer
capped if the owner fails the TPS test, and the latest available cost-based
offer is determined to be lower than the price-based offer.147 Units runningin real time as part of their original commitment on the price-based offer on
economics, and that can provide incremental relief to a constraint, cannot beswitched to their cost-based offer.

Day-Ahead

2021
Jan
Feb
Mar
Apr
May
Jun
Total

Number of Unit Hours
With Negative Markup
And No Matching Fuelon Cost
2,633
5,360
3,096
4,173
1,560
1,478
18,300Total Number of Unit
Hours By Units With
Multiple Fuels
198,432
170,184
195,816
176,976
181,872
182,952
1,106,232

Real-Time
Percent Unit Hours With
Negative Markup And No
Matching Fuel on Cost
1.3%
3.1%
1.6%
2.4%
0.9%
0.8%
1.7%

Number of Unit Hours
With Negative Markup
And No Matching Fuelon Cost
2,633
5,360
3,096
4,173
1,560
1,478
18,300The offer capping percentages
shown in Table 3-96 include units
that are committed to provide
constraint relief whose owners
failed the TPS test in the energy
market excluding units thatwere committed for reliability
reasons, providing black start andproviding reactive support. Offer
capped unit run hours and offer capped generation (in MWh) are shown asa percentage of the total run hours and the total generation (MWh) from all
Total Number of Unit
Hours By Units With
Multiple Fuels
178,118
145,413150,583
152,556
159,862
177,296
963,828

Percent Unit Hours With
Negative Markup And No
Matching Fuel on Cost
1.5%
3.7%
2.1%
2.7%
1.0%
0.8%
1.9%

146 The MMU proposed these offer rule changes as part of a broader reform to address generator offer flexibility and associated impact onmarket power mitigation rules in the Generator Offer Flexibility Senior Task Force (GOFSTF) and subsequently in the MMU’s protest in thehourly offers proceeding in Docket No. ER16-372-000, filed December 14, 2015.
147 See OA Schedule 1 § 6.4.1.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 217

2021 Quarterly State of the Market Report for PJM: January through June

the units in the PJM energy market.148 Beginning November 1, 2017, with
the introduction of hourly offers, certain online units, whose owners fail the
TPS test in the real-time energy market for providing constraint relief, can beoffer capped and dispatched on their cost-based offer subsequent to a realtime hourly offer update. This is reflected in the slightly higher rate of offer
capping in the real-time energy market since 2017.
Table 3-96 Offer capping statistics – energy only: January through June,2017 to 2021
(Jan-Jun)
2017
2018
2019
2020
2021

Real-Time
Unit Hours Capped
0.2%
1.3%
0.8%
0.9%
1.3%

MWh Capped
0.1%
0.5%
0.7%
1.4%
1.1%

Day-Ahead
Unit Hours Capped
MWh Capped
0.0%
0.0%
0.1%
0.1%
0.5%
0.4%
1.2%
1.2%
1.3%
0.8%

Table 3-97 shows the offer capping percentages including units committed toprovide constraint relief and units committed for reliability reasons. Reliability
reasons include reactive support or local voltage support. PJM creates closed
loop interfaces to, in some cases, model reactive constraints. The result was
higher LMPs in the closed loop interfaces, which increased economic dispatch,which contributed to the reduction in units offer capped for reactive support
over time in Table 3-98. In instances where units are committed and offer
capped for the modeled closed loop interface constraints, they are considered
offer capped for providing constraint relief, and not for reliability. They areincluded in the offer capping percentages in Table 3-96. Prior to closed loop
interfaces, these units were considered as committed for reactive support, andwere included in the offer capping statistics for reliability in Table 3-98.

Table 3-97 Offer capping statistics for energy and reliability: January throughJune, 2017 to 2021
(Jan-Jun)
2017
2018
2019
2020
2021

Real-Time
Unit Hours Capped
0.3%
1.5%
0.8%
0.9%
1.3%

MWh Capped
0.5%
0.8%
0.7%
1.4%
1.1%

Day-Ahead
Unit Hours Capped
MWh Capped
0.2%
0.4%
0.2%
0.4%
0.5%
0.4%
1.2%
1.2%
1.3%
0.8%

Table 3-98 shows the offer capping percentages for units committed forreliability reasons, including units committed for reactive support. The
low offer cap percentages do not mean that units manually committed forreliability reasons do not have market power. All units manually committed
for reliability have market power and all are treated as if they had market
power. These units are not capped to their cost-based offers because they tend
to offer with a negative markup in their price-based offers, particularly atthe economic minimum level, which means that PJM’s offer capping process
results in the use of the price-based offer for commitment. However, the pricebased offers have inflexible parameters such as longer minimum run times
that may lead to higher total commitment cost if the unit was only needed fora shorter period that is less than its inflexible minimum run time.
Table 3-98 Offer capping statistics for reliability: January through June, 2017
to 2021(Jan-Jun)
2017
2018
2019
2020
2021

Real-Time
Unit Hours Capped
0.13%
0.18%
0.01%
0.01%
0.01%

MWh Capped
0.40%
0.32%
0.02%
0.01%
0.01%

Day-Ahead
Unit Hours Capped
MWh Capped
0.16%
0.38%
0.13%
0.25%
0.01%
0.02%
0.00%
0.00%
0.02%
0.01%

148 Prior to the 2018 Quarterly State of the Market Report for PJM: January through June, these tables presented the offer cap percentages
based on total bid unit hours and total load MWh. Beginning with the quarterly report for January through June, 2018, the statistics
have been updated with percentages based on run hours and total generation MWh from units modeled in the energy market.

218

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-99 presents data on the frequency with which units were offer cappedin the first six months of 2020 and 2021 as a result of failing the TPS test to
provide energy for constraint relief in the real-time energy market and forreliability reasons. Table 3-99 shows that 12 units were offer capped for 90
percent or more of their run hours in the first six months of 2021 comparedto three units in the first six months of 2020.

Figure 3-55 shows the frequency with which units were offer capped in thefirst six months of 2020 and 2021 for failing the TPS test to provide energy
for constraint relief in the real–time energy market and for reliability reasons.
Figure 3-55 Real-time offer capped unit statistics: January through June,
2020 and 2021
80

Table 3-99 Real-time offer capped unit statistics: January through June,
2020 and 2021

90%
80% and < 90%
75% and < 80%
70% and < 75%
60% and < 70%
50% and < 60%
25% and < 50%
10% and < 25%

Jan Jun
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021

Hours ≥
500
0
3
1
0
0
1
0
1
0
0
0
0
3
2
1
2

Hours ≥
400 and
< 500
0
0
0
0
0
0
1
1
0
0
1
0
0
0
0
2

Offer-Capped Hours
Hours ≥
Hours ≥
300 and
200 and
< 400
< 300
0
0
0
0
0
0
1
1
0
0
1
0
0
0
2
2
0
1
0
0
1
0
1
1
2
2
1
8
0
4
2
4

Hours ≥
100 and
< 200
0
0
0
4
1
1
0
1
0
1
1
3
5
15
3
10

Hours ≥
1 and
< 100
3
9
1
3
2
1
2
1
4
6
6
10
32
44
36
47

60

Number of units offer capped

Run Hours Offer-Capped,
Percent Greater Than Or
Equal To:

70

50
40
30
20
10
0

2020 2021

2020 2021

2020 2021

2020 2021

2020 2021

2020 2021

2020 2021

2020 2021>90%

80% - 90%75% - 80%

70% - 75%

60% - 70%

50% - 60%

25% - 50%

10% - 25%

Percent of run hours offer capped
Run Hours ≥ 500

Run Hours ≥ 400 and < 500

Run Hours ≥ 300 and < 400

Run Hours ≥ 200 and < 300

Run Hours ≥ 100 and < 200

Run Hours ≥ 1 and < 100

Markup Index
Markup is a summary measure of participant offer behavior or conduct forindividual units. When a seller responds competitively to a market price,
markup is zero. When a seller exercises market power in its pricing, markup is
positive. The degree of markup increases with the degree of market power. The
markup index for each marginal unit is calculated as (Price – Cost)/Price.149
The markup index is normalized and can vary from -1.00 when the offer
price is less than the cost-based offer price, to 1.00 when the offer price is
149 In order to normalize the index results (i.e., bound the results between +1.00 and -1.00) for comparison across both low and high cost
units, the index is calculated as (Price – Cost)/Price when price is greater than cost, and (Price – Cost)/Cost when price is less than cost.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 219

2021 Quarterly State of the Market Report for PJM: January through Junehigher than the cost-based offer price. The markup index does not measure
the impact of unit markup on total LMP. The dollar markup for a unit is thedifference between price and cost.

Real-Time Markup Index
Table 3-100 shows the average markup index of marginal units in the realtime energy market, by offer price category using unadjusted cost-based
offers. Table 3-101 shows the average markup index of marginal units in thereal-time energy market, by offer price category using adjusted cost-based
offers. The unadjusted markup is the difference between the price-based offer
and the cost-based offer including the 10 percent adder in the cost-based
offer. The adjusted markup is the difference between the price-based offer andthe cost-based offer excluding the 10 percent adder from the cost-based offer.
The adjusted markup is calculated for coal, gas and oil units because theseunits have consistently had price-based offers less than cost-based offers.150
The markup is negative if the cost-based offer of the marginal unit exceeds its
price-based offer at its operating point.
All generating units are allowed to add an additional 10 percent to their costbased offer. The 10 percent adder was included prior to the implementationof PJM markets in 1999, based on the uncertainty of calculating the hourly
operating costs of CTs under changing ambient conditions. The owners ofcoal units, facing competition, typically exclude the additional 10 percent
from their actual offers. The owners of many gas fired and oil fired units havealso begun to exclude the 10 percent adder. The introduction of hourly offers
and intraday offer updates in November 2017 allows gas and oil generators
to directly incorporate the impact of ambient temperature changes in fuelconsumption in offers.
Even the adjusted markup overestimates the negative markup because units
facing increased competitive pressure have excluded both the 10 percent andcomponents of operating and maintenance costs that are not short run marginal
costs. The PJM Market rules permit the 10 percent adder and maintenancecosts, which are not short run marginal costs, under the definition of cost150 The MMU will calculate adjusted markup for gas units also in future reports because gas units also more consistently have price-based
offers less than cost-based offers.

220

Section 3 Energy Market

based offers. Actual market behavior reflects the fact that neither is part of acompetitive offer and neither is a short run marginal cost.151
In the first six months of 2021, the average markup index in the real-time
market was -0.02. The average dollar markups of units with offer prices lessthan $10 was negative (-$7.36 per MWh) when using unadjusted cost-based
offers. The average dollar markups of units with offer prices between $10 and$15 was negative (-$1.23 per MWh) when using unadjusted cost-based offers.
Negative markup means the unit is offering to run at a price less than its costbased offer, revealing a short run marginal cost that is less than the maximum
allowable cost-based offer under the PJM Market Rules.
Some marginal units did have substantial markups. Among the units thatwere marginal in the first six months of 2021, less than one percent had offer
prices above $400 per MWh. Among the units that were marginal in the firstsix months of 2020, none had offer prices greater than $400 per MWh. Using
the unadjusted cost-based offers, the highest markup for any marginal unit in
the first six months of 2021 was more than $400, and the highest markup in
the first six months of 2020 was more than $150.
Table 3-100 Average, real-time marginal unit markup index (By offer pricecategory unadjusted): January through June, 2020 and 2021
Offer Price
Category< $10$10 to $15$15 to $20$20 to $25$25 to $50$50 to $75$75 to $100
$100 to $125
$125 to $150
$150 to $400
All Offers

2020 (Jan - Jun)
Average
Average
DollarMarkup Index
Markup(0.02)($1.15)
0.04
$0.43
0.02
($0.12)
0.04
$0.63
0.18
$5.96
0.54
$31.850.68$60.370.77$87.540.32$41.51
0.53$90.420.03$0.48

2021 (Jan - Jun)
Average
Average
DollarFrequency Markup Index
Markup13.3%
0.07($7.36)45.0%(0.07)($1.23)30.9%(0.04)($0.97)8.4%(0.02)($0.81)1.9%(0.00)($0.90)
0.2%
0.20
$9.67
0.1%
0.16
$12.69
0.0%
0.09
$8.86
0.0%
0.28
$37.140.1%
0.12$22.84100.0%(0.02)($0.76)Frequency
7.3%
7.6%
32.1%
27.2%
22.4%
1.7%
0.5%
0.4%
0.2%
0.6%
100.0%

151 See PJM. “Manual 15: Cost Development Guidelines,” Rev. 37 (Dec. 9, 2020).

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-101 Average, real-time marginal unit markup index (By offer pricecategory adjusted): January through June, 2020 and 2021
Offer Price
Category< $10$10 to $15$15 to $20$20 to $25$25 to $50$50 to $75$75 to $100
$100 to $125
$125 to $150
$150 to $400
All Offers

2020 (Jan - Jun)
Average
Average
DollarMarkup Index
Markup0.03($0.66)
0.13
$1.56
0.10
$1.46
0.12
$2.54
0.25
$8.20
0.58
$34.240.71$62.920.79$89.930.39$49.81
0.58$97.560.11$1.792021 (Jan - Jun)
Average
Average
DollarFrequency Markup Index
Markup13.3%
0.08($7.28)45.0%
0.00($0.10)
30.9%
0.03
$0.44
8.4%
0.05
$1.06
1.9%
0.07
$1.72
0.2%
0.27
$13.520.1%
0.22$18.240.0%
0.17$17.440.0%
0.34$45.300.1%
0.20$36.14100.0%
0.05$1.15

Frequency
7.3%
7.6%
32.1%
27.2%
22.4%
1.7%
0.5%
0.4%
0.2%
0.6%
100.0%

Table 3-102 shows the percentage of marginal units that had markups,
calculated using unadjusted cost-based offers, below, above and equal tozero for coal, gas and oil fuel types.152 Table 3-103 shows the percentage ofmarginal units that had markups, calculated using adjusted cost-based offers,
below, above and equal to zero for coal, gas and oil fuel types. In the firstsix months of 2021, using unadjusted cost-based offers for coal units, 54.46
percent of marginal coal units had negative markups. In the first six monthsof 2021, using adjusted cost-based offers for coal units, 33.73 percent ofmarginal coal units had negative markups. The share of marginal gas units
with negative markups at the dispatch point on their offer curve increased
from 33.83 percent in the first six months of 2020 to 50.99 percent in the firstsix months of 2021 when using unadjusted cost based offers. Most marginal
combined cycle units had significant negative markups, particularly during
the periods of high natural gas prices in February 2021. Cost-based offers
for gas fired units are frequently based on the current spot price of fuelwhile price-based offers may reflect a range of factors including sellers’ fuelpurchase prices and power sales prices.

152 Other fuel types were excluded based on data confidentiality rules.

© 2021 Monitoring Analytics, LLC

Table 3-102 Percent of marginal units with markup below, above and equal tozero (By fuel type with unadjusted offers): January through June, 2020 and
2021
Type/Fuel
Coal
Gas
Oil

Negative58.86%
33.83%
0.00%

2020 (Jan - Jun)
Zero
23.67%
3.90%
100.00%

Positive17.47%
62.27%
0.00%

Negative54.46%
50.99%
12.66%

2021 (Jan - Jun)
Zero
22.80%
16.50%
83.55%

Positive22.74%
32.51%
3.79%

Table 3-103 Percent of marginal units with markup below, above and equal
to zero (By fuel type with adjusted offers): January through June, 2020 and
2021
Type/Fuel
Coal
Gas
Oil

Negative36.32%
20.88%
0.00%

2020 (Jan - Jun)
Zero
17.42%
2.71%
84.62%

Positive46.26%
76.41%
15.38%

Negative33.73%
31.70%
2.48%

2021 (Jan - Jun)
Zero
13.52%
6.47%
81.20%

Positive52.75%
61.84%
16.32%

Figure 3-56 shows the frequency distribution of hourly markups for all gas
units offered in the first six months of 2020 and the first six months of2021 using unadjusted cost-based offers. The highest markup within theeconomic operating range of the unit’s offer curve was used in the frequency
distributions.153 Of the gas units offered in the PJM market in the first six
months of 2021, 17.8 percent of gas unit hours had a maximum markup thatwas negative and 11.5 percent of gas fired unit hours had a maximum markup
above $100 per MWh. The share of offered gas units with maximum markup
that was negative decreased in the first six months of 2021 compared to thefirst six months of 2020 while the share of marginal gas units with negative
markups increased.

153 The categories in the frequency distribution were chosen so as to maintain data confidentiality.

2021 Quarterly State of the Market Report for PJM: January through June 221

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-56 Frequency distribution of highest markup of gas units offeredusing unadjusted cost offers: January through June, 2020 and 2021

Figure 3-57 Frequency distribution of highest markup of coal units offeredusing unadjusted cost offers: January through June, 2020 and 2021
60%

35%
2020

30%

2021

2020

$200 - $1000$100 - $200

$75 - $100

$50 - $75

$25 - $50

$20 - $25

$15 - $20

$10 - $15

$5 - $10

0%$0 - $50%$(25) - $0

10%<$(25)

5%

Markup Range ($/MWh)Figure 3-57 shows the frequency distribution of hourly markups for all coal
units offered in the first six months of 2020 and the first six months of2021 using unadjusted cost-based offers. Of the coal units offered in the PJM
market in the first six months of 2021, 38.9 percent of coal unit hours had amaximum markup that was negative or equal to zero, decreasing from 48.4 in
the first six months of 2020. The share of offered coal units with maximum
markup that was negative and the share of marginal coal units with negative
markups decreased in the first six months of 2021 compared to the first six
months of 2020.

Section 3 Energy Market$25 - $1000

20%$10 - $25

10%

30%

$5 - $10

15%$0 - $5

20%

40%

<= $0

Percent of Unit Hours

Percent of Unit Hours

25%

222

2021

50%

Markup Range ($/MWh)Figure 3-58 shows the frequency distribution of hourly markups for all offered
oil units in the first six months of 2020 and the first six months of 2021 using
unadjusted cost-based offers. Of the oil units offered in the PJM market in
the first six months of 2021, 42.1 percent of oil unit hours had a maximum
markup that was negative or equal to zero. More than 7.0 percent of oil fired
unit hours had a maximum markup above $100 per MWh.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Figure 3-58 Frequency distribution of highest markup of oil units offeredusing unadjusted cost offers: January through June, 2020 and 2021
45%
40%

2020

2021

Figure 3-59 Cumulative number of unit intervals with markups above $150
per MWh: January through June, 2020 and 2021

30%

100

25%
20%
15%
10%

$20 - $100

$100 - $1,000

Markup Range ($/MWh)$15 - $20

$5 - $15$0 - $5

0%

<= $0

5%

The markup frequency distributions show that a significant proportion ofunits make price-based offers less than the cost-based offers permitted under
the PJM market rules. This behavior means that competitive price-based
offers reveal actual unit marginal costs and that PJM market rules permit theinclusion of costs in cost-based offers that are not short run marginal costs.
The markup behavior shown in the markup frequency distributions also showsthat a substantial number of units were offered with high markups, consistent
with the exercise of market power.
Figure 3-59 shows the number of marginal unit intervals in the first six
months of 2021 and 2020 with markup above $150 per MWh. For severalof the marginal unit intervals with markups above $150 per MWh, the units
failed the TPS test for the hour. These exercises of market power are a result© 2021 Monitoring Analytics, LLC

Number of Unit Intervals with Markup Above $150/MWh

Percent of Unit Hours

35%

of PJM’s failure to address the issues with the offer capping process identified
by the MMU. If PJM adopted the MMU’s recommendations, these exercises ofmarket power would not occur.

80

60

40

20

0

Jan

Feb

Mar

Apr

May

2020 Adjusted

Jun

Jul

Day

2020 Unadjusted

Aug

Sep

2021 Adjusted

Oct

Nov

Dec

2021 Unadjusted

Day-Ahead Markup Index
Table 3-104 shows the average markup index of marginal generating units inthe day-ahead energy market, by offer price category using unadjusted costbased offers. The majority of marginal units are virtual transactions, which do
not have markup. The average dollar markups of units with offer prices lessthan $10 was negative (-$0.91 per MWh) when using unadjusted cost-based
offers. The average dollar markups of units with offer prices between $10 and$15 was negative (-$0.49 per MWh) when using unadjusted cost-based offers.

2021 Quarterly State of the Market Report for PJM: January through June 223

2021 Quarterly State of the Market Report for PJM: January through June

Some marginal units did have substantial markups. Among the units thatwere marginal in the day-ahead market in January through June, 2021, none
had offer prices above $400 per MWh. Using the unadjusted cost-based offers,
the highest markup for any marginal unit in the day-ahead market in the firstsix months of 2021 was more than $120 per MWh while the highest markup
in the first six months of 2020 was less than $80 per MWh.
Table 3-104 Average day-ahead marginal unit markup index (By offer pricecategory, unadjusted): January through June, 2020 and 2021
Offer Price
Category< $10$10 to $15$15 to $20$20 to $25$25 to $50$50 to $75$75 to $100
$100 to $125
$125 to $150>= $150
All Offers

2020 (Jan - Jun)
Average
Average
DollarMarkup Index
Markup0.01($0.71)
0.09
$0.96
0.15
$2.03
0.01
($0.28)
0.03
$0.57
0.00
$0.00
0.51
$47.56(0.05)($6.24)
0.00
$0.00
0.15
$25.350.10$1.122021 (Jan - Jun)
Average
Average
DollarFrequency Markup Index
Markup8.7%
0.17($0.91)36.8%(0.01)($0.49)
41.1%
0.07
$0.94
11.2%
(0.00)($0.35)
2.2%
0.03
$0.28
0.0%
0.08
($20.89)0.0%
0.24$21.260.0%
0.13$10.230.1%
0.10$11.98
0.0%
0.03
$4.94
100.0%
0.04($0.19)Frequency
6.4%
3.4%
25.7%
31.9%
28.9%
2.4%
0.5%
0.4%
0.2%
0.2%
100.0%

Table 3-105 shows the average markup index of marginal generating units
in the day-ahead energy market, by offer price category using adjusted
cost-based offers. In the first six months of 2021, 25.7 percent of marginal
generating units had offers between $15 and $20 per MWh, and the average
dollar markup and the average markup index were both positive. The averagemarkup index increased from 0.08 in the first six months of 2020, to 0.22 in
the first six months of 2021 in the offer price category less than $10.

224

Section 3 Energy Market

Table 3-105 Average day-ahead marginal unit markup index (By offer pricecategory, adjusted): January through June, 2020 and 2021
Offer Price
Category< $10$10 to $15$15 to $20$20 to $25$25 to $50$50 to $75$75 to $100
$100 to $125
$125 to $150>= $150
All Offers

2020 (Jan - Jun)
Average
Average
DollarMarkup Index
Markup0.08($0.26)
0.16
$2.05
0.22
$3.41
0.09
$1.72
0.11
$3.09
0.00
$0.00
0.52
$48.18
0.04
$5.11
0.09
$12.160.15$25.350.17$2.422021 (Jan - Jun)
Average
Average
DollarFrequency Markup Index
Markup8.7%
0.22($0.68)
36.8%
0.06
$0.65
41.1%
0.15
$2.46
11.2%
0.08
$1.70
2.2%
0.11
$3.09
0.0%
0.15
($13.83)
0.0%
0.30$26.490.0%
0.19$18.500.1%
0.14$18.090.0%
0.11$17.76100.0%
0.12$1.99

Frequency
6.4%
3.4%
25.7%
31.9%
28.9%
2.4%
0.5%
0.4%
0.2%
0.2%
100.0%No Load and Start Cost Markup
Generator energy offers in PJM are comprised of three parts, an incremental
energy offer curve, no load cost and start cost. In cost-based offers, all threeparts are capped at the level allowed by Schedule 2 of the Operating Agreement,
the Cost Development Guidelines (Manual 15) and fuel cost policies approved
by PJM. In price-based offers, the incremental energy offer curve is cappedat $1,000 per MWh (unless the verified cost-based offer exceeds $1,000 per
MWh, but cannot exceed $2,000 per MWh). Generators are allowed to choose
whether to use price-based or cost-based no load cost and start costs twice ayear. If price-based is selected, the no load and start costs do not have a cap,
but the offers cannot be changed for six months (April through September
and October through March). If cost-based is selected, the cap is the same as
the cap of the no load and start costs in the cost-based offers, and the offers
can be updated daily or hourly. Table 3-106 shows the caps on the three partsof cost-based and price-based offers.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-106 Cost-based and price-based offer caps
Offer Type
Cost-Based

Price-Based

No Load andStart Cost
OptionIncremental Offer Curve Cap
No Load Cost Cap
Start Cost Cap
Cost-Based Based on OA Schedule 2, Cost Development Guidelines (Manual 15) and Fuel Cost Policies
Based on OA
Based on OA
Schedule 2, Cost
Schedule 2, Cost
Development
Development$1,000/MWh or based on OA Schedule 2,
Cost-Based
Guidelines (Manual Guidelines (Manual
Cost Development Guidelines (Manual 15)15) and Fuel Costand Fuel Cost Policies if verified cost-based 15) and Fuel Cost
Policies.
offer exceeds $1,000/MWh but no more than Policies.
$2,000/MWh.
No cap but can only No cap but can only
Price-Basedbe changed twice
be changed twicea year.
a year.

Table 3-107 shows the number of units that chose the cost-based option andthe price-based option. In the first six months of 2021, 92 percent of all
generators that submitted no load or start costs chose to have cost-based noload and start costs in their price-based offers, two percentage points higher
than in the first six months of 2020.
Table 3-107 Number of units selecting cost-based and price-based no loadand start costs: January through June, 2020 and 2021
No Load and Start
Cost Option
Cost-Based
Price-Based
Total

2020
Number of
units
539
58
597

Percent
90%
10%
100%

2021
Number of
units
522
45
567

Percent
92%
8%
100%

Generators can have positive or negative markups in their no load and start
costs under the price-based option. Generators cannot have positive markups
in no load and start costs when they select the cost-based option. Table 3-108
shows the average markup in the no load and start costs in the first six
months of 2020 and 2021. Generators that selected the cost-based start andno load option offered on average with a negative markup on the no load costand a negative markup on the start costs. The price-based offers were actually
lower than the cost-based offers. Generators that selected the price-based start© 2021 Monitoring Analytics, LLC

and no load option offered on average with a negative markup on the no load
cost but with very large positive markups on the start costs.
Table 3-108 No load and start cost markup: January through June, 2020 and
2021
Period
2020
2021

No Load and Start
Cost Option
Cost-Based
Price-Based
Cost-Based
Price-Based

No Load Cost Cold Start Cost
(9%)
(7%)
(5%)
546%
(8%)
(8%)
(59%)
373%

Intermediate
Start Cost
(6%)
669%
(9%)
429%

Hot Start Cost
(6%)
703%
(9%)
530%

Energy Market Cost-Based Offers
The application of market power mitigation rules in the day-ahead energy
market and the real-time energy market helps ensure competitive market
outcomes even in the presence of structural market power.
Cost-based offers in PJM affect all aspects of the PJM energy market. Costbased offers affect prices when units are committed and dispatched on theircost-based offers. In the first six months of 2021, 7.3 percent of the marginalunits set prices based on cost-based offers, 0.6 percentage points higher thanin the first six months of 2020.
The efficacy of market power mitigation rules depends on the definition of acompetitive offer. A competitive offer is equal to short run marginal costs. The
enforcement of market power mitigation rules is undermined if the definitionof a competitive offer is not correct. The significance of competition metrics
like markup is also undermined if the definition of a competitive offer is notcorrect. The definition of a competitive offer in the PJM market rules is notcorrect. Some unit owners include costs that are not short run marginal costs
in offers, including maintenance costs. This issue can be resolved by simple
changes to the PJM market rules to incorporate a clear and accurate definitionof short run marginal costs.
The efficacy of market power mitigation rules also depends on the accuracyof cost-based offers. Some unit owners use fuel cost policies that are not2021 Quarterly State of the Market Report for PJM: January through June 225

2021 Quarterly State of the Market Report for PJM: January through Junealgorithmic, verifiable, and systematic. These inadequate fuel cost policies
permit overstated fuel costs in cost-based offers. FERC’s decision to permit
maintenance costs in cost-based offers that are not short run marginal costs
also results in overstated cost-based offers.
When market power mitigation is not effective due to inaccurate cost-based
offers that exceed short run marginal costs, market power causes increases inmarket prices above the competitive level.

Short Run Marginal Costs
Short run marginal costs are the only costs relevant to competitive offers in theenergy market. Specifically, the competitive energy offer level is the short run
marginal cost of production. The current PJM market rules distinguish costs
includable in cost-based energy offers from costs includable in cost-based
capacity market offers based on whether costs are directly related to energy
production. The rules do not provide a clear standard. Energy production is thesole purpose of a power plant. Therefore, all costs, including the sunk costs,
are directly related to energy production. This current ambiguous criterion isincorrect and, in addition, allows for multiple interpretations, which could
lead to tariff violations. The incorrect rules will lead to higher energy market
prices and higher uplift.
There are three types of costs identified under PJM rules as of April 15, 2019:variable costs, avoidable costs, and fixed costs. The criterion for whether agenerator may include a cost in an energy market cost-based offer, a variable
cost, is that the cost is “directly related to electric production.”154
Variable costs are comprised of short run marginal costs and avoidable costs
that are directly related to electric production. Short run marginal costs are
the cost of inputs consumed or converted to produce energy, and the costs
associated with byproducts that result from consuming or converting materials
to produce energy, net of any revenues from the sale of those byproducts. The
categories of short run marginal costs are fuel costs, emission allowance costs,
operating costs, and energy market opportunity costs.155

Avoidable costs are annual costs that would be avoided if energy were notproduced over an annual period. The PJM rules divide avoidable costs into
those that are directly related to electric production and those not directly
related to electric production. The distinction is ambiguous at best. PJM
includes overhaul and maintenance costs, replacement of obsolete equipment,
and overtime staffing costs in costs related to electric production. PJM includes
taxes, preventative maintenance to auxiliary equipment, improvement ofworking equipment, maintenance expenses triggered by a time milestone(e.g. annual, weekly) and pipeline reservation charges in costs not related toelectric production.
Fixed costs are costs associated with an investment in a facility including thereturn on and of capital.
The MMU recommends that PJM require that the level of costs includable incost-based offers not exceed the unit’s short run marginal cost.

Fuel Cost Policies
Fuel cost policies (FCP) document the process by which market sellers calculate
the fuel cost component of their cost-based offers. Short run marginal fuelcosts include commodity costs, transportation costs, fees, and taxes for thepurchase of fuel.

Fuel Cost Policy Review
Table 3-109 shows the status of all fuel cost policies (FCP) as of June 30,
2021. As of June 30, 2021, 735 units (87 percent) had an FCP passed by the
MMU, zero units had an FCP under MMU review (submitted) and 110 units (13percent) had an FCP failed by the MMU. The units with fuel cost policies failed
by the MMU represented 23,163 MW. All units’ FCPs were approved by PJM.
The number of units with fuel cost policies passed by the MMU decreased by
38 on June 30, 2021 compared to December 31, 2020, mostly from units thatoffer zero that are no longer required to have Fuel Cost Policies. As of June 30,
2021, 469 units did not have FCPs approved by PJM. Units without approved
FCPs cannot submit nonzero cost based offers.

154 See 167 FERC ¶ 61,030 (2019).
155 See OA Schedule 2(a).

226

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-109 FCP Status for PJM generating units: June 30, 2021
PJM Status
Submitted
Under Review
Customer Input Required
Approved
Total

Pass
0
0
0
735
735

MMU Status
Submitted
0
0
0
0
0

Fail
0
0
0
110
110

Total
0
0
0
845
845

The MMU performed a detailed review of every FCP. PJM approved the FCPs
that the MMU passed. PJM approved every FCP failed by the MMU.
The standards for the MMU’s market power evaluation are that FCPs be
algorithmic, verifiable and systematic, accurately reflecting the short run
marginal cost of producing energy. In its filings with FERC, PJM agreed
with the MMU that FCPs should be verifiable and systematic.156 Verifiablemeans that the FCP requires a market seller to provide a fuel price that canbe calculated by the MMU after the fact with the same data available to themarket seller at the time the decision was made, and documentation for thatdata from a public or a private source. Systematic means that the FCP must
document a clearly defined quantitative method or methods for calculating
fuel costs, including objective triggers for each method.157 PJM and FERC
did not agree that fuel cost policies should be algorithmic, although PJM’sstandard effectively requires algorithmic fuel cost policies by describing therequirements.158 Algorithmic means that the FCP must use a set of defined,
logical steps, analogous to a recipe, to calculate the fuel costs. These steps may
be as simple as a single number from a contract, a simple average of broker
quotes, a simple average of bilateral offers, or the weighted average index
price posted on the Intercontinental Exchange trading platform (‘ICE’).159
FCPs are not verifiable and systematic if they are not algorithmic. The natural
gas FCPs failed by the MMU and approved by PJM are not verifiable andsystematic.
156 Answer of PJM Interconnection, L.L.C. to Protests and Comments, Docket No. ER16-372-002 (October 7, 2016) at P 11 (“October 7th
Filing”).
157 Protest of the Independent Market Monitor for PJM, Docket No. ER16-372-002 (September 16, 2016) at P 8 (“September 16th Filing”).
158 October 7th Filing at P12; 158 FERC ¶ 61,133 at P 57 (2017).
159 September 16th Filing at P 8.

© 2021 Monitoring Analytics, LLC

Not all FCPs approved by PJM met the standard of the PJM tariff. The tariffstandards that some fuel cost policies did not meet are:160 accuracy (reflectapplicable costs accurately); and fuel contracts (reflect the market seller’sapplicable commodity and/or transportation contracts where it holds suchcontracts).
The MMU failed FCPs not related to natural gas submitted by some market
sellers because they do not accurately describe the short run marginal cost of
fuel. Some policies include contractual terms (in dollars per MWh or in dollars
per MMBtu) that do not reflect the actual cost of fuel. The MMU determinedthat the terms used in these policies do not reflect the cost of fuel based on
the information provided by the market sellers and information gathered by
the MMU for similar units.
The MMU failed the remaining FCPs because they do not accurately reflect thecost of natural gas. The main issues identified by the MMU in the natural gas
policies were the use of unverifiable fuel costs and the use of available market
information that results in inaccurate expected costs.
Some of the failed fuel cost polices include unverifiable cost estimates.
Some policies include options under which the estimate of the natural gas
commodity cost can be calculated by the market seller without specifying
a verifiable, systematic method. For example, some FCPs specify thatthe source of the natural gas cost would be communications with traders
within the market seller’s organization. A fuel cost from discretionary andundocumented decision making within the market seller’s organization is notverifiable. The point of FCPs is to eliminate such practices as the basis forfuel costs, as most companies have done. Verifiability requires that fuel costestimates be transparently derived from market information and that PJM
or the MMU could reproduce the same fuel cost estimates after the fact byapplying the methods documented in the FCP to the same inputs. Verifiable
is a key requirement of an FCP. If it is not verifiable, an FCP is meaninglessand has no value. Unverifiable fuel costs permit the exercise of market power.

160 See PJM Operating Agreement Schedule 2 § 2.3 (a).

2021 Quarterly State of the Market Report for PJM: January through June 227

2021 Quarterly State of the Market Report for PJM: January through June

Some of the failed fuel cost polices include the use of available market
information that results in inaccurate expected costs because the information
does not represent a cleared market price. Some market sellers include the useof offers to sell natural gas on ICE as the sole basis for the cost of natural gas.
An offer to sell is generally not a market clearing price and is not an accurate
indication of the expected fuel cost. The price of uncleared offers on theexchange generally exceeds the price of cleared transactions, often by a wide
margin. Use of sell offers alone is equivalent to using the supply curve alone
to determine the market price of a good without considering the demand
curve. It is clearly incorrect.
The FCPs that failed the MMU’s evaluation also fail to meet the standards
defined in the PJM tariff. PJM should not have approved noncompliant fuelcost policies. The MMU recommends that PJM require that all fuel cost policies
be algorithmic, verifiable, and systematic.

Cost-Based Offer Penalties
Market Sellers are assessed penalties when they submit cost-based offers that
do not comply with Schedule 2 of the PJM Operating Agreement and PJM
Manual 15.161 Penalties are assessed when both PJM and the MMU are inagreement.
In the first six months of 2021, 103 penalty cases were identified, 61 resulted
in assessed cost-based offer penalties, five resulted in disagreement between
the MMU and PJM, and 37 remain pending PJM’s determination. The five
disagreements in 2021 between the MMU and PJM are related to calculationof fuel costs during pipeline constrained situations. These cases were for 102
units owned by 16 different companies. Table 3-111 shows the penalties by theyear in which participants were notified.

161 See OA Schedule 2 § 6.

228

Section 3 Energy Market

Table 3-110 Cost-based offer penalty cases by year notified: May 2017
through June 2021
Year
notified
2017
2018
2019
2020
2021
Total

Assessed MMU and PJM
Cases penalties Disagreement
57
56
1
187
161
26
57
57
0
142
136
5
103
61
5
546
471
37

Pending
Number ofcases units impacted
0
55
0
138
0
57
1
124
37
102
38
385

Number ofcompanies impacted
16
35
19
25
16
58

Since 2017, 546 penalty cases have been identified, 471 resulted in assessedcost-based offer penalties, 37 resulted in disagreement between the MMU and
PJM, and 38 remain pending PJM’s determination. The 471 cases were from
385 units owned by 58 different companies. The total penalties were $4.6
million, charged to units that totaled 155,899 available MW. The average
penalty was $1.32 per available MW. This means that a 100 MW unit would
have paid a penalty of $3,167.162 Table 3-111 shows the total cost-based offer
penalties since 2017 by year.
Table 3-111 Cost-based offer penalties by year: May 2017 through June 2021
Year
2017
2018
2019
2020
2021
Total

Number of
units
92
127
79
229
78
605

Number ofcompanies
20
34
20
29
13
58

Penalties$556,826$1,265,698$490,926$1,625,915$708,062$4,647,427

Average Available
Capacity Charged(MW)
16,93026,343
19,79872,777
20,051
155,899

Average Penalty($/MW)
$1.56
$2.27
$1.10
$0.96
$1.53
$1.32

The incorrect cost-based offers resulted from incorrect application of Fuel
Cost Policies, lack of approved fuel cost policies, fuel cost policy violations,miscalculation of no load costs, inclusion of prohibited maintenance costs,
use of incorrect incremental heat rates, use of incorrect start cost, and use ofincorrect emission costs.
162 Cost-based offer penalties are assessed by hour. Therefore, a $1 per available MW penalty results in a total of $24 for a 1 MW unit if theviolation is for the entire day.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

2020 Fuel Cost Policy Changes
On July 28, 2020, the Commission approved tariff revisions that modified thefuel cost policy process and the cost-based offer penalties.163
The tariff revisions replaced the annual review process with a periodic review
set by PJM. The revisions reinstated the periodic review process employed by
the MMU prior to PJM’s involvement in the review and approval of fuel cost
policies. Monitoring participant behavior through the use of fuel cost policies
is an ongoing process that necessitates frequent updates. Market sellers must
revise their fuel cost policies whenever circumstances change that impact fuelpricing (e.g. different pricing points, dual fuel addition capability).
The tariff revisions removed the requirement for units with zero marginal
cost to have an approved fuel cost policy but also included a zero offer cap
for cost-based offers for units that do not have an approved fuel cost policy.
The tariff revisions allow a temporary cost offer method for units that do
not have an approved fuel cost policy. The revisions allow units to submit
nonzero cost-based offers without an approved fuel cost policy if they follow
the temporary cost offer method. The use of the method results in cost-based
offers that do not follow the fuel cost policy rules. The approach significantly
weakens market power mitigation by allowing market sellers to make offers
without an approved fuel cost policy. The proposed approach allows the useof an inaccurate and unsupported fuel cost calculation in place of an accurate
fuel cost policy.
The MMU recommends that the temporary cost method be removed andthat all units that submit nonzero cost-based offers be required to have anapproved fuel cost policy.
The tariff revisions replace the fuel cost policy revocation provision with theability for PJM to terminate fuel cost policies.
The tariff revisions reduce the penalties for noncompliant cost-based offersin two situations. When market sellers report their noncompliant cost-based
163 172 FERC ¶ 61,094.

© 2021 Monitoring Analytics, LLC

offers, the penalty is reduced by 75 percent. When market sellers do not meet
conditions defined to measure a potential market impact the penalty is reducedby 90 percent. The conditions include if the market seller failed the TPS test,
if the unit was committed on its cost-based offer, if the unit was marginal orif the unit was paid uplift.
The tariff revisions eliminate penalties entirely when units submit
noncompliant cost-based offers if PJM determines that an unforeseen event
hindered the market seller’s ability to submit a compliant cost-based offer.
This new provision allows market sellers to not follow their fuel cost policy,
submit cost-based offers that are not verifiable or systematic and not face any
penalties for doing so.
The MMU recommends that the penalty exemption provision be removed andthat all units that submit nonzero cost-based offers be required to follow theirapproved fuel cost policy.

Cost Development Guidelines
The Cost Development Guidelines contained in PJM Manual 15 do not
clearly or accurately describe the short run marginal cost of generation. The
MMU recommends that PJM Manual 15 be replaced with a straightforward
description of the components of cost-based offers based on short run
marginal costs and the correct calculation of cost-based offers.

Variable Operating and Maintenance Costs
PJM Manual 15 and the PJM Operating Agreement Schedule 2 include rules
related to VOM costs. On October 29, 2018, PJM filed tariff revisions changing
the rules related to VOM costs.164 The changes proposed by PJM attempted but
failed to clarify the rules. The proposed rules defined all costs directly related
to electricity production as includable in cost-based offers. This also included
the long term maintenance costs of combined cycles and combustion turbines,
which had been explicitly excluded in PJM Manual 15.

164 See PJM Interconnection Maintenance Adder Revisions to the Amended and Restated Operating Agreement, L.L.C., Docket No. EL19-8000.

2021 Quarterly State of the Market Report for PJM: January through June 229

2021 Quarterly State of the Market Report for PJM: January through June

On April 15, 2019, FERC accepted PJM’s filing order, subject to revisions
requested by FERC.165 On October 28, 2019, FERC issued a final order accepting
PJM’s compliance filing.166 Regardless of the changes, the rules remain unclear
and are now inconsistent with economic theory and effective market power
mitigation and competitive market results.
Maintenance costs are not short run marginal costs. Generators perform
maintenance during outages. Generators do not perform maintenance in the
short run, while operating the generating unit. Generators do not perform
maintenance in real time to increase the output of a unit. Some maintenancecosts are correlated with the historic operation of a generator. Correlation
between operating hours or starts and maintenance expenditures over a longrun, multiyear time frame does not indicate the necessity of any specificmaintenance expenditure to produce power in the short run.
A generating unit does not consume a defined amount of maintenance partsand labor in order to start. A generating unit does not consume a defined
amount of maintenance parts and labor in order to produce an additional
MWh. Maintenance events do not occur in the short run. The company cannot
optimize its maintenance costs in the short run.
PJM allows for the calculation of VOM costs in dollars per MWh, dollars per
MMBtu, dollars per run hour, dollars per equivalent operating hour (EOH)
and dollars per start. The MMU converted all VOM costs into dollars per
MWh using the units’ heat rates, the average economic maximum and averageminimum run time of the units in 2020.
The average variable operating and maintenance cost approved by PJM for
combustion turbines and diesels for 2020 was 16 percent lower than theapproved variable operating and maintenance cost approved by PJM in
2019.167165 167 FERC ¶ 61,030.
166 168 FERC ¶ 61,134.
167 PJM reviews VOM once per year. The results reflect PJM’s most recent review.

230

Section 3 Energy Market

The average variable operating and maintenance cost approved by PJM for
combined cycles for 2020 was seven percent higher than the approved variable
operating and maintenance cost approved by PJM in 2019.
The average variable operating and maintenance cost approved by PJM forcoal units for 2020 was 8 percent lower than the approved variable operating
and maintenance cost approved by PJM in 2019.
Table 3-112 shows the amount of capacity offered within several ranges of
VOM costs. Table 3-112 shows that 1,000 MW have an approved effective
VOM above $100 per MWh and 3,146 MW have an approved effective VOM
between $50 and $100 per MWh.
Table 3-112 2019/2020 and 2020/2021 Approved Effective VOM Costs
Approved VOM Range ($/MWh)$0 to $5 per MWh$5 to $10 per MWh$10 to $20 per MWh$20 to $50 per MWh$50 to $100 per MWh
Above $100 per MWh

Offered MW
2019/2020
69,02537,325
14,276
5,402
2,302
1,159

2020/2021
71,89830,325
15,931
4,938
3,146
1,044

High VOM levels allow generators to economically withhold energy and to
exercise market power even when offers are capped at the cost-based offer tomitigate market power. The MMU recommendation to limit cost-based offers
to short run marginal costs would prevent such withholding. When units are
not committed due to high VOM costs and instead a unit with higher short run
marginal costs is committed, the market outcome is inefficient. When units
that fail the TPS test are committed on their price-based offer when their short
run marginal cost is lower, the market outcome is inefficient.
MMU analysis shows that as CTs, CCs and coal units run for more hours, theVOM cost approved by PJM decreases. This is an indication that fixed costs
are included in VOM costs. Fuel costs per MWh remain constant or increase
as run hours and the heat rate increase. Fixed costs should not be includable
in cost-based energy offers.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

The level of costs accepted by PJM for inclusion in VOM depends on PJM’s
interpretation of the maintenance activities or expenses directly related toelectricity production and the level of detailed support provided by market
sellers to PJM.
PJM’s VOM review is not adequate to determine whether all costs includedin VOM are compliant. PJM’s VOM review focuses only on the expenses
submitted for the last year of up to 20 years of data and PJM’s review isdependent on the level of detail provided by the market seller. Recent changes
in PJM’s review process, triggered by MMU questions, required more details
from market sellers and have led to the appropriate exclusion of expenses thatwere previously included.168
The flaws in PJM’s review process for VOM are compounded by the ambiguityin the criteria used to determine if costs are includable. PJM’s definition ofallowable costs for cost-based offers, “costs resulting from electric production,”
is so broad as to be meaningless. Most costs incurred at a generating station
result from electric production in one way or another. The generator itself
would not exist but for the need for electric production. PJM’s broad definition
cannot identify which costs associated with electric production are includable
in cost-based offers. The definition is not verifiable or systematic and permits
wide discretion by PJM and generators.
The MMU recommends that market participants be required to document theamount and cost of consumables used when operating in order to verify thatthe total operating cost is consistent with the total quantity used and the unitcharacteristics.
The MMU recommends, given that maintenance costs are currently allowedin cost-based offers, that market participants be permitted to include only
variable maintenance costs, linked to verifiable operational events and thatcan be supported by clear and unambiguous documentation of operational
data (e.g. run hours, MWh, MMBtu) that support the maintenance cycle of theequipment being serviced/replaced.
168 See “Maintenance Adder & Operating Cost Submission Process,” 55-57 PJM presentation to the Tech Change Forum. (April 21, 2020)<https://pjm.com/-/media/committees-groups/forums/tech-change/2020/20200421-special/20200421-item-01-maintenance-adderand-operating-cost-submission-process.ashx>.

© 2021 Monitoring Analytics, LLC

The MMU understands that companies have different document retention
policies but in order to be allowed to include maintenance costs, suchcosts must be verified, and they cannot be verified without documentation.
Supporting documentation includes internal financial records, maintenanceproject documents, invoices, and contracts. Market participants should be
required to provide the operational data (e.g. run hours, MWh, MMBtu) that
supports the maintenance cycle of the equipment being serviced/replaced.
For example, if equipment is serviced every 5,000 run hours, the market
participant must include at least 5,000 run hours of historical operation in its
maintenance cost history.

FERC System of Accounts
PJM Manual 15 relies on the FERC System of Accounts, which predates
markets and does not define costs consistent with market economics.
Market sellers should not rely solely on the FERC System of Accounts forthe calculation of their variable operating and maintenance costs. The FERC
System of Accounts does not differentiate between short run marginal costs
and avoidable costs. The FERC System of Accounts does not differentiate
between costs directly related to energy production and costs not directly
related to energy production. Reliance on the FERC System of Accounts forthe calculation of variable operating and maintenance costs is likely to leadto incorrect, overstated costs.
The MMU recommends removal of all references to and reliance on the FERC
System of Accounts in PJM Manual 15.

Cyclic Starting and Peaking Factors
The use of cyclic starting and peaking factors for calculating VOM costs for
combined cycles and combustion turbines is designed to allocate a greater
proportion of long term maintenance costs to starts and the tail block of theincremental offer curve. The use of such factors is not appropriate given thatlong term maintenance costs are not short run marginal costs and should not
be included in cost offers. PJM Manual 15 allows for a peaking cyclic factorof three, which means that a unit with a $300 per hour (EOH) VOM cost can
add $180 per MWh to a 5 MW peak segment.169
169 The peak adder is equal to $300 times three divided by 5 MW.

2021 Quarterly State of the Market Report for PJM: January through June 231

2021 Quarterly State of the Market Report for PJM: January through June

The MMU recommends the removal of all cyclic starting and peaking factors
from PJM Manual 15.

Labor Costs
PJM Manual 15 allows for the inclusion of plant staffing costs in energy
market cost offers. This is inappropriate given that labor costs are not short
run marginal costs.
The MMU recommends the removal of all labor costs from the PJM Manual 15.

Combined Cycle Start Heat Input Definition
PJM Manual 15 defines the start heat input of combined cycles as the amountof fuel used from the firing of the first combustion turbine to the close of thesteam turbine breaker plus any fuel used by other combustion turbines in the
combined cycle from firing to the point at which the HRSG steam pressure
matches the steam turbine steam pressure. This definition is inappropriate
given that after each combustion turbine is synchronized, some of the fuelis used to produce energy for which the unit is compensated in the energy
market. To account for this, PJM Manual 15 requires reducing the station
service MWh used during the start sequence by the output in MWh producedby each combustion turbine after synchronization and before the HRSG steampressure matches the steam turbine steam pressure. The formula and thelanguage in this definition are not appropriate and are unclear.
The MMU recommends changing the definition of the start heat input for
combined cycles to include only the amount of fuel used from firing each
combustion turbine in the combined cycle to the breaker close of each
combustion turbine. This change will make the treatment of combined cycles
consistent with steam turbines. Exceptions to this definition should be granted
when the amount of fuel used from synchronization to steam turbine breakerclose is greater than the no load heat plus the output during this period times
the incremental heat rate.

Nuclear Costs
The fuel costs for nuclear plants are fixed in the short run and amortized overthe period between refueling outages. The short run marginal cost of fuel for
nuclear plants is zero. Operations and maintenance costs for nuclear power
plants consist primarily of labor and maintenance costs incurred during
outages, which are also fixed in the short run.
The MMU recommends the removal of nuclear fuel and nonfuel operations
and maintenance costs that are not short run marginal costs from the PJM
Manual 15.

Pumped Hydro Costs
The calculation of pumped hydro costs for energy storage in Section 7.3 of
PJM Manual 15 is inaccurate. The mathematical formulation does not take
into account the purchase of power for pumping in the day-ahead market.
The MMU recommends revising the pumped hydro fuel cost calculation to
include day-ahead and real-time power purchases.

Frequently Mitigated Units (FMU) and Associated Units (AU)The rules for determining the qualification of a unit as an FMU or AU became
effective November 1, 2014. The number of units that were eligible for an
FMU or AU adder declined from an average of 70 units during the first 11
months of 2014, to zero units eligible for an FMU or AU adder for the period
between December 2014 and August 2019.170 One unit qualified for an FMU
adder for the months of September and October, 2019. In 2020, five units
qualified for an FMU adder in at least one month. In the first six months of2021, one unit qualified for an FMU adder in January.
Table 3-113 shows, by month, the number of FMUs and AUs from January
2020 through June 2021. For example, in September 2020, there was one FMU
and AU in Tier 1, zero FMUs and AUs in Tier 2, and two FMUs and AUs inTier 3.
170 F or a definition of FMUs and AUs, and for historical FMU/AU results, see the 2018 State of the Market Report for PJM, Volume 2, Section
3, Energy Market, at Frequently Mitigated Units (FMU) and Associated Units (AU).

232

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-113 Number of frequently mitigated units and associated units (By month): January 2020 through June 2021
2020

January
February
March
April
May
June
July
AugustSeptember
OctoberNovember
DecemberTier 1
0
0
0
0
0
2
2
1
1
2
2
2

Tier 2
0
0
0
0
0
0
0
0
0
0
1
1

Tier 3
0
0
0
0
0
0
0
0
2
2
2
2

2021
Total Eligible
for Any Adder
0
0
0
0
0
2
2
1
3
4
5
5

Tier 100
0
0
00Tier 2100
000Tier 3000
000

Total Eligible
for Any Adder
1
0
0
0
0
0

Effective in the 2020/2021 planning year, default Avoidable Cost Rates will no longer be defined in the tariff. If a generating unit’s Projected PJM Market
Revenues plus the unit’s PJM capacity market revenues on a rolling 12-month basis (in $/MW-year) are greater than zero, and if the generating unit does nothave an approved unit specific Avoidable Cost Rate, the generating unit will not qualify as an FMU as the Avoidable Cost Rate will be assumed to be zero for
FMU qualification purposes.
The MMU recommends the elimination of FMU and AU adders. FMU and AU adders no longer serve the purpose for which they were created and interfere withthe efficient operation of PJM markets.

Market Performance
Ownership of Marginal Resources
Table 3-114 shows the contribution to real-time, load-weighted LMP by individual marginal resource owners.171 The contribution of each marginal resource toprice at each load bus is calculated for each five-minute interval of the first six months of 2021, and summed by the parent company that offers the marginal
resource into the real-time energy market. In the first six months of 2021, the offers of one company resulted in 14.2 percent of the real-time, load-weighted
PJM system LMP and the offers of the top four companies resulted in 43.3 percent of the real-time, load-weighted, average PJM system LMP. In the first six
months of 2021, the offers of one company resulted in 13.4 percent of the peak hour real-time, load-weighted PJM system LMP.

171 See the MMU Technical Reference for PJM Markets, at “Calculation and Use of Generator Sensitivity/Unit Participation Factors.”© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 233

2021 Quarterly State of the Market Report for PJM: January through June

Table 3-114 Marginal unit contribution to real-time, load-weighted LMP (By parent company): January through June, 2020 and 2021
2020 (Jan - Jun)
All Hours
Percent of
Price
16.2%
12.4%
10.7%
7.8%
5.9%
5.6%
4.9%
4.5%
3.4%

Company
1
2
3
4
5
6
7
8
9
Other
(68 companies)

28.5%

2021 (Jan - Jun)

Peak Hours
Cumulative
Percent ofPercent Company
Price16.2% 1
17.3%
28.6% 2
14.8%
39.3% 3
10.2%
47.2% 4
7.4%
53.0% 55.6%
58.6% 64.8%
63.6% 74.6%
68.1% 83.6%
71.5% 92.8%
Other100.0%
28.8%(61 companies)

All Hours
Cumulative
Percent Company
17.3% 1
32.2% 2
42.4% 3
49.8% 4
55.4% 5
60.2% 6
64.8% 7
68.4% 871.2% 9Other
100.0%(71 companies)

Percent of
Price
14.2%
11.3%
9.6%
8.2%
7.3%
6.1%
4.5%
3.1%
3.1%
32.7%

Peak Hours
Cumulative
Percent ofPercent Company
Price14.2% 1
13.4%
25.4% 2
12.0%
35.1% 3
10.1%
43.3% 48.6%
50.6% 56.4%
56.6% 66.1%
61.1% 74.2%
64.2% 83.5%
67.3% 93.2%
Other
100.0%
32.6%(69 companies)

Cumulative
Percent
13.4%
25.4%
35.4%
44.0%
50.4%
56.5%
60.7%
64.2%
67.4%
100.0%

Figure 3-60 shows the marginal unit contribution to the real-time, load-weighted PJM system LMP summed by parent companies since 2012.
Figure 3-60 Marginal unit contribution to real-time, load-weighted LMP (By parent company): January through June, 2012 through 2021
90%
80%

Percent of Marginal Unit Contribution

70%
60%

50%
40%
30%
20%
10%

0%

234

2012

2013

2014

2015

2016

2017

2018

2019

1 Company

2 Companies

3 Companies

4 Companies

6 Companies

7 Companies

8 Companies

9 Companies

Section 3 Energy Market

2020

2021

5 Companies© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-115 shows the contribution to day-ahead, load-weighted LMP byindividual marginal resource owners.172 The contribution of each marginal
resource to price at each load bus is calculated hourly, and summed by theparent company that offers the marginal resource into the day-ahead energy
market. The results show that in the first six months of 2021, the offers of
one company contributed 6.6 percent of the day-ahead, load-weighted, PJM
system LMP and that the offers of the top four companies contributed 24.0
percent of the day-ahead, load-weighted, average, PJM system LMP.
Table 3-115 Marginal resource contribution to day-ahead, load-weighted
LMP (By parent company): January through June, 2020 and 2021
2020 (Jan - Jun)

Company
1
2
3
4
5
6
7
8
9
Other
(132 companies)

All Hours
Percent of
Price
13.3%
11.7%
10.5%
5.6%
4.9%
4.5%
4.1%
3.6%
3.2%
38.5%

Cumulative
Percent Company
13.3% 1
25.0% 2
35.5% 3
41.2% 4
46.1% 5
50.6% 6
54.7% 758.3% 8
61.5% 9Other
100.0%(126 companies)

Peak Hours
Percent of
Price
17.7%
13.7%
13.5%
5.3%
4.8%
4.2%
3.9%
3.4%
3.4%
30.0%

Cumulative
Percent Company
17.7% 1
31.4% 2
44.8% 3
50.2% 4
54.9% 559.2% 6
63.1% 7
66.5% 8
70.0% 9Other
100.0%(131 companies)

The MMU calculates an explicit measure of the impact of marginal unit
incremental energy offer markups on LMP using the mathematical relationships
among LMPs in the market solution.173 The markup impact calculation sums,
over all marginal units, the product of the dollar markup of the unit and themarginal impact of the unit’s offer on the system load-weighted LMP. The
markup impact includes the impact of the identified markup behavior of all
marginal units. Positive and negative markup impacts may offset one another.
The markup analysis is a
2021 (Jan - Jun)
direct measure of market
All Hours
Peak Hours
performance. It does not
Percent of Cumulative
Percent of Cumulative
take into account whether
Price
Percent Company
Price
Percent
6.6%
6.6% 1
6.8%
6.8%
or not marginal units
6.4%
13.0% 2
6.2%
12.9%
have either locational
5.5%
18.5% 3
5.3%
18.2%
5.5%
24.0% 4
5.0%
23.1%
or aggregate structural
5.3%
29.3% 54.8%
27.9%
market power.
5.1%
34.4% 64.0%
31.9%

Markup
The markup index is a measure of the competitiveness of participant behavior
for individual units. The markup in dollars is a measure of the impact ofparticipant behavior on the generator bus market price when a unit ismarginal. As an example, if unit A has a $90 cost and a $100 price, while
unit B has a $9 cost and a $10 price, both would show a markup index of 10
percent, but the price impact of unit A’s markup at the generator bus would be$10 while the price impact of unit B’s markup at the generator bus would be$1. Depending on each unit’s location on the transmission system, those bus
level impacts could also have different impacts on total system price. Markup
172 Id.

© 2021 Monitoring Analytics, LLC

can also affect prices when units with markups are not marginal by altering
the economic dispatch order of supply.

3.5%
3.1%
2.8%

37.9%
40.9%
43.7%

7
8
9
Other
100.0%(127 companies)

3.3%
3.1%
3.0%

35.2%
38.3%
41.3%

The markup calculation
is not based on a
56.3%
58.7%
100.0%
counterfactual redispatchof the system to determine
the marginal units and their marginal costs that would have occurred if allunits had made all offers at short run marginal cost. A full redispatch analysis
is practically impossible and a limited redispatch analysis would not be
dispositive. Nonetheless, such a hypothetical counterfactual analysis would
reveal the extent to which the actual system dispatch is less than competitive
if it showed a difference between dispatch based on short run marginal costand actual dispatch. It is possible that the unit specific markup, based on aredispatch analysis, would be lower than the markup component of priceif the reference point were an inframarginal unit with a lower price and a
173 The MMU calculates the impact on system prices of marginal unit price-cost markup, based on analysis using sensitivity factors. The
calculation shows the markup component of LMP based on a comparison between the price-based incremental energy offer and thecost-based incremental energy offer of each actual marginal unit on the system. This is the same method used to calculate the fuel costadjusted LMP and the components of LMP. The markup analysis does not include markup in start up or no load offers. See Calculationand Use of Generator Sensitivity/Unit Participation Factors, 2010 State of the Market Report for PJM: Technical Reference for PJM
Markets.

2021 Quarterly State of the Market Report for PJM: January through June 235

2021 Quarterly State of the Market Report for PJM: January through Junehigher cost than the actual marginal unit. If the actual marginal unit has
short run marginal costs that would cause it to be inframarginal, a new unit
would be marginal. If the offer of that new unit were greater than the cost of
the original marginal unit, the markup impact would be lower than the MMU
measure. If the newly marginal unit is on a price-based schedule, the analysis
would have to capture the markup impact of that unit as well.

Real-Time Markup
Markup Component of Real-Time Price by Fuel, Unit TypeThe markup component of price is the difference between the system price,when the system price is determined by the active offers of the marginal units,
whether price or cost-based, and the system price, based on the cost-based
offers of those marginal units.
Table 3-116 shows the impact (markup component of LMP) of the marginalunit markup behavior by fuel type and unit type on the real-time, loadweighted, average system LMP, using unadjusted and adjusted offers. The
adjusted markup component of LMP decreased from $1.93 per MWh in thefirst six months of 2020 to $1.91 per MWh in the first six months of 2021. The
adjusted markup contribution of coal units in the first six months of 2021 was$0.22 per MWh. The adjusted markup component of gas fired units in the firstsix months of 2021 was $1.81 per MWh, an increase of $0.08 per MWh fromthe first six months of 2020. The markup component of wind units was lessthan $0.0 per MWh. If a price-based offer is negative, but less negative than acost-based offer, the markup is positive. In the first six months of 2021, among
the wind units that were marginal, 87.1 percent had negative offer prices.

Table 3-116 Markup component of real-time, load-weighted, average LMP byprimary fuel type and unit type: January through June, 2020 and 2021174

Fuel
Coal
Gas
Gas
Gas
Gas
Landfill Gas
Municipal Waste
Oil
Oil
Oil
Oil
Other
Wind
Total

Technology
Steam
CC
CT
RICE
Steam
CT
RICE
CC
CT
RICE
Steam
Steam
Wind

2020 (Jan - Jun)
MarkupComponentMarkupof LMP
Component of(Unadjusted) LMP (Adjusted)($0.51)
$0.14
$0.82
$1.65
$0.10
$0.17
$0.05
$0.05
($0.10)($0.07)
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
($0.01)($0.01)($0.00)($0.00)($0.01)($0.01)
$0.34
$1.93

2021 (Jan - Jun)
MarkupComponentMarkupof LMP
Component of(Unadjusted) LMP (Adjusted)($0.28)
$0.22
$0.09
$1.32
$0.20
$0.45
$0.00
$0.01
($0.00)$0.03($0.00)($0.00)
$0.00
$0.00
$0.00
$0.01
($0.00)
$0.02
$0.00
$0.00
($0.03)($0.03)$0.00$0.00($0.11)($0.11)($0.13)$1.91

Markup Component of Real-Time Price
Table 3-117 shows the markup component, calculated using unadjusted offers,of average prices and of average monthly on peak and off peak prices. Table
3-118 shows the markup component, calculated using adjusted offers, of
average prices and of average monthly on peak and off peak prices. In thefirst six months of 2021, when using unadjusted cost-based offers, -$0.13 per
MWh of the PJM real-time, load-weighted, average LMP was attributable tomarkup. Using adjusted cost-based offers, $1.91 per MWh of the PJM realtime, load-weighted, average LMP was attributable to markup. In the firstsix months of 2021, the peak markup component was highest in June, $2.76
per MWh using unadjusted cost-based offers and peak markup component
was highest in June, $5.22 per MWh using adjusted cost-based offers. This
corresponds to 6.9 percent and 13.1 percent of the real-time, peak, loadweighted, average LMP in June.

174 The unit type RICE refers to Reciprocating Internal Combustion Engines.

236

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-117 Monthly markup components of real-time, load-weighted, LMP(Unadjusted): January 2020 through June, 2021
2020
Peak Markup
Component$0.94($0.00)
$0.46
$0.17
$1.03
$2.02
$1.75
$2.88
$0.97
$0.71
$0.72
$0.37
$1.08

Off PeakMarkupComponent$0.03($0.28)($0.66)($0.33)$0.10$0.30($0.30)$0.70($0.08)($0.57)($0.68)$0.37($0.10)MarkupComponent(All Hours)($0.45)($0.53)$0.02($1.85)($0.02)$1.75

Peak Markup
Component($0.30)$0.06$0.16($2.88)
$0.62
$2.76

Off PeakMarkupComponent($0.58)($1.12)($0.13)($0.71)($0.62)$0.58($0.13)$0.18($0.43)

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

© 2021 Monitoring Analytics, LLC

2021
Off PeakMarkupComponent
$1.60
$1.30
$0.81
$1.11
$1.39
$1.58
$1.33
$2.35
$1.22
$0.95
$0.88
$2.37
$1.44

350
2020 Markup Contribution to LMP (Unadjusted)2021 Markup Contribution to LMP (Unadjusted)

150

2020
Peak Markup
Component
$2.80
$1.85
$2.07
$1.73
$2.65
$3.75
$3.81
$4.83
$2.50
$2.51
$2.53
$2.56
$2.90

Figure 3-61 Markup contribution to real-time, hourly, load-weighted LMP(Unadjusted): 2020 through June 2021

250

Table 3-118 Monthly markup components of real-time, load-weighted, LMP(Adjusted): January 2020 through June, 2021
MarkupComponent(All Hours)
$2.21
$1.57
$1.44
$1.43
$1.98
$2.77
$2.70
$3.61
$1.89
$1.76
$1.68
$2.46
$2.19

Figure 3-61 shows the markup contribution to the hourly load-weighted, LMP
using unadjusted cost offers in 2020 and the first six months of 2021. Figure
3-62 shows the markup contribution to the hourly load-weighted, LMP using
adjusted cost-based offers in 2020 and the first six months of 2021.

MarkupComponent(All Hours)
$1.43
$2.41
$1.63
($0.35)
$1.93
$3.96

Peak Markup
Component
$1.73
$3.21
$1.85
($1.47)
$2.75
$5.22

Off PeakMarkupComponent
$1.17
$1.60
$1.39
$0.89
$1.17
$2.52

$1.91

$2.34

$1.47

Markup Contribution ($/MWh)

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

MarkupComponent(All Hours)$0.49($0.15)($0.09)($0.07)
$0.54
$1.24
$0.83
$1.80
$0.47
$0.09
($0.01)
$0.37
$0.50

2021

Hourly Markup Component of Real-Time Prices

50
-50
-150
-250
-350
-450
-550

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

2021 Quarterly State of the Market Report for PJM: January through June 237

2021 Quarterly State of the Market Report for PJM: January through June

Figure 3-62 Markup contribution to real-time, hourly, load-weighted, LMP(Adjusted): 2020 through June 2021

Table 3-119 Average, real-time, zonal markup component (Unadjusted):
January through June, 2020 and 2021

350

2020 (Jan - Jun)
2020 Markup Contribution to LMP (Adjusted)

250

2021 Markup Contribution to LMP (Adjusted)

Markup Contribution ($/MWh)

150
50
-50
-150
-250

-350
-450
-550

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC

MarkupComponent(All Hours)
$0.29
$0.35
$0.40
$0.41
$0.59
$0.28
$0.41
$0.38
$0.22
$0.38
$0.48
$0.33
$0.28
$0.25
$0.17
$0.32
$0.23
$0.48
$0.23
$0.25
$0.21

Peak Markup
Component
$0.68
$0.81
$0.93
$0.87
$1.28
$0.81
$0.88
$0.89
$0.62
$0.87
$1.04
$0.85
$0.62
$0.60
$0.62
$0.70
$0.62
$1.07
$0.45
$0.62
$0.53

2021 (Jan - Jun)
Off PeakMarkupComponent($0.10)($0.12)($0.13)($0.08)($0.10)($0.29)($0.09)($0.14)($0.19)($0.13)($0.10)($0.17)($0.09)($0.12)($0.23)($0.09)($0.17)($0.12)$0.01($0.13)($0.14)

MarkupComponent(All Hours)$0.10($0.21)($0.27)($0.05)($0.14)($0.07)($0.17)($0.51)$0.24($0.21)($0.09)($0.29)$0.16$0.07($0.33)$0.05$0.10($0.14)
$0.10
$0.23
$0.64

Peak Markup
Component
$0.70
$0.03
($0.03)$0.12($0.06)$0.30($0.03)($0.23)$0.81($0.10)$0.03($0.16)$0.62$0.61($0.48)$0.53$0.66($0.21)
$0.57
$0.72
$1.39

Off PeakMarkupComponent($0.48)($0.45)($0.51)($0.22)($0.22)($0.45)($0.32)($0.79)($0.32)($0.33)($0.22)($0.42)($0.32)($0.49)($0.20)($0.44)($0.48)($0.06)($0.38)($0.27)($0.19)Markup Component of Real-Time Zonal Prices
The unit markup component of average real-time price using unadjusted
offers is shown for each zone in the first six months of 2020 and the first six
months of 2021 in Table 3-119 and for adjusted offers in Table 3-120.175 The
smallest zonal all hours average markup component using unadjusted offers
in the first six months of 2021, was in the DOM Control Zone, -$0.51 per
MWh, while the highest was in the REC Control Zone, $0.64 per MWh. The
smallest zonal on peak average markup component using unadjusted offers in
the first six months of 2021, was in the OVEC Control Zone, -$0.48 per MWh,while the highest was in the REC Control Zone, $1.39 per MWh.

175 A marginal unit’s offer price affects LMPs in the entire PJM market. The markup component of average zonal real-time price is based onoffers of units located within the zone and units located outside the transmission zone.

238

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-120 Average, real-time, zonal markup component (Adjusted): January
through June 2020 and 2021
2020 (Jan - Jun)

ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC

MarkupComponent(All Hours)
$1.80
$1.96
$2.02
$2.03
$2.29
$1.76
$2.10
$2.01
$1.76
$1.99
$2.09
$1.95
$1.81
$1.80
$1.74
$1.85
$1.73
$2.14
$1.71
$1.78
$1.74

Peak Markup
Component
$2.30
$2.57
$2.68
$2.65
$3.13
$2.47
$2.71
$2.67
$2.24
$2.62
$2.81
$2.59
$2.27
$2.25
$2.34
$2.35
$2.21
$2.86
$2.01
$2.26
$2.17

2021 (Jan - Jun)
Off PeakMarkupComponent
$1.31
$1.35
$1.34
$1.39
$1.45
$1.01
$1.44
$1.36
$1.28
$1.35
$1.35
$1.33
$1.34
$1.32
$1.21
$1.32
$1.24
$1.40
$1.39
$1.29
$1.26

MarkupComponent(All Hours)
$1.97
$1.83
$1.78
$1.98
$2.20
$1.93
$1.97
$1.64
$2.15
$1.87
$1.90
$1.82
$2.06
$2.00
$1.65
$2.02
$1.92
$2.05
$1.98
$2.20
$2.72

Peak Markup
Component
$2.66
$2.20
$2.16
$2.25
$2.46
$2.44
$2.26
$2.10
$2.78
$2.13
$2.12
$2.12
$2.63
$2.64
$1.65
$2.61
$2.56
$2.11
$2.56
$2.87
$3.71

Off PeakMarkupComponent
$1.29
$1.46
$1.40
$1.70
$1.95
$1.39
$1.67
$1.19
$1.53
$1.60
$1.67
$1.54
$1.47
$1.33
$1.65
$1.41
$1.26
$1.98
$1.38
$1.51
$1.61

Markup by Real-Time Price Levels
Table 3-121 shows the markup contribution to the LMP, based on theunadjusted cost-based offers and adjusted cost-based offers of the marginalunits, when the PJM system wide, load-weighted, average, LMP was in theidentified price range.
Table 3-121 Real-time markup contribution (By load-weighted, LMP category,unadjusted): January through June, 2020 and 2021
LMP Category< $10$10 to $15$15 to $20$20 to $25$25 to $50$50 to $75$75 to $100
$100 to $125
$125 to $150>= $1502021 (Jan - Jun)
Frequency Markup Component
2.5%
$0.00
25.9%
($0.82)43.8%($0.50)18.6%($0.55)7.9%($0.07)
1.0%
$1.39
0.2%
$4.37
0.0%
$3.25
0.0%
$3.91
0.0%
$7.46

Frequency
0.0%
0.9%
22.7%
32.4%
36.8%
4.1%
1.5%
1.0%
0.3%
0.4%

Table 3-122 Real-time markup contribution (By load-weighted, LMP category,adjusted): January through June, 2020 and 2021
LMP Category< $10$10 to $15$15 to $20$20 to $25$25 to $50$50 to $75$75 to $100
$100 to $125
$125 to $150>= $150© 2021 Monitoring Analytics, LLC

2020 (Jan - Jun)
Markup Component($0.53)($0.22)($0.43)
$0.29
$2.80
$7.69
$5.86
$6.26
$1.20
$2.85

2020 (Jan - Jun)
Markup Component($0.05)
$0.41
$0.41
$1.26
$3.89
$9.21
$6.85
$7.09
$3.18
$3.62

2021 (Jan - Jun)
Frequency Markup Component
2.6%
$0.00
25.7%
($0.12)
44.1%
$0.26
18.5%
$0.41
7.7%
$1.06
1.0%
$2.89
0.2%
$6.57
0.0%
$6.10
0.0%
$7.71
0.0%
$9.77

Frequency
0.0%
0.9%
23.2%
32.5%
36.3%
4.0%
1.5%
0.9%
0.3%
0.4%

2021 Quarterly State of the Market Report for PJM: January through June 239

2021 Quarterly State of the Market Report for PJM: January through June

Markup by Company
Table 3-123 shows the markup contribution based on the unadjusted cost-based offers and adjusted cost-based offers to real-time, load-weighted, average LMP
by individual marginal resource owners. The markup contribution of each marginal resource to price at each load bus is calculated for each five-minute interval,and summed by the parent company that offers the marginal resource into the real-time energy market. In the first six months of 2021, when using unadjusted
cost-based offers, the markup of one company accounted for 0.9 percent of the load-weighted, average LMP, the markup of the top five companies accounted
for 2.4 percent of the load-weighted, average LMP and the markup of all companies accounted for -0.4 percent of the load-weighted, average LMP. The top fivecompanies’ markup contribution to the load-weighted, average LMP and the dollar values of their markup decreased in the first six months of 2021. The markup
contribution to the load-weighted, average LMP and share of the markup contribution to the load-weighted, average LMP also decreased in the first six monthsof 2021. The markup contribution of a unit to the real-time, load-weighted, average LMP can be positive or negative.
Table 3-123 Markup component of real-time, load-weighted, average LMP by Company: January through June, 2020 and 2021

Top 1 Company
Top 2 Companies
Top 3 Companies
Top 4 Companies
Top 5 Companies
All Companies

240

2020 (Jan - Jun)
Markup Component ofMarkup Component of
LMP (Unadjusted)
LMP (Adjusted)
Percent of Load
Percent of Load$/MWh Weighted LMP $/MWh Weighted LMP
$0.39
2.0%
$0.62
3.2%
$0.57
2.9%
$0.85
4.4%
$0.70
3.6%
$1.06
5.5%
$0.83
4.3%
$1.24
6.4%
$0.91
4.7%
$1.40
7.2%
$0.34
1.8%
$1.93
9.9%

Section 3 Energy Market

2021 (Jan - Jun)
Markup Component ofMarkup Component of
LMP (Unadjusted)
LMP (Adjusted)
Percent of Load
Percent of Load$/MWh Weighted LMP $/MWh Weighted LMP
$0.26
0.9%
$0.43
1.4%
$0.46
1.5%
$0.82
2.7%
$0.63
2.1%
$1.08
3.5%
$0.69
2.2%
$1.30
4.3%
$0.74
2.4%
$1.48
4.8%
($0.13)(0.4%)$1.92
6.3%© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Day-Ahead Markup
Markup Component of Day-Ahead Price by Fuel, Unit TypeThe markup component of the PJM day-ahead, load-weighted average LMP by primary fuel and unit type is shown in Table 3-124. INC, DEC and up tocongestion transactions (UTC) have zero markups. UTCs were 36.5 percent of marginal resources, INCs were 17.7 percent of marginal resources and DECs were25.1 percent of marginal resources in the first six months of 2021.
The adjusted markup of coal, gas and oil units is calculated as the difference between the price-based offer, and the cost-based offer excluding the 10 percent
adder. Table 3-124 shows the markup component of LMP for marginal generating resources. Generating resources were only 20.4 percent of marginal resourcesin the first six months of 2021. Using adjusted cost-based offers, the markup component of LMP for marginal generating resources increased for coal fired steam
units from $0.02 to $0.31 per MWh and increased for gas fired CC units from $0.98 to $1.00 per MWh.
Table 3-124 Markup component of day-ahead, load-weighted, average LMP by primary fuel type and technology type: January through June, 2020 and 2021

Fuel
Coal
Gas
Gas
Gas
Gas
Municipal Waste
Oil
Oil
Oil
Oil
Other
Other
Uranium
Water
Wind
Total

Technology
Steam
CC
CT
RICE
Steam
RICE
CC
CT
RICE
Steam
Solar
Steam
Steam
Hydro
Wind

2020 (Jan - Jun)
MarkupMarkupComponent of
Component of
LMP (Unadjusted)
LMP (Adjusted)($0.67)
$0.02
$0.58
$0.98
($0.00)$0.00($0.00)($0.00)($0.05)($0.03)
$0.00
$0.00
$0.00
$0.00
$0.00
($0.00)
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
($0.00)($0.00)
$0.00
$0.00
$0.00
$0.00
$0.01
$0.01
($0.14)$0.98© 2021 Monitoring Analytics, LLC

Frequency
34.0%
57.6%
0.6%
0.1%
2.2%
0.1%
0.0%
0.2%
0.0%
0.0%
0.2%
0.7%
1.7%
0.0%
2.7%
100.0%

2021 (Jan - Jun)
MarkupMarkupComponent of
Component of
LMP (Unadjusted)
LMP (Adjusted)($0.27)
$0.31
$0.12
$1.00
$0.00
$0.01
($0.00)$0.00($0.03)
$0.03
$0.01
$0.01
$0.00
$0.00
($0.00)
$0.00
$0.00
$0.00
$0.00
$0.01
$0.00
$0.00
($0.00)($0.00)
$0.00
$0.00
$0.00
$0.00
$0.39
$0.39
$0.22
$1.75

Frequency
36.3%
53.6%
0.8%
0.4%
2.3%
0.2%
0.1%
0.1%
0.1%
0.1%
0.2%
0.3%
0.2%
0.0%
5.2%
100.0%

2021 Quarterly State of the Market Report for PJM: January through June 241

2021 Quarterly State of the Market Report for PJM: January through June

Markup Component of Day-Ahead Price
The markup component of price is the difference between the system price,when the system price is determined by the active offers of the marginalunits, whether price or cost-based, and the system price, based on the costbased offers of those marginal units. Only hours when generating units were
marginal on either priced-based offers or on cost-based offers were includedin the markup calculation.
Table 3-125 shows the markup component of average prices and of averagemonthly on peak and off peak prices using unadjusted cost-based offers. In
the first six months of 2021, when using unadjusted cost-based offers, $0.22
per MWh of the PJM day-ahead load-weighted, average LMP was attributableto markup. In the first six months of 2021, the peak markup component was
highest in February, $2.13 per MWh using unadjusted cost-based offers.
Table 3-125 Monthly markup components of day-ahead (Unadjusted), loadweighted LMP: January 2020 through June 2021
2020

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

242

MarkupComponent(All Hours)($0.03)($0.23)($0.21)($0.27)($0.19)$0.07($0.54)$0.07($0.01)$0.15($0.22)$0.13($0.11)

Peak Markup
Component$0.29($0.08)($0.19)($0.19)$0.17$0.39($0.41)
$0.70
$0.55
$0.48
$0.28
$0.37
$0.19

Section 3 Energy Market

2021
Off PeakMarkupComponent($0.35)($0.39)($0.23)($0.36)($0.52)($0.33)($0.72)($0.59)($0.63)($0.21)($0.70)($0.12)($0.43)MarkupComponent(All Hours)($0.42)($0.35)
$0.62
$0.36
$0.85
$0.44

Peak Markup
Component($0.25)
$2.13
$0.55
$0.83
$0.91
$0.61

Off PeakMarkupComponent($0.56)($2.90)$0.70($0.19)
$0.78
$0.24

$0.22

$0.80

($0.37)

Table 3-126 shows the markup component of average prices and of averagemonthly on peak and off peak prices using adjusted cost-based offers. In thefirst six months of 2021, when using adjusted cost-based offers, $1.75 per
MWh of the PJM day-ahead, load-weighted, average LMP was attributableto markup. In the first six months of 2021, the peak markup component was
highest in February, $4.51 per MWh using adjusted cost-based offers.
Table 3-126 Monthly markup components of day-ahead (Adjusted), loadweighted, LMP: January 2020 through June 2021
2020

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

MarkupComponent(All Hours)
$1.35
$0.99
$0.96
$0.70
$0.72
$1.04
$0.65
$1.14
$0.95
$1.12
$0.89
$1.49
$1.01

Peak Markup
Component
$1.65
$1.17
$1.02
$0.91
$1.00
$1.35
$0.75
$1.77
$1.50
$1.37
$1.29
$1.68
$1.29

2021
Off PeakMarkupComponent
$1.03
$0.83
$0.90
$0.47
$0.47
$0.67
$0.51
$0.48
$0.34
$0.84
$0.52
$1.29
$0.70

MarkupComponent(All Hours)
$1.11
$2.07
$1.77
$1.62
$2.24
$1.74

Peak Markup
Component
$1.22
$4.51
$1.72
$1.97
$2.25
$1.90

Off PeakMarkupComponent$1.02($0.42)
$1.82
$1.22
$2.23
$1.55

$1.75

$2.27

$1.20

Markup Component of Day-Ahead Zonal Prices
The markup component of annual average day-ahead price using unadjusted
cost-based offers is shown for each zone in Table 3-127. The markup
component of annual average day-ahead price using adjusted cost-based
offers is shown for each zone in Table 3-128. The smallest zonal all hours
average markup component using adjusted cost-based offers for the first six
months of 2021 was in the ATSI Zone, $1.12 per MWh, while the highest wasin the BGE Control Zone, $2.36 per MWh. The smallest zonal on peak averagemarkup using adjusted cost-based offers was in the ATSI Control Zone, $1.27
per MWh, while the highest was in the BGE Control Zone, $3.64 per MWh.

© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

Table 3-127 Day-ahead, average, zonal markup component (Unadjusted):
January through June, 2020 and 2021
2020 (Jan - Jun)

ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC

MarkupComponent (All
Hours)$0.09($0.30)($0.25)($0.24)($0.27)($0.23)($0.12)($0.39)$0.14$0.07($0.31)($0.12)
$0.05
$0.08
$0.05
$0.07
$0.09
($0.40)
$0.86
$0.06
$0.12

Peak Markup
Component$0.25($0.10)($0.03)($0.05)
$0.10
$0.01
$0.24
($0.28)$0.32$0.64($0.14)
$0.26
$0.19
$0.23
$0.03
$0.25
$0.25
($0.24)
$1.18
$0.21
$0.37

© 2021 Monitoring Analytics, LLC

Table 3-128 Day-ahead, average, zonal markup component (Adjusted):
January through June, 2020 and 2021

2021 (Jan - Jun)
Off PeakMarkupMarkup Component (AllComponent
Hours)($0.06)$0.20($0.51)$0.21($0.47)$0.26($0.44)($0.49)($0.65)$0.91($0.49)$0.37($0.51)$0.25($0.49)$0.23($0.04)$0.16($0.53)$0.27($0.49)($0.18)($0.50)$0.31($0.11)$0.21($0.07)$0.36$0.10($0.26)($0.15)$0.12($0.08)$0.30($0.57)
$0.62
$0.52
$0.34
($0.11)$0.15($0.15)($0.00)Peak Markup
Component
$0.37
$0.81
$1.00
($0.31)
$2.34
$1.07
$0.80
$1.02
$0.07
$0.97
$0.05
$1.31
$0.42
$0.72
($0.21)
$0.56
$0.47
$1.70
$0.64
$0.33
$0.24

2020 (Jan - Jun)
Off PeakMarkupComponent$0.04($0.40)($0.49)($0.67)($0.53)($0.36)($0.34)($0.54)$0.26($0.45)($0.42)($0.65)($0.00)($0.03)($0.33)($0.36)$0.12($0.50)$0.03($0.04)($0.26)

ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC

MarkupComponent (All
Hours)
$1.20
$0.85
$0.88
$0.91
$0.85
$0.87
$1.04
$0.73
$1.23
$1.16
$0.79
$1.00
$1.18
$1.20
$1.15
$1.11
$1.19
$0.76
$1.90
$1.16
$1.20

Peak Markup
Component
$1.38
$1.04
$1.13
$1.11
$1.21
$1.12
$1.38
$0.87
$1.41
$1.67
$0.98
$1.34
$1.34
$1.37
$1.15
$1.32
$1.38
$0.96
$2.23
$1.32
$1.43

2021 (Jan - Jun)
Off PeakMarkupMarkup Component (AllComponent
Hours)
$1.02
$1.76
$0.66
$1.71
$0.62
$1.80
$0.68
$1.12
$0.49
$2.36
$0.60
$1.85
$0.68
$1.84
$0.58
$1.76
$1.05
$1.63
$0.64
$1.77
$0.60
$1.34
$0.67
$1.86
$0.99
$1.79
$1.01
$1.83
$1.15
$1.38
$0.85
$1.64
$1.00
$1.85
$0.56
$2.15
$1.55
$1.83
$0.98
$1.72
$0.93
$1.51

Peak Markup
Component
$2.00
$2.26
$2.47
$1.27
$3.64
$2.51
$2.34
$2.40
$1.53
$2.39
$1.53
$2.76
$2.04
$2.17
$1.39
$2.08
$2.07
$3.10
$2.14
$1.95
$1.75

Off PeakMarkupComponent
$1.53
$1.15
$1.11
$0.96
$1.08
$1.15
$1.30
$1.13
$1.74
$1.12
$1.15
$0.98
$1.53
$1.46
$1.36
$1.16
$1.62
$1.16
$1.52
$1.48
$1.25

2021 Quarterly State of the Market Report for PJM: January through June 243

2021 Quarterly State of the Market Report for PJM: January through June

Markup by Day-Ahead Price Levels
Table 3-129 and Table 3-130 show the average markup component of LMP,
based on the unadjusted cost-based offers and adjusted cost-based offers ofthe marginal units, when the PJM system LMP was in the identified pricerange.
Table 3-129 Average, day-ahead markup component (By LMP category,unadjusted): January through June, 2020 and 2021
LMP Category< $10$10 to $15$15 to $20$20 to $25$25 to $50$50 to $75$75 to $100
$100 to $125
$125 to $150>= $1502020 (Jan - Jun)
Average Markup
Component$0.00($0.05)($0.22)
$0.03
$0.11
$0.00
$0.00
$0.00
$0.00
$0.00

Frequency
1.5%
19.0%
47.8%
23.4%
8.2%
0.1%
0.0%
0.0%
0.0%
0.0%

2021 (Jan - Jun)
Average Markup
Component$0.00($0.00)$0.05($0.10)$0.26($0.12)$0.08$0.00($0.03)$0.09

Frequency
0.0%
0.1%
16.5%
32.2%
45.9%
3.4%
0.8%
0.5%
0.4%
0.2%

Table 3-130 Average, day-ahead markup component (By LMP category,adjusted): January through June, 2020 and 2021
LMP Category< $10$10 to $15$15 to $20$20 to $25$25 to $50$50 to $75$75 to $100
$100 to $125
$125 to $150>= $1502020 (Jan - Jun)
Average Markup
Component
$0.01
$0.09
$0.36
$0.34
$0.18
$0.00
$0.00
$0.00
$0.00
$0.00

Frequency
1.5%
19.0%
47.8%
23.4%
8.2%
0.1%
0.0%
0.0%
0.0%
0.0%

2021 (Jan - Jun)
Average Markup
Component$0.00($0.00)
$0.21
$0.34
$1.01
($0.04)$0.10$0.03($0.00)$0.10

Frequency
0.0%
0.1%
16.5%
32.2%
45.9%
3.4%
0.8%
0.5%
0.4%
0.2%

Market Structure, Participant Behavior, and Market
Performance
The goal of regulation through competition is to achieve competitivemarket outcomes even in the presence of market power. Market structurein the PJM energy market is not competitive in local markets created bytransmission constraints. At times, market structure is not competitive in theaggregate energy market. Market sellers pursuing their financial interests may
choose behavior that benefits from structural market power in the absenceof an effective market power mitigation program. The overall competitive
assessment evaluates the extent to which that participant behavior results incompetitive or above competitive pricing. The competitive assessment brings
together the structural measures of market power, HHI and pivotal suppliers,
with participant behavior, specifically markup, and pricing outcomes.

HHI and Markup
In theory, the HHI provides insight into the relationship between market structure,
behavior, and performance. In the case where participants compete by producing
output at constant, but potentially different, marginal costs, the HHI is directly
proportional to the expected average price cost markup in the market:176

where e is the absolute value of the price elasticity of demand, P is the market
price, and MC is the average marginal cost of production. This is called the
Lerner Index. The left side of the equation quantifies market structure, andthe right side of the equation measures market performance. The assumed
participant behavior is profit maximization. As HHI decreases, implying amore competitive market, prices converge to marginal cost, the competitivemarket outcome. But even a low HHI may result in substantial markup witha low price elasticity of demand. If HHI is very high, meaning competitionis lacking, prices can reach the monopoly level. Price elasticity of demand(e) determines the degree to which suppliers with market power can impose
higher prices on customers. The Lerner Index is a measure of market power that
176 See Tirole, Jean. The Theory of Industrial Organization, MIT (1988), Chapter 5: Short-Run Price Competition.

244

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 3 Energy Market

connects market structure (HHI and demand elasticity) to market performance(markup).

With the flaws in PJM’s implementation of the TPS test, resources can and do
set prices with a positive markup while failing the TPS test.

The PJM energy market HHIs and application of the FERC concentration
categories may understate the degree of market power because, in the absenceof aggregate market power mitigation, even the unconcentrated HHI level
would imply substantial markups due to the low short run price elasticity ofdemand. For example, research estimates find short run electricity demand
elasticity ranging from -0.2 to -0.4.177 Using the Lerner Index, the elasticities
imply, for example, an average markup ranging from 25 to 50 percent at theunconcentrated to moderately concentrated threshold HHI of 1000:178

Table 3-131 categorizes day-ahead and real-time marginal unit intervals bymarkup level and TPS test status. In the first six months of 2021, 3.8 percent
of real-time marginal unit intervals and 3.4 percent of day-ahead marginalunit hours included a positive markup even though the resource failed the
TPS test for local market power. Unmitigated local market power affects PJM
market prices. Zero markup with a TPS test failure indicates the mitigation ofa marginal unit.

With knowledge of HHI, elasticity, and marginal cost, one can solve forthe price level theoretically indicated by the Lerner Index, based on profit
maximizing behavior including the exercise of market power. With marginal
costs of $30.74 per MWh and an average HHI of 751 in the first six monthsof 2021, average PJM prices would theoretically range from $38 to $49 per
MWh using the elasticity range of -0.2 to -0.4.179 The theoretical prices exceed
marginal costs because the exercise of market power is profit maximizingin the absence of market power mitigation. Actual prices, averaging $30.62
per MWh, and markups, at -0.4 percent, are lower than the theoretical range,
supporting the MMU’s competitive assessment of the market. However,markup is not zero. In some market intervals, markup and prices reach levels
that reflect the exercise of market power.

Market Power Mitigation and Markup
Fully effective market power mitigation would not allow a seller that fails the
structural market power test (the TPS test) to set prices with a positive markup.
177 See Patrick, Robert H. and Frank A. Wolak (1997), “Estimating the Customer-Level Demand for Electricity Under Real-Time Market
Prices,” <https://web.stanford.edu/group/fwolak/cgi-bin/sites/default/files/files/Estimating%20the%20Customer-Level%20Demand%20
for%‌20Electricity%20Under%20Real-Time%20Market%20Prices_Aug%201997_Patrick,%‌20Wolak.pdf>, last accessed August 3, 2018
and Fan, Shu and Rob Hyndman (2010), “The price elasticity of electricity demand in South Australia,” <https://robjhyndman.com/
papers/‌Elasticity2010.pdf>.
178 The HHI used in the equation is based on market shares. For the FERC HHI thresholds and standard HHI reporting, market shares are
multiplied by 100 prior to squaring the market shares.
179 The average HHI is found in Table 3-1. Marginal costs are the sum of all components of LMP except markup, as shown in Table 3-51.

© 2021 Monitoring Analytics, LLC

Table 3-131 Percent of real-time marginal unit intervals with markup andlocal market power: January through June, 2021
Markup Category
Negative Markup
Zero Markup

Day-ahead Market
Not Failing Failing TPS
Percent in
TPS Test
Test
Category
38.2%
8.0%
46.2%
17.2%
5.3%
22.5%

Real-time Market
Not Failing Failing TPS
Percent in
TPS Test
Test
Category
38.5%
9.1%
47.6%
16.2%
8.5%
24.7%

$0 to $5
$5 to $10
$10 to $15$15 to $20$20 to $25$25 to $50$50 to $75$75 to $100
Above $100
Total Positive Markup

22.2%
2.0%
0.8%
1.9%
0.3%
0.3%
0.5%
0.0%
0.0%
27.9%

2.6%
0.3%
0.2%
0.1%
0.1%
0.1%
0.0%
0.0%
0.0%
3.4%

24.8%
2.3%
1.0%
1.9%
0.4%
0.4%
0.5%
0.0%
0.0%
31.3%

19.6%
2.4%
0.7%
0.4%
0.2%
0.5%
0.1%
0.1%
0.1%
23.9%

2.8%
0.5%
0.1%
0.1%
0.1%
0.2%
0.0%
0.0%
0.1%
3.8%

22.4%
2.8%
0.8%
0.4%
0.3%
0.7%
0.1%
0.1%
0.1%
27.7%

Total

83.3%

16.7%

100.0%

78.6%

21.4%

100.0%The markup of marginal units was zero or negative in 72.3 percent of real-time
marginal unit intervals and 68.7 percent of day-ahead marginal unit intervals
in the first six months of 2021. Pivotal suppliers in the aggregate market also
set prices with high markups in the first six months of 2021. Allowing positive
markups to affect prices in the presence of market power permits the exercise
of market power and has a negative impact on the competitiveness of the PJM
energy market. This problem can and should be addressed.

2021 Quarterly State of the Market Report for PJM: January through June 245

2021 Quarterly State of the Market Report for PJM: January through June

246

Section 3 Energy Market© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Energy Uplift (Operating Reserves)
Energy uplift is paid to market participants under specified conditions in orderto ensure that competitive energy and ancillary service market outcomes do
not require efficient resources to operate for the PJM system at a loss.1 Referred
to in PJM as operating reserve credits, lost opportunity cost credits, reactive
services credits, synchronous condensing credits or black start services credits,these uplift payments are intended to be one of the incentives to generation
owners to offer their energy to the PJM energy market for dispatch basedon short run marginal costs and to operate their units as directed by PJM
operators. These credits are paid by PJM market participants as operating
reserve charges, reactive services charges, synchronous condensing charges
or black start services charges. Effective November 1, 2020, UTC transactions
are allocated day-ahead and real-time uplift charges, and are treated for uplift
purposes as being equivalent to a decrement bid (DEC) at the sink point of
the UTC.2
Uplift is an inherent part of the PJM market design. Part of that uplift is theresult of the nonconvexity of power production costs. Uplift payments cannot
be eliminated, but uplift payments should be limited to the efficient level. In
wholesale power market design, a choice must be made between efficient prices
and prices that fully compensate costs. Economists recognize that no single
price achieves both goals in markets with nonconvex production costs, likethe costs of producing electric power.3 4 In wholesale power markets like PJM,
efficient prices equal the short run marginal cost of production by location.
The dispatch of generators based on these efficient price signals minimizes
the total market cost of production. For generators with nonconvex costs,
marginal cost prices may not cover the total cost of starting the generator andrunning at the efficient output level. Uplift payments cover the difference.
The PJM market design incorporates efficient prices with minimal uplift
1 Loss exists when gross energy and ancillary services market revenues are less than short run marginal costs, including all elements of theenergy offer, which are startup, no load and incremental offers.
2 See 172 FERC ¶ 61,046 (2020).
3 See Stoft, Power System Economics: Designing Markets for Electricity, New York: Wiley (2002) at 272; Mas-Colell, Whinston, and Green,
Microeconomic Theory, New York: Oxford University Press (1995) at 570; and Quinzii, Increasing Returns and Efficiency, New York: Oxford
University Press (1992).
4 The production of output is convex if the production function has constant or decreasing returns to scale, which result in constantor rising average costs with increases in output. Production is nonconvex with increasing returns to scale, which is the case whengenerating units have start or no load costs that are large relative to marginal costs. See Mas-Colell, Whinston, and Green at 132.

© 2021 Monitoring Analytics, LLC

payments. There are improvements to the market design and uplift rules that
could further reduce uplift payments while maintaining efficient prices.
In PJM, all energy payments to demand response resources are uplift
payments. The energy payments to these resources are not part of the supply
and demand balance, they are not paid by LMP revenues and therefore theenergy payments to demand response resources have to be paid as out ofmarket uplift. The energy payments to economic DR are funded by real-timeload and real-time exports. The energy payments to emergency DR are fundedby participants with net energy purchases in the real-time energy market. The
current payment structure for DR is an inefficient element of the PJM market
design.5

Overview
Energy Uplift Credits• Types of credits. In the first six months of 2021, energy uplift credits were

$79.2 million, including $7.2 million in day-ahead generator credits, $55.4
million in balancing generator credits, $11.1 million in lost opportunity
cost credits, and $4.6 million in local constraint control credits.

• Types of units. In the first six months of 2021, coal units received 74.8
percent of day-ahead generator credits, and combustion turbines received
93.8 percent of balancing generator credits and 98.3 percent of lost
opportunity cost credits.

• Economic and Noneconomic Generation. In the first six months of 2021,

89.1 percent of the day-ahead generation eligible for operating reserve
credits was economic and 62.3 percent of the real-time generation eligible
for operating reserve credits was economic.

• Day-Ahead Unit Commitment for Reliability. In the first six months of2021, 0.1 percent of the total day-ahead generation MWh was scheduled
as must run for reliability by PJM, of which 76.1 percent received energy
uplift payments.

5 Demand response payments are addressed in Section 6: Demand Response.

2021 Quarterly State of the Market Report for PJM: January through June 247

2021 Quarterly State of the Market Report for PJM: January through June

• Concentration of Energy Uplift Credits. In the first six months of 2021,

the top 10 units receiving energy uplift credits received 16.8 percent
of all credits and the top 10 organizations received 71.4 percent of allcredits. The HHI for day-ahead operating reserves was 7670, the HHI for
balancing operating reserves was 2882 and the HHI for lost opportunity
cost was 6595, all of which are classified as highly concentrated.

• Lost Opportunity Cost Credits. Lost opportunity cost credits increased by$4.4 million or 66.7 percent, in the first six months of 2021 comparedto the first six months of 2020, from $6.6 million to $11.1 million.
Some combustion turbines and diesels are scheduled day-ahead but not
requested in real time, and receive day-ahead lost opportunity cost credits
as a result. This was the source of 97.9 percent of the $11.1 million. The
day-ahead generation paid LOC credits for this reason decreased by 343.5
GWh or 64.0 percent during 2021, compared to 2020, from 536.5 GWh
to 193.1 GWh.

• Following Dispatch. Some units are incorrectly paid uplift despite notmeeting uplift eligibility requirements, including not following dispatch,
not having the correct commitment status, or not operating with proper
offer parameters. Since 2018, the MMU has made cumulative resettlement
requests for overpaid units that total $13.0 million, of which PJM has
resettled 10.6 percent.

Energy Uplift Charges• Energy Uplift Charges. Total energy uplift charges increased by $55.7

million, or 236.1 percent, in the first six months of 2021 compared to thefirst six months of 2020, from $23.5 million to $79.0 million.

• Energy Uplift Charges Categories. The increase of $55.7 million in thefirst six months of 2021 was comprised of a $4.2 million increase in dayahead operating reserve charges, a $51.1 million increase in balancing
operating reserve charges, and a $0.4 million increase in reactive services
charges.

• Average Effective Operating Reserve Rates in the Eastern Region. Day-

ahead load paid $0.017 per MWh, real-time load paid $0.088 per MWh,

248

Section 4 Energy Uplift

DECs and UTCs paid $0.354 per MWh and an INC and any load, generation
or interchange transaction deviation paid $0.337 per MWh.

• Average Effective Operating Reserve Rates in the Western Region. Dayahead load paid $0.017 per MWh, real-time load paid $0.073 per MWh,
DECs and UTCs paid $0.317 per MWh and an INC and any load, generation
or interchange transaction deviation paid $0.300 per MWh in the first six
months of 2021.

• Reactive Services Rates. PPL and MEC were the two zone with the highest

local voltage support rates, excluding reactive capability payments. PPL
had a rate of $0.034 per MWh, MEC had a rate of $0.001 per MWh

Geography of Charges and Credits• In the first six months of 2021, 89.5 percent of all uplift charges allocatedregionally (day-ahead operating reserves and balancing operating
reserves) were paid by transactions at control zones, 3.5 percent bytransactions at hubs and aggregates, and 7.0 percent by transactions atinterchange interfaces.

• In the first six months of 2021, generators in the Eastern Region received
41.3 percent of all balancing generator credits, including lost opportunity
cost and canceled resources credits.

• In the first six months of 2021, generators in the Western Region received

56.1 percent of all balancing generator credits, including lost opportunity
cost and canceled resources credits.

• In the first six months of 2021, external generators received 2.6 percent

of all balancing generator credits, including lost opportunity cost andcanceled resources credits.

Recommendations• The MMU recommends that uplift be paid only based on operating
parameters that reflect the flexibility of the benchmark new entrant unit
(CONE unit) in the PJM Capacity Market. (Priority: High. First reported
2018. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift• The MMU recommends that PJM initiate an analysis of the reasons•

why a significant number of combustion turbines and diesels scheduledin the day-ahead energy market are not called in real time when they
are economic. (Priority: Medium. First Reported 2012. Status: Partiallyadopted, 2019.)
The MMU recommends that PJM develop and implement an accurate
metric to define when a unit is following dispatch to determine eligibility
to receive balancing operating reserve credits and for assessing generator
deviations and that PJM not pay uplift to units not following dispatch.
(Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that PJM designate units whose offers are flagged

for fixed generation in Markets Gateway as not eligible for uplift. Units
that are flagged for fixed generation are not dispatchable. Following
dispatch is an eligibility requirement for uplift compensation. (Priority:
Medium. First reported 2020. Status: Not adopted.)• The MMU recommends eliminating intraday segments from the calculationof uplift payments and returning to calculating the need for uplift basedon the entire 24 hour operating day. (Priority: High. First reported 2018.
Status: Not adopted.)• The MMU recommends the elimination of day-ahead uplift to ensure that
units receive an energy uplift payment based on their real-time output andnot their day-ahead scheduled output. (Priority: Medium. First reported
2013. Status: Not adopted.)• The MMU recommends enhancing the current energy uplift allocation•

rules to reflect the recommended elimination of day-ahead uplift, thetiming of commitment decisions and the commitment reasons. (Priority:
High. First reported 2012. Status: Not adopted.)
The MMU recommends that units not be paid lost opportunity cost
uplift when PJM directs a unit to reduce output based on a transmission
constraint or other reliability issue. There is no lost opportunity because
the unit is required to reduce for the reliability of the unit and the system.
(Priority: High. New recommendation. Status: Not adopted.)© 2021 Monitoring Analytics, LLC• The MMU recommends reincorporating the use of net regulation revenues
as an offset in the calculation of balancing operating reserve credits.
(Priority: Medium. First reported 2009. Status: Not adopted.)• The MMU recommends that self scheduled units not be paid energy uplift

for their startup cost when the units are scheduled by PJM to start before
the self scheduled hours. (Priority: Low. First reported 2013. Status: Not
adopted.)• The MMU recommends three modifications to the energy lost opportunity
cost calculations:— The MMU recommends calculating LOC based on 24 hour daily periods

for combustion turbines and diesels scheduled in the day-aheadenergy market, but not committed in real time. (Priority: Medium. First
reported 2014. Status: Not adopted.)— The MMU recommends that units scheduled in the day-ahead energy

market and not committed in real time should be compensated for
LOC based on their real-time desired and achievable output, not theirscheduled day-ahead output. (Priority: Medium. First reported 2015.
Status: Not adopted.)— The MMU recommends that only flexible fast start units (startup
plus notification times of 10 minutes or less) and units with shortminimum run times (one hour or less) be eligible by default for the
LOC compensation to units scheduled in the day-ahead energy market
and not committed in real time. Other units should be eligible for
LOC compensation only if PJM explicitly cancels their day-ahead
commitment. (Priority: Medium. First reported 2015. Status: Not
adopted.)• The MMU recommends that up to congestion transactions be required to

pay energy uplift charges for both the injection and the withdrawal sidesof the UTC. (Priority: High. First reported 2011. Status: Partially adopted.)• The MMU recommends eliminating the use of internal bilateraltransactions (IBTs) in the calculation of deviations used to allocate

2021 Quarterly State of the Market Report for PJM: January through June 249

2021 Quarterly State of the Market Report for PJM: January through Junebalancing operating reserve charges. (Priority: High. First reported 2013.
Status: Adopted 2018.6)• The MMU recommends allocating the energy uplift payments to units

scheduled as must run in the day-ahead energy market for reasons otherthan voltage/reactive or black start services as a reliability charge to realtime load, real-time exports and real-time wheels. (Priority: Medium. First
reported 2014. Status: Not adopted. Stakeholder process.)• The MMU recommends that the total cost of providing reactive support

be categorized and allocated as reactive services. Reactive services credits
should be calculated consistent with the balancing operating reserve
credit calculation. (Priority: Medium. First reported 2012. Status: Not
adopted. Stakeholder process.)• The MMU recommends including real-time exports and real-time wheels

in the allocation of the cost of providing reactive support to the 500
kV system or above, in addition to real-time load. (Priority: Low. First
reported 2013. Status: Not adopted.)• The MMU recommends modifications to the calculation of lost opportunity

costs credits paid to wind units. The lost opportunity costs credits paid
to wind units should be based on the lesser of the desired output, theestimated output based on actual wind conditions and the capacity
interconnection rights (CIRs). The MMU recommends that PJM allow
wind units to request CIRs that reflect the maximum output wind units
want to inject into the transmission system at any time. (Priority: Low.
First reported 2012. Status: Not adopted.)• The MMU recommends that PJM clearly identify and classify all reasonsfor incurring uplift in the day-ahead and the real-time energy markets
and the associated uplift charges in order to make all market participants
aware of the reasons for these costs and to help ensure a long term solution
to the issue of how to allocate the costs of uplift. (Priority: Medium. First
reported 2011. Status: Partially adopted.)

6 As of November 1, 2018, internal bilateral transactions are no longer used for the calculation of deviations for purposes of allocatingbalancing operating reserve charges. See the 2018 State of the Market Report for PJM, Volume II, Section 3: “Energy Market” at “Internal
Bilateral Transactions” for an analysis of the impact of this change on virtual bidding activity.

250

Section 4 Energy Uplift• The MMU recommends that PJM revise the current uplift (operating

reserve) confidentiality rules in order to allow the disclosure of complete
information about the level of uplift (operating reserve charges) by unit
and the detailed reasons for the level of operating reserve credits by unit
in the PJM region. (Priority: High. First reported 2013. Status: Partiallyadopted.7)• The MMU recommends that PJM pay uplift based on the offer at the lowerof the actual unit output or the dispatch signal MW. (Priority: Medium.
First reported 2018. Status: Not adopted.)• The MMU recommends that PJM eliminate the exemption for fast start

resources (CTs and diesels) from the requirement to follow dispatch.
The performance of these resources should be evaluated in a mannerconsistent with all other resources (Priority: Medium. First reported 2018.
Status: Not adopted.)Conclusion
Competitive market outcomes result from energy offers equal to short run
marginal costs that incorporate flexible operating parameters. When PJM
permits a unit to include inflexible operating parameters in its offer and pays
uplift based on those inflexible parameters, there is an incentive for the unit
to remain inflexible. The rules regarding operating parameters should be
implemented in a way that creates incentives for flexible operations rather
than inflexible operations. The standard for paying uplift should be themaximum achievable flexibility, based on OEM standards for the benchmark
new entrant unit (CONE unit) in the PJM Capacity Market. Applying a weakerstandard effectively subsidizes inflexible units by paying them based on
inflexible parameters that result from lack of investment and that could bemade more flexible. The result both inflates uplift costs and suppresses energy
prices.
It is not appropriate to accept that inflexible units should be paid or set
price based on short run marginal costs plus start up and no load costs. The
7 On September 7, 2018, PJM made a compliance filing for FERC Order No. 844 to publish unit specific uplift credits. The compliance filing
was accepted by FERC on March 21, 2019. 166 FERC ¶ 61,210. PJM began posting unit specific uplift reports on May 1, 2019. 167 FERC ¶61,280 (2019).

© 2021 Monitoring Analytics, LLC

Section 4 Energy Upliftquestion of why units make inflexible offers should be addressed directly. Are
units inflexible because they are old and inefficient, because owners have notinvested in increased flexibility or because they serve as a mechanism forthe exercise of market power? The question of why the inflexible unit was
built, whether it was built under cost of service regulation and whether it isefficient to retain the unit should be answered directly. The question of how toprovide market incentives for investment in flexible units and for investment
in increased flexibility of existing units should be addressed directly. The
question of whether inflexible units should be paid uplift at all should be
addressed directly. Marginal cost pricing without paying uplift to inflexible
units would create incentives for market participants to provide flexible
solutions including replacing inefficient units with flexible, efficient units.
Implementing combined cycle modeling, to permit the energy market model
optimization to take advantage of the versatility and flexibility of combined
cycle technology in commitment and dispatch, would provide significant
flexibility without requiring a distortion of the market rules.
The reduction of uplift payments should not be a goal to be achieved at theexpense of the fundamental logic of the LMP system. For example, the use of
closed loop interfaces to reduce uplift should be eliminated because it is notconsistent with LMP fundamentals and constitutes a form of subjective pricesetting. The same is true of what PJM terms its CT price setting logic. The
same is true of fast start pricing. The same is true of PJM’s proposal to modify
the ORDC in order to increase energy prices and reduce uplift.
Accurate short run price signals, equal to the short run marginal cost ofgenerating power, provide market incentives for cost minimizing production
to all economically dispatched resources and provide market incentives toload based on the marginal cost of additional consumption. The objectiveof efficient short run price signals is to minimize system production costs,
not to minimize uplift. Repricing the market to reflect commitment costs
will create a tradeoff between minimizing production costs and reduction of
uplift. The tradeoff will exist because when commitment costs are included
in prices, the price signal no longer equals the short run marginal cost and© 2021 Monitoring Analytics, LLC

therefore no longer provides the correct signal for efficient behavior formarket participants making decisions on the margin, whether resources,load, interchange transactions, or virtual traders. This tradeoff will be created
by PJM’s fast start pricing proposal (limited convex hull pricing). Fast start
pricing has been approved by FERC subject to a PJM compliance filing on
the definition of fast start resources, and is expected to be implemented in
September 2021.8 Fast start pricing will significantly affect uplift calculations.
When units receive substantial revenues through energy uplift payments,
these payments are not fully transparent to the market, in part because of thecurrent confidentiality rules. As a result, other market participants, including
generation and transmission developers, do not have the opportunity tocompete to displace them. As a result, substantial energy uplift payments
to a concentrated group of units and organizations have persisted. FERC
Order No. 844 authorized the publication of unit specific uplift payments for
credits incurred after July 1, 2019.9 However, Order No. 844 failed to require
the publication of unit specific uplift credits for the largest units receiving
significant uplift payments, inflexible steam units committed for reliability inthe day-ahead market.
One part of addressing the level and allocation of uplift payments is to eliminate
all day-ahead operating reserve credits. It is illogical and unnecessary to pay
units day-ahead operating reserve credits because units do not incur any
costs to run and any revenue shortfalls are addressed by balancing operating
reserve credits.
On July 16, 2020, following its investigation of the issue, the Commission
ordered PJM to revise its rules so that UTCs are required to pay uplift on
the withdrawal side (DEC) only.10 The uplift payments for UTCs began on
November 1, 2020.11
8 See 173 FERC ¶ 61,244 (2020).
9 On March 21, 2019 FERC accepted PJM’s Order No. 844 compliance filing. 166 FERC ¶ 61,210 The filing stated that PJM would begin
posting unit specific uplift reports on May 1, 2019. On April 8, 2019, PJM filed for an extension on the implementation date of the zonal
uplift reports and unit specific uplift reports to July 1, 2019. On June 28, 2019, FERC accepted PJM’s request for extension of effective
dates. 167 FERC ¶ 61,280.
10 See 172 FERC ¶ 61,046.
11 On October 17, 2017, PJM filed a proposed tariff change at FERC to allocate uplift to UTC transactions in the same way uplift is allocatedto other virtual transactions, as a separate injection and withdrawal deviation. FERC rejected the proposed tariff change. See 162 FERC ¶61,019 (2018).

2021 Quarterly State of the Market Report for PJM: January through June 251

2021 Quarterly State of the Market Report for PJM: January through JunePJM needs to pay substantially more attention to the details of uplift payments
including accurately tracking whether units are following dispatch, identifying
the actual need for units to be dispatched out of merit and determining whether
local reserve zones or better definitions of constraints would be a more market
based approach. PJM pays uplift to units even when they do not operate asrequested by PJM, i.e. they do not follow dispatch. PJM uses dispatcher logs asa primary screen to determine if units are eligible for uplift regardless of how
they actually operate or if they followed the PJM dispatch signal. The relianceon dispatcher logs for this purpose is impractical, inefficient, and incorrect.
PJM needs to define and implement rules for determining when units arefollowing dispatch as a primary screen for eligibility for uplift payments. PJM
should not pay uplift to units that do not follow dispatch.
The MMU notifies PJM and generators of instances in which, based on the
PJM dispatch signal and the real time output of the unit, it is clear thatthe unit did not operate as requested by PJM. The MMU sends requests forresettlements to PJM to make these units ineligible for uplift credits. Since
2018, the MMU has identified $13.0 million of incorrect uplift credits.

Energy Uplift Credits Results
The level of energy uplift credits paid to specific units depends on the levelof the resource’s energy offer, the LMP, the resource’s operating parameters
and the decisions of PJM operators. Energy uplift credits result in part fromdecisions by PJM operators, who follow reliability requirements and market
rules, to start resources or to keep resources operating even when LMP isless than the offer price including incremental, no load and startup costs.
Energy uplift payments also result from units’ operational parameters that
require PJM to schedule or commit resources when they are not economic.
The resulting costs not covered by energy revenues are collected as energy
uplift.
Table 4-1 shows the totals for each credit category for the first six monthsof 2020 and 2021.12 In the first six months of 2021, energy uplift credits
increased by $55.7 million or 236.9 percent compared to the first six monthsof 2020.

While energy uplift charges are an appropriate part of the cost of energy,
market efficiency would be improved by ensuring that the level and variabilityof these charges are as low as possible consistent with the reliable operationof the system and consistent with pricing at short run marginal cost. The goal
should be to minimize the total incurred energy uplift charges and to increase
the transactions over which those charges are spread in order to reduce theimpact of energy uplift charges on markets. The result would be to reduce
the level of per MWh charges, to reduce the uncertainty associated withuplift charges and to reduce the impact of energy uplift charges on decisions
about how and when to participate in PJM markets. The result would also be
to increase incentives for flexible operation and to decrease incentives forthe continued operation of inflexible and uneconomic resources. PJM does
not need a flexibility product. PJM needs to provide incentives to existingand new entrant resources to unlock the significant flexibility potential that
already exists and to stop creating incentives for inflexibility.
12 Billing data can be modified by PJM Settlements at any time to reflect changes in the evaluation of energy uplift. The billing data
reflected in this report were current on July 8, 2021.

252

Section 4 Energy Uplift© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Table 4-1 Energy uplift credits by category: January through June, 2020 and 202113(Jan - Jun) 2020 (Jan - Jun) 2021
Type
Credits (Millions) Credits (Millions)
Generators
$3.0
$7.2
Imports$0.0$0.0
Day-Ahead
Load Response
$0.0
$0.0
Canceled Resources
$0.0
$0.0
Generators
$11.2
$55.4
Imports$0.0$0.0
Balancing
Load Response
$0.0
$0.0
Local Constraints Control
$2.1
$4.6
Lost Opportunity Cost
$6.7
$11.1
Day-Ahead$0.0$0.3
Local Constraints Control
$0.0
$0.0
Reactive Services
Lost Opportunity Cost
$0.0
$0.0
Reactive Services
$0.3
$0.5
Synchronous Condensing
$0.0
$0.0
Synchronous Condensing
$0.0
$0.0
Day-Ahead$0.0$0.0Black Start Services
Balancing$0.0$0.0
Testing
$0.1
$0.2
Total
$23.5
$79.2
Category

Change$4.2$0.0($0.0)
$0.0
$44.2
$0.0
$0.0
$2.5
$4.4
$0.2
$0.0
$0.0
$0.1
$0.0
$0.0
$0.0
($0.0)$0.0$55.7

Percent
Change141.3%
NA
NA
NA
392.7%
NANA
119.1%
66.7%
482.0%
NA
NA
36.7%
NA
NA
NA
NA
NA
236.9%

2020
Share
12.7%
0.0%
0.0%
0.0%
47.8%
0.0%
0.0%
9.0%
28.3%
0.2%
0.0%
0.0%
1.4%
0.0%
0.0%
0.0%
0.0%
0.6%
100.0%

2021
Share
9.1%
0.0%
0.0%
0.0%
70.0%
0.0%
0.0%
5.9%
14.0%
0.3%
0.0%
0.0%
0.6%
0.0%
0.0%
0.0%
0.0%
0.2%
100.0%

Characteristics of Credits
Types of Units
Table 4-2 shows the distribution of total energy uplift credits by unit type for 2020 and 2021. Uplift credits increased for all unit types. A combination of factors
led to increased uplift payments in the first six months of 2021, including increased real-time generation from CTs, higher natural gas prices, and increased load.
Uplift credits paid to combustion turbines increased by $50.6 million or 282.9 percent in the first six months of 2021 compared to the same period in 2020. This
increase can largely be attributed to higher natural gas prices and higher reliance on CT generation in real time that was not scheduled in day ahead.
Uplift credits paid to coal units increased by $3.7 million or 112.3 percent in the first six months of 2021 compared with the same period in 2020. This increase
can largely be attributed to a small number of coal units in the DPL, PEPCO, and BGE Zones committed for reliability.
In the first six months of 2021, uplift credits to wind units were $0.2 million, up by 68.0 percent compared to the first six months of 2020.

13 Year to year change is rounded to one tenth of a million, and includes values less than $0.05 million.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 253

2021 Quarterly State of the Market Report for PJM: January through June

Table 4-2 Total energy uplift credits by unit type: January through June, 2020
and 202114 15
Unit Type
Combined Cycle
Combustion Turbine
DieselHydro
Nuclear
Solar
Steam - Coal
Steam - Other
Wind
Total

(Jan - Jun) 2020 (Jan - Jun) 2021
Credits (Millions) Credits (Millions)
$1.7
$2.4
$17.9
$68.5
$0.2
$0.8
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$3.3
$6.9
$0.3
$0.4
$0.1
$0.2
$23.5
$79.2

Change
$0.7
$50.6
$0.6
$0.0
$0.0
$0.0
$3.7
$0.1
$0.1
$55.7

Percent
Change42.6%
282.9%
242.1%
0.0%
0.0%
529.7%
112.3%
22.9%
68.0%
236.9%(Jan - Jun)
2020 Share
7.2%
76.1%
1.0%
0.0%
0.0%
0.0%
13.9%
1.4%
0.4%
100.0%(Jan - Jun)
2021 Share
3.0%
86.5%
1.0%
0.0%
0.0%
0.0%
8.8%
0.5%
0.2%
100.0%

Table 4-3 shows the distribution of energy uplift credits by category and byunit type in the first six months of 2021. The characteristics of the different
unit types explain why uplift in specific categories is paid primarily to specificunit types. For example, the majority of day-ahead credits, 78.5 percent, went
to steam units because steam units tend to be longer lead time units that arecommitted before the operating day. If a steam unit is needed for reliability
and it is uneconomic, it will be committed in the day-ahead energy market
and receive day-ahead credits. Combustion turbines, which, unlike other unit
types, can be committed and decommitted in the real-time market, received
93.8 percent of balancing credits and 96.5 percent of lost opportunity credits.
Combustion turbines committed in the real-time market tend to requirebalancing credits due to inflexible operating parameters, volatile real-time
LMPs, and intraday segment settlements. Combustion turbines with a dayahead schedule and not committed in real time receive lost opportunity
credits when they incur a loss as a result of not operating. A unit incurs a loss
when the real-time LMPs are greater than the day-ahead LMPs at the unit’s
pricing node and the unit’s balancing charges are greater than its day-ahead
revenues.

14 Table 4-2 does not include balancing imports credits and load response credits in the total amounts.
15 Solar units should be ineligible for all uplift payments because they do not follow PJM’s dispatch instructions. The MMU notified PJM ofthe discrepancy.

254

Section 4 Energy Uplift

Table 4-3 Energy uplift credits by unit type: January through June, 2021
Unit Type
Combined Cycle
Combustion Turbine
DieselHydro
Nuclear
Solar
Steam - Coal
Steam - OtherWind
Total (Millions)

Day-Ahead
Generator
15.7%
5.7%
0.1%
0.0%
0.0%
0.0%
74.8%
3.7%
0.0%

Balancing
Generator
2.0%
93.8%
1.0%
0.0%
0.0%
0.0%
2.8%
0.2%
0.2%

Canceled
Resources
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

$7.2

$55.4

$0.0

Local
Lost
Constraints Opportunity
Control
Cost
0.0%
1.1%
99.0%
96.5%
1.0%
1.8%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.6%
$4.6

Reactive
Services
0.0%
97.5%
0.0%
0.0%
0.0%
0.0%
0.0%
2.5%
0.0%

Synchronous
Condensing
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

Black
Start
Services
32.5%
67.5%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

$0.7

$0.0

$0.2

$11.1

Day-Ahead Unit Commitment for Reliability
PJM may schedule units as must run in the day-ahead energy market thatwould otherwise not have been committed in the day-ahead market whenneeded in real time to address reliability issues. Such reliability issues include
reactive transfer interface control needed to maintain system reliability ina zone or reactive service.16 Participants can submit units as self scheduled(must run), meaning that the unit must be committed, but a unit submitted
as must run by a participant is not eligible for day-ahead operating reserve
credits.17 Units committed for reliability by PJM are eligible for day-ahead
operating reserve credits and may set LMP if raised above economic minimum
and follow the dispatch signal.
Table 4-4 shows total day-ahead generation and the subset of that generationcommitted for reliability by PJM. There was a significant increase in the dayahead generation committed for reliability by PJM, from 229 GWh in the firstsix months of 2020 to 481 GWh in the first six months of 2021. The increase
in day-ahead generation committed for reliability by PJM was due to anincreased need to commit uneconomic units in the PEPCO and BGE zones forreliability.
16 See OA Schedule 1 § 3.2.3(b).
17 See PJM. “PJM Markets Gateway User Guide,” Section Managing Unit Data (version July 16, 2018) at 33, <http://www.pjm.com/-/media/
etools/markets-gateway/markets-gateway-user-guide.ashx?la=en>.

© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Table 4-4 Day-ahead generation committed for reliability (GWh): January
2020 through June 2021
2020
Total Day-Ahead Day-Ahead PJM Must
Generation (GWh) Run Generation (GWh)Jan
71,1160
Feb65,827
5
Mar63,0586
Apr55,09141
May58,114
117
Jun
69,65160
Jul85,58563
Aug79,17388
Sep
65,105145
Oct59,974
107
Nov
60,0787
Dec
71,59127
Total (Jan - Jun)
382,857
229
Total
804,363
666

Share
0.0%
0.0%
0.0%
0.1%
0.2%
0.1%
0.1%
0.1%
0.2%
0.2%
0.0%
0.0%
0.1%
0.1%

2021
Total Day-Ahead Day-Ahead PJM Must
Generation (GWh) Run Generation (GWh)
73,63595
71,35413
64,713
209
57,137
13
60,95726
72,987
126400,783
400,783

Pool scheduled units and units committed for reliability are made whole inthe day-ahead energy market if their total offer (including no load and startup
costs) is greater than the revenues from the day-ahead energy market. Such
units are paid day-ahead uplift (operating reserve credits). Total day-ahead
operating reserve credits in the first six months of 2021 were $7.2 million. The
top 10 units received $5.5 million or 76.0 percent of all day-ahead operating
reserve credits. These units were large units with long commitment times andinflexible operating parameters.
It is illogical and unnecessary to pay units day-ahead operating reservesbecause units do not incur any costs to run in the day-ahead market and any
revenue shortfalls are addressed by balancing operating reserve payments.
Table 4-5 shows the total day-ahead generation committed for reliability
by PJM by category. In the first six months of 2021, 76.1 percent of the
day-ahead generation committed for reliability by PJM received operating
reserve credits, 74.3 percent paid as day-ahead operating reserve credits and1.7 percent paid as reactive services credits. The remaining 23.9 percent was© 2021 Monitoring Analytics, LLC

481
481

Share
0.1%
0.0%
0.3%
0.0%
0.0%
0.2%

0.1%
0.1%

economic, meaning prices covered all resource operating costs and the unit
did not receive operating reserve credits.
Table 4-5 Day-ahead generation committed for reliability by credit category(GWh): January through June, 2021
Jan
Feb
Mar
Apr
May
Jun
Total (Jan - Jun)
Share

Reactive Services Day-Ahead Operating(GWh)
Reserves (GWh)
7.0
44.3
1.3
4.1
0.0
179.6
0.0
7.2
0.0
20.6
0.0
101.8
8.3
357.6
1.7%
74.3%

Economic (GWh)
43.2
7.5
29.5
5.9
5.1
23.8
115.1
23.9%

Total (GWh)
94.6
12.9
209.1
13.1
25.8
125.6
481.0
100.0%

Total day-ahead operating reserve credits in the first six months of 2021 were
$7.2 million, of which $3.8 million or 52.8 percent was paid to units committed
for reliability by PJM, and not scheduled to provide reactive services. An
additional 3.6 percent, or $0.3 million, was paid to units scheduled to provide
reactive services.

2021 Quarterly State of the Market Report for PJM: January through June 255

2021 Quarterly State of the Market Report for PJM: January through June

Balancing Operating Reserve Credits
Balancing operating reserve (BOR) credits are paid to resources that operate
as requested by PJM that do not recover their operating costs from market
revenues. BOR credits are calculated as the difference between a resource’s
revenues (day-ahead market, balancing market, reserve markets, reactive
service credits, and day-ahead operating reserve credits) and its real-timecosts (startup, no load, and energy offer). Combustion turbines (CTs) received$52.0 million or 93.8 percent of all balancing operating reserve (BOR) credits
in the first six months of 2021. The majority of these credits, 98.8 percent,are paid to CTs that are committed in real time either without or outside of a
day-ahead schedule.18 Uplift is higher than necessary because settlement rules
do not include all revenues and costs for the entire day.

Balancing operating reserve credits for generators increased by 392.7 percent
in the first six months of 2021 compared to the first six months of 2020.
Rising natural gas prices contributed to CTs running uneconomically more
frequently combined with PJM’s need to run CTs more frequently resulted
in increased balancing operating reserve credits during the first six monthsof 2021. The overall increase in credits in the DOM, COMED, and AEP Zones
accounted for 56.8 percent of the total annual change in balancing operating
reserve credits.
The credits paid to combustion turbines committed in real time without a dayahead commitment occurs despite the fact that the total combustion turbine
MW committed in the day-ahead energy market are similar to the totals in
the real-time energy market. Table 4-6 shows the monthly day-ahead andreal-time generation by combustion turbines. In the first six months of 2021,
generation by combustion turbines was 31.0 percent higher in the real-timeenergy market than in the day-ahead energy market, although this varied bymonth. Table 4-6 shows that only 2.7 percent of generation from combustion
turbines in the day-ahead market was uneconomic, while 50.6 percent ofgeneration from combustion turbines in the real-time market was uneconomic
and required $52.0 million in BOR credits. This increase in uneconomic realtime generation resulted in increased BOR credits during the first six monthsof 2021.

Uplift is also higher than necessary because settlement rules do not disqualify
units from receiving uplift when they do not follow PJM’s dispatch instructions.
Units are disqualified from receiving uplift when the PJM dispatcher is able toidentify units that are not following the dispatch signals, and after agreementwith the generator, the dispatch reason is changed to self scheduled. PJM
dispatchers should not be forced to decide which units qualify for uplift. The
MMU recommends that PJM develop and implement an accurate metric todefine when a unit is following dispatch, instead of relying on PJM dispatchers’
manual determinations, to evaluate eligibility for receiving balancing
operating reserve credits and for assessing generator deviations. As part ofTable 4-6 Characteristics of day-ahead and real-time generation by
the metric, the MMU recommends that
combustion turbines eligible for operating reserve credits: January throughPJM designate units whose offers areJune, 2021
flagged for fixed generation in Markets
Percent of Day-Ahead
Day-Ahead
Percent of Real-TimeBalancing Generation Difference
Gateway as not eligible for uplift. Units
Day-Ahead Generation that was Generator Credits
Real-Time Generation that was Generator Credits as a Percent of RealMonth
Generation (GWh)
Noneconomic(Millions) Generation (GWh)
Noneconomic(Millions)Time Generationthat are flagged for fixed generation are
Jan
240
6.5%
$0.0
483
62.7%
$4.4
50.3%
not dispatchable. Following dispatch
Feb
298
5.8%
$0.1
485
57.4%
$9.9
38.6%
Mar
309
2.1%
$0.1
471
51.6%
$4.5
34.5%
is an eligibility requirement for uplift
Apr
662
2.1%
$0.0
1,270
62.5%
$16.0
47.8%
compensation.
May
845
1.7%
$0.2
890
48.5%
$5.0
5.1%
Jun
Total (Jan - Jun)

1,541
3,895

2.3%
2.7%

$0.0
$0.4

2,042
5,642

39.3%
50.6%

$12.2
$52.0

24.5%
31.0%

18 Operating outside of a day-ahead schedule refers to units that operate for a period either before or after their day-ahead schedule, or arecommitted in the real-time market and do not have a day-ahead schedule for any part of the day.

256

Section 4 Energy Uplift© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Balancing operating reserve credits to generators in the first six months of2021 were $55.4 million, of which $51.3 million, or 92.6 percent, was paid
to combustion turbines operating without or outside a day-ahead schedule(Table 4-7).
Table 4-7 and Table 4-8 show real-time generation by combustion turbinesby day-ahead commitment status during the first six months of 2021 and2020. CTs that operated on a day-ahead schedule during the first six monthsof 2021 constituted 48.6 percent of real-time generation by CTs, of which
36.7 percent (17.8 percent of real-time generation) was uneconomic in thereal-time market and received $0.6 million in BOR credits. CTs that operated
on a day-ahead schedule during the first six months of 2020 constituted 69.9
percent of real-time generation by CTs, of which 15.0 percent (10.5 percent of
real-time generation) was uneconomic in the real-time market and received
zero BOR credits.
In the first six months of 2021, 51.4 percent of real-time generation by CTs
was from CTs that operated outside of a day-ahead schedule, of which 63.7
percent (32.7 percent of real-time generation) was uneconomic in the realtime market and received $51.3 million in BOR credits. In the first six monthsof 2020, 30.1 percent of real-time generation by CTs was from CTs that
operated outside of a day-ahead schedule, of which 35.9 percent (10.8 percent
of real-time generation) was uneconomic in the real-time market and received$9.6 million in BOR credits.

CTs that operate on a day ahead schedule tend to receive lower BOR credits
because it is more likely that the day-ahead LMPs will support (prices above
offer) committing the units because the day-ahead model optimizes the system
for all 24 hours unlike in real time when PJM uses ITSCED to optimize CT
commitments with a roughly two hour look ahead. In addition, uplift rules
continue to define all day ahead scheduled hours as one segment for the uplift
calculation (in which profits and losses during all hours offset each other)while in real time there are shorter segments defined by the minimum run
time. Losses during the minimum run time segment are not offset by profits
made in other segments on that day.
There are multiple reasons why the commitment of CTs is different in the
day-ahead and real-time markets, including differences in the hourly patternof load, and differences in interchange transactions. Modeling differences
between the day-ahead and real-time markets also affect CT commitment,
including: the modeling of different transmission constraints in the dayahead and real-time market models; the exclusion of soak time for generatorsin the day-ahead market model; and the different optimization time periods
used in the day-ahead and real-time markets.

During the first six months of 2021, real-time generation operating on a dayahead schedule decreased significantly compared to the first six months of
2020, while real-time generation operating outside of a day-ahead schedule
increased significantly. This shift of real-time generation operating on a dayahead schedule to real-time generation operating outside of a day-aheadschedule is the primary source of the increase of BOR credits and constitutes
92.6 percent of all BOR credits. Balancing operating reserves for real-time
generation committed on a day-ahead schedule are calculated differently thanfor real-time generation committed outside of a day-ahead schedule, and thisdifference resulted in increased credits.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 257

2021 Quarterly State of the Market Report for PJM: January through June

Table 4-7 Real-time generation by combustion turbines by day-ahead commitment: January through June, 2021

Month
Jan
Feb
Mar
Apr
May
Jun
Total (Jan - Jun)

Real-Time Generation Operating on a Day-Ahead Schedule
Percent of Real-TimeBalancing
Generation
Share of Real- Generation that was Generator Credits(GWh) Time Generation
Noneconomic(Millions)
154
31.8%
44.2%
$0.1
184
38.0%
32.3%
$0.2
214
45.5%
37.1%
$0.1
511
40.2%
44.9%
$0.1
528
59.3%
41.1%
$0.0
1,153
56.4%
30.6%
$0.2
2,744
48.6%
36.7%
$0.6

Real-Time Generation Operating Outside of a Day-Ahead Schedule
Percent of Real-TimeBalancing
Generation
Share of Real- Generation that was Generator Credits(GWh) Time Generation
Noneconomic(Millions)
330
68.2%
71.3%
$4.3
301
62.0%
72.8%
$9.7
257
54.5%
63.7%
$4.4
759
59.8%
74.4%
$15.9
362
40.7%
59.3%
$4.9
890
43.6%
50.5%
$12.0
2,898
51.4%
63.7%
$51.3

Table 4-8 Real-time generation by combustion turbines by day-ahead commitment: January through June, 2020

Month
Jan
Feb
Mar
Apr
May
Jun
Total

Real-Time Generation Operating on a Day-Ahead Schedule
Percent of Real-TimeBalancing
Generation
Share of Real- Generation that was Generator Credits(GWh) Time Generation
Noneconomic(Millions)
363
66.1%
3.8%
$0.0
241
76.1%
4.3%
$0.0
316
69.1%
4.8%
$0.0
257
65.2%
16.9%
$0.0
579
70.2%
15.2%
$0.1
1,210
71.2%
22.8%
$0.1
2,966
69.9%
15.0%
$0.2

Real-Time Generation Operating Outside of a Day-Ahead Schedule
Percent of Real-TimeBalancing
Generation
Share of Real- Generation that was Generator Credits(GWh) Time Generation
Noneconomic(Millions)
186
33.9%
36.4%
$1.5
76
23.9%
32.3%
$0.6
141
30.9%
27.9%
$0.8
137
34.8%
40.3%
$0.8
246
29.8%
45.2%
$1.7
489
28.8%
32.6%
$4.4
1,275
30.1%
35.9%
$9.6

Lost Opportunity Cost Credits
Balancing operating reserve lost opportunity cost (LOC) credits are intended to provide an incentive for units to follow PJM’s dispatch instructions when
PJM’s dispatch instructions deviate from a unit’s desired or scheduled output. LOC credits are paid under two different scenarios. The first scenario occurs if aunit of any type generating in real time with an offer price lower than the real-time LMP at the unit’s bus is manually reduced or suspended by PJM due to atransmission constraint or other reliability issue. In this scenario the unit will receive a credit for LOC based on its desired output. Such units are not actuallyforgoing an option to increase output because the reliability of the system and in some cases the generator depend on reducing output. This LOC is referred
to as real-time LOC. The second scenario occurs if a combustion turbine or diesel engine is scheduled to operate in the day-ahead energy market, but it is not
requested by PJM in real time. In this scenario the unit will receive a credit which covers any loss in the day-ahead financial position of the unit plus thebalancing energy market position. This LOC is referred to as day-ahead LOC.
Table 4-9 shows monthly day-ahead and real-time LOC credits in the first six months of 2020 and 2021. In the first six months of 2021, LOC credits increased
by $4.4 million or 66.7 percent compared to the first six months of 2020, including a $5.0 million increase in day-ahead LOC and a $0.6 million decrease inreal-time LOC.

258

Section 4 Energy Uplift© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

In the first six months of 2021, wind units received less than $0.1 million of real-time LOC, up by 50.0 percent from the first six months of 2020. In the first six
months of 2021, real-time LOC credits to wind units were 40.6 percent of the uplift payments to wind units. Wind units in the AEP and COMED Zones received
100 percent of real-time LOC credits to wind units.
Table 4-9 Monthly lost opportunity cost credits (Millions): January 2020 through June 2021

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total (Jan - Jun)
Share (Jan - Jun)
Total
Share

Day-Ahead Lost
Opportunity Cost
$0.5
$0.4
$0.6
$0.3
$0.8
$3.3
$4.2
$4.4
$1.6
$0.9
$0.8
$0.4
$5.9
88.7%
$18.2
93.9%

2020
Real-Time Lost
Opportunity Cost
$0.0
$0.0
$0.1
$0.5
$0.0
$0.1
$0.1
$0.1
$0.0
$0.0
$0.0
$0.2
$0.75
11.3%
$1.2
6.1%

Total
$0.5
$0.4
$0.6
$0.9
$0.8
$3.4
$4.2
$4.5
$1.7
$0.9
$0.8
$0.6
$6.6
100.0%$19.3
100.0%

Day-Ahead Lost
Opportunity Cost
$0.4
$0.5
$3.5
$0.6
$2.8
$3.1

2021
Real-Time Lost
Opportunity Cost
$0.0
$0.0
$0.0
$0.0
$0.0
$0.1

Total
$0.4
$0.6
$3.6
$0.6
$2.8
$3.2

$10.9
98.2%
$10.9
98.2%

$0.20
1.8%
$0.2
1.8%

$11.1
100.0%$11.1
100.0%

Table 4-10 shows day-ahead generation for combustion turbines and diesels, including scheduled day-ahead generation, scheduled day-ahead generation notrequested in real time, and day-ahead generation receiving LOC credits. In the first six months of 2021, 12.5 percent of day-ahead generation by combustion
turbines and diesels was not requested in real time, 5.0 percentage points lower than in the first six months of 2020. In the first six months of 2021 compared to
the first six months of 2020, day-ahead generation by combustion turbines decreased by 12.9 percent, day-ahead generation not requested in real time decreased
by 37.8 percent, and day-ahead generation not requested in real time receiving lost opportunity costs decreased by 64.0 percent. Unlike steam units, combustion
turbines that clear the day-ahead energy market have to be instructed by PJM to come online in real time.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 259

2021 Quarterly State of the Market Report for PJM: January through June

Table 4-10 Day-ahead generation from combustion turbines and diesels (GWh): January 2020 through June 2021
2020

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total (Jan - Jun)
Share (Jan - Jun)

Day-Ahead
Generation (GWh)
873
653
729
656
1,126
2,278
4,759
2,728
1,696
1,677
1,051
641
6,315
100.0%

Day-Ahead Generation
Not Requested in RealTime (GWh)
171
114
103
95
188
437
589
433
342
155
119
61
1,108
17.5%

2021
Day-Ahead Generation
Day-Ahead Generation
Not Requested in RealDay-Ahead Generation Not Requested in RealTime Receiving LOC
Day-Ahead Not Requested in RealTime Receiving LOC
Credits (GWh) Generation (GWh)Time (GWh)
Credits (GWh)
73
486
69
17
49
507
53
12
55
527
66
17
36
957
63
16
80
1,153
214
55
243
1,869
224
76
271
205
129
83
66
24
537
5,499
689
193
8.5%
100.0%
12.5%
3.5%

Uplift Eligibility
In PJM, units can have either a pool scheduled or self scheduled commitment status. Pool scheduled units are committed by PJM as a result of the day-ahead
and real-time market clearing while self scheduled units are committed by generation owners. Table 4-11 provides a description of commitment and dispatch
status, uplift eligibility and the ability to set price.19 In the day-ahead energy market only pool scheduled resources are eligible for day-ahead operating reserve
credits. A unit may self schedule in day ahead to clear and then pool schedule in subsequent days to remain online, in which case they would be eligible for
uplift for the subsequent days. In the real-time energy market only pool scheduled resources that follow PJM’s dispatch are eligible for balancing operating
reserve credits. Units are paid day-ahead operating reserve credits based on their scheduled operation for the entire day. Balancing operating reserve credits arepaid on a segmented basis for each period defined by the greater of the day-ahead schedule and minimum run time. Resources receive day-ahead and balancing
operating reserve credits only when they are eligible and unable to recover their operating cost for the day or segment. 20

19 PJM has modified the basic rules of eligibility to set price using its CT price setting logic.
20 Resources do not recover their operating cost when market revenues for the day are less than the short run marginal cost defined by the startup, no load, and incremental offer curve.

260

Section 4 Energy Uplift© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Table 4-11 Dispatch status, commitment status and uplift eligibility21

Dispatch Status
Block Loaded
Economic Minimum

Dispatchable

Dispatch Description
MWh offered to PJM as a single MWhblock which is not dispatchable
MWh from the nondispatchable economic
minimum component for units that offer adispatchable range to PJM
MWh above the economic minimum levelfor units that offer a dispatchable range
to PJM

Commitment Status
Self Scheduled
Pool Scheduled and following(units committed by the
PJM’s dispatch signal
generation owner)(units committed by PJM)

Eligible to
Set LMPNo

Not eligible to receive uplift

Eligible to receive upliftNo

Not eligible to receive uplift

Eligible to receive uplift

Yes

Only eligible to receive LOC credits
if dispatched down by PJMEligible to receive uplift

Table 4-12 shows day-ahead and real-time generation by commitment and dispatch status.
Table 4-12 Day-ahead and real-time generation by offer status and eligibility to set LMP (GWh): January through June, 2021

Day-Ahead Generation
Share of Day-Ahead
Real-Time Generation
Share of Real-Time

Self Scheduled
Economic
Dispatchable Minimum
47,07898,472
11.7%
24.6%
41,713
94,482
10.4%
23.5%

Block
Loaded87,111
21.7%
87,476
21.7%

Pool Scheduled
Economic
Dispatchable Minimum
78,24979,477
19.5%
19.8%
78,64487,490
19.5%
21.7%

Block
Total Pool Total Self
Loaded Total GWh Scheduled Scheduled
10,397400,783
168,123
232,6612.6%
100.0%
41.9%
58.1%
12,522
402,326
178,656
223,6703.1%
100.0%
44.4%
55.6%

Total Generation
Eligible to Set
Price
125,32731.3%
120,356
29.9%

Economic and Noneconomic Generation22
Economic generation includes units scheduled day ahead by PJM, or produce energy in real time, at an incremental offer less than or equal to the LMP at theunit’s bus. Noneconomic generation includes units scheduled day ahead by PJM, or produce energy in real time, at an incremental offer greater than the LMP
at the unit’s bus.
The MMU analyzed PJM’s day-ahead and real-time generation eligible for operating reserve credits to determine the shares of economic and noneconomic
generation. Each unit’s hourly generation was determined to be economic or noneconomic based on the unit’s hourly incremental offer, excluding the hourly noload and any applicable startup cost. A unit could be economic for every hour during a day or segment, but still receive operating reserve credits because theenergy revenues did not cover the hourly no load and startup cost. A unit could be noneconomic for multiple hours and not receive operating reserve credits
when the total revenues covered the total offer (including no load and startup cost) for the entire day or segment.
Table 4-13 shows the day-ahead and real-time economic and noneconomic generation from units eligible for operating reserve credits as defined by PJM. In thefirst six months of 2021, 89.1 percent of the day-ahead generation MWh eligible for operating reserve credits was economic and 62.3 percent of the real-time
21 PJM allows block loaded CTs to set LMP by relaxing the economic minimum by 10 to 20 percent using CT price setting logic.
22 The analysis of economic and noneconomic generation is based on units’ incremental offers, the value used by PJM to calculate LMP. The analysis does not include no load or startup costs.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 261

2021 Quarterly State of the Market Report for PJM: January through June

generation MWh eligible for operating reserve credits was economic. A unit’s
generation MWh may be noneconomic for a portion of their daily generationand economic for the rest.
Table 4-13 Economic and noneconomic generation from units eligible for
operating reserve credits (GWh): January through June, 2021
Energy Market
Day-Ahead
Real-Time

Economic
Generation
149,724
94,092

Noneconomic
Generation
18,39856,827

Total Eligible
Generation
168,123
150,919

Economic
Generation
Percent
89.1%
62.3%

Noneconomic
Generation
Percent
10.9%
37.7%

2019 and would now require a directive from FERC for them to be resettled.
The MMU continues to bring new cases to the attention of PJM.
The MMU identifies units that are not following the dispatch signal, andthat are therefore not eligible to receive uplift payments. These findings
are communicated to PJM and/or Market Sellers. The units are identified
by comparing their actual generation to the dispatch level that they shouldhave achieved based on the real-time LMP, unit operating parameters (e.g.
economic minimum, maximum and ramp rate) and energy offer.

Concentration of Energy Uplift Credits
Noneconomic generation only leads to operating reserve credits when a unit isunable to recover its operating costs for the entire day or segment. Table 4-14
shows the generation receiving day-ahead and balancing operating reserve
credits. In the first six months of 2021, 1.3 percent of the day-ahead generation
eligible for operating reserve credits received credits and 1.8 percent of thereal-time generation eligible for operating reserve credits received credits.
Table 4-14 Generation receiving operating reserve credits (GWh): January
through June, 2021
Energy Market
Day-Ahead
Real-Time

Generation Eligible forOperating Reserve Credits
168,123
150,919

Generation Receiving
Operating Reserve Credits
2,177
2,647

Generation Receiving
Operating Reserve Credits
Percent
1.3%
1.8%

The recipients of uplift payments are highly concentrated by unit and bycompany. This concentration results from a combination of unit operating
parameters, PJM’s persistent need to commit specific units out of merit inparticular locations and the fact that a lack of full transparency has made it
more difficult for competition to affect these payments.23
Figure 4-1 shows the concentration of energy uplift credits. The top 10 units
received 16.8 percent of total energy uplift credits in the first six months of2021, compared to 19.1 percent in the first six months of 2020. In the firstsix months of 2021, 236 units received 90 percent of all energy uplift credits,
compared to 211 units in the first six months of 2020.

Uplift Resettlement
Some units have been incorrectly paid uplift despite not meeting uplift
eligibility requirements, such as not following dispatch, not having the correctcommitment status, or not operating with proper offer parameters. The MMU
has requested that PJM correctly resettle the uplift payments in these cases.
Since 2018, the cumulative resettlement requests totaled $13.0 million. Of
that amount, PJM has agreed and resettled 10.6 percent of the requests, 86.3
percent remains pending. The remaining 3.1 percent occurred prior to June
23 As a result of FERC Order No. 844, PJM began publishing total uplift credits by unit by month for credits incurred on and after July 1,
2019 on September 10, 2019.

262

Section 4 Energy Uplift© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Figure 4-1 Cumulative share of energy uplift credits: January through June,
2020 and 2021 by unit
100%
211

Accumulated Percent of Energy Uplift Credits90%

Jan - Jun 2020

236

Table 4-15 Top 10 units and organizations energy uplift credits: January
through June, 2021

Top 10 Units Jan - Jun 2020
Top 50 Units Jan - Jun 2020

80%

Table 4-15 shows the credits received by the top 10 units and top 10
organizations in each of the energy uplift categories paid to generators in
2021.

Top 100 Units Jan - Jun 2020

70%

Units with 90% of Credits in Jan - Jun 2020

67.4%

Category
Day-AheadJan - Jun 2021

60%
50%

62.2%

Top 10 Units Jan - Jun 2021
Top 50 Units Jan - Jun 2021

49.3%

Top 100 Units Jan - Jun 2021

Balancing

Units with 90% of Credits in Jan - Jun 2021

42.8%

40%

Reactive Services
Synchronous Condensing
Black Start Services
Total

30%
20%

19.1%
16.8%

10%
0%

0

Type
Generators
Canceled Resources
Generators
Local Constraints Control
Lost Opportunity Cost

100

200

300

400

500
Number of units

600

700

800

900

1,000

Top 10 Units
Credits
Credits(Millions)
Share
$5.5
76.0%
$0.0
0.0%
$8.0
14.5%
$4.6
98.0%
$3.7
33.7%
$0.7
100.0%
$0.0
0.0%
$0.1
53.2%
$13.3
16.8%

Top 10 Organizations
Credits
Credits(Millions)
Share
$6.9
96.1%
$0.0
0.0%
$41.4
74.6%
$4.6
100.0%
$9.4
84.9%
$0.7
100.0%
$0.0
0.0%
$0.1
90.6%
$56.6
71.4%

Table 4-16 shows balancing operating reserve credits received by the top 10
units identified for reliability or for deviations in each region. In the first six
months of 2021, 59.2 percent of all credits paid to these units were allocatedas charges to deviations while the remaining 40.8 percent were paid forreliability reasons.
Table 4-16 Balancing operating reserve credits to top 10 units as charged bycategory and region: January through June, 2021
Credits (Millions)Share© 2021 Monitoring Analytics, LLC

RTO
$2.8
35.0%

Reliability
East
$0.5
5.8%

West
$0.0
0.0%

RTO
$4.2
51.9%

Deviations
East
$0.6
7.2%

West
$0.0
0.1%

Total
$8.0
100.0%

2021 Quarterly State of the Market Report for PJM: January through June 263

2021 Quarterly State of the Market Report for PJM: January through June

In the first six months of 2021, concentration in all energy uplift credit categories was high.24 25 The HHI for energy uplift credits was calculated based on eachorganization’s share of daily credits for each category.26 Table 4-17 shows the average HHI for each category. HHI for day-ahead operating reserve credits togenerators was 7670, for balancing operating reserve credits to generators was 2882, for lost opportunity cost credits was 6595 and for reactive services credits
was 9811. All of these HHI values are characterized as highly concentrated.
Table 4-17 Daily energy uplift credits HHI: January through June, 2021
Category
Day-Ahead

BalancingType
Generators
Imports
Load Response
Canceled Resources
Generators
Imports
Load Response
Lost Opportunity Cost

Reactive Services
Synchronous Condensing
Black Start Services
Total

Average
7670
NA
NA
NA
2882
NA
NA
6595
9811
NA
9772
2610

Minimum
1842
NA
NA
NA
725
NA
NA
1480
5088
NA
5275
696

Maximum
10000
NA
NA
NA
10000
NA
NA
10000
10000
NA
10000
7893

Highest Market
Share (One day)
100.0%
NA
NA
NA
100.0%
NA
NA
100.0%
100.0%
NA
100.0%
99.3%

Highest Market
Share (All days)
37.0%
NA
NA
NA
20.8%
NA
NA
26.0%
93.7%
NA
21.8%
18.8%

Unit Specific Uplift Payments
FERC Order No. 844 allows PJM and the MMU to publish unit specific uplift payments by category by month. Table 4-18 through Table 4-21 show the top 10
recipients of total uplift, day-ahead operating reserve credits and lost opportunity cost credits. The top 10 units receiving uplift credits received 16.8 percent of
all credits, with the top recipient receiving 2.2 percent. The top 10 units receiving day-ahead operating reserves received 76.0 percent. The top 10 recipients ofbalancing operating reserves received 14.5 percent of balancing operating reserve credits. The top 10 recipients of lost opportunity cost credits received 33.7
percent of total lost opportunity cost credits.

24 See the 2020 State of the Market Report for PJM, Volume 2, Section 3: “Energy Market” at “Market Concentration” for a discussion of concentration ratios and the Herfindahl-Hirschman Index (HHI).
25 Table 4-16 excludes local constraint control categories.
26 Concentration is measured using the entity (or entities) to which the uplift credit is paid.

264

Section 4 Energy Uplift© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Table 4-18 Top 10 recipients of total uplift: January through June, 2021
Rank
Unit Name
1
BC BRANDON SHORES 2 F
2DAY GREENVILLE 1 CT
3DAY GREENVILLE 4 CT
4DPL INDIAN RIVER 4 F
5VP MARSHRUN 2 CT
6
DAY GREENVILLE 3 CT
7
VP MARSHRUN 1 CT
8
PEP MORGANTOWN 1 F
9VP MARSHRUN 3 CT
10
VP LOUISA 5 CT
Total of Top 10
Total Uplift Credits

Zone
BGE
DAY
DAY
DPL
DOM
DAY
DOM
PEPCO
DOM
DOM

Total Uplift
Credit$1,762,870$1,538,258$1,403,390$1,302,160$1,281,221$1,275,524$1,224,146$1,200,084$1,182,219$1,136,033$13,305,906$79,235,400

Share of Total
Uplift Credits
2.2%
1.9%
1.8%
1.6%
1.6%
1.6%
1.5%
1.5%
1.5%
1.4%
16.8%
100.0%

Table 4-19 Top 10 recipients of day-ahead generation credits: January
through June, 2021
Rank
Unit Name
1
BC BRANDON SHORES 2 F
2PEP MORGANTOWN 1 F
3DPL INDIAN RIVER 4 F
4BC BRANDON SHORES 1 F
5DPL WILDCAT POINT 1 CC
6
VP BRUNSWICK 1CC
7
PL BRUNNER ISLAND 1 F
8BC WAGNER 3 F
9PEP MORGANTOWN 2 F
10VP CLOVER 2 F
Total of Top 10
Total day-ahead operating reserve credits© 2021 Monitoring Analytics, LLC

Zone
BGE
PEPCO
DPL
BGE
DPL
DOM
PPL
BGE
PEPCO
DOM

Day-Ahead
Share of DayOperating Ahead Operating
Reserve Credit Reserve Credits$1,618,871
22.5%$1,165,694
16.2%$1,007,435
14.0%$467,539
6.5%$314,247
4.4%$280,850
3.9%$199,003
2.8%$187,090
2.6%$124,369
1.7%$92,678
1.3%$5,457,775
76.0%$7,183,628
100.0%

Table 4-20 Top 10 recipients of balancing operating reserve credits: January
through June, 2021

Rank
Unit Name
1
VP MARSHRUN 2 CT
2VP MARSHRUN 1 CT
3
VP MARSHRUN 3 CT
4VP LOUISA 5 CT
5FE LEMOYNE 1 CT
6
FE LEMOYNE 2 CT
7
AEP ROBERT P MONE 2 CT
8
EKPC JK SMITH 10 CT
9AEP ROBERT P MONE 1 CT
10
AEP ROBERT P MONE 3 CT
Total of Top 10
Total balancing operating reserve credits

Zone
DOM
DOM
DOM
DOM
ATSI
ATSI
AEP
EKPC
AEP
AEP

BalancingOperatingReserve Credit$1,240,592$1,214,139$1,162,531$1,068,805$671,147$589,444$539,801$525,312$521,996$507,526$8,041,294$55,430,471

Share of
BalancingOperatingReserve Credits
2.2%
2.2%
2.1%
1.9%
1.2%
1.1%
1.0%
0.9%
0.9%
0.9%
14.5%
100.0%

Table 4-21 Top 10 recipients of lost opportunity cost credits: January throughJune, 2021
Rank
Unit Name1
DPL COMM CHESAPEAKE - NEW CHURCH 3 CT
2DPL COMM CHESAPEAKE - NEW CHURCH 4 CT
3DPL COMM CHESAPEAKE - NEW CHURCH 5 CT
4DPL COMM CHESAPEAKE - NEW CHURCH 7 CT
5DPL COMM CHESAPEAKE - NEW CHURCH 2 CT
6
VP FOUR RIVERS 1 CT
7
VP DOSWELL 2 CT
8DPL COMM CHESAPEAKE - NEW CHURCH 6 CT
9
VP DOSWELL 3 CT
10
FE LEMOYNE 1 CT
Total of Top 10
Total lost opportunity cost credits

Zone
DPL
DPL
DPL
DPL
DPL
DOM
DOM
DPL
DOM
ATSI

Share of Lost
Lost Opportunity Opportunity Cost
Cost Credit
Credits$593,804
5.4%$545,976
4.9%$471,660
4.3%$406,181
3.7%$327,493
3.0%$312,587
2.8%$278,367
2.5%$275,766
2.5%$265,267
2.4%$258,916
2.3%$3,736,018
33.7%$11,080,105
100.0%

2021 Quarterly State of the Market Report for PJM: January through June 265

2021 Quarterly State of the Market Report for PJM: January through June

Credits and Charges Categories
Energy uplift charges include day-ahead and balancing operating reserves, reactive services, synchronous condensing and black start services categories. Totalenergy uplift credits paid to PJM participants equal the total energy uplift charges paid by PJM participants. Table 4-22 and Table 4-23 show the categories ofcredits and charges and their relationship. These tables show how the charges are allocated.
Table 4-22 Day-ahead and balancing operating reserve credits and charges
Credits Received For:

Credits Category:

Charges Category:

Charges Paid By:

Day-Ahead
Day-Ahead Import Transactions and Day-Ahead Operating Reserve Transaction
Generation Resources Day-Ahead Operating Reserve Generator
Economic Load Response Resources

Day-Ahead Operating Reserve

Day-Ahead Operating Reserves for Load
Response

Day-Ahead Operating Reserve for Load
Response

Unallocated Negative Load Congestion Charges
Unallocated Positive Generation Congestion Credits

Unallocated Congestion

Day-Ahead Load
Day-Ahead Export Transactions
Decrement Bids & UTCs
Day-Ahead Load
Day-Ahead Export Transactions
Decrement Bids & UTCs
Day-Ahead Load
Day-Ahead Export Transactions
Decrement Bids & UTCs

in RTO Regionin RTO Regionin RTO Region

Balancing

Generation Resources

Canceled Resources
Lost Opportunity Cost (LOC)
Real-Time Import Transactions
Economic Load Response Resources

266

Section 4 Energy Uplift

Balancing Operating
Reserve Generator
Balancing Operating Reserve Startup
Cancellation
Balancing Operating Reserve LOC
Balancing Operating
Reserve Transaction
Balancing Operating Reserves for Load
Response

Balancing Operating Reserve for
Reliability
Balancing Operating Reserve for
Deviations
Balancing Local Constraint

Real-Time Load plus Real-Time Export
Transactionsin RTO, Eastern orWestern Region

Deviations
Applicable Requesting Party

Balancing Operating Reserve for
Deviations

Deviationsin RTO Region

Balancing Operating Reserve for Load
Response

Deviationsin RTO Region© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Table 4-23 Reactive services, synchronous condensing and black start services credits and charges
Credits Received For:

Credits Category:

Charges Category:

Charges Paid By:

Reactive Services Charge

Zonal Real-Time Load

Reactive Services Local Constraint

Applicable Requesting Party

Synchronous Condensing

Real-Time Load
Real-Time Export Transactions

Black Start Service Charge

Zone/Non-zone Peak Transmission
Use and Point to Point Transmission
Reservations

Reactive

Resources Providing Reactive Service

Day-Ahead Operating Reserve
Reactive Services Generator
Reactive Services LOC
Reactive Services Condensing
Reactive Services Synchronous
Condensing LOC
Synchronous Condensing

Resources Providing Synchronous
Condensing

Synchronous Condensing
Synchronous Condensing LOC

Resources Providing Black Start Service

Day-Ahead Operating Reserve
Balancing Operating Reserve
Black Start Testing

Black Start

Energy Uplift Charges Results
Energy Uplift Charges
Total energy uplift charges increased by $55.7 million or 236.8 percent in the first six months of 2021 compared to the first six months of 2020.
Table 4-24 shows total energy uplift charges by category in the first six months of 2020 and the first six months of 2021.27 The increase of $55.7 million iscomprised of an increase of $4.2 million in day-ahead operating reserve charges, an increase of $51.1 million in balancing operating reserve charges and anincrease of $0.4 million in reactive service charges.
Table 4-24 Total energy uplift charges by category: January through June, 2020 and 2021
Category
Day-Ahead Operating Reserves
Balancing Operating Reserves
Reactive Services
Synchronous Condensing
Black Start Services
Total
Energy Uplift as a Percent of Total PJM Billing(Jan - Jun) 2020
(Jan - Jun) 2021
Charges (Millions) Charges (Millions)
$3.0
$7.2
$20.0
$71.1
$0.4
$0.7
$0.0
$0.0
$0.1
$0.2
$23.5
$79.2
0.2%
0.4%

Change(Millions)
$4.2
$51.1
$0.4
$0.0
$0.0
$55.7
0.2%

Percent
Change141.2%
255.3%
92.1%
0.0%
12.0%
236.8%
156.9%

27 Table 4-24 includes all categories of charges as defined in Table 4-22 and Table 4-23 and includes all PJM Settlements billing adjustments. Billing data can be modified by PJM Settlements at any time to reflect changes in the evaluation of energy uplift. The billing data reflected in thisreport were current on July 8, 2021.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 267

2021 Quarterly State of the Market Report for PJM: January through June

Table 4-25 compares monthly energy uplift charges by category for the first six months of 2020 and 2021.
Table 4-25 Monthly energy uplift charges: January 2020 through June 2021

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total (Jan - Jun)
Share (Jan - Jun)

DayAhead
$0.1
$0.2
$0.0
$0.8
$1.0
$0.9
$1.2
$0.8
$2.1
$1.1
$0.6
$0.5
$3.0
12.7%

Balancing
$4.0
$1.2
$1.6
$2.0
$2.7
$8.5
$13.0
$12.6
$5.4
$8.0
$8.8
$13.2
$20.0
85.1%

2020 Charges (Millions)
Reactive Synchronous Black Start
Services
Condensing
Services
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.1
$0.0
$0.1
$0.3
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.1
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.4
$0.0
$0.1
1.6%
0.0%
0.6%

Total
$4.1
$1.4
$1.7
$2.9
$4.0
$9.5
$14.2
$13.4
$7.5
$9.1
$9.4
$13.7
$23.5
100.0%

DayAhead
$0.7
$0.9
$2.8
$0.8
$0.6
$1.3

Balancing
$6.8
$13.6
$8.5
$17.0
$8.6
$16.5

$7.2
9.1%

$71.1
89.8%

2021 Charges (Millions)
Reactive Synchronous Black Start
Services
Condensing
Services
$0.7
$0.0
$0.0
$0.1
$0.0
$0.0
$0.0
$0.0
$0.1
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

$0.7
0.9%

$0.0
0.0%

$0.2
0.2%

Total
$8.2
$14.6
$11.4
$17.8
$9.3
$17.8

$79.2
100.0%

Table 4-26 shows the composition of day-ahead operating reserve charges. Day-ahead operating reserve charges consist of day-ahead operating reserve charges
that pay for credits to generators and import transactions, day-ahead operating reserve charges for economic load response resources and day-ahead operating
reserve charges from unallocated congestion charges.28 29 Day-ahead operating reserve charges increased by $4.2 million 141.2 percent in the first six monthsof 2021 compared to the first six months of 2020.
Table 4-26 Day-ahead operating reserve charges: January through June, 2020 and 2021
Type
Day-Ahead Operating Reserve Charges
Day-Ahead Operating Reserve Charges for Load Response
Unallocated Congestion Charges
Total(Jan - Jun) 2020
(Jan - Jun) 2021
Charges (Millions) Charges (Millions)
$3.0
$7.2
$0.0
$0.0
$0.0
$0.0
$3.0
$7.2

Change(Millions)$4.2($0.0)$0.0$4.2(Jan - Jun)
2020 Share
100.0%
0.0%
0.0%
100.0%(Jan - Jun)
2021 Share
100.0%
0.0%
0.0%
100.0%

Table 4-27 shows the composition of the balancing operating reserve charges. Balancing operating reserve charges consist of balancing operating reserve
reliability charges (credits to generators), balancing operating reserve deviation charges (credits to generators and import transactions), balancing operating
reserve charges for economic load response and balancing local constraint charges. Balancing operating reserve charges increased by $51.1 million or 255.3
percent in the first six months of 2021 compared to 2020.
28 See PJM Operating Agreement Schedule 1 § 3.2.3(c). Unallocated congestion charges are added to the total costs of day-ahead operating reserves. Congestion charges have been allocated to day-ahead operating reserves only 10 times since 1999, totaling $26.9 million.
29 See the 2021 Quarterly State of the Market Report for PJM: January through June, Section 13, Financial Transmission Rights and Auction Revenue Rights.

268

Section 4 Energy Uplift© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Table 4-27 Balancing operating reserve charges: January through June, 2020 and 2021
Type
Balancing Operating Reserve Reliability Charges
Balancing Operating Reserve Deviation Charges
Balancing Operating Reserve Charges for Load Response
Balancing Local Constraint Charges
Total(Jan - Jun) 2020
(Jan - Jun) 2021
Charges (Millions) Charges (Millions)
$4.4
$31.1
$13.5
$35.3
$0.0
$0.0
$2.1
$4.6
$20.0
$71.1

Change(Millions)
$26.8
$21.8
$0.0
$2.5
$51.1

(Jan - Jun)
2020 Share
21.8%
67.6%
0.0%
10.6%
100.0%(Jan - Jun)
2021 Share
43.8%
49.7%
0.0%
6.5%
100.0%

Table 4-28 shows the composition of the balancing operating reserve deviation charges. Balancing operating reserve deviation charges are equal to the sum of
the following three categories: make whole credits paid to generators and import transactions, energy lost opportunity costs paid to generators, and payments toresources scheduled by PJM but canceled by PJM before coming online. In the first six months of 2021, energy lost opportunity cost deviation charges increased
by $4.4 million or 66.2 percent, and make whole deviation charges increased by $17.4 million or 252.9 percent compared to the first six months of 2020.
Table 4-28 Balancing operating reserve deviation charges: January through June, 2020 and 2021
Charge Attributable To
Make Whole Payments to Generators and Imports
Energy Lost Opportunity Cost
Canceled Resources
Total(Jan - Jun) 2020
(Jan - Jun) 2021
Charges (Millions) Charges (Millions)
$6.9
$24.3
$6.6
$11.0
$0.0
$0.0
$13.5
$35.3

Change(Millions)
$17.4
$4.4
$0.0
$21.8

(Jan - Jun)
2020 Share
50.9%
49.1%
0.0%
100.0%(Jan - Jun)
2021 Share
68.7%
31.3%
0.0%
100.0%

Table 4-29 shows reactive services, synchronous condensing and black start services charges. Reactive services charges increased by $0.4 million or 92.1 percent
in the first six months of 2021, compared to the first six months of 2020.
Table 4-29 Additional energy uplift charges: January through June, 2020 and 2021
Type
Reactive Services Charges
Synchronous Condensing Charges
Black Start Services Charges
Total(Jan - Jun) 2020
(Jan - Jun) 2021
Charges (Millions) Charges (Millions)
$0.4
$0.7
$0.0
$0.0
$0.1
$0.2
$0.5
$0.9

Change(Millions)
$0.4
$0.0
$0.0
$0.4

(Jan - Jun)
2020 Share
73.0%
0.0%
27.0%
100.0%(Jan - Jun)
2021 Share
82.2%
0.0%
17.8%
100.0%

Table 4-30 and Table 4-31 show the amount and shares of regional balancing charges in the first six months of 2020 and 2021. Regional balancing operating
reserve charges consist of balancing operating reserve reliability and deviation charges. These charges are allocated regionally across PJM. In the first six monthsof 2021, the largest share of regional charges was paid by real-time load which paid 44.4 percent of all regional balancing charges. The regional balancing
charges allocation table does not include charges attributed for resources controlling local constraints.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 269

2021 Quarterly State of the Market Report for PJM: January through June

In the first six months of 2021, regional balancing operating reserve charges increased by $ 48.6 million compared to the first six months of 2020. Balancing
operating reserve reliability charges increased by $26.8 million or 613.1 percent, and balancing operating reserve deviation charges increased by $21.8 million,
or 161.3 percent.
Table 4-30 Regional balancing charges allocation (Millions): January through June, 2020
ChargeReliability Charges

Deviation Charges

Allocation
Real-Time Load
Real-Time Exports
Total
DemandSupplyGenerator
Total

Total Regional Balancing Charges

RTO
$3.3
$0.2
$3.5
$8.1
$1.8
$2.7
$12.6
$16.1

18.5%
1.0%
19.4%
45.2%
9.8%
15.3%
70.3%
89.7%

East
$0.7
$0.0
$0.8
$0.4
$0.1
$0.1
$0.7
$1.5

4.1%
0.1%
4.3%
2.5%
0.8%
0.8%
4.2%
8.5%

West
$0.1
$0.0
$0.1
$0.1
$0.0
$0.0
$0.2
$0.3

0.6%
0.1%
0.7%
0.7%
0.1%
0.2%
1.1%
1.8%

Total
$4.2
23.3%
$0.2
1.1%
$4.4
24.4%
$8.7
48.5%
$1.9
10.8%
$2.9
16.4%
$13.5
75.6%
$17.9
100%

Table 4-31 Regional balancing charges allocation (Millions): January through June, 2021
ChargeReliability Charges

Deviation Charges

Allocation
Real-Time Load
Real-Time Exports
Total
DemandSupplyGenerator
Total

Total Regional Balancing Charges

RTO
$25.9
$1.4
$27.3
$23.6
$3.2
$5.5
$32.3
$59.6

39.0%
2.1%
41.1%
35.5%
4.8%
8.3%
48.6%
89.7%

East
$3.1
$0.1
$3.3
$1.7
$0.2
$0.4
$2.4
$5.7

4.7%
0.2%
4.9%
2.6%
0.4%
0.7%
3.6%
8.5%

West
$0.5
$0.0
$0.5
$0.5
$0.1
$0.1
$0.7
$1.2

0.7%
0.1%
0.8%
0.8%
0.1%
0.1%
1.0%
1.8%

Total
$29.6
44.4%
$1.6
2.4%
$31.1
46.8%
$25.8
38.8%
$3.5
5.2%
$6.1
9.1%
$35.4
53.2%
$66.5
100%

Operating Reserve Rates
Under the operating reserves cost allocation rules, PJM calculates nine separate rates, a day-ahead operating reserve rate, a reliability rate for each region, adeviation rate for each region, a lost opportunity cost rate and a canceled resources rate for the entire RTO region. Table 4-32 shows how these charges areallocated.30
Figure 4-2 shows the daily day-ahead operating reserve rate for 2020 and 2021. The average rate in 2021 was $0.017 per MWh, $0.009 per MWh higher than
the average in 2020. The highest rate in 2021 occurred on May 4, when units were called on by PJM for transmission constraints, and the rate reached $0.128
per MWh, $0.037 per MWh lower than the $0.164 per MWh reached in 2020, on April 6. Figure 4-2 also shows the daily day-ahead operating reserve rate
including the congestion charges allocated to day-ahead operating reserves. There were no congestion charges allocated to day-ahead operating reserves in 2020
through the first six months of 2021.

30 The lost opportunity cost and canceled resources rates are not posted separately by PJM. PJM adds the lost opportunity cost and the canceled resources rates to the deviation rate for the RTO Region since these three charges are allocated following the same rules.

270

Section 4 Energy Uplift© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

$/MWh

$0.20
$0.18
$0.16
$0.14
$0.12
$0.10
$0.08
$0.06
$0.04
$0.02
$0.00
$0.20
$0.18
$0.16
$0.14
$0.12
$0.10
$0.08
$0.06
$0.04
$0.02
$0.00

Day-Ahead Rate 2020
Day-Ahead + Congestion Rate 2020

Figure 4-3 shows the RTO and the regional reliability rates for 2020 and 2021.
The average RTO reliability rate in the first six months of 2021 was $0.070 per
MWh. The highest RTO reliability rate in the first six months of 2021 occurredon June 29 when the rate reached $0.662 per MWh, $0.511 per MWh higher
than the $0.152 per MWh rate reached in 2020, on June 10.
Figure 4-3 Daily balancing operating reserve reliability rates ($/MWh):
January 2020 through June 2021
$0.70

RTO Reliability 2020

$0.60

East Reliability 2020
West Reliability 2020

$0.50
Day-Ahead Rate 2021
Day-Ahead + Congestion Rate 2021

$/MWh

$/MWh

Figure 4-2 Daily day-ahead operating reserve rate ($/MWh): January 2020
through June 2021

$0.40
$0.30
$0.20
$0.10
$0.00

$0.70
RTO Reliability 2021

$0.60
Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

East Reliability 2021

$0.50West Reliability 2021

$/MWh

$0.40
$0.30
$0.20

$0.10
$0.00

© 2021 Monitoring Analytics, LLC

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

2021 Quarterly State of the Market Report for PJM: January through June 271

2021 Quarterly State of the Market Report for PJM: January through June

Figure 4-4 shows the RTO and regional deviation rates for 2020 and 2021.
The average RTO deviation rate in the first six months of 2021 was $0.190
per MWh. The highest daily rate in the first six months of 2021 occurred on
April 20, when the RTO deviation rate reached $1.710 per MWh, $0.539 per
MWh more than the $1.170 per MWh rate reached in the first six months of
2020, on June 9.

Figure 4-5 shows the daily lost opportunity cost rate and the daily canceledresources rate for 2020 and 2021. The average lost opportunity cost rate in2020 was $0.099 per MWh. The highest lost opportunity cost rate in the firstsix months of 2021 occurred on May 26, when it reached $1.161 per MWh,
$0.773 per MWh lower than the $1.923 per MWh rate reached in the first six
months of 2020, on June 2.

Figure 4-4 Daily balancing operating reserve deviation rates ($/MWh):
January 2020 through June 2021

Figure 4-5 Daily lost opportunity cost and canceled resources rates ($/MWh):
January 2020 through June 2021
$2.50

$1.80
$1.60
$1.40
$1.20
$1.00
$0.80
$0.60
$0.40
$0.20
$0.00
-$0.20

RTO Deviation 2020

Lost Opportunity Cost 2020

East Deviation 2020

$2.00

$/MWh

$/MWh

West Deviation 2020

$1.50
$1.00
$0.50
$0.00
$2.50

$1.80

Lost Opportunity Cost 2021

RTO Deviation 2021
East Deviation 2021
West Deviation 2021

$1.60
$1.40

$2.00
$/MWh

$1.20
$/MWh

Canceled Resources 2020

$1.00
$0.80

Canceled Resources 2021

$1.50

$1.00

$0.60
$0.50

$0.40
$0.20

$0.00

272

$0.00
Jan

Feb

Mar

Apr

Section 4 Energy Uplift

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Table 4-32 shows the average rates for each region in each category for 2020
and 2021.					Table 4-33 Operating reserve rates statistics ($/MWh): January through June,
2021
Rates Charged ($/MWh)

Table 4-32 Operating reserve rates ($/MWh): January through June, 2020 and
2021
Rate
Day-Ahead
Day-Ahead with Unallocated Congestion
RTO Reliability
East Reliability
West Reliability
RTO Deviation
East Deviation
West Deviation
Lost Opportunity Cost
Canceled Resources(Jan - Jun) 2020 (Jan - Jun) 2021($/MWh)($/MWh)
0.008
0.017
0.008
0.017
0.009
0.070
0.004
0.018
0.001
0.003
0.079
0.190
0.020
0.048
0.005
0.011
0.089
0.099
0.000
0.000

Difference($/MWh)
0.009
0.009
0.061
0.013
0.002
0.111
0.027
0.006
0.010
NA

Percent
Difference
112.8%
112.8%
651.0%
298.5%
317.3%
139.4%
133.9%
107.5%
11.3%
N/A

Table 4-33 shows the operating reserve cost of a one MW transaction in thefirst six months of 2021. For example, in the Eastern Region a day-ahead
withdrawal, such as a decrement bid or UTC, paid an average rate of $0.354
per MWh with a maximum rate of $2.385 per MWh, a minimum rate of lessthan $0.001 per MWh and a standard deviation of $0.362 per MWh. The rates
in Table 4-33 include all operating reserve charges including RTO deviation
charges. The rates also include charges for UTCs, which were implemented
on November 1, 2020 and which are treated similarly to DECs. Table 4-33
illustrates both the average level of operating reserve charges by transaction
types and the uncertainty reflected in the maximum, minimum and standard
deviation levels. INCs, DECs, and UTCs have higher rates compared to realtime load because they always result in a deviation while day-ahead and realtime load do not always result in a deviation.

RegionEast

WestTransaction
INC
DEC
DA LoadRT LoadDeviation
INC
DEC
DA LoadRT LoadDeviation

Maximum
2.370
2.385
0.128
0.835
2.370
1.714
1.728
0.128
0.682
1.714

Average
0.337
0.354
0.017
0.088
0.337
0.300
0.317
0.017
0.073
0.300

Minimum<0.001<0.001<0.001<0.001<0.001<0.001<0.001<0.001<0.001<0.001

Standard
Deviation
0.360
0.362
0.025
0.124
0.360
0.331
0.333
0.025
0.109
0.331

Reactive Services Rates
Reactive services charges associated with local voltage support are allocatedto real-time load in the control zone or zones where the service is provided.
These charges result from uplift payments to units committed by PJM tosupport reactive/voltage requirements that do not recover their energy offer
through LMP payments. These charges are separate from the reactive service
capability revenue requirement charges which are a fixed annual charge
based on approved FERC filings.31 Reactive services charges associated withsupporting reactive transfer interfaces above 345 kV are allocated daily toreal-time load across the entire RTO based on the real-time load ratio share ofeach network customer.
While reactive services rates are not posted by PJM, a local voltage support
rate for each control zone can be calculated and a reactive transfer interface
support rate can be calculated for the entire RTO. Table 4-34 shows the reactive
services rates associated with local voltage support in the first six monthsof 2020 and 2021. Table 4-34 shows that in the first six months of 2021
only three zones incurred reactive charges, in addition to reactive capability
charges. Real-time load in the PPL Zone, where reactive service charges were
the highest, paid an average of $0.034 per MWh for reactive services. Reactive
31 See 2021 Quarterly State of the Market Report for PJM: January through June, Section 10: Ancillary Service Markets.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 273

2021 Quarterly State of the Market Report for PJM: January through June

service charges were second highest in the MEC Zone, where the average rate
was $0.001 per MWh.

Table 4-35 Balancing operating reserve determinants (GWh): January throughJune, 2020 and 2021
Reliability Charge Determinants(GWh)

Table 4-34 Local voltage support rates: January through June, 2020 and 2021
Control Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DUQ
DOM
DAY
EKPC
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC

(Jan - Jun) 2020($/MWh)
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.003
0.017
0.001
0.000
0.000
0.000
0.000
0.009
0.000
0.000

(Jan - Jun) 2021($/MWh) Difference ($/MWh)
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
(0.001)0.000(0.003)0.000(0.017)
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.034
0.025
0.000
0.000
0.000
0.000

Percent Difference
0.0%
NA
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
(100.0%)(100.0%)(100.0%)
55.0%
0.0%
0.0%
0.0%
0.0%
283.4%
0.0%
0.0%

Balancing Operating Reserve Determinants
Table 4-35 shows the determinants used to allocate the regional balancing
operating reserve charges in the first six months of 2020 and 2021. Total
real-time load and real-time exports were 390,583 GWh, 4.0 percent higher
in the first six months of 2021 compared to the first six months 2020. Total
deviations summed across the demand, supply, and generator categories were111,663 GWh, 48.6 percent higher in the first six months of 2021 compared to
the first six months of 2020.

274

Section 4 Energy Uplift(Jan - Jun) 2020

(Jan - Jun) 2021

Difference

RTO
East
West
RTO
East
West
RTO
East
West

Real-Time Real-Time
Load
Exports
357,240
18,250168,601
5,394
188,640
12,857373,317
17,267
178,071
6,971
195,246
10,296
16,077
(983)
9,470
1,577
6,606
(2,561)

Reliability
Total
375,490
173,994
201,496
390,583
185,042
205,542
15,093
11,0484,045

Deviation Charge Determinants (GWh)
DemandSupply Generator
Deviations Deviations Deviations Deviations
(MWh)
(MWh)
(MWh)
Total
46,896
11,962
16,26575,124
22,1897,081
7,471
36,741
24,5084,741
8,794
38,04381,74011,32918,594
111,663
35,772
5,143
9,107
50,02145,105
6,014
9,487
60,607
34,844(633)
2,329
36,54013,583(1,938)
1,635
13,28020,5981,272
693
22,563

Under PJM’s operating reserve rules, balancing operating reserve charges areallocated regionally. PJM defined the Eastern and Western regions, in addition
to the RTO region to allocate the cost of balancing operating reserves. These
regions consist of three location types: zones, hubs/aggregates, and interfaces.
The deviations, calculated between day ahead and real time generation, areaggregated regionally by location type, depending on where the charge occurs.
Credits paid to generators that are defined as operating for reliability purposes
are charged to real-time load and exports. Credits paid to generators andcredits paid to import transactions that are defined to be operating control
deviations on the system, such as energy lost opportunity credits andcancellation credits, are charged to deviations.
Deviations fall into three categories: demand, supply and generator deviations.
Table 4-36 shows the different categories by type of transactions that incurreddeviations. In the first six months of 2021, 51.6 percent of all RTO deviations
were incurred by virtual transactions, or by a transaction that combines virtualswith exports or load. During the first six months of 2021, the average dailyvolume of UTC deviations represented 30.4 percent of total daily deviations.
The highest share of UTC deviations was 44.4 percent on February 28, 2021,
and the lowest share of UTC deviations was 17.9 percent, on May 26, 2021.

© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Table 4-36 Deviations by transaction type: January through June, 2021
Deviation Category

DemandSupplyTransaction
DECs Only
UTCs Only
Load Only
Exports Only
Combination of Load, Export, DECs & UTCs
Combination of Load, Export & UTCs
Combination of Load, Export & DECs
Combination of Load/Exports with DECs/UTCs
Combination of Load/Exports without DECs/UTCs
INCs Only
Combination of Imports & INCs
Imports Only

Generators
Total

Deviation (GWh)
Share
RTO
East
West
RTO
East
West
12,5296,778
5,548 11.2% 13.6%
9.2%
33,939 11,545 21,734 30.4% 23.1% 35.9%
30,433 15,735 14,698 27.3% 31.5% 24.3%
3,435
1,336
2,099
3.1%
2.7%
3.5%
133
15
117
0.1%
0.0%
0.2%
1,214
321
893
1.1%
0.6%
1.5%
55
38
16
0.0%
0.1%
0.0%
1,401
375
1,027
1.3%
0.7%
1.7%
3
3
0
0.0%
0.0%
0.0%
9,591
4,012
5,406
8.6%
8.0%
8.9%
185
156
29
0.2%
0.3%
0.0%
1,553
974
579
1.4%
1.9%
1.0%
18,5949,107
9,487 16.7% 18.2% 15.7%
111,663 50,021 60,607 100.0% 100.0% 100.0%

Geography of Charges and Credits
Table 4-37 shows the geography of charges and credits in the first six months of 2021. Table 4-37 includes only day-ahead operating reserve charges andbalancing operating reserve reliability and deviation charges since these categories are allocated regionally, while other charges, such as reactive services,synchronous condensing and black start services are allocated by control zone, and balancing local constraint charges are charged to the requesting party.
Charges are categorized by the location (control zone, hub, aggregate or interface) where they are allocated according to PJM’s operating reserve rules. Credits
are categorized by the location where the resources are located. The shares columns reflect the operating reserve credits and charges balance for each location.
For example, transactions in the PPL Control Zone paid 5.4 percent of all operating reserve charges allocated regionally while resources in the PPL Control Zone
were paid 2.3 percent of the corresponding credits. The PPL Control Zone received less operating reserve credits than operating reserve charges paid and had 10.4
percent of the deficit. The deficit is the net of the credits and charges paid at a location. Transactions in the BGE Control Zone paid 4.3 percent of all operating
reserve charges allocated regionally, and resources in the BGE Control Zone were paid 5.8 percent of the corresponding credits. The BGE Control Zone received
more operating reserve credits than operating reserve charges paid and had 5.4 percent of the surplus. The surplus is the net of the credits and charges paid at alocation. Table 4-37 also shows that 89.5 percent of all charges were allocated in control zones, 3.6 percent in hubs and aggregates and 7.0 percent in interfaces.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 275

2021 Quarterly State of the Market Report for PJM: January through June

Table 4-37 Geography of regional charges and credits: January through June,
2021
Location
Zones

Hubs and
AggregatesInterfaces

ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DUQ
DOM
DPL
EKPC
External
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
All Zones
AEP - Dayton
Dominion
Eastern
New Jersey
Ohio
Western Interface
Western
RTEP B0328 Source
All Hubs and Aggregates
CPLE Exp
CPLE Imp
Duke Exp
Duke Imp
Hudson
IMO
LindenMISONCMPA Imp
Neptune
NIPSCONorthwest
NYIS
South ExpSouth ImpSouth
All Interfaces
Total

Charges(Millions)
$1.0
$11.2
$3.4
$4.4
$3.1
$7.6
$1.3
$2.4
$1.0
$8.4
$1.7
$1.6
$0.0
$1.7
$1.4
$0.2
$3.0
$1.9
$2.4
$4.0
$3.8
$0.4
$65.9
$0.7
$0.3
$0.2
$0.2
$0.4
$0.0
$0.8
$0.0
$2.6
$0.0
$0.0
$0.0
$0.0
$0.4
$0.1
$0.2
$2.5
$0.0
$0.2
$0.0
$0.0
$0.6
$0.6
$0.3
$0.2
$5.2
$73.7

Credits(Millions)
$0.6
$10.2
$1.8
$3.7
$4.3
$14.1
$2.8
$1.4
$0.0
$14.2
$6.4
$3.8
$1.8
$0.7
$0.6
$0.0
$0.5
$1.0
$2.3
$1.7
$2.0
$0.0
$73.7
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$73.7

Balance($0.4)($1.0)($1.6)($0.7)
$1.2
$6.5
$1.5
($1.0)($1.0)
$5.8
$4.7
$2.2
$1.8
($1.0)($0.8)($0.2)($2.6)($0.8)($0.2)($2.3)($1.8)($0.4)$7.8($0.7)($0.3)($0.2)($0.2)($0.4)$0.0($0.8)$0.0($2.6)
$0.0
$0.0
$0.0
$0.0
($0.4)($0.1)($0.2)($2.5)$0.0($0.2)$0.0$0.0($0.6)($0.6)($0.3)($0.2)($5.2)$0.0

Total
Charges
1.4%
15.2%
4.6%
6.0%
4.2%
10.3%
1.7%
3.2%
1.4%
11.5%
2.3%
2.1%
0.0%
2.3%
1.9%
0.3%
4.1%
2.6%
3.3%
5.4%
5.1%
0.6%
89.5%
1.0%
0.4%
0.3%
0.3%
0.5%
0.0%
1.0%
0.0%
3.5%
0.0%
0.0%
0.0%
0.0%
0.5%
0.2%
0.3%
3.4%
0.0%
0.3%
0.0%
0.0%
0.8%
0.8%
0.4%
0.2%
7.0%
100.0%

Shares
Total
Credits
Deficit
0.8%
1.7%
13.9%
4.1%
2.5%
6.8%
5.1%
2.9%
5.8%
0.0%
19.1%
0.0%
3.8%
0.0%
1.9%
4.3%
0.1%
4.2%
19.3%
0.0%
8.7%
0.0%
5.1%
0.0%
2.4%
0.0%
0.9%
4.4%
0.8%
3.5%
0.0%
0.9%
0.6%
10.9%
1.4%
3.6%
3.1%
0.7%
2.3%
9.9%
2.7%
7.8%
0.0%
1.8%
100.0%
67.4%
0.0%
3.0%
0.0%
1.3%
0.0%
1.0%
0.0%
1.0%
0.0%
1.5%
0.0%
0.0%
0.0%
3.2%
0.0%
0.0%
0.0%
11.1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
1.7%
0.0%
0.6%
0.0%
1.1%
0.0%
10.7%
0.0%
0.0%
0.0%
0.9%
0.0%
0.0%
0.0%
0.0%
0.0%
2.6%
0.0%
2.5%
0.0%
1.4%
0.0%
0.7%
0.0%
21.5%
100.0%
100.0%

Surplus
0.0%
0.0%
0.0%
0.0%
5.0%
27.6%
6.4%
0.0%
0.0%
24.5%
19.8%
9.2%
7.5%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
100.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
100.0%

Energy Uplift Issues
Intraday Segments Uplift Settlement
PJM pays uplift separately for multiple segmented blocks of time during
the operating day (intraday).32 The use of intraday segments to calculate theneed for uplift payments results in higher uplift payments than necessary to
make units whole, including uplift payments to units that are profitable on adaily basis. The MMU recommends eliminating intraday segments from thecalculation of uplift payments and returning to calculating the need for uplift
based on the entire 24 hour operating day.
Table 4-38 shows balancing operating reserve credits calculated using
intraday segments and balancing operating reserve payments calculated on adaily basis. In the first six months of 2021, balancing operating reserve credits
would have been $8.4 million or 15.2 percent lower if they were calculated
on a daily basis. In the first six months of 2020, balancing operating reserve
credits would have been $2.2 million or 19.4 percent lower if they were
calculated on a daily basis.
Table 4-38 Intraday segments and daily balancing operating reserve credits:
January through June, 2020 and 2021

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total (Jan - Jun)

2020 BOR Credits (Millions)IntradaySegments
Daily
Calculation
Calculation
Difference
$1.6
$1.3
($0.3)$0.7$0.5($0.2)$0.9$0.7($0.2)$1.1$0.9($0.2)$1.9$1.6($0.3)$5.1$4.1($1.0)$8.8$5.7($3.0)$8.1$6.0($2.1)$3.7$2.8($0.9)$6.8$5.9($0.9)$7.8$7.0($0.8)$11.8$11.0($0.9)$11.2$9.1($2.2)

2021 BOR Credits (Millions)IntradaySegments
Daily
Calculation
Calculation
Difference
$4.8
$4.2
($0.5)$10.5$9.4($1.2)$5.0$4.0($1.0)$16.4$15.0($1.3)$5.8$4.7($1.1)$13.0$9.8($3.2)

$55.4

$47.0

($8.4)

32 See PJM “Manual 28: Operating Reserve Accounting,” Rev. 84 (Dec. 17, 2020).

276

Section 4 Energy Uplift© 2021 Monitoring Analytics, LLC

Section 4 Energy Uplift

Prior to April 1, 2018, for purposes of calculating LOC credits, each hour was
defined as a unique segment. Following the implementation of five minutesettlements on April 1, 2018, LOC credits are calculated with each five minuteinterval defined as a unique segment. Thus a profit in one five minute segment,
resulting from the real-time LMP being lower than the day-ahead LMP, is
not used to offset a loss in any other five minute segment. This change insettlements causes an increase in LOC credits compared to hourly settlement
as generators are made whole for any losses incurred in a five minute interval
while previously gains and losses were netted within the hour. Table 4-39
compares the impact on day-ahead LOC credits of adopting five minutesettlements over hourly settlements in April 2018 and the impact of having
adopted the recommended daily settlements over five minute settlements. For
the first six months of 2021, LOC credits would have been 8.5 percent lower
if they had been settled on an hourly basis rather than on a five minute basis.
For the first six months of 2021, LOC credits would have been $3.5 million or
22.7 percent lower if they had been settled on the recommended daily basis
rather than being settled on a five minute settlement.
Table 4-39 Comparison of five minute, hourly, and daily settlement of dayahead lost opportunity cost credits: January through June, 2021

Jan
Feb
Mar
Apr
May
Jun
Total (Jan - Jun)

2021 Day-Ahead LOC Credits (Millions)Five MinuteSettlement Hourly Settlement
Daily Settlement(Status Quo)
(Pre-April 2018)
Difference (Recommendation)
$0.4
$0.3
($0.1)
$0.2
$0.5
$0.5
($0.1)
$0.4
$3.5
$3.1
($0.4)
$2.3
$0.6
$0.6
$0.0
$0.5
$2.8
$2.5
($0.3)
$2.3
$3.1
$2.8
($0.2)
$2.4
$10.8
$9.8
($1.0)$8.1

Difference($0.1)($0.2)($1.2)($0.1)($0.5)($0.7)($2.8)

Uplift Credits and Offer Capping
Absent market power mitigation, unit owners that submit noncompetitive
offers or offers with inflexible operating parameters, can exercise market
power, resulting in noncompetitive and excessive uplift payments.

The three pivotal supplier (TPS) test is the test for local market power in theenergy market.33 If the TPS test is failed, market power mitigation is applied
by offer capping the resources of the owners identified as having local market
power. Offer capping is designed to set offers at competitive levels.
Table 4-40 shows the uplift credits paid to units that were committed anddispatched on cost offers during the first six months of 2021.
Table 4-40 Operating Reserve Credits by Offer Type: January through June,
2021
Offer Type
Cost
Price
Price PLS
Cost & Price
Cost & PLS
Price & PLS
Total

Day Ahead
Operating Reserve
Credits (Millions)
$1.1
$6.0
$0.0
$0.0
$0.0
$0.0
$7.2

BalancingOperating Reserve Day Ahead Reactive
Credits (Millions)Credits (Millions)
$8.8
0.3
$40.5
0.0
$4.0
0.0
$1.8
0.0
$0.1
0.0
$0.0
0.0
$55.2
0.3

Real Time Reactive
Credits (Millions)
$0.5
$0.0
$0.0
$0.0
$0.0
$0.0
$0.5

Table 4-41 shows day-ahead operating reserve credits paid to units called ondays with hot and cold weather alerts, classified by commitment schedule
type. Of all the day-ahead credits received during days with weather alerts,
61.1 percent went to units that were committed on price schedules less flexible
than PLS.
Table 4-41 Day-ahead operating reserve credits during weather alerts bycommitment schedule: January through June, 2021
Commitment Type During Hot and Cold Weather Alerts
Committed on cost (cost capped)
Committed on price schedule as flexible as PLS
Committed on price schedule less flexible than PLS
Committed on price PLS
Total

Day Ahead Operating
Reserve Credits$23,700$2,052$109,469$43,939$179,159

Share of DAOR during
Hot and Cold Weather
Alerts
13.2%
1.1%
61.1%
24.5%
100.0%

33 See the MMU Technical Reference for PJM Markets, at “Three Pivotal Supplier Test” for a more detailed explanation of the three pivotal
supplier test. <http://www.monitoringanalytics.com/reports/Technical_References/references.shtml>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 277

2021 Quarterly State of the Market Report for PJM: January through June

278

Section 4 Energy Uplift© 2021 Monitoring Analytics, LLC

Section 5 Capacity• Participant behavior was evaluated as not competitive in the 2021/2022

Capacity Market
Each organization serving PJM load must meet its capacity obligations
through the PJM Capacity Market, where load serving entities (LSEs) must pay
the locational capacity price for their zone. LSEs can also construct generationand offer it into the capacity market, enter into bilateral contracts, develop
demand resources and energy efficiency (EE) resources and offer them into
the capacity market, or construct transmission upgrades and offer them into
the capacity market.
The Market Monitoring Unit (MMU) analyzed market structure, participant
conduct and market performance in the PJM Capacity Market, including supply,
demand, concentration ratios, pivotal suppliers, volumes, prices, outage rates
and reliability.1 The conclusions are a result of the MMU’s evaluation of thelast Base Residual Auction, for the 2021/2022 Delivery Year. The MMU has
not completed its analysis of the 2022/2023 RPM Base Residual Auction.
Table 5-1 The capacity market results were not competitive
Market Element
Market Structure: Aggregate Market
Market Structure: Local Market
Participant Behavior
Market Performance

Evaluation
Not Competitive
Not Competitive
Not Competitive
Not Competitive

Market Design

Mixed• The aggregate market structure was evaluated as not competitive. For

almost all auctions held from 2007 to the present, the PJM region failed
the three pivotal supplier test (TPS), which is conducted at the time of
the auction.2 Structural market power is endemic to the capacity market.

• The local market structure was evaluated as not competitive. For almost

every auction held, all LDAs have failed the TPS test, which is conductedat the time of the auction.3

1
2
3

The values stated in this report for the RTO and LDAs refer to the aggregate level including all nested LDAs unless otherwise specified.
For example, RTO values include the entire PJM market and all LDAs. Rest of RTO values are RTO values net of nested LDA values.
In the 2008/2009 RPM Third Incremental Auction, 18 participants in the RTO market passed the TPS test. In the 2018/2019 RPM Second
Incremental Auction, 35 participants in the RTO market passed the test.
In the 2012/2013 RPM Base Residual Auction, six participants included in the incremental supply of EMAAC passed the TPS test. In the
2014/2015 RPM Base Residual Auction, seven participants in the incremental supply in MAAC passed the TPS test. In the 2021/2022
RPM First Incremental Auction, two participants in the incremental supply in EMAAC passed the TPS test. In the 2021/2022 RPM Second
Incremental Auction, two participants in the incremental supply in EMAAC passed the TPS test.

© 2021 Monitoring Analytics, LLC

RPM Base Residual Auction. The MMU has not completed its analysisof the 2022/2023 RPM Base Residual Auction. Market power mitigation
measures were applied when the capacity market seller failed the market
power test for the auction, the submitted sell offer exceeded the definedoffer cap, and the submitted sell offer, absent mitigation, would increase
the market clearing price. But the net CONE times B offer cap under thecapacity performance design, in the absence of 30 performance assessment
hours, exceeds the competitive level and should be reevaluated for each
BRA. In the 2021/2022 RPM Base Residual Auction, some participants’offers were above the competitive level. The MMU recognizes that thesemarket participants followed the capacity market rules by offering at lessthan the stated offer cap of Net CONE times B. But Net CONE times B is not
a competitive offer when the expected number of performance assessment
intervals is zero or a very small number and the nonperformance charge
rate is defined as Net CONE/30. Under these circumstances, a competitive
offer, under the logic defined in PJM’s capacity performance filing, is net
ACR. That is the way in which most market participants offered in thisand prior capacity performance auctions.

• Market performance was evaluated as not competitive based on the2021/2022 RPM Base Residual Auction. Although structural market power
exists in the Capacity Market, a competitive outcome can result fromthe application of market power mitigation rules. The outcome of the2021/2022 RPM Base Residual Auction was not competitive as a result ofparticipant behavior which was not competitive, specifically offers which
exceeded the competitive level. The MMU has not completed its analysisof the 2022/2023 RPM Base Residual Auction.

• Market design was evaluated as mixed because while there are many
positive features of the Reliability Pricing Model (RPM) design and thecapacity performance modifications to RPM, there are several featuresof the RPM design which still threaten competitive outcomes. These
include the definition of DR which permits inferior products to substitutefor capacity, the replacement capacity issue, the definition of unit offer

2021 Quarterly State of the Market Report for PJM: January through June279

2021 Quarterly State of the Market Report for PJM: January through Juneparameters, the inclusion of imports which are not substitutes for internal
capacity resources, and the definition of the default offer cap.

• As a result of the fact that the capacity market design was found to be

not just and reasonable by FERC and a final market design had not been
approved, the 2022/2023 Base Residual Auction was delayed and held in
May 2020, the 2023/2024 Base Residual Auction is delayed and scheduledfor December 2021, and first and second incremental auctions for the2022/2023 through 2025/2026 Delivery Years are canceled if within 10
months of the revised BRA schedule.4

Overview
RPM Capacity Market
Market Design
The Reliability Pricing Model (RPM) Capacity Market is a forward-looking,annual, locational market, with a must offer requirement for Existing
Generation Capacity Resources and mandatory participation by load, withperformance incentives, that includes clear market power mitigation rules andthat permits the direct participation of demand-side resources.5
Under RPM, capacity obligations are annual.6 Base Residual Auctions (BRA)
are held for delivery years that are three years in the future. First, Second andThird Incremental Auctions (IA) are held for each delivery year.7 First, Second,
and Third Incremental Auctions are conducted 20, 10, and three months prior
to the delivery year.8 A Conditional Incremental Auction may be held if there
is a need to procure additional capacity resulting from a delay in a plannedlarge transmission upgrade that was modeled in the BRA for the relevantdelivery year.9

4
5
6
7
8
9

174 FERC ¶ 61,036 (2021).
The terms PJM Region, RTO Region and RTO are synonymous in this report and include all capacity within the PJM footprint.
Effective for the 2020/2021 and subsequent delivery years, the RPM market design incorporated seasonal capacity resources. Summer
period and winter period capacity must be matched either with commercial aggregation or through the optimization in equal MWamounts in the LDA or the lowest common parent LDA.
See 126 FERC ¶ 61,275 at P 86 (2009).
See Letter Order, FERC Docket No. ER10-366-000 (January 22, 2010).
See 126 FERC ¶ 61,275 at P 88 (2009). There have been no Conditional Incremental Auctions.

280

Section 5 Capacity

The 2021/2022 RPM Third Incremental Auction and the 2022/2023 RPM Base
Residual Auction were conducted in the first six months of 2021.
RPM prices are locational and may vary depending on transmission constraints
and local supply and demand conditions.10 Existing generation capable ofqualifying as a capacity resource must be offered into RPM auctions, except
for resources owned by entities that elect the fixed resource requirement (FRR)
option. Participation by LSEs is mandatory, except for those entities that electthe FRR option. There is an administratively determined demand curve thatdefines scarcity pricing levels and that, with the supply curve derived from
capacity offers, determines market prices in each BRA. RPM rules provide
performance incentives for generation, including the requirement to submit
generator outage data and the linking of capacity payments to the level of
unforced capacity, and the performance incentives have been strengthened
significantly under the Capacity Performance modifications to RPM. Under
RPM there are explicit market power mitigation rules that define the must
offer requirement, that define structural market power based on the marginal
cost of capacity, that define offer caps, that define the minimum offer price,and that have flexible criteria for competitive offers by new entrants. Market
power mitigation is effective only when these definitions are up to date andaccurate. Demand resources and energy efficiency resources may be offereddirectly into RPM auctions and receive the clearing price without mitigation.

Market Structure• RPM Installed Capacity. In the first six months of 2021, RPM installedcapacity decreased 307.7 MW or 0.2 percent, from 184,245.0 MW on
January 1 to 183,962.3 MW on June 30. Installed capacity includes net
capacity imports and exports and can vary on a daily basis.

• RPM Installed Capacity by Fuel Type. Of the total installed capacity on June30, 2021, 46.0 percent was gas; 26.5 percent was coal; 17.6 percent was
nuclear; 4.8 percent was hydroelectric; 3.0 percent was oil; 0.8 percent
was wind; 0.4 percent was solid waste; and 1.0 percent was solar.

10

Transmission constraints are local capacity import capability limitations (low capacity emergency transfer limit (CETL) margin overcapacity emergency transfer objective (CETO)) caused by transmission facility limitations, voltage limitations or stability limitations.

© 2021 Monitoring Analytics, LLC

Section 5 Capacity• Market Concentration. In the 2022/2023 RPM Base Residual Auction all

Delivery Year. The weighted average capacity price for the 2021/2022
Delivery Year is $147.33 per MW-day, including all RPM auctions for the2021/2022 Delivery Year.

participants in the total PJM market as well as the LDA RPM markets failed
the three pivotal supplier (TPS) test.11 Offer caps were applied to all selloffers for resources which were subject to mitigation when the capacity
market seller did not pass the test, the submitted sell offer exceeded
the defined offer cap, and the submitted sell offer, absent mitigation,
increased the market clearing price.12 13 14• For the 2021/2022 Delivery Year, RPM annual charges to load are $9.4
billion.

• In the 2021/2022 RPM Base Residual Auction, the market performance

was determined to be not competitive as a result of noncompetitive offersthat affected market results. The MMU has not completed its analysis of
the 2022/2023 RPM Base Residual Auction.

• Imports and Exports. Of the 1,558.0 MW of imports in the 2022/2023 RPM
Base Residual Auction, 1,558.0 MW cleared. Of the cleared imports, 954.9
MW (61.3 percent) were from MISO.

• Demand-Side and Energy Efficiency Resources. Capacity in the RPM load

management programs was 12,115.9 MW for June 1, 2021, as a result ofcleared capacity for demand resources and energy efficiency resourcesin RPM auctions for the 2021/2022 Delivery Year (16,233.9 MW) lesspurchases of replacement capacity (4,118.0 MW).

Market Conduct• 2022/2023 RPM Base Residual Auction. Of the 1,083 generation resources

Reliability Must Run Service• Of the seven companies (23 units) that have provided RMR service,
two companies (seven units) filed to be paid for RMR service under thedeactivation avoidable cost rate (DACR), the formula rate. The other fivecompanies (16 units) filed to be paid for RMR service under the cost ofservice recovery rate.

Generator Performance• Forced Outage Rates. The average PJM EFORd in the first six months ofthat submitted Capacity Performance offers, the MMU calculated unit
specific offer caps for zero generation resources (0.0 percent).

2021 was 6.8 percent, an increase from 5.9 percent in the first six monthsof 2020.16• Generator Performance Factors. The PJM aggregate equivalent availability

Market Performance• The 2021/2022 RPM Third Incremental Auction and 2022/2023 RPM

Base Residual Auction were conducted in the first six months of 2021.15
The weighted average capacity price for the 2020/2021 Delivery Yearis $111.07 per MW-day, including all RPM auctions for the 2020/2021

11
12
13
14

15

There are 27 Locational Deliverability Areas (LDAs) identified to recognize locational constraints as defined in “Reliability Assurance
Agreement Among Load Serving Entities in the PJM Region,” Schedule 10.1. PJM determines, in advance of each BRA, whether thedefined LDAs will be modeled in the given delivery year using the rules defined in OATT Attachment DD § 5.10(a)(ii).
See OATT Attachment DD § 6.5.
Prior to November 1, 2009, existing DR and EE resources were subject to market power mitigation in RPM Auctions. See 129 FERC ¶61,081 at P 30 (2009).
Effective January 31, 2011, the RPM rules related to market power mitigation were changed, including revising the definition for
Planned Generation Capacity Resource and creating a new definition for Existing Generation Capacity Resource for purposes of themust offer requirement and market power mitigation, and treating a proposed increase in the capability of a generation capacity
resource the same in terms of mitigation as a Planned Generation Capacity Resource. See 134 FERC ¶ 61,065 (2011).
FERC granted PJM’s request for waiver of its Open Access Transmission Tariff to delay the 2022/2023 RPM Base Residual Auction fromMay 2019 to August 2019. See 164 FERC ¶ 61,153 (2018). FERC subsequently denied PJM’s motion seeking clarification of the June 29,
2018, Order (163 FERC ¶ 61,236) and directed PJM not to run the 2022/2023 BRA in August 2019. See 168 FERC ¶ 61,051 (2019).

© 2021 Monitoring Analytics, LLC

factor in the first six months of 2021 was 82.5 percent, a decrease from85.8 percent in the first six months of 2020.

Recommendations17
Definition of Capacity• The MMU recommends the enforcement of a consistent definition of

capacity resource. The MMU recommends that the requirement to be a

16

17

The generator performance analysis includes all PJM capacity resources for which there are data in the PJM generator availability
data systems (GADS) database. Data was downloaded from the PJM GADS database on July 21, 2021. EFORd data presented in stateof the market reports may be revised based on data submitted after the publication of the reports as generation owners may submit
corrections at any time with permission from PJM GADS administrators.
The MMU has identified serious market design issues with RPM and the MMU has made specific recommendations to address thoseissues. These recommendations have been made in public reports. See Table 5-2.

2021 Quarterly State of the Market Report for PJM: January through June281

2021 Quarterly State of the Market Report for PJM: January through June•

physical resource be enforced and enhanced. The requirement to be aphysical resource should apply at the time of auctions and should also
constitute a commitment to be physical in the relevant delivery year. The
requirement to be a physical resource should be applied to all resource
types, including planned generation, demand resources and imports.18 19(Priority: High. First reported 2013. Status: Not adopted.)
The MMU recommends that DR providers be required to have a signed
contract with specific customers for specific facilities for specific levels of
DR at least six months prior to any capacity auction in which the DR isoffered. (Priority: High. First reported 2016. Status: Not adopted.)Market Design and Parameters• The MMU recommends that the test for determining modeled Locational

Deliverability Areas (LDAs) in RPM be redefined. A detailed reliability
analysis of all at risk units should be included in the redefined model.
(Priority: Medium. First reported 2013. Status: Not adopted.)• The MMU recommends that the net revenue calculation used by PJM

to calculate the net Cost of New Entry (CONE) VRR parameter reflect
the actual flexibility of units in responding to price signals rather thanusing assumed fixed operating blocks that are not a result of actual unit
limitations.20 21 The result of reflecting the actual flexibility is higher
net revenues, which affect the parameters of the RPM demand curveand market outcomes. (Priority: High. First reported 2013. Status: Not
adopted.)• The MMU recommends that energy efficiency resources (EE) not be
included on the supply side of the capacity market, because PJM’s load
forecasts now account for future EE, unlike the situation when EE wasfirst added to the capacity market. However, the MMU recommends that
the PJM load forecast method should be modified so that EE impacts
immediately affect the forecast without the long lag times incorporated

18
19
20
21

See also Comments of the Independent Market Monitor for PJM, Docket No. ER14-503-000 (December 20, 2013).
See “Analysis of Replacement Capacity for RPM Commitments: June 1, 2007 to June 1, 2019,” <http://www.monitoringanalytics.com/
reports/Reports/2019/IMM_Analysis_of_Replacement_Capacity_for_RPM_Commitments_June_1_2007_to_June_1_2019_20190913.
pdf> (September 13, 2019).
See PJM Interconnection, L.L.C., Docket No. ER12-513-000 (December 1, 2011) (“Triennial Review”).
See the 2019 State of the Market Report for PJM, Volume 2, Section 7: Net Revenue.

282

Section 5 Capacity

in the current forecast method. If EE is not included on the supply side,
there is no reason to have an add back mechanism. If EE remains on the
supply side, the implementation of the EE add back mechanism should be
modified to ensure that market clearing prices are not affected. (Priority:
Medium. First reported 2016. Status: Not adopted.)• The MMU recommends that PJM reduce the number of incremental

auctions to a single incremental auction held three months prior to
the start of the delivery year and reevaluate the triggers for holding
conditional incremental auctions. (Priority: Medium. First reported 2013.
Status: Not adopted.)• The MMU recommends that PJM offer to sell back capacity in incremental

auctions only at the BRA clearing price for the relevant delivery year.
(Priority: Medium. First reported 2017. Status: Not adopted.)• The MMU recommends changing the RPM solution method to explicitly
incorporate the cost of make whole payments in the objective function.
(Priority: Medium. First reported 2014. Status: Not adopted.)• The MMU recommends that PJM clear the capacity market based on nodal

capacity resource locations and the characteristics of the transmission
system consistent with the actual electrical facts of the grid. The current
nested LDA structure used in the capacity market does not adequately
represent all the capacity transfers that are feasible among LDAs. Absent
a fully nodal capacity market clearing process, the MMU recommends that
PJM use a nonnested model for all LDAs and specify a VRR curve for each
LDA separately. Each LDA requirement should be met with the capacity
resources located within the LDA and exchanges from neighboring
LDAs up to the transmission limit. LDAs should price separate if thatis the result of the LDA supply curves and the transmission constraints.
(Priority: Medium. First reported 2017. Status: Not adopted.)• The MMU recommends that the maximum price on the VRR curve bedefined as net CONE. (Priority: Medium. First reported 2019. Status: Not
adopted.)• The MMU recommends that the Fixed Resource Requirement (FRR) rules,

including obligations and performance requirements, be revised and© 2021 Monitoring Analytics, LLC

Section 5 Capacity

updated to ensure that the rules reflect current market realities and that
FRR entities do not unfairly take advantage of those customers paying
for capacity in the PJM capacity market. (Priority: Medium. First reported
2019. Status: Not adopted.)Offer Caps, Offer Floors, and Must Offer• The MMU recommends use of the Sustainable Market Rule (SMR) in orderto protect competition in the capacity market from nonmarket revenues.22(Priority: High. First reported 2016. Status: Not adopted.)• The MMU recommends that, as part of the MOPR unit specific standardof review, all projects be required to use the same basic modelingassumptions. That is the only way to ensure that projects compete on thebasis of actual costs rather than on the basis of modeling assumptions.23(Priority: High. First reported 2013. Status: Not adopted.)• The MMU recommends that modifications to existing resources not betreated as new resources for purposes of market power related offer caps
or MOPR offer floors. (Priority: Low. First reported 2012. Status: Not
adopted.)• The MMU recommends that the RPM market power mitigation rule bemodified to apply offer caps in all cases when the three pivotal supplier
test is failed and the sell offer is greater than the offer cap. This will
ensure that market power does not result in an increase in make whole
payments. (Priority: Medium. First reported 2017. Status: Not adopted.)• The MMU recommends that the offer cap for capacity resources be definedas the net avoidable cost rate (ACR) of each unit so that the clearing
prices are a result of such net ACR offers, consistent with the fundamental
economic logic for a competitive offer of a CP resource. (Priority: High.
First reported 2017. Status: Not adopted.)

22
23

Brief of the Independent Market Monitor for PJM, Docket No. EL16-49, ER18-1314-000,-001; EL18-178 (October 2, 2018).
See 143 FERC ¶ 61,090 (2013) (“We encourage PJM and its stakeholders to consider, for example, whether the unit-specific review
process would be more effective if PJM requires the use of common modeling assumptions for establishing unit-specific offer floors
while, at the same time, allowing sellers to provide support for objective, individual cost advantages. Moreover, we encourage PJM
and its stakeholders to consider these modifications to the unit-specific review process together with possible enhancements to thecalculation of Net CONE.”); see also, Comments of the Independent Market Monitor for PJM, Docket No. ER13-535-001 (March 25,2013); Complaint of the Independent Market Monitor for PJM v. Unnamed Participant, Docket No. EL12-63-000 (May 1, 2012); Motion
for Clarification of the Independent Market Monitor for PJM, Docket No. ER11-2875-000, et al. (February 17, 2012); Protest of the
Independent Market Monitor for PJM, Docket No. ER11-2875-002 (June 2, 2011); Comments of the Independent Market Monitor for
PJM, Docket Nos. EL11-20 and ER11-2875 (March 4, 2011).

© 2021 Monitoring Analytics, LLC• The MMU recommends that PJM develop a process for calculating

a forward looking estimate for the expected number of Performance
Assessment Intervals (H) to use in calculating the Market Seller Offer Cap(MSOC). The MMU recommends that the Nonperformance Charge Ratebe left at its current level. The MMU recommends that PJM develop a
forward looking estimate for the Balancing Ratio (B) during Performance
Assessment Intervals (PAIs) to use in calculating the MSOC. Both H
and B parameters should be included in the annual review of planningparameters for the Base Residual Auction, and should incorporate theactual observed reserve margins, and other assumptions consistent withthe annual IRM study. (Priority: High. First reported 2017. Status: Not
adopted.)• The MMU recommends that capacity market sellers be required to request

the use of minimum MW quantities greater than 0 MW (inflexible selloffer segments) and that the requests should only be permitted for defined
physical reasons. (Priority: Medium. First reported 2018. Status: Not
adopted.)• The MMU recommends that PJM update the values in the CRF table in thetariff when the components change. (Priority: High. First reported 2020.
Status: Not adopted.)

Performance Incentive Requirements of RPM• The MMU recommends that any unit which is not capable of supplying

energy consistent with its day-ahead offer which should equal its ICAP,
reflect an appropriate outage. (Priority: Medium. First reported 2009.
Status: Not adopted.)• The MMU recommends that retroactive replacement transactions

associated with a failure to perform during a PAI not be allowed andthat, more generally, retroactive replacement capacity transactions not be
permitted. (Priority: Medium. First reported 2016. Status: Not adopted.)• The MMU recommends that there be an explicit requirement that capacity
resource offers in the day-ahead energy market be competitive, where

2021 Quarterly State of the Market Report for PJM: January through June283

2021 Quarterly State of the Market Report for PJM: January through June•

competitive is defined to be the short run marginal cost of the units.
(Priority: Low. First reported 2013. Status: Not adopted.)
The MMU recommends that Capacity Performance resources be required
to perform without excuses. Resources that do not perform should not be
paid regardless of the reason for nonperformance. (Priority: High. First
reported 2019. Status: Not adopted.)• The MMU recommends that the market data posting rules be modified

to allow the disclosure of expected performance, actual performance,
shortfall and bonus MW during a PAI by area without the requirementthat more than three market participants’ data be aggregated for posting.
(Priority: Low. First reported 2019. Status: Not adopted.)

Capacity Imports and Exports

Deactivations/Retirements• The MMU recommends that the notification requirement for deactivations

be extended from 90 days prior to the date of deactivation to 12 months
prior to the date of deactivation and that PJM and the MMU be provided
60 days rather than 30 days to complete their reliability and market
power analyses. (Priority: Low. First reported 2012. Status: Not adopted.)• The MMU recommends that RMR units recover all and only theincremental costs, including incremental investment costs, required by
the RMR service that the unit owner would not have incurred if the unit
owner had deactivated its unit as it proposed. Customers should bear no
responsibility for paying previously incurred costs, including a return on
or of prior investments. (Priority: Low. First reported 2010. Status: Not
adopted.)• The MMU recommends that all capacity imports be required to be• The MMU recommends elimination of the cost of service recovery rate in• The MMU recommends that all costs incurred as a result of a pseudo tied

Conclusiondeliverable to PJM load prior to the relevant delivery year to ensure thatthey are full substitutes for internal, physical capacity resources. Pseudoties alone are not adequate to ensure deliverability. (Priority: High. First
reported 2016. Status: Not adopted.)
unit be borne by the unit itself and included as appropriate in unit offers
in the capacity market. (Priority: High. First reported 2016. Status: Not
adopted.)• The MMU recommends clear, explicit and detailed rules that define theconditions under which PJM will and will not recall energy from PJM
capacity resources and prohibit new energy exports from PJM capacity
resources. The MMU recommends that those rules define the conditions
under which PJM will purchase emergency energy while at the sametime not recalling energy exports from PJM capacity resources. PJM
has modified these rules, but the rules need additional clarification andoperational details. (Priority: Low. First reported 2010. Status: Partiallyadopted.)284

Section 5 Capacity

OATT Section 119, and that RMR service should be provided under thedeactivation avoidable cost rate in Part V. The MMU also recommends
specific improvements to the DACR provisions. (Priority: Medium. First
reported 2017. Status: Not adopted.)

The analysis of PJM Capacity Markets begins with market structure, which
provides the framework for the actual behavior or conduct of market
participants. The analysis examines participant behavior within that market
structure. In a competitive market structure, market participants are constrained
to behave competitively. The analysis examines market performance, measured
by price and the relationship between price and marginal cost, that resultsfrom the interaction of market structure and participant behavior. Market
power is and will remain endemic to the structure of the PJM Capacity Market.
Nonetheless a competitive outcome can be assured by appropriate market
power mitigation rules.
The MMU concludes that the 2021/2022 RPM Base Residual Auction results
were not competitive as a result of offers above the competitive level bysome market participants. The MMU has not completed its analysis of the© 2021 Monitoring Analytics, LLC

Section 5 Capacity

2022/2023 RPM Base Residual Auction. The MMU recognizes that thesemarket participants followed the capacity market rules by offering at lessthan the stated offer cap of net CONE times B. But net CONE times B is not
a competitive offer when the expected number of performance assessment
intervals is zero or a very small number and the nonperformance charge rateis defined as net CONE/30. Under these circumstances, a competitive offer,
under the logic defined in PJM’s capacity performance filing, is net ACR. Thatis the way in which most market participants offered in this and prior capacity
performance auctions.
The FERC approved PJM tariff defines the offer cap as net CONE times B,
rather than including the full logic supporting the definition of the offer cap
under the capacity performance paradigm. If the tariff had defined the offer
cap consistent with PJM’s filing in the capacity performance matter, the offer
cap would have been net ACR rather than net CONE times B.
The MMU filed a complaint with the Commission asserting that the market
seller offer cap is overstated.24 The result of an overstated market seller offer cap
is to permit the exercise of market power, as occurred in the 2021/2022 BRA.
The MMU has not completed its analysis of the 2022/2023 RPM Base ResidualAuction. On March 18, 2021, the Commission issued an order determining thatthe current default market seller offer cap “is incorrectly calibrated such thatit may unjustly and unreasonably prevent the appropriate review of offers,
thereby allowing potential exercises of market power.”25 The Commission
asked the parties to file briefs to address “whether an alternative method formarket power mitigation in the PJM capacity market would better address
the concern that the current methodology precludes the Market Monitor from
reviewing offers that raise market power concerns and mitigating offers whereappropriate.” The MMU filed a brief on the market seller offer cap issue.26

The MMU is required to identify market issues and to report them to theCommission and to market participants. The Commission decides on any
action related to the MMU’s findings.
The MMU found serious market structure issues, measured by the threepivotal supplier test results in the PJM Capacity Market in the last BRA andin subsequent incremental auctions. Explicit market power mitigation rules in
the RPM construct only partially offset the underlying market structure issues
in the PJM Capacity Market under RPM. In the 2021/2022 RPM Base ResidualAuction, the default offer cap of net CONE times B exceeded the competitive
offer for a number of resources. Some seasonal resources were paid additional
make whole based on a failure of the market power rules to apply offer
capping. The MMU has not completed its analysis of the 2022/2023 RPM Base
Residual Auction.
The MMU has identified serious market design issues with RPM and the MMU
has made specific recommendations to address those issues.27 28 29 30 31 32 In 2020
and 2021, the MMU prepared a number of RPM related reports and testimony,shown in Table 5-2.
The capacity performance modifications to the RPM construct significantly
improved the capacity market and addressed a number of issues that had been
identified by the MMU. But significant issues remain in the PJM capacity
market design.
The PJM markets have worked to provide incentives to entry and to retain
capacity. PJM had excess reserves of 7,828.5 ICAP MW on June 1, 2021, andwill have excess reserves of 8,065.7 ICAP MW on June 1, 2022, based on
27
28
29
30

24
25
26

In 2019, the MMU filed a complaint seeking an order directing PJM to update the assumptions regarding the expected number of
performance assessment intervals (PAI) in calculating the default capacity market seller offer cap (MSOC). Complaint of the Independent
Market Monitor for PJM, Docket No. EL19-47-000 (February 21, 2019).
174 FERC ¶ 61,212.
Brief of the Independent Market Monitor for PJM, Docket No. EL19-47 and EL19-63, not consolidated (April 28, 2021).

© 2021 Monitoring Analytics, LLC

31
32

See “Analysis of the 2018/2019 RPM Base Residual Auction Revised,” <http://www.monitoringanalytics.com/reports/Reports/2016/
IMM_Analysis_of_the_20182019_RPM_Base_Residual_Auction_20160706.pdf> (July 6, 2016).
See “Analysis of the 2019/2020 RPM Base Residual Auction Revised,” <http://www.monitoringanalytics.com/reports/Reports/2016/
IMM_Analysis_of_the_20192020_RPM_BRA_20160831-Revised.pdf> (August 31, 2016).
See “Analysis of the 2020/2021 RPM Base Residual Auction,” <http://www.monitoringanalytics.com/reports/Reports/2017/IMM_
Analysis_of_the_20202021_RPM_BRA_20171117.pdf> (November 11, 2017).
See “Analysis of the 2021/2022 RPM Base Residual Auction - Revised,” <http://www.monitoringanalytics.com/reports/Reports/2018/
IMM_Analysis_of_the_20212022_RPM_BRA_Revised_20180824.pdf> (August 24, 2018).
See “Analysis of Replacement Capacity for RPM Commitments: June 1, 2007 to June 1, 2017,” <http://www.monitoringanalytics.com/
reports/Reports/2017/IMM_Report_on_Capacity_Replacement_Activity_4_20171214.pdf> (December 14, 2017).
See “Analysis of Replacement Capacity for RPM Commitments: June 1, 2007 to June 1, 2019,” <http://www.monitoringanalytics.com/
reports/Reports/2019/IMM_Analysis_of_Replacement_Capacity_for_RPM_Commitments_June_1_2007_to_June_1_2019_20190913.
pdf> (September 13, 2019).

2021 Quarterly State of the Market Report for PJM: January through June285

2021 Quarterly State of the Market Report for PJM: January through Junecurrent positions.33 A majority of capacity investments in PJM were financed
by market sources.34 Of the 42,969.5 MW of additional capacity that cleared in
RPM auctions for the 2007/2008 through 2021/2022 Delivery Years, 31,509.22
MW (73.3 percent) were based on market funding. Of the 6,675.0 MW of
additional capacity that cleared in RPM auctions for the 2022/2023 through2023/2024 Delivery Years, 5,007.8 MW (75.0 percent) were based on market
funding. Those investments were made based on the assumption that markets
would be allowed to work and that inefficient units would exit.
The issue of external subsidies, particularly for economic nuclear power plants,
continued to evolve. The subsidies are not part of the PJM market design but
nonetheless threaten the foundations of the PJM Capacity Market as well as
the competitiveness of PJM markets overall. These subsidy programs originate
from the fact that competitive markets result in the exit of uneconomic anduncompetitive generating units. Regardless of the specific rationales offeredby unit owners, the proposed solution for all such generating units has been
to provide out of market subsidies in order to retain such units. The proposedsolution in all cases ignores the opportunity cost of subsidizing uneconomic
units, which is the displacement of new resources and technologies thatwould otherwise be economic. Some subsidies were requested by the ownersof economic resources. Some subsidies were requested by the owners ofspecific uneconomic generating units in order to improve the profitabilityof those specific units. These subsidies were not requested to accomplish
broader social goals. Broader social goals can all be met with market-based
mechanisms available to all market participants on a competitive basis andwithout discrimination.

It is essential that any approach to the PJM markets incorporate a consistentview of how the preferred market design is expected to provide competitive
results in a sustainable market design over the long run. A sustainable
market design means a market design that results in appropriate incentives
to competitive market participants to retire units and to invest in new units
over time such that reliability is ensured as a result of the functioning of themarket.
A sustainable competitive wholesale power market must recognize threesalient structural elements: state nonmarket revenues for renewable energy; asignificant level of generation resources subject to cost of service regulation;and the structure and performance of the existing market based generation
fleet.

Subsidies are contagious. Competition in the markets could be replaced andis now being replaced by competition to receive subsidies. Competition toreceive subsidies is now a reality and is accelerating in PJM.

33
34

The calculated reserve margin for June 1, 2022, does not account for cleared buy bids that have not been used in replacement capacitytransactions.
“2020 PJM Generation Capacity and Funding Sources 2007/2008 through 2021/2022 Delivery Years,” <http://www.monitoringanalytics.
com/reports/Reports/2020/IMM_2020_PJM‌_Generation_Capacity_and_Funding_Sources_20072008_through_20212022_
DY_20200915.pdf> (September 15, 2020).

286

Section 5 Capacity© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Table 5-2 RPM related MMU reports: 2020 through 2021
Date
January 16, 2020
January 17, 2020
January 21, 2020
February 5, 2020
February 17, 2020
February 18, 2020
February 18, 2020
February 21, 2020
February 28, 2020
March 20, 2020
April 16, 2020
May 6, 2020
May 13, 2020
May 15, 2020
May 15, 2020
May 20, 2020
June 22, 2020
June 24, 2020
June 30, 2020
July 15, 2020
July 17, 2020
July 20, 2020
July 23, 2020
July 27, 2020
September 15, 2020
September 19, 2020
September 30, 2020
October 19, 2020
October 19, 2020
November 5, 2020
November 20, 2020
December 4, 2020
December 14, 2020
December 17, 2020
December 18, 2020
December 29, 2020

Name
Net Revenues for PJM RPM Base Residual Auctions in 2020 http://www.monitoringanalytics.com/reports/Market_Messages/RPM_Material/IMM_Net_Revenues_20232024_RPM_BRA_20200116.pdf
IMM Request for Clarification re MOPR Order Docket Nos. EL16-49 and EL18-178 http://www.monitoringanalytics.com/filings/2020/IMM_Request_for_Clarification_Docket_Nos_EL16-49_EL18-178_20200117.pdf
CONE and ACR Values - Preliminary http://www.monitoringanalytics.com/reports/Presentations/2020/IMM_MIC_Special_Special_Session_CONE_and_ACR_Values_20200128.pdf
IMM Answer to Requests for Rehearing’s Docket No. EL14-69 and EL18-178 http://www.monitoringanalytics.com/filings/2020/IMM_Answer_To_RFRS_Docket_Nos_EL14-69_EL18-178_20200205.pdf
IMM MOPR Gross CONE Template http://www.monitoringanalytics.com/reports/Presentations/2020/IMM_MOPR_Gross_CONE_Template_20200217.xlsx
IMM Second Request for Clarification re MOPR Docket No. EL18-178, EL16-49
http://www.monitoringanalytics.com/filings/2020/IMM_Second_Request_for_Clarification_Docket_No_EL18-178_%20EL16-49_20200218.pdf
Unit Specific Nuclear ACR Information http://www.monitoringanalytics.com/reports/Presentations/2020/IMM_MIC_MOPR_Unit_Specific_Nuclear_ACR_Information_20200219.pdf
Generation Capacity Resources in PJM Region Subject to RPM Must Offer Obligation for 2020/2021, 2021/2022 and 2022/2023 Delivery Years
http://www.monitoringanalytics.com/reports/Market_Messages/RPM_Material/IMM_RPM_Must_Offer_Obligations_20200221.pdf
Monitoring Analytics ACR Template http://www.monitoringanalytics.com/reports/Presentations/2020/IMM_MIC_Special_Session_ACR_Template_20200228.pdf
Potential Impacts of the MOPR Order http://www.monitoringanalytics.com/reports/Reports/2020/IMM_Potential_Impacts_of_the_MOPR_Order_20200320.pdf
Potential Impacts of the Creation of Maryland FRRs http://www.monitoringanalytics.com/reports/Reports/2020/IMM_Potential_Impacts_of_the_Creation_of_Maryland_FRRs_20200416.pdf
Potential Compliance with P386 of FERC Order on Rehearing
http://www.monitoringanalytics.com/reports/Presentations/2020/IMM_MIC_Special_Session_Potential_Compliance_with_P386_of_FERC_Order_on_Rehearing_20200506.pdf
Potential Impacts of the Creation of New Jersey FRRs http://www.monitoringanalytics.com/reports/Reports/2020/IMM_Potential_Impacts_of_the_Creation_of_New_Jersey_FRRS_20200513.pdf
IMM Request for Clarification re MOPR Ex Investigation Docket Nos. EL18-178-002 and EL16-49-002
http://www.monitoringanalytics.com/filings/2020/IMM_Request_for_Clarification_Docket_No_EL18-178-002_EL16-49-002_20200515.pdf
IMM Comments re MOPR-Ex Docket Nos. ER18-1314-00, EL16-49-000, EL18-178-000
http://www.monitoringanalytics.com/filings/2020/IMM_Comments_Docket_No_ER18-1314-003_EL16-49_EL18-178_20200515.pdf
IMM Comments re NJBPU Investigation of Resource Adequacy Alternatives Docket No. EO20030203 http://www.monitoringanalytics.com/filings/2020/IMM_Comments_Docket_No_EO20030203_20200520.pdf
IMM Comments re MOPR-Ex Compliance Filing Docket Nos. ER18-1314, EL16-49 and ERL8-178
http://www.monitoringanalytics.com/filings/2020/IMM_Comments_Docket_No_ER18-1314_EL16-49_ER18-178_20200622.pdf
IMM Reply Comments re NJ BPU Resource Adequacy Alternatives Docket No. EO20030203 http://www.monitoringanalytics.com/filings/2020/IMM_Reply_Comments_Docket_No_EO20030203_20200624.pdf
Generation Capacity Resources in PJM Region Subject to RPM Must Offer Obligation for 2021/2022 and 2022/2023 Delivery Years
http://www.monitoringanalytics.com/reports/Market_Messages/RPM_Material/IMM_RPM_Must_Offer_Obligations_20200630.pdf
IMM Answer to PSEG and Exelon Reply re New Jersey FRR Docket No. EO20030203 http://www.monitoringanalytics.com/filings/2020/IMM_Answer_to_Exelon_PSEG_Docket_No_EO20030203_20200715.pdf
Potential Impacts of the Creation of Ohio FRRs http://www.monitoringanalytics.com/reports/Reports/2020/IMM_Potential_Impacts_of_the_Creation_of%20Ohio_FRRs_20200717.pdf
IMM Comments re NJ BPU Nuclear Power Plant ZECs Docket No. EO18080899 http://www.monitoringanalytics.com/filings/2020/IMM_Comments_Docket_No_EO18080899_20200720.pdf
IMM Answer re MOPR Ex Docket No. EL16-49, ER18-1314 and EL18-178 http://www.monitoringanalytics.com/filings/2020/IMM_Answer_Docket_No_EL16-49_ER18-1314_EL18-178_20200724.pdf
IMM Comments re ORDC Compliance Filing Docket No. EL19-58-002 and ER19-1486 http://www.monitoringanalytics.com/filings/2020/IMM_Comments_EL19-58-002_ER19-1486-20200727.pdf
2020 PJM Generation Capacity and Funding Sources: 2007/2008 through 2021/2022
http://www.monitoringanalytics.com/reports/Reports/2020/IMM_2020_PJM_Generation_Capacity_and_Funding_Sources_20072008_through_20212022_DY_20200915.pdf
ELCC-IMM Comments https://www.monitoringanalytics.com/reports/Presentations/2020/IMM_MRC_ELCC_IMM_Comments_20200919.pdf
Generation Capacity Resources in PJM Region Subject to RPM Must Offer Obligation for 2021/2022 and 2022/2023 Delivery Years
https://www.monitoringanalytics.com/reports/Market_Messages/RPM_Material/IMM_RPM_Must_Offer_Obligations_20200930.pdf
Issues with HVDC as Capacity https://www.monitoringanalytics.com/reports/Presentations/2020/IMM_HVDCSTF_Issues_with_HVDC_as_Capacity_20201019.pdf
IMM Answer re EAS Docket No. EL19-58-003 https://www.monitoringanalytics.com/filings/2020/IMM_Answer_Docket_No_EL19-58-003_20201019.pdf
PAI Settlement Issues https://www.monitoringanalytics.com/reports/Presentations/2020/IMM_MIC_PAI_Settlement_Issues_20201102.pdf
IMM Comments re ELCC Docket No. ER21-278 https://www.monitoringanalytics.com/filings/2020/IMM_Comments_Docket_No_ER21-278_20201120.pdf
CRF Issues in the Capacity Market https://www.monitoringanalytics.com/reports/Market_Messages/Messages/IMM_CRF_Issues_in_the_Capacity_Market_20201204.pdf
IMM Answer and Motion for Consolidation re ELCC Docket No. ER21-278 https://www.monitoringanalytics.com/filings/2020/IMM_Answer_Docket_No_ER21-278_20201214.pdf
IMM Comments re PAI Docket No. ER15-623, et al https://www.monitoringanalytics.com/filings/2020/IMM_Comments_Docket_No_ER15-623_et_al_20201217.pdf
IMM Answer re PJM ELCC Proposal Docket No. ER21-278 https://www.monitoringanalytics.com/filings/2020/IMM_Answer_Docket_No_ER21-278_20201218.pdf
Generation Capacity Resources in PJM Region Subject to RPM Must Offer Obligation for 2021/2022 and 2022/2023 Delivery Years
https://www.monitoringanalytics.com/reports/Market_Messages/RPM_Material/IMM_Notice_RPM_Must_Offer_Obligations_20201229.pdf© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June287

2021 Quarterly State of the Market Report for PJM: January through June

Table 5-2 RPM related MMU reports: 2020 through 2021 (continued)
Date
January 29, 2021
February 19, 2021
March 4, 2021
March 5, 2021
March 22, 2021
March 31, 2021
April 7, 2021
April 12, 2021
April 19, 2021
April 26, 2021
April 28, 2021
April 29, 2021
May 18, 2021
May 19, 2021
May 25, 2021
June 9, 2021
June 15, 2021
June 16, 2021
June 22, 2021
June 25, 2021
June 28, 2021
June 30, 2021

Name
Analysis of NJ Zero Emissions Credit(ZEC)Applications https://www.monitoringanalytics.com/reports/Reports/2021/IMM_Public_Report_Analysis_of_NJ_ZEC_Applications_20210129.pdf
Generation Capacity Resources in PJM Region Subject to RPM Must Offer Obligation for 2021/2022 and 2022/2023 Delivery Years
https://www.monitoringanalytics.com/reports/Market_Messages/RPM_Material/IMM_RPM_Must_Offer_Obligations_20210219.pdf
Next Steps in Capacity Market Design https://www.monitoringanalytics.com/reports/Presentations/2021/IMM_Capacity_Market_Workshop_Session_2_Next_Steps_in_Capacity_Market_Design_20210304.pdf
IMM Comment re New Jersey FRR Docket No. EO20030203 https://www.monitoringanalytics.com/filings/2021/IMM_Comment_Docket_No_EO20030203_20210305.pdf
IMM Comments re ELCC Docket No. ER21-278-001 https://www.monitoringanalytics.com/filings/2021/IMM_Comments_Docket_No_ER21-278-001_20210322.pdf
IMM Answer re Jackson Complaint Docket No. EL21-62, et al https://www.monitoringanalytics.com/filings/2021/IMM_Answer_Docket_Nos_EL21-62_EL21-63_20210331.pdf
RPM Capacity Transfer Rights: Education https://www.monitoringanalytics.com/reports/Presentations/2021/IMM_MIC_RPM_Capacity_Transfer_Rights_Education_20210407.pdf
IMM Commentsr re Jackson Complaint Docket No. EL21-62, et al https://www.monitoringanalytics.com/filings/2021/IMM_Comments_Docket_Nos_EL21-62_EL21-63_20210412.pdf
IMM Answer to P3 re MSOC Docket Nos. EL19-47-001, et al https://www.monitoringanalytics.com/filings/2021/IMM_Answer_Docket_No_EL19-47_et_al_20210419.pdf
IMM Comments re Modernizing Electricity Market Design Docket No. AD21-10 https://www.monitoringanalytics.com/filings/2021/IMM_Post_Technical_Conference_Comments_Docket_No_AD21-10_20210426.pdf
IMM Brief re MSOC Docket No. EL19-47 and EL19-63 https://www.monitoringanalytics.com/filings/2021/IMM_Brief_Docket_No_EL19-47_et_al_20210428.pdf
IMM Answer to PJM re ELCC Docket No. ER21-278 https://www.monitoringanalytics.com/filings/2021/IMM_Answer_to_PJM_Docket_No_ER21-278_20210429.pdf
Generation Capacity Resources in PJM Region Subject to RPM Must Offer Obligation for 2022/2023 Delivery Yearhttps://www.monitoringanalytics.com/reports/Market_Messages/Messages/IMM_RPM_Must_Offer_Obligations_20210518.pdf
IMM Answer to Motion re ELCC Docket No. EL19-100 and ER20-584 https://www.monitoringanalytics.com/filings/2021/IMM_Answer_to_Motion_Docket_No_EL19-100_20210519.pdf
IMM Comments re PJM Capacity Market CRF Docket No. ER21-1844 https://www.monitoringanalytics.com/filings/2021/IMM_Comments_Docket_No_ER21-1844_20210525.pdf
IMM Reply Brief re MSOC Docket No. EL19-47 and EL19-63 https://www.monitoringanalytics.com/filings/2021/IMM_Reply_Brief_Docket_No_EL19-47_EL19-63_20210609.pdf
IMM Response to Exelon re 10 Year Report Case No. 9271 https://www.monitoringanalytics.com/filings/2021/IMM_Response_to_Exelon_MDPSC_Case_No_%209271_20210615.pdf
IMM MOPR Matrix Entries https://www.monitoringanalytics.com/reports/Presentations/2021/IMM_MOPR_Matrix_Entries_20210616.pdf
IMM Comments re ELCC Docket No. ER21-2043 https://www.monitoringanalytics.com/filings/2021/IMM_Comment_Docket_No_ER21-2043_20210622.pdf
IMM Answer to Replies re MSOC Docket No. EL19-47 and EL19-63 https://www.monitoringanalytics.com/filings/2021/IMM_Answer_Docket_No_EL19-47_20210625.pdf
Data Submission Window Opening: 2023/2024 Base Residual Auction
https://www.monitoringanalytics.com/reports/Market_Messages/RPM_Material/IMM_Data_Submission_Window_Opening_2023-2024_BRA_20210628.pdf
IMM MOPR Matrix Entries https://www.monitoringanalytics.com/reports/Presentations/2021/IMM_CIFP_MOPR_MOPR_Matrix_Entries_20210630.pdf

Installed Capacity
On January 1, 2021, RPM installed capacity was 184,245.0 MW (Table 5-3).35 Over the next six months, new generation, unit deactivations, facility reratings,
plus import and export shifts resulted in RPM installed capacity of 183,962.3 MW on June 30, 2021, a decrease of 282.7 MW or 0.2 percent from the January
1 level.36 37 The 282.7 MW decrease was the result of an increase in exports (154.9 MW), derates (964.4 MW), and deactivations (2,736.5 MW), offset by new orreactivated generation (2,958.3 MW), capacity modifications (430.3 MW), and an increase in imports (184.5 MW).
At the beginning of the new delivery year on June 1, 2021, RPM installed capacity was 183,962.3 MW, an increase of 1,024.4 MW or 0.6 percent from the May
31, 2021, level of 182,937.9 MW.

35
36
37

Percent values shown in Table 5-3 are based on unrounded, underlying data and may differ from calculations based on the rounded values in the tables.
Unless otherwise specified, the capacity described in this section is the summer installed capacity rating of all PJM generation capacity resources, as entered into the Capacity Exchange system, regardless of whether the capacity cleared in the RPM auctions.
Wind resources accounted for 1,522.9 MW, and solar resources accounted for 1,779.5 MW of installed capacity in PJM on June 30, 2021. PJM administratively reduces the capabilities of all wind generators to 14.7 percent for wind farms in mountainous terrain and 17.6 percent for windfarms in open terrain, and solar generators to 42.0 percent for ground mounted fixed panel, 60.0 percent for ground mounted tracking panel, and 38.0 percent for other than ground mounted solar arrays, of nameplate capacity when determining the installed capacity because windand solar resources cannot be assumed to be available on peak and cannot respond to dispatch requests. As data become available, unforced capability of wind and solar resources will be calculated using actual data. There are additional wind and solar resources not reflected in total
capacity because they are energy only resources and do not participate in the PJM Capacity Market. See “PJM Manual 21: Rules and Procedures for Determination of Generating Capability,” Appendix B.3 Calculation Procedure, Rev. 15 (May 26, 2021).

288

Section 5 Capacity© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Table 5-3 Installed capacity (By fuel source): January 1, May 31, June 1, and June 30, 2021
Coal
Gas
Hydroelectric
Nuclear
Oil
Solar
Solid waste
Wind
Total

01-Jan-21
MW
Percent
49,747.0
27.0%
84,031.3
45.6%
8,754.3
4.8%
32,312.4
17.5%
5,512.6
3.0%
1,014.7
0.6%
695.6
0.4%
2,177.1
1.2%
184,245.0
100.0%

31-May-21
MW
Percent
49,340.2
27.0%
83,914.1
45.9%
8,753.5
4.8%
32,301.2
17.7%
5,507.1
3.0%
1,051.1
0.6%
650.5
0.4%
1,420.2
0.8%
182,937.9
100.0%

01-Jun-21
MW
Percent
48,714.4
26.5%
84,651.7
46.0%
8,792.0
4.8%
32,301.2
17.6%
5,550.1
3.0%
1,779.5
1.0%
650.5
0.4%
1,522.9
0.8%
183,962.3
100.0%

30-Jun-21
MW
Percent
48,714.4
26.5%
84,651.7
46.0%
8,792.0
4.8%
32,301.2
17.6%
5,550.1
3.0%
1,779.5
1.0%
650.5
0.4%
1,522.9
0.8%
183,962.3
100.0%

Figure 5-1 shows the share of installed capacity by fuel source for the first day of each delivery year, from June 1, 2007, to June 1, 2021, as well as the expected
installed capacity for the 2022/2023 Delivery Year, based on the results of all auctions held through June 30, 2021.38 On June 1, 2007, coal comprised 40.7
percent of the installed capacity, reached a maximum of 42.9 percent in 2012, decreased to 25.5 percent on June 1, 2021, and is projected to decrease to 21.2
percent by June 1, 2022. The share of gas increased from 29.1 percent on June 1, 2007, to 50.6 percent on June 1, 2021, and is projected to increase to 54.3
percent on June 1, 2022.
Figure 5-1 Percent of installed capacity (By fuel source): June 1, 2007 through June 1, 202
Coal

Gas

Hydroelectric

Nuclear

Oil

Solar

Solid waste

Wind

Percent of Installed Capacity

50%

40%

30%

20%

38

Jun-2022

Jun-2021

Jun-2020

Jun-2019

Jun-2018

Jun-2017

Jun-2016

Jun-2015

Jun-2014

Jun-2013

Jun-2012

Jun-2011

Jun-2010

Jun-2009

Jun-20080%

Jun-2007

10%

Due to EFORd values not being finalized for future delivery years, the projected installed capacity is based on cleared unforced capacity (UCAP) MW using the EFORd submitted with the offer.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June289

2021 Quarterly State of the Market Report for PJM: January through June

Table 5-4 shows the RPM installed capacity on January 1, 2021, through June 30, 2021, for the top five generation capacity resource owners, excluding FRR
committed MW.
Table 5-4 Installed capacity by parent company: January 1, May 31, June 1, and June 30, 202139
Parent Company
Exelon Corporation
Dominion Resources, Inc.
Vistra Energy Corp.
Riverstone Holdings LLC
LS Power Group

01-Jan-21
Percent of
ICAP (MW) Total ICAP
20,843.6
12.2%
19,533.2
11.4%
11,319.0
6.6%
10,941.4
6.4%
10,843.7
6.3%

31-May-21
Percent ofRank ICAP (MW) Total ICAP
120,787.3
12.2%
2
19,505.1
11.5%
3
11,319.0
6.7%
4
10,866.5
6.4%
5
11,053.7
6.5%

01-Jun-21
Percent ofRank ICAP (MW) Total ICAP
120,747.0
12.2%
2
19,702.1
11.6%
3
11,327.8
6.7%
5
10,914.8
6.4%
4
11,253.4
6.6%

30-Jun-21
Percent ofRank ICAP (MW) Total ICAP
120,747.0
12.2%
2
19,702.1
11.6%
3
11,327.8
6.7%
5
10,914.8
6.4%
4
11,253.4
6.6%

Rank
1
2
3
5
4

The sources of funding for generation owners can be categorized as one of two types: market and nonmarket. Market funding is from private investors bearing
the investment risk without guarantees or support from any public sources, subsidies or guaranteed payment by ratepayers. Providers of market funding rely
entirely on market revenues. Nonmarket funding is from guaranteed revenues, including cost of service rates for a regulated utility and subsidies. Table 5-5
shows the RPM installed capacity on January 1, 2021, to June 30, 2021, by funding type.
Table 5-5 Installed capacity by funding type: January 1, May 31, June 1, and June 30, 202140
01-Jan-21
31-May-21
01-Jun-21
30-Jun-21
Percent ofPercent ofPercent ofPercent ofFunding Type ICAP (MW) Total ICAP ICAP (MW) Total ICAP ICAP (MW) Total ICAP ICAP (MW) Total ICAP
Market137,312.5
74.5% 136,106.1
74.4% 136,807.7
74.4% 136,807.7
74.4%
Nonmarket
46,932.5
25.5%
46,831.8
25.6%
47,154.6
25.6%
47,154.6
25.6%
Total
184,245.0
100.0% 182,937.9
100.0% 183,962.3
100.0% 183,962.3
100.0%

Fuel Diversity
Figure 5-2 shows the fuel diversity index (FDIc) for RPM installed capacity.41 The FDIc is defined as, where si is the percent share of fuel type i. The
minimum possible value for the FDIc is zero, corresponding to all capacity from a single fuel type. The maximum possible value for the FDIc is achieved wheneach fuel type has an equal share of capacity. For a capacity mix of eight fuel types, the maximum achievable index is 0.875. The fuel type categories used in
the calculation of the FDIc are the eight fuel sources in Table 5-3. The FDIc is stable and does not exhibit any long-term trends. The only significant deviation
occurred with the expansion of the PJM footprint. On April 1, 2002, PJM expanded with the addition of Allegheny Power System, which added about 12,000
MW of generation.42 The reduction in the FDIc resulted from an increase in coal capacity resources. A similar but more significant reduction occurred in 2004
with the expansion into the COMED, AEP, and DAY Control Zones.43 The average FDIc for the first six months of 2021 decreased 0.3 percent compared to the
39
40
41
42
43

The calculated MW for January 1, 2021, were revised from the 2021 Quarterly State of the Market Report for PJM: January through March.
The calculated MW for January 1, 2021, were revised from the 2021 Quarterly State of the Market Report for PJM: January through March.
Monitoring Analytics developed the FDI to provide an objective metric of fuel diversity. The FDI metric is similar to the HHI used to measure market concentration. The FDI is calculated separately for energy output and for installed capacity.
On April 1, 2002, the PJM Region expanded with the addition of Allegheny Power System under a set of agreements known as “PJM-West.” See page 4 in the 2002 State of the Market Report for PJM for additional details.
See the 2019 State of the Market Report for PJM, Volume II, Appendix A, “PJM Geography” for an explanation of the expansion of the PJM footprint. The integration of the COMED Control Area occurred in May 2004 and the integration of the AEP and DAY Control Zones occurred in
October 2004.

290

Section 5 Capacity© 2021 Monitoring Analytics, LLC

Section 5 Capacity

The FDIc was used to measure the impact of potential retirements of resourcesthat the MMU has identified as being at risk of retirement. A total of 4,763 MWof coal, CT and other capacity were identified as being at risk of retirement.44
Generation owners that intend to retire a generator are required by the tariff
to notify PJM at least 90 days in advance of the retirement.45 There are 10,161
MW of generation that have a requested retirement date after June 30, 2021.46
The dashed green line in Figure 5-2 shows the FDIc calculated assuming thatthe capacity that cleared in an RPM auction from the at risk resources andother resources with deactivation notices is replaced by gas, wind and solar
capacity.47 48 The FDIc under these assumptions would decrease by 1.3 percent
on average from the expected FDIc for the period July 1, 2021, through June
1, 2022.

Figure 5-2 Fuel Diversity Index for installed capacity: January 1, 2002
through June 1, 2023
1.0
0.9
0.8
0.7
Fuel Diversity Index (FDI)

first six months of 2020. Figure 5-2 also includes the expected FDIc throughJune 2022 based on cleared RPM auctions. The expected FDIc is indicated in
Figure 5-2 by the dashed orange line.

0.6
0.5
0.4

0.3
FDI

0.2

Maximum Achievable FDI (8 Fuel Types)
FDI after replacing capacity from at risk resources and announced
retirements with capacity from gas, solar and wind resources

0.1
0.0

RPM Capacity Market

44
45
46
47

48

See Table 7-47 in the 2020 State of the Market Report for PJM, Volume II, Section 7: Net Revenue.
See OATT Part V § 113.1.
See 2020 State of the Market Report for PJM: January through June, Volume II, Section 12: Generation and Transmission Planning, Table
12-11.
It is assumed that 2,212.4 MW of replacement capacity is from solar units and 205.2 MW from wind units, with the remaining
replacement capacity coming from gas units. This is the amount of derated wind and solar capacity needed to produce 3,561.2 GWhof generation over a six month period assuming the average capacity derate factors in the Planned Generation Additions subsectionof Section 12 and the average capacity factors for wind and solar capacity resources in Table 8-27 and Table 8-30. This level of GWh
represents the increase in renewable generation required by RPS in the first six months of 2022 over the level of renewable generationthat was required by RPS in the first six months of 2022. The split between solar and wind is based on queue data.
For this analysis resources for which PJM has received deactivation notifications were replaced with capacity beginning on the projected
retirement date listed in the deactivation data. At risk resources that have not notified PJM regarding deactivation were replaced withcapacity beginning on July 1, 2021.

© 2021 Monitoring Analytics, LLC

The RPM Capacity Market, implemented June 1, 2007, is a forward-looking,annual, locational market, with a must offer requirement for Existing
Generation Capacity Resources and mandatory participation by load, withperformance incentives, that includes clear market power mitigation rules andthat permits the direct participation of demand-side resources.
Annual base auctions are held in May for delivery years that are three years
in the future. Effective January 31, 2010, First, Second, and Third Incremental
Auctions are conducted 20, 10, and three months prior to the delivery year.49
49

See Letter Order, Docket No. ER10-366-000 (January 22, 2010).

2021 Quarterly State of the Market Report for PJM: January through June291

2021 Quarterly State of the Market Report for PJM: January through June

In the first six months of 2021, the 2021/2022 RPM Third Incremental Auctionand 2022/2023 RPM Base Residual Auction were conducted.50

not account for cleared buy bids that have not been used in replacement
capacity transactions.

Market Structure

Future Changes in Generation Capacity51

SupplyAs shown in Table 5-6, for the period from the introduction of the RPM
capacity market design in the 2007/2008 Delivery Year through the 2020/2021
Delivery Year, internal installed capacity decreased by 3,654.3 MW after
accounting for new capacity resources, reactivations, and uprates (42,969.5
MW) and capacity deactivations and derates (46,623.8 MW).

Table 5-6 shows generation capacity changes since the implementation of the
Reliability Pricing Model through the 2020/2021 Delivery Year. The 19,278.5
MW increase was the result of new generation capacity resources (34,017.5
MW), reactivated generation capacity resources (1,374.4 MW), uprates (7,577.6
MW), integration of external zones (21,967.5 MW), a net decrease in capacity
exports (2,016.8 MW), offset by a net decrease in capacity imports (1,051.5
MW), deactivations (42,972.0 MW) and derates (3,651.8 MW).

For the current and future delivery years (2021/2022 through 2022/2023), newgeneration capacity is defined as capacity that cleared an RPM auction for the
first time in the specified delivery year. Based on expected completion rates
of cleared new generation capacity (4,841.2 MW) and pending deactivations(9,246.5 MW), PJM capacity is expected to decrease by 4,405.3 MW for the2021/2022 through 2022/2023 Delivery Years.

Table 5-7 shows the calculated RPM reserve margin and reserve in excessof the defined installed reserve margin (IRM) for June 1, 2016, throughJune 1, 2022, and accounts for cleared capacity, replacement capacity, anddeficiency MW for all auctions held and the most
Table 5-6 Generation capacity changes: 2007/2008 through 2020/202152
recent peak load forecast for each delivery year.
ICAP (MW)Net Change in
Net Change in
The completion of the replacement process using
New Reactivations
Uprates
Integration Capacity Imports Capacity Exports Deactivations
Derates
Net Change
cleared buy bids from RPM incremental auctions
2007/2008
45.0
0.0
691.5
0.0
70.0
15.3
380.0
417.0
(5.8)
2008/2009
815.4
238.3
987.0
0.0
473.0
(9.9)
609.5
421.0
1,493.1
includes two transactions. The first step is for the
2009/2010
406.5
0.0
789.0
0.0
229.0
(1,402.2)
108.4
464.3
2,254.0
entity to submit and clear a buy bid in an RPM
2010/2011
153.4
13.0
339.6
0.0
137.0
367.7
840.6
223.5
(788.8)
2011/2012
3,096.4
354.5
507.9
16,889.5(1,183.3)(1,690.3)
2,542.0
176.2
18,637.1
incremental auction. The next step is for the entity
2012/2013
1,784.6
34.0
528.1
47.0
342.4
84.0
5,536.0
317.8(3,201.7)
to complete a separate replacement transaction
2013/2014
198.4
58.0
372.8
2,746.0934.3
28.9
2,786.9288.3
1,205.4
using the cleared buy bid capacity. Without an
2014/2015
2,276.8
20.7
530.2
0.0
2,335.7
177.3
4,915.6
360.3(289.8)
2015/2016
4,291.8
90.0
449.0
0.0
511.4
(117.8)8,338.2
215.8(3,094.0)
approved early replacement transaction requested
2016/2017
3,679.3
532.0
419.2
0.0
575.6
722.9
659.4
206.7
3,617.1
for defined physical reasons, replacement capacity
2017/2018
4,127.3
5.0
562.1
0.0
(1,025.1)(695.1)
2,657.4
148.5
1,558.5
2018/2019
8,127.5
4.0
330.9
2,120.0(3,217.0)
212.7
6,730.0
89.2
333.5
transactions can be completed only after the
2019/2020
4,612.0
13.3
494.9
165.0
(1,196.6)
401.3
3,296.0
116.8
274.5
EFORds for the delivery year are finalized, on
2020/2021
403.1
11.6
575.4
0.0
(37.9)(111.6)
3,572.0
206.4(2,714.6)
Total
34,017.5
1,374.4
7,577.6
21,967.5(1,051.5)(2,016.8)
42,972.0
3,651.8
19,278.5
November 30 in the year prior to the delivery
year, but before the start of the delivery day. The
calculated reserve margins for June 1, 2022, does
51
50

FERC granted PJM’s request for waiver of its Open Access Transmission Tariff to delay the 2022/2023 RPM Base Residual Auction fromMay 2019 to August 2019. See 164 FERC ¶ 61,153 (2018). FERC subsequently denied PJM’s motion seeking clarification of the June 29,
2018, Order (163 FERC ¶ 61,236) and directed PJM not to run the 2022/2023 BRA in August 2019. See 168 FERC ¶ 61,051 (2019).

292

Section 5 Capacity

52

For more details on future changes in generation capacity, see “2020 PJM Generation Capacity and Funding Sources 2007/2008 through2021/2022 Delivery Years,” <http://www.monitoringanalytics.com/reports/Reports/2020/IMM_2020_PJM_Generation_Capacity_and_Funding_Sources_20072008_through_20212022_DY_20200915.pdf> (September 15, 2020).
The capacity changes in this report are calculated based on June 1 through May 31.

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Table 5-7 RPM reserve margin: June 1, 2016, to June 1, 202253 54

01-Jun-16
01-Jun-17
01-Jun-18
01-Jun-19
01-Jun-20
01-Jun-21
01-Jun-22

Generation and DR
RPM Committed Less
Deficiency UCAP (MW)
160,883.3
163,872.0
161,242.6
162,276.1
159,560.4
156,633.6
139,666.7

Forecast
Peak Load
152,356.6
153,230.1
152,407.9
151,643.5
148,355.3
149,482.9
150,229.0

FRR
Peak Load
12,511.6
12,837.5
12,732.9
12,284.2
11,488.3
11,717.7
28,535.5

PRD
0.0
0.0
0.0
0.0
558.0
510.0
230.0

RPM PeakLoad
139,845.0
140,392.6
139,675.0
139,359.3
136,309.0
137,255.2
121,463.5

IRM
16.4%
16.6%
16.1%
16.0%
15.5%
14.7%
14.5%

Pool Wide
Average
EFORd
5.91%
5.94%
6.07%
6.08%
5.78%
5.22%
5.08%

Generation and DR
RPM Committed Less
Deficiency ICAP (MW)
170,988.7
174,220.7
171,662.5
172,781.2
169,348.8
165,260.2
147,141.5

Reserve
Margin
22.3%
24.1%
22.9%
24.0%
24.2%
20.4%
21.1%

Reserve Margin
Projected Replacementin Excess of IRM
Capacity using Cleared
Percent ICAP (MW)Buy Bids UCAP (MW)5.9%8,209.2
0.0
7.5%
10,522.9
0.0
6.8%
9,499.80.0
8.0%
11,124.4
0.0
8.7%
11,911.9
0.0
5.7%
7,828.5
0.0
6.6%
8,065.7
0.0

Projected Reserve
Margin
22.3%
24.1%
22.9%
24.0%
24.2%
20.4%
21.1%

Sources of Funding55
Developers use a variety of sources to fund their projects, including Power Purchase Agreements (PPA), cost of service rates, and private funds (from internalsources or private lenders and investors). PPAs can be used for a variety of purposes and the use of a PPA does not imply a specific source of funding.
New and reactivated generation capacity from the 2007/2008 Delivery Year through the 2021/2022 Delivery Year totaled 35,391.9 MW (82.4 percent of all
additions), with 26,320.6 MW from market funding and 9,071.3 MW from nonmarket funding. Uprates to existing generation capacity from the 2007/2008
Delivery Year through the 2021/2022 Delivery Year totaled 7,577.6 MW (17.6 percent of all additions), with 5,188.6 MW from market funding and 2,389.0 MW
from nonmarket funding. In summary, of the 42,969.5 MW of additional capacity from new, reactivated, and uprated generation that cleared in RPM auctions
for the 2007/2008 through 2021/2022 Delivery Years, 31,509.2 MW (73.3 percent) were based on market funding.
Of the 6,675.0 MW of the additional generation capacity (new resources, reactivated resources, and uprates) that cleared in RPM auctions for the 2022/2023
through 2023/2024 Delivery Years, 5,680.5 MW are not yet in service. Of those 5,680.5 MW that have not yet gone into service, 4,215.7 MW have market
funding and 1,464.8 MW have nonmarket funding. Applying the historical completion rates, 67.7 percent of all the projects in development are expected to go
into service (2,870.4 MW of the 4,215.7 MW of in development market funded projects; 976.3 MW of the 1,464.8 MW of in development nonmarket funded
projects). Together, 3,846.7 MW of the 5,680.5 MW of new generation capacity that cleared MW in RPM and are not yet in service are expected to go into service
through the 2023/2024 Delivery Year.
Of the 994.5 MW of the additional generation capacity that cleared in RPM auctions for the 2022/2023 through 2023/2024 Delivery Years and are already inservice, 792.1 MW (79.6 percent) are based on market funding and 202.4 MW (20.4 percent) are based on nonmarket funding. In summary, 5,007.8 MW (75.0
percent) of the additional generation capacity (4,215.7 MW in service and 792.1 MW not yet in service) that cleared in RPM auctions for the 2022/2023 through2023/2024 Delivery Years are based on market funding. Capacity additions based on nonmarket funding are 1,667.2 MW (25.0 percent) of proposed generationthat cleared at least one RPM auction for the 2022/2023 through 2023/2024 Delivery Years.
53
54
55

The calculated reserve margins in this table do not include EE on the supply side or the EE add back on the demand side. The EE excluded from the supply side for this calculation includes annual EE and summer EE. This is how PJM calculates the reserve margin.
These reserve margin calculations do not consider Fixed Resource Requirement (FRR) load.
For more details on sources of funding for generation capacity, see “2020 PJM Generation Capacity and Funding Sources 2007/2008 through 2021/2022 Delivery Years,” <http://www.monitoringanalytics.com/reports/Reports/2020/IMM_2020_PJM_Generation_Capacity_and_Funding_
Sources_20072008_through_20212022_DY_20200915.pdf> (September 15, 2020).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June293

2021 Quarterly State of the Market Report for PJM: January through June

DemandThe MMU analyzed market sectors in the PJM Capacity Market to determine
how they met their load obligations. The PJM Capacity Market was divided
into the following sectors:• PJM EDC. EDCs with a franchise service territory within the PJM
footprint. This sector includes traditional utilities, electric cooperatives,municipalities and power agencies.

• PJM EDC Generating Affiliate. Affiliate companies of PJM EDCs that own

is shown in Figure 5-3. PJM EDCs’ and their affiliates’ share of load obligation
has decreased from 77.5 percent on June 1, 2007, to 55.2 percent on June 1,
2021. The share of load obligation held by LSEs not affiliated with any EDC
and non-PJM EDC affiliates increased from 22.5 percent on June 1, 2007, to
44.8 percent on June 1, 2021. Prior to the 2012/2013 Delivery Year, obligation
was defined as cleared and make whole MW in the Base Residual Auction and
the Second Incremental Auction plus ILR forecast obligations. Effective withthe 2012/2013 Delivery Year, obligation is defined as the sum of the unforced
capacity obligations satisfied through all RPM auctions for the delivery year.

generating resources.

• PJM EDC Marketing Affiliate. Affiliate companies of PJM EDCs that sell
power and have load obligations in PJM, but do not own generating
resources.

• Non-PJM EDC. EDCs with franchise service territories outside the PJM
footprint.

• Non-PJM EDC Generating Affiliate. Affiliate companies of non-PJM EDCs
that own generating resources.

• Non-PJM EDC Marketing Affiliate. Affiliate companies of non-PJM
EDCs that sell power and have load obligations in PJM, but do not own
generating resources.

• Non-EDC Generating Affiliate. Affiliate companies of non-EDCs that own
generating resources.

• Non-EDC Marketing Affiliate. Affiliate companies of non-EDCs that sell
power and have load obligations in PJM, but do not own generating
resources.

On June 1, 2021, PJM EDCs and their affiliates maintained a large market shareof load obligations under RPM, together totaling 55.2 percent (Table 5-8),
down from 59.7 percent on June 1, 2020. The combined market share of LSEs
not affiliated with any EDC and of non-PJM EDC affiliates was 44.8 percent,up from 40.3 percent on June 1, 2020. The share of capacity market load
obligation fulfilled by PJM EDCs and their affiliates, and LSEs not affiliatedwith any EDC and non-PJM EDC affiliates from June 1, 2007, to June 1, 2021,

294

Section 5 Capacity© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Table 5-8 Capacity market load obligation served: June 1, 2020 and June 1, 2021
1-Jun-20
Obligation Percent of total(MW)obligation
104,849.4
59.7%
70,838.3
40.3%
175,687.7
100.0%PJM EDCs and Affiliates
LSEs not affiliated with any EDC + non EDC Affiliates
Total

Figure 5-3 Capacity market load obligation served: June 1, 2007 throughJune 1, 2021
90%
80%
70%

Load Obligation Served

ChangeObligation Percent of total(MW)obligation(8,543.1)(4.5%)
7,275.8
4.5%(1,267.3)
0.0%

For LDAs in which the RPM auctions for a delivery year resulted in a positive
average weighted Locational Price Adder, an LSE with CTRs corresponding to
the LDA is entitled to a payment or charge equal to the Locational Price Adder
multiplied by the MW of the LSEs’ CTRs.

60%
50%
40%

In the 2022/2023 RPM Base Residual Auction, EMAAC had 4,946.8 MW of
CTRs with a total value of $3,737,529, COMED had 2,367.2 MW of CTRs witha total value of $16,381,936, BGE had 4,745.1 MW of CTRs with a total valueof $53,188,332 and DEOK had 3,034.8 MW of CTRs with a total value of$24,026,133.

30%
20%
10%

PJM EDCs and affiliates
LSEs not affiliated with any EDC + non-EDC affiliates0%

to receive the benefit of importing cheaper
capacity using transmission capability. The
MW of CTRs available for allocation to LSEs
in an LDA are equal to the Unforced Capacity
imported into the LDA, based on the resultsof the Base Residual Auction and Incremental
Auctions, less any MW of CETL paid for
directly by market participants in the form of Qualifying Transmission
Upgrades (QTUs) cleared in an RPM Auction, and Incremental Capacity
Transfer Rights (ICTRs). There are two types of ICTRs, those allocated to a
New Service Customer obligated to fund a transmission facility or upgrade
and those associated with Incremental Rights Eligible Required Transmission
Enhancements.

1-Jun-21
Obligation Percent of total(MW)obligation
96,306.4
55.2%
78,114.1
44.8%
174,420.4
100.0%

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

Capacity Transfer Rights (CTRs)
Capacity Transfer Rights (CTRs) are used to return capacity market congestion
revenues to load. Load pays for the transmission system through firmtransmission charges and pays congestion. Capacity market congestion
revenues are the difference between the total dollars paid by load for capacity
and the total dollars received by capacity market sellers. CTRs permit customers© 2021 Monitoring Analytics, LLC

MAAC had 270.1 MW of customer funded ICTRs with a total value of$4,513,768, EMAAC had 40.0 MW of customer funded ICTRs with a total
value of $30,222, BGE had 65.7 MW of customer funded ICTRs with a total
value of $736,441, COMED had 1,376.0 MW of customer funded ICTRs with a
total value of $9,522,470 and DEOK had 155.0 MW of customer funded ICTRs
with a total value of $1,227,112.
MAAC had 128.0 MW of ICTRs due to Incremental Rights-Eligible Required
Transmission Enhancements with a value of $2,139,474, EMAAC had 948.0

2021 Quarterly State of the Market Report for PJM: January through June295

2021 Quarterly State of the Market Report for PJM: January through June

MW with a value of $716,261 and BGE had 306.0 MW with a value of$3,430,000.

Figure 5-4 VRR curve relative to the reliability requirement: 2022/2023
Delivery Year
VRR Curve

Demand Curve

The PJM definition of the VRR curve means the clearing price and cleared
quantity will be higher, almost without exception, using the current VRR
curve than using a vertical demand curve at the reliability requirement. As
a result, payments for capacity will be higher. Figure 5-4 shows the RTO
VRR curve and RTO reliability requirement for the 2022/2023 RPM BRA. The
clearing price and cleared quantity would be lower if a vertical VRR curve set
at the reliability requirement were used in place of the existing VRR curve.
This is the case if the supply curve intersects the VRR curve to the right side of
the reliability requirement (Offer Curve 1). The only exception would be if the
supply curve intersects the VRR curve to the left of the reliability requirement(Offer Curve 2). In that case, the clearing price and cleared quantity would behigher with the vertical demand curve than with the existing VRR curve. In
almost all RPM auctions, the offer curve intersected the VRR curve to the rightside of the vertical demand curve.

Offer Curve 2

C
96

97

98

99
100
101
102
103
104
105
106
107
Capacity (Unforced MW as a percentage of Reliability Requirement)

108

109

110

Market Concentration
Auction Market Structure
As shown in Table 5-9, in the 2022/2023 RPM Base Residual Auction allparticipants in the total PJM market as well as the LDA RPM markets failed
the three pivotal supplier (TPS) test.56 Offer caps were applied to all sell offers
for resources which were subject to mitigation when the capacity market seller
did not pass the test, the submitted sell offer exceeded the defined offer cap,and the submitted sell offer, absent mitigation, increased the market clearing
price.57 58 59
57
58
59

Section 5 Capacity

B

95

56

296

Reliability Requirement
Offer Curve 1$ per MW-day

Effective for the 2018/2019 and subsequent delivery years, PJM revised thevariable resource requirement (VRR) curve. The starting MW point of thedownward sloping demand curve is set at 99.0 percent of the reliability
requirement. The highest MW point is set at 106.7 percent of the reliability
requirement. Almost all of the downward sloping part of the VRR curve lies tothe right side of the reliability requirement.

A

The market definition used for the TPS test includes all offers with costs less than or equal to 1.50 times the clearing price. See MMU
Technical Reference for PJM Markets, at “Three Pivotal Supplier Test” for additional discussion.
See OATT Attachment DD § 6.5.
Prior to November 1, 2009, existing DR and EE resources were subject to market power mitigation in RPM Auctions. See 129 FERC ¶61,081 at P 30 (2009).
Effective January 31, 2011, the RPM rules related to market power mitigation were changed, including revising the definition forplanned generation capacity resource and creating a new definition for existing generation capacity resource for purposes of the must
offer requirement and market power mitigation, and treating a proposed increase in the capability of a generation capacity resource thesame in terms of mitigation as a planned generation capacity resource. See 134 FERC ¶ 61,065 (2011).

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

In applying the market structure test, the relevant supply for the RTO market
includes all supply offered at less than or equal to 150 percent of the RTO
cost-based clearing price. The relevant supply for the constrained LDA
markets includes the incremental supply inside the constrained LDAs which
was offered at a price higher than the unconstrained clearing price for theparent LDA market and less than or equal to 150 percent of the cost-based
clearing price for the constrained LDA. The relevant demand consists of the
MW needed inside the LDA to relieve the constraint.
Table 5-9 presents the results of the TPS test. A generation owner or owners
are pivotal if the capacity of the owners’ generation facilities is needed tomeet the demand for capacity. The results of the TPS are measured by theresidual supply index (RSIX). The RSIX is a general measure that can be usedwith any number of pivotal suppliers. The subscript denotes the number ofpivotal suppliers included in the test. If the RSIX is less than or equal to 1.0,
the supply owned by the specific generation owner, or owners, is needed tomeet market demand and the generation owners are pivotal suppliers witha significant ability to influence market prices. If the RSIX is greater than
1.0, the supply of the specific generation owner or owners is not needed tomeet market demand and those generation owners have a reduced ability tounilaterally influence market price.

Table 5-9 RSI results: 2019/2020 through 2022/2023 RPM Auctions60
RSI1, 1.05

RSI3

Total
Participants

Failed RSI3
Participants

0.81
0.79
0.74
0.00

0.66
0.23
0.12
0.00

131
6
6
1

131
6
6
1

2019/2020 First Incremental Auction
RTO
EMAAC

0.63
0.00

0.50
0.00

53
5

53
5

2019/2020 Second Incremental Auction
RTO
BGE

0.61
0.00

0.48
0.00

38
1

38
1

2019/2020 Third Incremental Auction
RTO

0.70

0.59

72

72

2020/2021 Base Residual Auction
RTO
MAAC
EMAAC
ComEd
DEOK

0.81
0.67
0.45
0.47
0.00

0.69
0.77
0.18
0.20
0.00

119
24
21
14
1

119
24
21
14
1

2020/2021 First Incremental Auction
RTO

0.47

0.42

47

47

2020/2021 Second Incremental Auction
RTO

0.40

0.56

34

34

2020/2021 Third Incremental Auction
RTO
MAAC

0.54
0.25

0.72
0.18

59
14

59
14

2021/2022 Base Residual Auction
RTO
EMAAC
PSEG
ATSI
ComEd
BGE

0.80
0.71
0.20
0.01
0.08
0.23

0.68
0.22
0.01
0.00
0.02
0.00

122
14
5
2
5
3

122
14
5
2
5
3

RPM Markets
2019/2020 Base Residual Auction
RTO
EMAAC
ComEd
BGE

60

© 2021 Monitoring Analytics, LLC

The RSI shown is the lowest RSI in the market.

2021 Quarterly State of the Market Report for PJM: January through June297

2021 Quarterly State of the Market Report for PJM: January through June

Table 5-9 RSI results: 2019/2020 through 2022/2023 RPM Auctions (continued)
RSI1, 1.05

RSI3

Total
Participants

Failed RSI3
Participants

0.57
0.00
0.00
0.00
0.00

0.48
0.82
0.00
0.00
0.00

26
5
1
2
1

26
3
1
2
1

2021/2022 Second Incremental Auction
RTO
EMAAC
PSEG
BGE

0.19
0.05
0.00
0.00

0.12
0.23
0.00
0.00

19
7
2
0

19
5
2
0

2021/2022 Third Incremental Auction
RTO
EMAAC
PSEG
BGE

0.57
1.00
0.00
0.00

0.41
0.19
0.00
-0.00

59
6
1
2

59
6
1
2

2022/2023 Base Residual Auction
RTO
MAAC
EMAAC
ComEd
BGE
DEOK

0.81
0.69
1.25
0.43
0.00
0.00

0.73
0.37
0.64
0.36
0.00
0.00

130
25
7
14
1
1

130
25
7
14
1
1

RPM Markets
2021/2022 First Incremental Auction
RTO
EMAAC
PSEG
PSEG North
BGE

tests.61 In addition, PJM may establish a constrained LDA even if it does not
qualify under the above tests if PJM finds that “such is required to achieve
an acceptable level of reliability.”62 A reliability requirement and a Variable
Resource Requirement (VRR) curve are established for each modeled LDA.
Effective for the 2014/2015 through 2016/2017 Delivery Years, a Minimum
Annual and a Minimum Extended Summer Resource Requirement are
established for each modeled LDA. Effective for the 2017/2018 Delivery
Year, Sub-Annual and Limited Resource Constraints, replacing the Minimum
Annual and a Minimum Extended Summer Resource Requirements, areestablished for each modeled LDA.63 Effective for the 2018/2019 through the
2019/2020 Delivery Years, Base Capacity Demand Resource Constraint anda Base Capacity Resource Constraint, replacing the Sub-Annual and Limited
Resource Constraints, are established for each modeled LDA.
Locational Deliverability Areas are shown in Figure 5-5, Figure 5-6 andFigure 5-7.
Figure 5-5 Map of locational deliverability areas

Locational Deliverability Areas (LDAs)
Under the PJM Tariff, PJM determines, in advance of each BRA, whether
defined Locational Deliverability Areas (LDAs) will be modeled in theauction. Effective with the 2012/2013 Delivery Year, an LDA is modeled asa potentially constrained LDA for a delivery year if the Capacity Emergency
Transfer Limit (CETL) is less than 1.15 times the Capacity Emergency Transfer
Objective (CETO), such LDA had a locational price adder in one or more of
the three immediately preceding BRAs, or such LDA is determined by PJM
in a preliminary analysis to be likely to have a locational price adder basedon historic offer price levels. The rules also provide that starting with the
2012/2013 Delivery Year, EMAAC, SWMAAC, and MAAC LDAs are modeled
as potentially constrained LDAs regardless of the results of the above three

298

Section 5 Capacity

61
62
63

Prior to the 2012/2013 Delivery Year, an LDA with a CETL less than 1.05 times CETO was modeled as a constrained LDA in RPM. No
additional criteria were used in determining modeled LDAs.
OATT Attachment DD § 5.10 (a) (ii).
146 FERC ¶ 61,052 (2014).

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Figure 5-6 Map of RPM EMAAC subzonal LDAs

Imports and Exports
Units external to the metered boundaries of PJM can qualify as PJM capacity
resources if they meet the requirements to be capacity resources. Generatorson the PJM system that do not have a commitment to serve PJM loads in thegiven delivery year as a result of RPM auctions, FRR capacity plans, locational
UCAP transactions, and/or are not designated as a replacement resource, areeligible to export their capacity from PJM.64
The PJM market rules should not create inappropriate barriers to either theimport or export of capacity. The market rules in other balancing authorities
should also not create inappropriate barriers to the import or export ofcapacity. The PJM market rules should ensure that the definition of capacity
is enforced including physical deliverability, recallability and the obligation
to make competitive offers into the PJM Day-Ahead Energy Market equal to
ICAP MW. Physical deliverability can only be assured by requiring that allimports are deliverable to PJM load to ensure that they are full substitutes
for internal capacity resources. Selling capacity into the PJM Capacity
Market but making energy offers daily of $999 per MWh would not fulfill therequirements of a capacity resource to make a competitive offer, but would
constitute economic withholding. This is one of the reasons that the rules
governing the obligation to make a competitive offer in the day-ahead energy
market should be clarified for both internal and external resources.

Figure 5-7 Map of RPM ATSI subzonal LDA

For the 2017/2018 through the 2019/2020 Delivery Years, Capacity Import
Limits (CILs) are established for each of the five external source zones andthe overall PJM region to account for the risk that external generation
resources may not be able to deliver energy during the relevant delivery
year due to the curtailment of firm transmission by third parties.65 Capacity
market sellers may request an exception to the CIL for an external generation
resource by committing that the resource will be pseudo tied prior to the startof the relevant delivery year, by demonstrating that it has long-term firmtransmission service confirmed on the complete transmission path from the
64
65© 2021 Monitoring Analytics, LLC

OATT Attachment DD § 5.6.6(b).
147 FERC ¶ 61,060 (2014).

2021 Quarterly State of the Market Report for PJM: January through June299

2021 Quarterly State of the Market Report for PJM: January through June

resource to PJM, and by agreeing to be subject to the same RPM must offer
requirement as internal PJM generation resources.
Effective June 9, 2015, an external generation capacity resource must obtainan exception to the CILs to be eligible to offer as a Capacity Performance
Resource, which means that effective with the 2020/2021 Delivery Year, CILs
are no longer defined as an RPM parameter.66
Effective May 9, 2017, enhanced pseudo tie requirements for external
generation capacity resources were implemented, including a transition
period with deliverability requirements for existing pseudo tie resources thathave previously cleared an RPM auction.67 The rule changes include: defining
coordination with other Balancing Authorities when conducting pseudo tie
studies; establishing an electrical distance requirement; establishing a market
to market flowgate test to establish limits on the number of coordinatedflowgates PJM must add in order to accommodate a new pseudo tie; a model
consistency requirement; the requirement for the capacity market seller toprovide written acknowledgement from the external Balancing Authority
Areas that such pseudo tie does not require tagging and that firm allocations
associated with any coordinated flowgates applicable to the external Generation
Capacity Resource under any agreed congestion management process then in
effect between PJM and such Balancing Authority Area will be allocated to
PJM; the requirement for the capacity market seller to obtain long-term firm
point to point transmission service for transmission outside PJM with rolloverrights and to obtain network external designated transmission service fortransmission within PJM; establishing an operationally deliverable standard;
and modifying the nonperformance penalty definition for external generation
capacity resources to assess performance at subregional transmission
organization granularity.

Table 5-10 RPM imports: 2007/2008 through 2022/2023 RPM Base ResidualAuctions
Base Residual Auction
2007/2008
2008/20092009/20102010/20112011/20122012/20132013/20142014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021
2021/2022
2022/2023

MISO
Offered
1,073.0
1,149.4
1,189.2
1,194.2
1,862.7
1,415.9
1,895.1
1,067.7
1,538.7
4,723.1
2,624.3
2,879.1
2,067.3
2,511.8
2,308.4
954.9

Cleared
1,072.9
1,109.0
1,151.0
1,186.6
1,198.6
1,298.8
1,895.1
1,067.7
1,538.7
4,723.1
2,624.3
2,509.1
1,828.6
1,671.2
1,909.9
954.9

UCAP (MW)Non-MISO
OfferedCleared
547.9
547.9
517.6
516.8
518.8
518.1
539.8
539.5
3,560.0
3,557.5
1,036.7
1,036.7
1,358.9
1,358.9
1,948.8
1,948.8
2,396.6
2,396.6
2,770.6
2,759.6
2,320.4
1,901.2
2,256.7
2,178.8
2,276.1
2,047.3
2,450.0
2,326.0
2,162.0
2,141.9
603.1
603.1

Total Imports
OfferedCleared
1,620.9
1,620.8
1,667.0
1,625.8
1,708.0
1,669.1
1,734.0
1,726.1
5,422.7
4,756.1
2,452.6
2,335.5
3,254.0
3,254.0
3,016.5
3,016.5
3,935.3
3,935.3
7,493.7
7,482.7
4,944.7
4,525.5
5,135.8
4,687.9
4,343.4
3,875.9
4,961.8
3,997.2
4,470.4
4,051.8
1,558.0
1,558.0

Demand Resources
There are two basic demand products incorporated in the RPM market design:68• Demand Resources (DR). Interruptible load resource that is offered into an

RPM Auction as capacity and receives the relevant LDA or RTO resource
clearing price.

• Energy Efficiency (EE) Resources. Load resources that are offered into an

RPM auction as capacity and receive the relevant LDA or RTO resource
clearing price. The EE resource type was eligible to be offered in RPM
auctions starting with the 2012/2013 Delivery Year and in incremental
auctions in the 2011/2012 Delivery Year.69

As shown in Table 5-10, of the 1,558.0 MW of imports offered in the 2022/2023
RPM Base Residual Auction, 1,558.0 MW cleared. Of the cleared imports,
954.9 MW (61.3 percent) were from MISO.
68
66
67

151 FERC ¶ 61,208 (2015).
161 FERC ¶ 61,197 (2017), order denying reh’g, 170 FERC ¶ 61,217 (2020).

300

Section 5 Capacity69

Effective June 1, 2007, the PJM active load management (ALM) program was replaced by the PJM load management (LM) program.
Under ALM, providers had received a MW credit which offset their capacity obligation. With the introduction of LM, qualifying load
management resources can be offered into RPM auctions as capacity resources and receive the clearing price.
Letter Order, Docket No. ER10-366-000 (January 22, 2010).

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Effective for the 2018/2019 and the 2019/2020 Delivery Years, there are two
types of demand resource and energy efficiency resource products included in
the RPM market design:70 71• Base Capacity Resources— Base Capacity Demand Resources. A demand resource that is required to

be available on any day from June through September for an unlimited
number of interruptions. Base capacity DR is required to be capableof maintaining each interruption for at least 10 hours only during thehours of 10:00 a.m. to 10:00 p.m. EPT.

— Base Capacity Energy Efficiency Resources. A project designed to achievea continuous (during summer peak periods) reduction in electric energy
consumption that is not reflected in the peak load forecast for thedelivery year for which the base capacity energy efficiency resource is
proposed, and that is fully implemented at all times during the relevantdelivery year, without any requirement of notice, dispatch, or operator
intervention. The peak period definition for the base capacity energy
efficiency resource type includes the period from the hour ending
15:00 EPT and the hour ending 18:00 EPT from June through August,excluding weekends and federal holidays.

• Capacity Performance Resources— Annual Demand Resources. A demand resource that is required to beavailable on any day in the relevant delivery year for an unlimited
number of interruptions. Annual DR is required to be capable ofmaintaining each interruption for only 10 hours during the hours of
10:00 a.m. to 10:00 p.m. EPT for the period May through October and6:00 a.m. to 9:00 p.m. EPT for the period November through April
unless there is an Office of the Interconnection approved maintenanceoutage during October through April.

— Annual Energy Efficiency Resources. A project designed to achieve acontinuous (during summer and winter peak periods) reduction inelectric energy consumption during peak periods that is not reflectedin the peak load forecast for the delivery year for which the energy

7071

151 FERC ¶ 61,208.
PJM Reliability Assurance Agreement Article 1.

© 2021 Monitoring Analytics, LLC

efficiency resource is proposed, and that is fully implemented at all
times during the relevant delivery year, without any requirement of
notice, dispatch, or operator intervention. The peak period definition
for the annual energy efficiency resource type includes the period fromthe hour ending 15:00 EPT and the hour ending 18:00 EPT from June
through August, and the period from the hour ending 8:00 EPT andthe hour ending 9:00 EPT and the period from the hour ending 19:00
EPT and the hour ending 20:00 EPT from January through February,
excluding weekends and federal holidays.
Effective with the 2020/2021 Delivery Year, the Capacity Performance Productwill be the only capacity product type, with two possible season types, annual
and summer.

• Annual Capacity Performance Resources— Annual Demand Resources— Annual Energy Efficiency Resources• Seasonal Capacity Performance Resources— Summer-Period Demand Resources. A demand resource that is required

to be available on any day from June through October and the following
May of the delivery year for an unlimited number of interruptions.
Summer period DR is required to be capable of maintaining eachinterruption between the hours of 10:00 a.m. to 10:00 p.m. EPT.

— Summer-Period Energy Efficiency Resources. A project designed toachieve a continuous (during summer peak periods) reduction inelectric energy consumption during peak periods that is not reflectedin the peak load forecast for the delivery year for which the energy
efficiency resource is proposed, and that is fully implemented at all
times during the relevant delivery year, without any requirement of
notice, dispatch, or operator intervention. The peak period definition
for the summer-period efficiency resource type includes the period
from the hour ending 15:00 EPT and the hour ending 18:00 EPT from
June through August, excluding weekends and federal holidays.

2021 Quarterly State of the Market Report for PJM: January through June301

2021 Quarterly State of the Market Report for PJM: January through June

As shown in Table 5-11, Table 5-12, and Table 5-13, capacity in the RPM load management programs was 12,115.9 MW for June 1, 2021, as a result of cleared
capacity for demand resources and energy efficiency resources in RPM auctions for the 2021/2022 Delivery Year (16,233.9 MW) less replacement capacity(4,118.0 MW).
Table 5-11 RPM load management statistics by LDA: June 1, 2018 to June 1, 202272 73 74
UCAP (MW)
PSEG
389.9
102.0
(150.9)
22.4
363.4

Pepco
559.3
186.1
(25.6)
(8.9)
710.9

ATSI
1,034.3
184.4(261.0)
14.7
972.4

ATSI
Cleveland
287.2
33.2
(136.7)
4.7
188.4

ComEd
1,895.2
807.4(430.0)29.02,301.6

BGE
667.1
131.5
(173.9)
116.5
741.2

PPL
716.2
43.1
(220.0)5.4
544.7

DR cleared
EE cleared
01-Jun-18 DR net replacements
EE net replacements
RPM load management

RTO
11,435.4
2,296.3(3,182.4)
248.8
10,798.1

MAAC
4,361.9706.8(1,268.4)
163.0
3,963.3

EMAAC
1,707.2315.9(584.3)45.5
1,484.3

DR cleared
EE cleared
01-Jun-19 DR net replacements
EE net replacements
RPM load management

10,703.1
2,528.5(2,138.8)(50.0)
11,042.8

3,878.9
821.4(1,004.2)(24.1)
3,672.0

1,659.2
395.3(468.8)4.7
1,590.4

817.0
301.7
(129.0)
3.3
993.0

91.3
7.8
(40.9)
(0.2)
58.0

381.2
134.5
(141.5)
2.7
376.9

176.5
52.8
(86.6)
9.1
151.8

554.6
170.0
(74.8)
2.2
652.0

1,047.0204.8(130.3)
3.4
1,124.9333.9
41.7(123.1)0.0
252.5

1,759.9792.9(143.0)0.0
2,409.8

262.4
131.7
(54.2)
1.1
341.0

741.4
72.7
(208.9)(20.4)
584.8

DR cleared
EE cleared
01-Jun-20 DR net replacements
EE net replacements
RPM load management

9,445.7
3,569.5(2,399.5)(29.7)
10,586.0

2,829.1
1,288.8(858.7)(0.5)
3,258.7

1,168.9700.3(369.0)(0.3)
1,499.9

485.8
394.5
(176.5)
5.9
709.7

72.6
28.8
(29.7)
0.0
71.7

339.0
246.1
(136.5)
(6.3)
442.3

152.7
111.3
(89.0)
12.0
187.0

236.3
196.2
(53.3)
(0.6)
378.6

951.7
356.0
(121.1)(0.2)
1,186.4

231.9
72.9(36.2)
0.0
268.6

1,657.3
852.0(314.5)(0.1)
2,194.7

249.5
198.3
(123.2)
6.5
331.1

DR cleared
EE cleared
DR net replacements
EE net replacements
RPM load management

11,427.7
4,806.2(4,111.0)(7.0)
12,115.9

3,454.1
1,810.5(1,302.8)
0.0
3,961.8

1,381.5
979.1(568.4)0.0
1,792.2

624.9
501.1
(160.8)
(1.1)
964.1

66.3
42.0
(28.1)
0.1
80.3

410.5
353.1
(195.8)
0.0
567.8

188.6
136.0
(100.2)
34.9
259.3

345.9
275.9
(106.5)
(2.6)
512.7

1,196.8420.5(483.2)80.0
1,214.1

272.8
95.7(137.4)7.0
238.1

2,073.7
982.7(609.5)10.6
2,457.5

DR cleared
EE cleared
01-Jun-22 DR net replacements
EE net replacements
RPM load management

8,811.9
4,810.6
0.0
0.0
13,622.5

2,817.4
1,974.4
0.0
0.0
4,791.8

1,139.9
1,090.80.0
0.0
2,230.7

485.3
463.7
0.0
0.0
949.0

48.4
49.6
0.0
0.0
98.0

294.6
384.4
0.0
0.0
679.0

93.8
182.6
0.0
0.0
276.4

322.7
263.8
0.0
0.0
586.5

924.1
417.0
0.0
0.0
1,341.1

166.5
41.8
0.0
0.0
208.3

1,511.0
723.9
0.0
0.0
2,234.901-Jun-21

72
73
74

SWMAAC DPL South
1,226.4
86.8
317.6
9.2
(199.5)(52.4)
107.6
1.1
1,452.1
44.7

PSEG
North
139.2
45.2
(43.6)
9.1
149.9

DAY

DEOK

616.6
111.4
(171.0)
(5.2)
551.8

241.5
79.5
(66.1)
0.0
254.9

184.7
105.6
(27.5)
(5.0)
257.8

279.0
225.2
(54.3)
1.5
451.4

697.7
186.7
(235.1)
(1.7)
647.6

227.7
111.0
(50.9)
8.0
295.8

220.5
135.5
(90.2)(17.5)
248.3

162.6
199.9
0.0
0.0
362.5

661.7
242.1
0.0
0.0
903.8

210.5
91.8
0.0
0.0
302.3

185.1
145.9
0.0
0.0
331.0

See OATT Attachment DD § 8.4. The reported DR cleared MW may reflect reductions in the level of committed MW due to relief from Capacity Resource Deficiency Charges.
Pursuant to OA § 15.1.6(c), PJM Settlement shall attempt to close out and liquidate forward capacity commitments for PJM Members that are declared in collateral default. The reported replacement transactions may include transactions associated with PJM members that were declared
in collateral default.
See OATT Attachment DD § 5.14E. The reported DR cleared MW for the 2016/2017, 2017/2018, and 2018/2019 Delivery Years reflect reductions in the level of committed MW due to the Demand Response Legacy Direct Load Control Transition Provision.

302

Section 5 Capacity© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Table 5-12 RPM commitments, replacements, and registrations for demand resources: June 1, 2007 to June 1, 202275 76 77
UCAP (MW)01-Jun-07
01-Jun-08
01-Jun-09
01-Jun-10
01-Jun-11
01-Jun-12
01-Jun-13
01-Jun-14
01-Jun-15
01-Jun-16
01-Jun-17
01-Jun-18
01-Jun-19
01-Jun-20
01-Jun-21
01-Jun-22

RPM Adjustments toClearedCleared
127.6
0.0
559.4
0.0
892.9
0.0
962.9
0.0
1,826.6
0.0
8,752.6(11.7)
10,779.6
0.0
14,943.0
0.0
15,774.8(321.1)
13,284.7(19.4)
11,870.7
0.0
11,435.4
0.0
10,703.1
0.0
9,445.7
0.0
11,427.7
0.0
8,811.9
0.0Net
Replacements
0.0(40.0)(474.7)(516.3)(1,052.4)(2,253.6)(3,314.4)(6,731.8)(4,829.7)(4,800.7)(3,870.8)(3,182.4)(2,138.8)(2,399.5)(4,111.0)
0.0

RPM
Commitments
127.6
519.4
418.2
446.6
774.2
6,487.3
7,465.2
8,211.2
10,624.0
8,464.6
7,999.9
8,253.0
8,564.3
7,046.2
7,316.7
8,811.9

RPM
Commitment
Shortage
0.0(58.4)(14.3)(7.7)
0.0(34.9)(30.5)(219.4)(61.8)(455.4)(30.3)
(0.4)
(0.1)
0.0
0.0

RPM Commitments
Less Commitment
Shortage
127.6
461.0
403.9
438.9
774.2
6,452.4
7,434.7
7,991.8
10,562.2
8,009.2
7,969.6
8,252.0
8,563.9
7,046.1
7,316.7
8,811.9

Registered DR
UCAPICAP Conversion(MW)
Factor
0.0
1.033
488.0
1.034
570.3
1.033
572.8
1.035
1,117.9
1.035
7,443.7
1.037
8,240.1
1.042
8,923.4
1.042
10,946.0
1.038
8,961.2
1.042
8,681.4
1.039
8,512.0
1.091
9,229.9
1.090
7,867.6
1.088
7,766.5
1.087
0.0
1.087

UCAP
(MW)
0.0
504.7
589.2
592.6
1,156.5
7,718.4
8,586.8
9,301.2
11,360.0
9,333.4
9,016.3
9,282.4
10,056.0
8,561.5
8,443.0
0.0

Table 5-13 RPM commitments and replacements for energy efficiency resources: June 1, 2007 to June 1, 202278 79
UCAP (MW)01-Jun-07
01-Jun-08
01-Jun-09
01-Jun-10
01-Jun-11
01-Jun-12
01-Jun-13
01-Jun-14
01-Jun-15
01-Jun-16
01-Jun-17
01-Jun-18
01-Jun-19
01-Jun-20
01-Jun-21
01-Jun-22
75
76
77
78
79

RPM Adjustments toClearedCleared
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
76.4
0.0
666.1
0.0
904.2
0.0
1,077.7
0.0
1,189.6
0.0
1,723.2
0.0
1,922.3
0.0
2,296.3
0.0
2,528.5
0.0
3,569.5
0.0
4,806.2
0.0
4,810.6
0.0

Net
Replacements
0.0
0.0
0.0
0.0
0.2
(34.9)
120.6
204.7
335.9
61.1
195.6
248.8
(50.0)(29.7)
(7.0)
0.0

RPM
Commitments
0.0
0.0
0.0
0.0
76.6
631.2
1,024.8
1,282.4
1,525.5
1,784.3
2,117.9
2,545.1
2,478.5
3,539.8
4,799.2
4,810.6

RPM
Commitment
Shortage
0.0
0.0
0.0
0.0
0.0
(5.1)
(13.5)
(0.2)
(0.9)
(0.5)
(7.4)
0.0
0.0
(0.1)
0.0
0.0

RPM Commitments
Less Commitment
Shortage
0.0
0.0
0.0
0.0
76.6
626.1
1,011.3
1,282.2
1,524.6
1,783.8
2,110.5
2,545.1
2,478.5
3,539.7
4,799.2
4,810.6

See OATT Attachment DD § 8.4. The reported DR adjustments to cleared MW include reductions in the level of committed MW due to relief from Capacity Resource Deficiency Charges.
See OATT Attachment DD § 5.14C. The reported DR adjustments to cleared MW for the 2015/2016 and 2016/2017 Delivery Years include reductions in the level of committed MW due to the Demand Response Operational Resource Flexibility Transition Provision.
See OATT Attachment DD § 5.14E. The reported DR adjustments to cleared MW for the 2016/2017, 2017/2018, and 2018/2019 Delivery Years include reductions in the level of committed MW due to the Demand Response Legacy Direct Load Control Transition Provision.
Pursuant to the OA § 15.1.6(c), PJM Settlement shall close out and liquidate all forward positions of PJM members that are declared in default. The replacement transactions reported for the 2014/2015 Delivery Year included transactions associated with RTP Controls, Inc., which was
declared in collateral default on March 9, 2012.
Effective with the 2019/2020 Delivery Year, available capacity from an EE Resource can be used to replace only EE Resource commitments. This rule change and related EE add back rule changes were endorsed at the December 17, 2015, meeting of the PJM Markets and Reliability Committee.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June303

2021 Quarterly State of the Market Report for PJM: January through June

Market Conduct
Offer Caps and Offer Floors
Market power mitigation measures were applied to capacity resources suchthat the sell offer was set equal to the defined offer cap when the capacity
market seller failed the market structure test for the auction, the submitted
sell offer exceeded the defined offer cap, and the submitted sell offer, absent
mitigation, would have increased the market clearing price.80 81 82 For Base
Capacity, offer caps are defined in the PJM Tariff as avoidable costs less PJM
market revenues, or opportunity costs based on the potential sale of capacity
in an external market. For Capacity Performance Resources, offer caps aredefined in the PJM Tariff as the applicable zonal net Cost of New Entry(CONE) times (B) where B is the average of the Balancing Ratios (B) during the
Performance Assessment Hours in the three consecutive calendar years thatprecede the base residual auction for such delivery year, unless net avoidable
costs exceed this level, or opportunity costs based on the potential sale ofcapacity in an external market exceed this level. For RPM Third Incremental
Auctions, capacity market sellers may elect, for Base Capacity offers, an offer
cap equal to 1.1 times the BRA clearing price for the relevant LDA and delivery
year or, for Capacity Performance offers, an offer cap equal to the greater ofthe net CONE for the relevant LDA and delivery year or 1.1 times the BRA
clearing price for the relevant LDA and delivery year.
Avoidable costs are the costs that a generation owner would not incur if thegenerating unit did not operate for one year, in particular the delivery year.83
In the calculation of avoidable costs, there is no presumption that the unit
would retire as the alternative to operating, although that possibility could
be reflected if the owner documented that retirement was the alternative.
Avoidable costs may also include annual capital recovery associated withinvestments required to maintain a unit as a generation capacity resource,
80
81
82

83

See OATT Attachment DD § 6.5.
Prior to November 1, 2009, existing DR and EE resources were subject to market power mitigation in RPM Auctions. See 129 FERC ¶61,081 at P 30 (2009).
Effective January 31, 2011, the RPM rules related to market power mitigation were changed, including revising the definition for
Planned Generation Capacity Resource and creating a new definition for Existing Generation Capacity Resource for purposes of themust offer requirement and market power mitigation, and treating a proposed increase in the capability of a Generation Capacity
Resource the same in terms of mitigation as a Planned Generation Capacity Resource. See 134 FERC ¶ 61,065 (2011).
OATT Attachment DD § 6.8 (b).

304

Section 5 Capacity

termed Avoidable Project Investment Recovery (APIR). Avoidable cost based
offer caps are defined to be net of revenues from all other PJM markets
and unit-specific bilateral contracts. For Capacity Performance Resources,
avoidable cost based offer caps are defined to be net of revenues from allother PJM markets and unit-specific bilateral contracts and expected bonus
performance payments/nonperformance charges.84 Capacity resource owners
could provide ACR data by providing their own unit-specific data or, fordelivery years prior to 2020/2021, by selecting the default ACR values. The
specific components of avoidable costs are defined in the PJM Tariff.85
Effective for the 2018/2019 and subsequent delivery years, the ACR definition
includes two additional components, Avoidable Fuel Availability Expenses(AFAE) and Capacity Performance Quantifiable Risk (CPQR).86 AFAE isavailable for Capacity Performance Resources. AFAE is defined to include
expenses related to fuel availability and delivery. CPQR is available for
Capacity Performance Resources and, for the 2018/2019 and 2019/2020
Delivery Years, Base Capacity Resources. CPQR is defined to be the quantifiable
and reasonably supported cost of mitigating the risks of nonperformanceassociated with submission of an offer.
The opportunity cost option allows capacity market sellers to offer based ona documented price available in a market external to PJM, subject to export
limits. If the relevant RPM market clears above the opportunity cost, thegeneration capacity resource is sold in the RPM market. If the opportunity
cost is greater than the clearing price and the generation capacity resource
does not clear in the RPM market, it is available to sell in the external market.

Calculation of Offer Caps
The competitive offer of a Capacity Performance resource is based on a market
seller’s expectations of a number of variables, some of which are resource
specific: the resource’s net going forward costs (Net ACR); and the resource’s
84
85
86

For details on the competitive offer of a capacity performance resource, see “Analysis of the 2021/2022 RPM Base Residual Auction—
Revised,” <http://www.monitoringanalytics.com/‌reports/Reports/2018/IMM_Analysis_of_the_20212022_RPM_BRA_Revised_20180824.
pdf> (August 24, 2018).
OATT Attachment DD § 6.8(a).
151 FERC ¶ 61,208.

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

performance during performance assessment intervals (A) in the delivery
year.87
The competitive offer of a Capacity Performance resource is also basedon a market seller’s expectations of system level variables: the number of
performance assessment intervals (PAI) in a delivery year (H) where theresource is located; the level of performance required to meet its capacity
obligation during those performance assessment intervals, measured as theaverage Balancing Ratio (B); and the level of the bonus performance payment
rate (CPBR) compared to the nonperformance charge rate (PPR). The level ofbonus performance payment rate depends on the level of underperforming
MW net of the underperforming MW excused by PJM during performanceassessment hours for reasons defined in the PJM OATT.88
The default offer cap defined in the PJM tariff, Net CONE times the average
Balancing Ratio, is based on a number of assumptions:
1. The Net ACR of a resource is less than its expected energy only bonuses:

2. The expected number of performance assessment intervals equals 360.
(H = 360 intervals, or 12 hours)
3. The expected value of the bonus performance payment rate (CPBR) is
equal to the nonperformance charge rate (PPR)
4. The average expected performance of the resource during performanceassessment hours ( )8788

The model is only applicable to generation resources and storage resources that have an annual obligation to perform with very limited
specific excuses as defined in the PJM OATT.
OATT Attachment DD § 10A (d).

© 2021 Monitoring Analytics, LLC

The competitive offer of such a resource is:In other words, the competitive offer of such a resource is the opportunity
cost of taking on the capacity obligation which equals the sum of theenergy only bonuses it would have earned (and the net
nonperformance charges it would incur by taking on the capacity obligation. Both the components are proportional to the
expected number of performance assessment intervals. If the expected numberof performance assessment intervals (H) is significantly lower than the value
used to determine the nonperformance charge rate (PPR), the opportunity ofearning bonuses as an energy only resource, as well as the net nonperformancecharges incurred by taking on a capacity obligation are lower. Under such a
scenario, the likelihood that that the resource’s Net ACR is lower than the
expected energy only bonuses is reduced. For resources whose Net ACR isgreater than the expected energy only bonuses, the competitive offer is the
Net ACR adjusted with any capacity performance bonuses or nonperformancecharges they expect to incur during the delivery year.
This means that when the expected number of performance assessment
intervals are lower than the value used to determine the nonperformancecharge rate (360 intervals, or 30 hours), the current default offer cap of Net
CONE times B overstates the competitive offer and the market seller offer cap.
The recent history of a low number of emergency actions in PJM reflect
the improvements to generator performance with the capacity performance
design, the reduction in actual and expected pool wide outage rates as aresult of new units added to the system and the retirement of old units, theupward biased peak load forecasts used in RPM, and the high reserve margins
in capacity.89 90 Given these developments, the assumption that there would
be 30 hours of emergency actions in a year that would trigger performanceassessment intervals is unsupported. Since the nonperformance charge rate
89
90

PJM experienced only one emergency event since April 2014 that triggered a PAI in an area that at least encompasses a PJM
transmission zone. On October 2, 2019, PJM declared a pre-emergency load management action that triggered PAIs in four zones for aperiod of two hours or 24 five minute intervals.
See Table 5-7.

2021 Quarterly State of the Market Report for PJM: January through June305

2021 Quarterly State of the Market Report for PJM: January through Juneis defined in the tariff as net CONE divided by 30 hours, the adjusted default
offer cap to reflect a lower estimate for the number of PAIs is much lower than
net CONE times B.
In the 2021/2022 RPM Base Residual Auction, net CONE times B exceeded
the actual competitive offer level of a Low ACR resource that the default
offer cap is based on.91 While most participants offered in the 2021/2022
RPM Base Residual Auction at competitive levels based on their expectationof the number of performance assessment hours and projected net revenues,
some market participants did not offer competitively and affected the market
clearing prices.

MOPR
Effective April 12, 2011, the RPM Minimum Offer Price Rule (MOPR) waschanged.92 The changes to the MOPR included updating the calculation of the
net Cost of New Entry (CONE) for Combined Cycle (CC) and Combustion Turbine(CT) plants which is used as a benchmark value in assessing the competitivenessof a sell offer, increasing the percentage value used in the screen to 90 percent
for CC and CT plants, eliminating the net-short requirement as a prerequisite
for applying the MOPR, eliminating the impact screen, revising the process forreviewing proposed exceptions to the defined minimum sell offer price, andclarifying which resources are subject to the MOPR along with the duration of
mitigation. Subsequent FERC Orders revised the MOPR, including clarificationon the duration of mitigation, which resources are subject to MOPR, and the
MOPR review process.93
Effective May 3, 2013, the RPM Minimum Offer Price Rule (MOPR) waschanged again.94 The changes to the MOPR included establishing Competitive
Entry and Self Supply Exemptions while also retaining the unit specificexception process for those that do not qualify for the Competitive Entry or
Self Supply Exemptions; changing the applicability of MOPR to include only
combustion turbine, combined cycle, integrated gasification combined cycle
91
92
93
94

See Monitoring Analytics, LLC “Analysis of the 2021/2022 RPM Base Residual Auction—Revised,” at Attachment B <http://www.
monitoringanalytics.com/reports/Reports/‌2018/IMM_Analysis_of_the_20212022_RPM_BRA_Revised_20180824.pdf> (August 24,2018).
135 FERC ¶ 61,022 (2011).
135 FERC ¶ 61,022 (2011), order on reh’g, 137 FERC ¶ 61,145 (2011).
143 FERC ¶ 61,090 (2013).

306

Section 5 Capacity(IGCC) technologies while excluding units primarily fueled with landfill gas orcogeneration units which are certified or self-certified as Qualifying Facilities(QFs); changing the applicability to increases in installed capacity of 20.0
MW or more combined for all units at a single point of interconnection to thetransmission system; changing the applicability to include the full capabilityof repowering of plants based on combustion turbine, combined cycle, IGCC
technology; increasing the screen from 90 percent to 100 percent of theapplicable net CONE values; and broadening the region subject to MOPR tothe entire RTO from modeled LDAs only.
Effective December 8, 2017, FERC issued an order on remand rejecting PJM’s
MOPR proposal in Docket No. ER13-535, and as a result, the rules that werein effect prior to PJM’s December 7, 2012, MOPR filing were reinstated. Thesechanges include eliminating the Competitive Entry and Self Supply Exemptions
and retaining only the Unit Specific Exception request; narrowing the region
subject to MOPR from the entire RTO to only modeled LDAs; eliminating the20.0 MW threshold for applicability; decreasing the screen from 90 percent
to 100 percent of the applicable net CONE values; redefining the applicability
criteria to exclude nuclear, coal, IGCC, hydroelectric, wind and solar facilities;
modifying the duration of mitigation criteria from clearing in a prior delivery
year to clearing in any delivery year; and changing the procedural deadlines.95
By order issued December 19, 2019, the RPM Minimum Offer Price Rule (MOPR)
was modified.96 The rules applying to natural gas fired capacity resources
without state subsidies were retained. The changes include expanding the
MOPR to new or existing state subsidized capacity resources; establishinga competitive exemption for new and existing resources other than natural
gas fired resources while also allowing a resource specific exception process
for those that do not qualify for the competitive exemption; defining limited
categorical exemptions for renewable resources participating in renewable
portfolio standards (RPS) programs, self supply, DR, EE, and capacity storage;
defining the region subject to MOPR for capacity resources with state subsidy
as the entire RTO; and defining the default offer price floor for capacity
resources with state subsidies as 100 percent of the applicable net CONE or net
95
96

161 FERC ¶ 61,252 (2017).
169 FERC ¶ 61,239 (2019), order denying reh’g, 171 FERC ¶ 61,035 (2020).

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

ACR values. The Commission approved PJM’s proposed revisions to the PJM
market rules to implement a forward looking EAS offset to include forward
looking energy and ancillary services revenues rather than historical.97 The
MMU has recommended such an approach. The change in the offset willaffect MOPR floor prices and the results of unit specific reviews under MOPR.
The Commission convened a Technical Conference on March 23, 2021, inorder to consider whether MOPR should be retained and to consider possible
alternative approaches.98 The MMU testified at the Technical Conference andprovided comments and responses to the Commission’s questions following
the conference.99
Issues addressed during the MOPR unit specific review process in 2021 for the2022/2023 BRA included documentation of asset life greater than 20 years,
degradation of resource performance, operating and maintenance expenses,
required capital expenditures, tax assumptions, documentation of forward net
revenues, and the use of retail savings as a source of net revenue offset to EE
gross CONE. The MMU did not agree with PJM’s judgments about parametersand calculations of MOPR floors in a significant number of cases (Table 5-15).

2022/2023 RPM Base Residual Auction
As shown in Table 5-14, 1,083 generation resources submitted Capacity
Performance offers in the 2022/2023 RPM Base Residual Auction. Unit specificoffer caps were not calculated for any generation resources (0.0 percent). Of
the 1,083 generation resources, 872 generation resources had the net CONE
times B offer cap (80.5 percent), 35 Planned Generation Capacity Resources
had uncapped offers (3.2 percent), 40 generation resources had uncappedplanned uprates plus net CONE times B offer cap for the existing portionof the units (3.7 percent), four generation resources had uncapped planned
uprates and were price takers for the existing portion of the unit (0.4 percent),
and the remaining 132 generation resources were price takers (12.2 percent).
Market power mitigation was not applied to any Capacity Performance selloffers.
97
98
99

MOPR Statistics
Market power mitigation measures are applied to MOPR Screened Generation
Resources such that the sell offer is set equal to the MOPR Floor Offer Pricewhen the submitted sell offer is less than the MOPR Floor Offer Price and an
exemption or exception was not granted, or the sell offer is set equal to theagreed upon minimum level of sell offer when the sell offer is less than theagreed upon minimum level of sell offer based on a Unit-Specific Exception
or Resource-Specific Exception.
As shown in Table 5-15, of the 13,149.2 ICAP MW of MOPR Unit-SpecificException and Resource-Specific Exception requests for the 2022/2023 RPM
Base Residual Auction, the MMU agreed with requests for 6,794.7 MW.
Table 5-14 ACR statistics: 2022/2023 RPM auction

Offer Cap/Mitigation TypeDefault ACR
Unit specific ACR (APIR)
Unit specific ACR (APIR and CPQR)
Unit specific ACR (non-APIR)
Unit specific ACR (non-APIR and CPQR)
Opportunity cost input
Default ACR and opportunity cost
Net CONE times B
Offer cap of 1.1 times BRA clearing price elected
Uncapped planned uprate and default ACR
Uncapped planned uprate and opportunity cost
Uncapped planned uprate and Net CONE times B
Uncapped planned uprate and price taker
Uncapped planned uprate and 1.1 times BRA clearing price elected
Uncapped planned generation resources
Existing generation resources as price takers
Total Generation Capacity Resources offered2022/2023 Base
Residual Auction
Number ofPercent ofGeneration
Generation
Resources
Resources Offered
NA
NA
0
0.0%
0
0.0%
0
0.0%
0
0.0%
0
0.0%
NA
NA
872
80.5%
NA
NA
NA
NA
0
0.0%
40
3.7%
4
0.4%
NA
NA
35
3.2%
132
12.2%
1,083
100.0%

173 FERC ¶ 61,134 (2020).
Technical Conference regarding Resource Adequacy in the Evolving Electricity Sector, Docket No. AD21-10 (March 23, 2021).
Modernizing Electricity Market Design, Comments of the Independent Market Monitor for PJM, Docket No. AD21-10 (April 26, 2021).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June307

2021 Quarterly State of the Market Report for PJM: January through June

Table 5-15 MOPR statistics: 2022/2023 RPM auction100
MOPR TypeCapacity Resources with No State Subsidy
Capacity Resources with State Subsidy - Cleared
Capacity Resources with State Subsidy - New
Capacity Resources with No State Subsidy
Capacity Resources with State Subsidy - Cleared
Capacity Resources with State Subsidy - New
Total

Calculation Type
Unit Specific Exception
Resource Specific Exception
Resource Specific Exception
Default
Default
Default

Number ofRequests
148
2
109
NA
NA
NA
259

ICAP (MW)
Requested MMU Agreed
8,849.0
4,882.7
2,134.0
1,240.0
2,166.2
672.0
NA
NA
NA
NA
NA
NA
13,149.2
6,794.7

Offered
1,720.0
2,134.0
1,207.1
116.7
6,590.9459.8
12,228.5

UCAP (MW)OfferedCleared
1,702.4
490.3
2,126.1
2,126.1
1,248.5
1,104.4
98.9
0.0
6,332.9
4,954.7
493.0
153.1
12,001.7
8,828.6

Replacement Capacity101
When a capacity resource is not available for a delivery year, the owner of thecapacity resource may purchase replacement capacity. Replacement capacity
is the vehicle used to offset any reduction in capacity from a resource which
is not available for a delivery year. But the replacement capacity mechanism
may also be used to manipulate the market.
Table 5-16 shows the committed and replacement capacity for all capacity
resources for June 1 of each year from 2007 through 2022. The 2022 numbers
are not final.
Sellers of demand resources in RPM auctions disproportionately replace thosecommitments on a consistent basis compared to sellers of other resource
types. External generation and internal generation not in service had highrates of replacement in some years and those are also of concern.
The dynamic that can result is that the speculative DR suppresses prices in the
BRA and displaces physical generation assets. Those generation assets thenhave an incentive to offer at a low price, including offers at zero and below
cost, in IAs in order to ensure some capacity market revenue for long lived
physical resources which the owners expect to maintain for multiple years.
The result is lower IA prices which permit the buyback of the speculative DR
100 There were additional MOPR Screened Generation Resources for which no exceptions or exemptions were requested and to which the
MOPR floor was applied. Some numbers are not reported as a result of PJM confidentiality rules.
101 For more details on replacement capacity, see “Analysis of Replacement Capacity for RPM Commitments: June 1, 2007 to June 1, 2019,”<http://www.monitoringanalytics.com/‌reports/Reports/2019/IMM_Analysis_of_Replacement_Capacity_for_RPM_Commitments_
June_1_2007_to_June_1_2019_20190913.pdf> (September 13, 2019).

308

Section 5 Capacity

at prices below the BRA prices which encourages the greater use of speculativeDR.
PJM’s sale of capacity in IAs at very low prices, given that PJM announces
the MW quantity and the sell offer price in advance of the auctions, further
reduces IA prices and increases the incentive of DR sellers to speculate in
the BRAs. The MMU recommends that if PJM sells capacity in incremental
auctions, PJM should offer the capacity for sale at the BRA clearing pricein order to avoid suppressing the IA price below the competitive level. If the
PJM sell offer price is not the BRA clearing price, PJM should not reveal its
proposed sell offer price or the MW quantity to be sold prior to the auction.
It has been asserted that selling at a high price in the BRA and buying backat a low price in the IA is just a market transaction and therefore does notconstitute a problem. But permitting DR to be an option in the BRA rather
than requiring DR to be a commitment to provide a physical asset gives DR
an unfair advantage and creates a self fulfilling dynamic that incents moreof the same behavior. Only DR is permitted to be an option in the BRA.
Generation resources must have met physical milestones in order to offer
in the BRA. It is not reasonable to permit DR capacity resources to have a
different product definition than generation capacity resources. Even if DR istreated as an annual product, this unique treatment as an option makes DR an
inferior resource and not a complete substitute for generation resources. The
current approach to DR is also inconsistent with the history of the definition© 2021 Monitoring Analytics, LLC

Section 5 Capacityof capacity in PJM, which has always been that capacity is physical and unit
specific. The current approach to DR effectively makes DR a virtual participant
in the PJM Capacity Market. That option should be eliminated.
The definition of demand side resources in PJM capacity markets is flawed ina variety of ways. The current demand side definition should be replaced witha definition that includes demand on the demand side of the market. There areways to ensure and enhance the vibrancy of demand side without negatively
affecting markets for generation. There are other price formation issues in thecapacity market that should also be examined and addressed.102
Table 5-16 RPM commitments and replacements for all Capacity Resources:
June 1, 2007 to June 1, 2022
UCAP (MW)01-Jun-07
01-Jun-08
01-Jun-09
01-Jun-10
01-Jun-11
01-Jun-12
01-Jun-13
01-Jun-14
01-Jun-15
01-Jun-16
01-Jun-17
01-Jun-18
01-Jun-19
01-Jun-20
01-Jun-21
01-Jun-22

RPM Adjustments toClearedCleared129,409.2
0.0
130,629.8
0.0
134,030.2
0.0
134,036.2
0.0
134,182.6
0.0
141,295.6(11.7)
159,844.5
0.0
161,214.4(9.4)
173,845.5(326.1)
179,773.6(24.6)
180,590.5
0.0
175,996.0
0.0
177,064.2
0.0
174,023.8(335.3)
174,713.0
0.0
144,477.3
0.0

Net
Replacements
0.0(766.5)(2,068.2)(4,179.0)(6,717.6)(9,400.6)(12,235.3)(13,615.9)(11,849.4)(16,157.5)(13,982.7)(12,057.8)(12,300.3)(10,582.7)(12,963.3)
0.0

RPM
Commitments
129,409.2
129,863.3
131,962.0
129,857.2
127,465.0
131,883.3
147,609.2
147,589.1
161,670.0
163,591.5
166,607.8
163,938.2
164,763.9
163,105.8
161,749.7
144,477.3

RPM
Commitment
Shortage(8.1)(246.3)(14.7)(8.8)(79.3)(157.2)(65.4)(1,208.9)(1,822.0)(924.4)(625.3)(150.5)(9.3)(5.7)(316.9)0.0

RPM Commitments
Less Commitment
Shortage
129,401.1
129,617.0
131,947.3
129,848.4
127,385.7
131,726.1
147,543.8
146,380.2
159,848.0
162,667.1
165,982.5
163,787.7
164,754.6
163,100.1
161,432.8
144,477.3

Market Performance
Figure 5-8 shows cleared MW weighted average capacity market prices
on a delivery year basis including base and incremental auctions for eachdelivery year, and the weighted average clearing prices by LDA in each Base
Residual Auction for the entire history of the PJM capacity markets.
Table 5-17 shows RPM clearing prices for all RPM auctions held through thefirst six months of 2021, and Table 5-18 shows the RPM cleared MW for all
RPM auctions held through the first six months of 2021.
Figure 5-9 shows the RPM cleared MW weighted average prices for each
LDA from the 2018/2019 Delivery Year to the current delivery year, and all
results for auctions for future delivery years that have been held throughthe first six months of 2021. A summary of these weighted average prices
is given in Table 5-19.
Table 5-20 shows RPM revenue by delivery year for all RPM auctions held
through the first six months of 2021 based on the unforced MW cleared andthe resource clearing prices. In the 2019/2020 Delivery Year RPM revenue
was $7.1 billion. In the 2020/2021 Delivery Year, RPM revenue was $7.0
billion.
Table 5-21 shows RPM revenue by calendar year for all RPM auctions held
through the first six months of 2021. In 2019, RPM revenue was $8.7 billion.
In 2020, RPM revenue was $7.1 billion.
Table 5-22 shows the RPM annual charges to load. For the 2019/2020
Delivery Year, RPM annual charges to load were $7.0 billion. For the
2020/2021 Delivery Year, annual charges to load are $7.0 billion.

102 See Monitoring Analytics, LLC, “Analysis of the 2021/2022 RPM Base Residual Auction – Revised,” <http://www.monitoringanalytics.com/
reports/Reports/2018/IMM_Analysis_of‌_the_20212022_RPM_BRA_Revised_20180824.pdf> (August 24, 2018).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June309

2021 Quarterly State of the Market Report for PJM: January through June

Table 5-17 Capacity market clearing prices: 2019/2020 through 2022/2023 RPM Auctions103

2019/2020 BRA
2019/2020 BRA
2019/2020 BRA
2019/2020 First Incremental Auction
2019/2020 First Incremental Auction
2019/2020 First Incremental Auction
2019/2020 Second Incremental Auction
2019/2020 Second Incremental Auction
2019/2020 Second Incremental Auction
2019/2020 Third Incremental Auction
2019/2020 Third Incremental Auction
2019/2020 Third Incremental Auction
2020/2021 BRA
2020/2021 First Incremental Auction
2020/2021 Second Incremental Auction
2020/2021 Third Incremental Auction
2021/2022 BRA
2021/2022 First Incremental Auction
2021/2022 Second Incremental Auction
2021/2022 Third Incremental Auction
2022/2023 BRA

Product Type
Base Capacity
Base Capacity DR/EE
Capacity Performance
Base Capacity
Base Capacity DR/EE
Capacity Performance
Base Capacity
Base Capacity DR/EE
Capacity Performance
Base Capacity
Base Capacity DR/EE
Capacity Performance
Capacity Performance
Capacity Performance
Capacity Performance
Capacity Performance
Capacity Performance
Capacity Performance
Capacity Performance
Capacity Performance
Capacity Performance

RTO$80.00$80.00$100.00$15.00$15.00$51.33$10.01$10.01$32.87$21.35$21.35$28.35$76.53$42.90$20.25$10.00$140.00$23.00$10.26$20.55$50.00MAAC$80.00$80.00$100.00$15.00$15.00$51.33$10.01$10.01$32.87$21.35$21.35$28.35$86.04$42.90$20.25$15.25$140.00$23.00$10.26$20.55$95.79APS$80.00$80.00$100.00$15.00$15.00$51.33$10.01$10.01$32.87$21.35$21.35$28.35$76.53$42.90$20.25$10.00$140.00$23.00$10.26$20.55$50.00

PPL$80.00$80.00$100.00$15.00$15.00$51.33$10.01$10.01$32.87$21.35$21.35$28.35$86.04$42.90$20.25$15.25$140.00$23.00$10.26$20.55$95.79EMAAC$99.77$99.77$119.77$22.22$22.22$58.55$10.01$10.01$32.87$21.35$21.35$28.35$187.87$42.90$20.25$15.25$165.73$25.00$15.37$26.36$97.86

RPM Clearing Price ($ per MW-day)
DPL
PSEG
SWMAAC
South
PSEG
North
$80.00$99.77$99.77$99.77$80.00$99.77$99.77$99.77$100.00 $119.77 $119.77 $119.77$15.00$22.22$22.22$22.22$15.00$22.22$22.22$22.22$51.33$58.55$58.55$58.55$10.01$10.01$10.01$10.01$10.01$10.01$10.01$10.01$32.87$32.87$32.87$32.87$21.35$21.35$21.35$21.35$21.35$21.35$21.35$21.35$28.35$28.35$28.35$28.35$86.04 $187.87 $187.87 $187.87$42.90$42.90$42.90$42.90$20.25$20.25$20.25$20.25$15.25$15.25$15.25$15.25$140.00 $165.73 $204.29 $204.29$23.00$25.00$45.00 $219.00$10.26$15.37 $125.00 $125.00$20.55$26.36$31.00$31.00$95.79$97.86$97.86$97.86PEPCO$80.00$0.01$100.00$15.00$15.00$51.33$10.01$10.01$32.87$21.35$20.00$28.35$86.04$42.90$20.25$15.25$140.00$23.00$10.26$20.55$95.79ATSI$80.00$80.00$100.00$15.00$15.00$51.33$10.01$10.01$32.87$21.35$21.35$28.35$76.53$42.90$20.25$10.00$171.33$23.00$10.26$20.55$50.00COMED$182.77$182.77$202.77$15.00$15.00$51.33$10.01$10.01$32.87$21.35$21.35$28.35$188.12$42.90$20.25$10.00$195.55$23.00$10.26$20.55$68.96BGE$80.30$80.30$100.30$15.00$15.00$51.33$32.14$32.14$55.00$21.35$21.35$28.35$86.04$42.90$20.25$15.25$200.30$60.00$70.00$39.00$126.50

DUKE$80.00$80.00$100.00$15.00$15.00$51.33$10.01$10.01$32.87$21.35$21.35$28.35$76.53$42.90$20.25$10.00$140.00$23.00$10.26$20.55$71.69

Table 5-18 Capacity market cleared MW: 2019/2020 through 2022/2023 RPM Auctions104
Delivery Year
2019/20202019/20202019/20202019/2020
2020/2021
2020/2021
2020/2021
2020/2021
2021/2022
2021/2022
2021/2022
2021/2022
2022/2023

AuctionBASE
FIRST
SECOND
THIRD
BASE
FIRST
SECOND
THIRD
BASE
FIRST
SECOND
THIRD
BASE

RTO
57,090.2
774.9
435.6
1,531.9
53,574.6
1,245.3
415.7
961.2
52,896.5
194.1
1,242.5
1,638.4
37,732.2

MAAC
9,996.2
249.4
160.4
440.9
11,413.2
331.0
206.9
569.7
12,565.1
200.4
335.8
168.7
12,804.7

APS
9,066.6
39.3
30.1
429.4
8,990.6
144.2
53.0
118.7
10,136.1
45.9
30.3
231.6
10,147.4

PPL
12,754.9
157.7
146.2
1,216.6
14,398.2
83.4
30.7
89.0
15,368.6
27.2
55.4
127.8
14,118.7

EMAAC
20,382.4
78.7
210.1
265.7
19,978.5
76.2
302.9
194.1
19,857.3
119.0
129.9
911.0
23,658.8

DPLSouth
1,598.5
11.7
21.2
2.4
1,647.2
38.9
28.4
33.1
1,673.8
15.3
39.3
18.3
1,305.3

UCAP (MW)
PSEG
PSEG
North
5,583.1
3,228.9
10.6
28.8
38.1
44.8
180.4
23.2
5,041.2
2,975.4
105.8
32.0
29.5
48.8
423.0
137.0
4,667.2
3,134.1
18.3
79.1
97.0
98.1
227.7
244.8
1,914.3
2,531.1

PEPCO
6,971.7
43.6
41.9
83.6
6,410.0
97.8
35.4
93.1
6,546.1
207.9
75.7
67.2
3,621.8

ATSI
10,291.1
147.5
263.6
454.2
9,925.9
666.9
366.2
554.3
8,010.5
739.3
1,216.8
942.7
10,550.7

COMED
22,971.4
711.4
105.8
867.4
23,960.3
644.4
194.6
127.7
22,358.1
360.4
205.9
221.7
19,223.7

BGE
4,422.9
31.9
107.5
255.2
4,021.1
38.7
160.3
39.8
3,667.8
48.7
115.5
275.9
4,750.9

DUKE
2,971.6
9.6
7.3
76.1
2,437.8
20.3
31.5
145.4
2,746.1
87.6
65.3
159.2
2,117.7

TOTAL
167,329.5
2,295.1
1,612.6
5,827.0
164,773.9
3,524.8
1,903.8
3,486.0
163,627.3
2,143.2
3,707.5
5,235.0
144,477.3

103 See the 2019 State of the Market Report for PJM, Volume 2, Section 5: Capacity Market
104 The MW values in this table refer to rest of LDA or RTO values, which are net of nested LDA values.

310

Section 5 Capacity© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Table 5-19 Weighted average clearing prices by zone: 2019/2020 through2022/2023
LDA
RTO
AEP
APS
ATSI
Cleveland
COMED
DAY
DUKE
DUQ
DOM
EKPC
MAAC
EMAAC
ACEC
DPL
DPL South
JCPLC
PECO
PSEG
PSEG NorthREC
SWMAAC
BGE
PEPCO
WMAAC
MEC
PE
PPL

Weighted Average Clearing Price ($ per MW-day)
2019/2020
2020/2021
2021/2022

2022/2023$93.63$93.63$92.97$89.17$188.90$93.63$93.63$93.63$93.63$93.63$74.42$74.42$69.75$68.93$182.15$72.42$121.24$74.42$74.42$74.42$133.84$133.84$142.59$90.81$189.54$132.69$127.66$133.84$133.84$133.84$50.00$50.00$50.00$50.00$69.02$50.00$71.66$50.00$50.00$50.00$112.48$112.48$115.95$112.48$112.48$110.56$116.03$112.48$182.04$182.04$178.65$182.04$182.04$165.74$176.45$182.04$158.72$158.72$159.65$158.72$158.72$184.82$190.48$158.72$97.79$97.79$97.86$97.79$97.79$97.77$97.82$97.79$88.20$90.59$80.71$84.24$174.43$133.37$126.49$95.19$93.81$93.81$88.53$81.85$81.85$85.07$134.56$134.56$138.51$95.79$95.79$95.77

Table 5-20 RPM revenue by delivery year: 2007/2008 through 2022/2023105
Delivery Year
2007/2008
2008/20092009/20102010/20112011/20122012/20132013/20142014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021
2021/2022
2022/2023

Weighted Average RPM
Price ($ per MW-day)$89.78$127.67$153.37$172.71$108.63$75.08$116.55$126.40$160.01$121.84$141.19$172.09$109.82$111.07$147.33$74.28Weighted Average
Cleared UCAP (MW)
129,409.2
130,629.8
134,030.2
134,036.2
134,182.6
141,283.9
159,844.5
161,205.0
173,519.4
179,749.0
180,590.5
175,996.0
177,064.2
173,688.5
174,713.0
144,477.3

Days
366
365
365
365
366
365
365
365
366
365
365
365
366
365
365
365

RPM Revenue$4,252,287,381$6,087,147,586$7,503,218,157$8,449,652,496$5,335,087,023$3,871,714,635$6,799,778,047$7,437,267,646$10,161,726,902$7,993,888,695$9,306,676,719$11,054,943,851$7,116,815,360$7,041,524,517$9,395,567,946$3,916,953,841

Table 5-21 RPM revenue by calendar year: 2007 through 2023106
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023

Weighted Average RPM
Price ($ per MW-day)$89.78$111.93$142.74$164.71$135.14$89.01$99.39$122.32$146.10$137.69$133.19$159.31$135.58$110.55$132.33$104.50$74.28Weighted Average
Cleared UCAP (MW)75,665.5
130,332.1
132,623.5
134,033.7
133,907.1
138,561.1
152,166.0
160,642.2
168,147.0
177,449.8
180,242.4
177,896.7
176,338.6
175,368.7
174,289.2
156,985.8
59,770.1

Effective Days
214
366
365
365
365
366
365
365
365
366
365
365
365
366
365
365
151

RPM Revenue$2,486,310,108$5,334,880,241$6,917,391,702$8,058,113,907$6,615,032,130$4,485,656,150$5,588,442,225$7,173,539,072$9,018,343,604$8,906,998,628$8,763,578,112$10,331,688,133$8,734,613,179$7,084,072,778$8,421,703,404$6,183,448,991$1,620,438,438

105 The results for the ATSI Integration Auctions are not included in this table.
106 The results for the ATSI Integration Auctions are not included in this table.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June311

2021 Quarterly State of the Market Report for PJM: January through June

Figure 5-8 History of capacity prices: 1999/2000 through 2022/2023107$400
Delivery year cleared MW weighted average clearing price$350

CCM Daily and Monthly weighted average clearing prices
RPM LDA weighted average clearing prices

$300

$200
$172.09$172.71$160.01$150$127.67$20.55$111.07$109.822022/2023

2021/2022

2020/2021

2019/20202018/20192017/20182016/20172014/20152013/20142011/20122010/20112009/20102008/20092007/2008$5.22

2006/2007$4.53

2005/2006

2004/2005

2003/2004

2002/2003$74.28$17.35$13.64

2001/2002$121.84$75.08$57.75

2000/2001$141.19$126.40$116.55$108.63$89.78$38.801999/2000$0$97.58

2012/2013

$100
$50

$147.33$153.37

2015/2016$ per MW-day$250

107 The 1999/2000 through 2006/2007 capacity prices are CCM combined market, weighted average prices. The 2007/2008 through 2021/2022 capacity prices are RPM weighted average prices. The CCM data points plotted are cleared MW weighted average prices for the daily and monthly
markets by delivery year. The RPM data points plotted are RPM LDA clearing prices. For the 2014/2015 and subsequent delivery years, only the prices for Annual Resources or Capacity Performance Resources are plotted.

312

Section 5 Capacity© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Figure 5-9 Map of RPM capacity prices: 2018/2019 through 2021/2022© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June313

2021 Quarterly State of the Market Report for PJM: January through June

Table 5-22 RPM cost to load: 2019/2020 through 2022/2023 RPM
Auctions108 109 110
Net Load Price($ per MW-day)

UCAP Obligation (MW)Annual Charges

2019/2020
Rest of RTO
Rest of EMAAC
BGE
COMED
PEPCO
PSEG
Total

$98.07$115.58$97.79$192.56$92.90$115.83

89,185.9
24,415.1
7,595.2
24,985.1
7,330.3
11,281.1
164,792.8$3,201,364,940$1,032,810,556$271,828,430$1,760,892,086$249,230,694$478,247,326$6,994,374,033

2020/2021
Rest of RTO
Rest of MAAC
EMAAC
COMED
DUKE
Total

$77.31$87.06$174.32$189.92$104.50

69,073.7
29,555.9
35,740.4
23,744.7
5,072.0
163,186.7$1,949,098,489$939,246,366$2,274,098,760$1,645,988,210$193,459,838$7,001,891,663

2021/2022
Rest of RTO
Rest of EMAAC
ATSI
BGE
COMED
PSEG
Total

$142.16$164.73$160.21$163.50$198.43$188.46

82,768.3
23,719.9
13,995.4
7,491.2
22,721.2
10,987.4
161,683.4$4,294,838,410$1,426,178,211$818,411,597$447,049,048$1,645,630,168$755,803,998$9,387,911,433

2022/2023
Rest of RTO
EMAAC
WMAAC
BGE
COMED
DUKE
PEPCO
Total

$50.09$97.75$96.42$107.92$67.17$59.38$95.97

51,125.9
35,300.9
15,495.6
7,611.3
22,940.7
5,304.6
6,698.3
144,477.3$934,814,759$1,259,545,677$545,317,684$299,826,001$562,472,028$114,962,107$234,639,139$3,951,577,394

108 The RPM annual charges are calculated using the rounded, net load prices as posted in the PJM RPM auction results.
109 There is no separate obligation for DPL South as the DPL South LDA is completely contained within the DPL Zone. There is no separate
obligation for PSEG North as the PSEG North LDA is completely contained within the PSEG Zone. There is no separate obligation for ATSI
Cleveland as the ATSI Cleveland LDA is completely contained within the ATSI Zone.
110 The net load prices and obligation MW for 2021/2022 are not finalized.

314

Section 5 Capacity

MOPR and FRR
The states have authority over their generation resources and can choose toremain in PJM capacity markets or to create FRR entities. The existing FRR
approach remains an option for utilities with regulated revenues based on costof service rates, including both privately and publicly owned (including public
power entities and electric cooperatives) utilities. Such regulated utilities have
had and continue to have the ability to opt out of the capacity market andprovide their own capacity. As made clear in recent analyses of FRR optionsin Illinois, Maryland, New Jersey, Ohio, and the District of Columbia, the FRR
approach is likely to lead to significant increases in payments by customers
when it replaces participation in the PJM markets.111 The existing FRR rules
were created in 2007 primarily for the specific circumstances of AEP as part ofthe original RPM capacity market design settlement. The MMU recommends
that the FRR rules be revised and updated to ensure that the rules reflectcurrent market realities and that FRR entities do not unfairly take advantageof those customers paying for capacity in the PJM Capacity Market.
FRR proposals in Illinois for the COMED Zone and in New Jersey are primarily
nuclear subsidy programs that would increase nuclear subsidies well beyond
the ZECs rules currently in place in both states while also providing for
payments to some renewable resources at above market prices.112 The MMU
has prepared reports with analysis on the potential impacts of states pursuing
the FRR option. In separate reports for Illinois, Maryland, New Jersey, Ohio,
Virginia, and the District of Columbia, the cost impacts of the state choosing
the FRR option are computed under different FRR capacity price assumptions
and different assumptions regarding the composition of the FRR service
111 The MMU has posted several reports regarding the creation of FRRs. “Potential Impacts of the Creation of a ComEd FRR,” (December
18, 2019). <http://www.monitoringanalytics.com/‌reports/Reports/2019/IMM_Potential_Impacts_of_the_Creation_of_a_ComEd_
FRR_20191218.pdf>. “Potential Impacts of the Creation of Maryland FRRs,” (April 16, 2020). <http://www.monitoringanalytics.com/
reports/Reports/2020/IMM_Potential_Impacts_of_the_Creation_of_Maryland_FRRs_20200416.pdf>. “Potential Impacts of the Creationof New Jersey FRRs,” (May 13, 2020). <http://www.monitoringanalytics.com/reports/Reports/2020/‌IMM_Potential_Impacts_of_the_Creation_of_New_Jersey_FRRS_20200513.pdf>. “Potential Impacts of the Creation of Ohio FRRs,” (July 17, 2020). <http://www.
monitoringanalytics.‌com/reports/Reports/2020/IMM_Potential_Impacts_of_the_Creation_of%20Ohio_FRRs_20200717.pdf>. “Potential
Impacts of the Creation of District of Columbia FRR,” (May 7, 2021) <https://www.monitoringanalytics.com/reports/Reports/2021/
IMM_Potential_Impact_of_the_Creation_of_District_of_Columbia_FRR_20210507.pdf>.
112 In the Matter of the Investigation of Resource Adequacy Alternatives, New Jersey Board of Public Utilities, Docket No. EO20030203.
Monitoring Analytics, LLC Comments, <http://www.monitoringanalytics.com/filings/2020/IMM_Comments_Docket_No_
EO20030203_20200520.pdf> (May 20, 2020). Monitoring Analytics, LLC, Reply Comments <http://www.monitoringanalytics.com/
filings/2020/IMM_Reply_Comments_Docket_No_EO20030203_20200624.pdf>. (June 24, 2020). Monitoring Analytics, Answer to Exelon
and PSEG, <http://www.monitoringanalytics.com/filings/2020/IMM_Answer_to_Exelon_PSEG_Docket_No_EO20030203_20200715.pdf>(July 15, 2020).

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

area.113 114 115 116 117 The impact on the remaining PJM capacity market footprint
is also computed for each scenario. In all but a few scenarios the MMU findsthat the FRR leads to higher costs for load included in the FRR service area. In
all scenarios the MMU finds that prices in what remains of the PJM Capacity
Market would be significantly lower.
Both FERC and the states have significant and overlapping authority affecting
wholesale power markets. While the FERC MOPR approach was designed toensure that subsidies did not affect the wholesale power markets, the states
have ultimate authority over the generation choices made in the states. The
FRR explorations by multiple states illustrated a possible path forward. Under
that path, the FERC market would be unaffected by subsidies but many states
would withdraw from the FERC regulated markets and create higher costnonmarket solutions rather than be limited by MOPR. That would not be an
efficient outcome and would not serve the interests of customers or generators.
With the expected elimination of the current MOPR rules, the capacity market
design must accommodate the choices made by states to subsidize renewableor clean resources in a way that maximizes the role of competition to ensurethat customers pay the lowest amount possible, consistent with state goals
and the costs of providing the desired resources. Such an approach can takeseveral forms, but none require the dismantling of the PJM capacity market
design. The PJM capacity market design can adapt to a wide range of state
supported resources and state programs. As a simple starting point, states cancontinue to support selected resources using a range of payment structures
and those resources could participate in the capacity auctions. As a broader
and more comprehensive option, PJM could create a demand curve for clean
resources based on the quantity of such resources identified by one or morestates and clear a market for clean resources as part of the capacity market
clearing process.
113 See Monitoring Analytics, LLC, “Potential Impacts of the Creation of a ComEd FRR,” <http://www.monitoringanalytics.com/reports/
Reports/2019/IMM_Potential_Impacts_of_the_Creation_of_a_ComEd_FRR_20191218.pdf> (December 18, 2020).
114 See Monitoring Analytics, LLC, “Potential Impacts of the Creation of Maryland FRRs,” <http://www.monitoringanalytics.com/reports/
Reports/2020/IMM_Potential_Impacts_of_the_Creation_of_Maryland_FRRs_20200416.pdf> (April 16, 2020).
115 See Monitoring Analytics, LLC, “Potential Impacts of the Creation of New Jersey FRRs,” <http://www.monitoringanalytics.com/reports/
Reports/2020/IMM_Potential_Impacts_of_the_Creation_of_New_Jersey_FRRS_20200513.pdf> (May 13, 2020).
116 See Monitoring Analytics, LLC, “Potential Impacts of the Creation of Ohio FRRs,” <http://www.monitoringanalytics.com/reports/
Reports/2020/IMM_Potential_Impacts_of_the_Creation_of%20Ohio_FRRs_20200717.pdf> (July 17, 2020).
117 See Monitoring Analytics, LLC, “Potential Impacts of the Creation of Virginia FRRs,” <https://www.monitoringanalytics.com/reports/
Reports/2021/IMM_VA_FRR_Report_20210518.pdf> (May 18, 2021).

© 2021 Monitoring Analytics, LLC

The MMU’s proposed modifications to the MOPR rules would retain thefundamentals of the current capacity market design and result in a deminimis impact on competitive market outcomes while recognizing definedstate authority. The MMU’s proposed modifications to the MOPR rules
would retain a clear MOPR rule while recognizing state authority over thegeneration facilities in each state. The MMU’s proposed modifications would
permit exemptions from MOPR for state programs designed to support specificemerging technologies that would not otherwise be competitive. All othertechnologies are competitive and are expected to clear in capacity auctions,even with the application of MOPR. The MMU’s proposed modifications
would not impede or interfere with authorized state policies, regardless of thetargeted technology. The MMU’s proposed modifications also recognize thatthe definition of a competitive offer, the MOPR floor, is net ACR and not net
CONE. Even when the MOPR rules are applied, the MOPR floors are defined
to be competitive offers and expected to clear when consistent with market
fundamentals. A competitive offer is a competitive offer. The MOPR offer
floor is the same as the market seller offer cap (MSOC).
Given that states have increasingly aggressive renewable energy targets,a core goal of a competitive market design should be to ensure that theresources required to provide reliability receive appropriate competitivemarket incentives for entry and for ongoing investment and for exit when
uneconomic. A significant level of renewable resources, operating withzero or near zero marginal costs, will result in very low energy prices.
Since renewable resources are intermittent, the contribution of renewables
to meeting reliability targets must be analyzed carefully to ensure that thecapacity value is calculated correctly.
PJM has proposed a flawed Effective Load Carrying Capability (ELCC)
approach to defining the capacity contribution of intermittent resources.118
Implementing PJM’s flawed ELCC approach, based on static average rather
than dynamic, market defined marginal values, and locking in values for oldtechnology for long periods regardless of market realities, and basing theresults on incorrect assumptions about the dispatch of some resource types,
118

PJM Interconnection L.L.C., Docket No. ER21-278 Effective Load Carrying Capability Construct (October 30, 2020).

2021 Quarterly State of the Market Report for PJM: January through June315

2021 Quarterly State of the Market Report for PJM: January through June

would be a significant mistake and create new issues for the PJM capacity
markets. The results could degrade reliability, impede innovation and theintroduction of new technologies, and inefficiently displace thermal resources.
It is essential to not build in a bad market design from the beginning as
such designs gain momentum and gain entrenched supporters among thebeneficiaries. If done correctly, ELCC would be an advance over the current
approach to discounting the reliability contribution of intermittent resources,
but only if done correctly and only if all the required assumptions are madeexplicit and decided explicitly.119
In order to attract and retain adequate resources for the reliable operation of
the energy market, revenues from PJM energy, ancillary services and capacity
markets must be adequate for those resources. That adequacy requires acapacity market. The capacity market plays the essential role of equilibrating
the revenues necessary to incent competitive entry and exit of the resources
needed for reliability, with the revenues from the energy market that are
directly affected by nonmarket sources.
Price suppression below the competitive level in the capacity market should
not be acceptable and is not consistent with a competitive market design.
Harmonizing means that the integrity of each paradigm is maintained andrespected. Harmonizing permits nonmarket resources to have an unlimited
impact on energy markets and energy prices. Harmonizing means designing acapacity market to account for these energy market impacts, clearly limiting
the impact of nonmarket revenues on the capacity market and ensuring
competitive outcomes in the capacity market and thus in the entire market.
To the extent that there are shared broader goals related to PJM markets, theyshould also be addressed, but this can happen with a slightly longer lead time. If
a shared goal is to reduce carbon output, a price on carbon is the market based
solution. If a shared goal is increased renewables in addition to their carbon
attributes, a common approach to RECs would be a market based solution.
119 Comments and Motions of the Independent Market Monitor for PJM, Docket No. ER21-278 and EL19-100 (November 20, 2020). Answer
and Motion for Leave to Answer and Alternative Motion for Consolidation of the Independent Market Monitor for PJM, Docket No.
ER21-278 (December 10, 2020). Answer and Motion for Leave to Answer of the Independent Market Monitor for PJM, Docket No.
ER21-278 (December 18, 2020). Comments and Motions of the Independent Market Monitor for PJM, ER21-278-001 (March 22, 2021).
Answer and Motion for Leave to Answer of the Independent Market Monitor for PJM, Docket No. ER21-278 (April 28, 2021).

316

Section 5 Capacity

Fuel diversity has also been mentioned as an issue. Current fuel diversity ishigher than ever in PJM. If there is an issue, the real issue is fuel security andnot fuel diversity. Significant reliance on specific fuels, including nuclear,coal and gas means that markets are at risk from a significant disruption in
any one fuel. If fuel security for gas is a concern, a number of issues should
be considered including the reliability of the pipelines, the compatibility of
the gas pipeline and the merchant generator business models, the degree towhich electric generators have truly firm gas service and the need for a gas
RTO/ISO to help ensure reliability. PJM should require firm fuel as a conditionof being a capacity resource.

CRF Issue120
As a result of the significant changes to the federal tax code in December
2017, the capital recovery factor (CRF) tables in PJM OATT Attachment DD §6.8(a) and Schedule 6A are not correct. These tables should have been updated
in 2018 and should be updated prior to the next capacity market auction.
Correct CRFs will ensure that offer caps and offer floors in the capacity
market are correct. The required changes are clear and unambiguous. On May
4, 2021, PJM filed updates to the OATT under FPA Section 205.121 In thefiling PJM proposed new CRFs based on the new tax law and new financial
assumptions. The new financial assumptions are identical to the assumptions
used in the PJM quadrennial review for the calculation of the cost of newentry (CONE) for the PJM reference resource. The MMU, in comments to theCommission, asked that the following formula be included in the tariff as anefficient alternative to use of tables which require updates whenever tax laws
or financial assumptions change:122 123

120 See related filing on CRF issue in black start: Comments of the Independent Market Monitor for PJM, Docket No. ER21-1635 (April 28,2021).
121 “Revisions to Capital Recovery Factor for Avoidable Project Investment Cost Determinations and Request for Waiver of Sixty-Day Notice
Requirement”, PJM Interconnection L.L.C., Docket ER21-1844-000 (May 4, 2021).
122 See “Comments of the Independent Market Monitor for PJM”, ER21-1844-000 (May 25, 2021).
123 The formula was first introduced in a related Section 205 filing regarding CRFs for black start service. See “Comments of the
Independent Market Monitor for PJM” (April 28, 2021) and “Answer and Motion to Answer of the Independent Market Monitor for PJM”
(May 19, 2021) in Docket ER21-1635-000.

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

The MMU also proposed that PJM discontinue the practice of using an averagestate tax rate in the CRF calculation. The CRF formula allows for the quick andefficient calculation of a unit’s CRF using the state tax rate that is applicable
to a specific unit.
FERC accepted PJM’s filing but also required that the CRF formula be
included in the tariff.124 FERC rejected the MMU’s unit specific state tax
recommendation. Going forward, PJM will post the CRFs on their website.
Table 5-24 shows the CRFs that are currently posted. The values in Table
5-24 were calculated using the formula above and the financial assumptionsin Table 5-25. Bonus depreciation assumptions vary by delivery year with
100 percent bonus depreciation assumed in the 2022/2023 Delivery Year. The
bonus depreciation in each subsequent delivery year is reduced by 20 percent.
Table 5-23 Variable descriptions for the CRF formula
FormulaSymbol
r
s
B
N
L
mj

Description
After tax weighted average cost of capital (ATWACC)
Effective tax rate
Bonus depreciation percent
Cost Recovery Period (years)
Lesser of N or 16 (years)
Modified Accelerated Cost Recovery System (MACRS) depreciation factor for year j = 1, …, 16

The MMU supports the changes to the tariff to correct the application of CRF
to the capacity market but there are still unresolved issues. The tariff revisions
lack clarity about how CRF values will be determined in the future and towhich projects they apply, and lack clarity about how CRF values would
be applied to APIR for project costs that are currently being recovered. For
example, Table 5-24, which is identical to the table posted by PJM, includes
CRF values for projects that go into service for four identified delivery years
but fails to note that these CRF values for a later delivery year would not apply
for investments made in prior delivery years that will still be in service in thelater delivery year.125 For example, a project that can use the depreciation
provisions relevant for the 2023/2024 Delivery Year uses the depreciation
124 Order 176 FERC ¶61,003 (July 2, 2021).
125 See “Capital Recovery Factors (“CRF”) for Avoidable Project Investment Cost (“APIR”) Determinations <https://pjm.com/-/media/marketsops/rpm/rpm-auction-info/crf-values-for-apir-determination.ashx>.

© 2021 Monitoring Analytics, LLC

provisions once and those provisions affect the project’s CRF for its entire
life, regardless of the CRF values in the table for subsequent delivery years.
However, changes in the tax rate apply each year and if the tax rate changes
the applicable CRF values would change for all projects, regardless of vintage.
As a result, the CRF values in Table 5-24 for delivery years after 2022/2023
would not apply to the calculation of APIR values for projects that go into
service for the 2022/2023 Delivery Year. A similar issue exist for projects thatwere assigned a CRF under the previous tariff rules. The change in the tax
rate should be reflected in the CRF going forward. PJM does not plan to do
this and the Commission indicated that the issue is “beyond the scope” of the
PJM filing.126
Table 5-24 Levelized CRF values: Delivery Year 2022/2023 through Delivery
Year 2025/2026
Age of Existing Units (Years)
1 to 56 to 1011 to 15
16 to 20
21 to 25
25 PlusMandatory CapEx
40 Plus Alternative

Remaining Levelized CRF Levelized CRF Levelized CRF Levelized CRF
Life of Plant
2022/2023
2023/2024
2024/2025
2025/2026
30
0.088
0.091
0.094
0.096
25
0.093
0.096
0.098
0.101
20
0.101
0.104
0.107
0.110
15
0.116
0.119
0.122
0.126
10
0.147
0.152
0.158
0.164
5
0.246
0.258
0.271
0.283
4
0.296
0.312
0.328
0.345
1
1.100
1.100
1.100
1.100

Table 5-25 Financial assumptions for CRF calculations
Financial Parameter
Equity Funding Percent
Debt Funding Percent
Equity Rate
Debt Interest Rate
Federal Tax Rate
State Tax Rate
Effective Tax Rate
After tax Weighted Average Cost of Capital

Parameter Value
45.000%55.000%13.000%6.000%
21.000%9.300%
28.347%8.215%

126 Order 176 FERC ¶61,003 (July 2, 2021) at 28.

2021 Quarterly State of the Market Report for PJM: January through June317

2021 Quarterly State of the Market Report for PJM: January through June

Timing of Unit Retirements

Reliability Must Run (RMR) Service

Generation owners that want to deactivate a unit, either to mothball or
permanently retire, must provide notice to PJM and the MMU at least 90
days prior to the proposed deactivation date. Generation owners seeking acapacity market must offer exemption for a delivery year must submit theirdeactivation request no later than the December 1 preceding the Base ResidualAuction or 120 days before the start of an Incremental Auction for thatdelivery year.127 If no reliability issues are found during PJM’s analysis of
the retirement’s impact on the transmission system, and the MMU finds nomarket power issues associated with the proposed deactivation, the unit may
deactivate at any time thereafter.128

PJM must make out of market payments to units for Reliability Must Run(RMR) service during periods when a unit that would otherwise have been
deactivated is needed for reliability.129 The need for RMR service reflects aflawed market design and/or planning process problems. If a unit is needed
for reliability, the market should reflect a locational value consistent with thatneed which would result in the unit remaining in service or being replaced
by a competitor unit. The planning process should evaluate the impact of theloss of units at risk and determine in advance whether transmission upgrades
are required.130

Table 5-26 shows the timing of actual deactivation dates and the initiallyrequested deactivation date, for all deactivation requests submitted fromJanuary 2018 through June 2021. Of the 89 deactivation requests submitted,
18 units (20.2 percent) deactivated an average of 220 days earlier than theirinitially requested date; 12 units (13.5 percent) deactivated an average of 95
days later than the originally requested deactivation date; and 30 units (33.7
percent) deactivated on their initially requested date. Twelve (13.5 percent)of the unit deactivations were cancelled an average of 435 days before theirscheduled deactivation date, and 17 (19.1 percent) of the unit deactivations
have not yet reached their target retirement date.
Table 5-26 Timing of actual unit deactivations compared to requested
deactivation date: Requests submitted January 2018 through June 2021
Early
Late
On timeCancelled
Pending
Total

Number of Units
18
12
30
12
17
89

127 OATT Attachment DD § 6.6(g).
128 OATT Part V §113

318

Section 5 Capacity

Percent
20.2%
13.5%
33.7%
13.5%
19.1%
100.0%

Average Days Deviation from
Originally Requested Date
(220)
95
0
(435)
-

When notified of an intended deactivation, the MMU performs a market
power study to ensure that the deactivation is economic, not an exercise of
market power through withholding, and consistent with competition.131 PJM
performs a system study to determine whether the system can accommodate
the deactivation on the desired date, and if not, when it could.132 If PJM
determines that it needs a unit for a period beyond the intended deactivation
date, PJM will request a unit to provide RMR service.133 The PJM market rules
do not require an owner to provide RMR service, but owners must provide 90
days advance notice of a proposed deactivation.134 The owner of a generation
capacity resource must provide notice of a proposed deactivation in order toavoid a requirement to offer in RPM auctions.135 In order to avoid submitting
an offer for a unit in the next three-year forward RPM base residual auction,
an owner must show “a documented plan in place to retire the resource,”
including a notice of deactivation filed with PJM, 120 days prior to such
auction.136
129 OATT Part V §114
130 See, e.g., 140 FERC ¶ 61,237 at P 36 (2012) (“The evaluation of alternatives to an SSR designation is an important step that deserves thefull consideration of MISO and its stakeholders to ensure that SSR Agreements are used only as a ‘limited, last-resort measure.’”); 118
FERC ¶ 61,243 at P 41 (2007) (“the market participants that pay for the agreements pay out-of-market prices for the service provided
under the RMR agreements, which broadly hinders market development and performance.[footnote omitted] As a result of thesefactors, we have concluded that RMR agreements should be used as a last resort.”); 110 FERC ¶ 61,315 at P 40 (2005) (“The Commission
has stated on several occasions that it shares the concerns . . . that RMR agreements not proliferate as an alternative pricing option forgenerators, and that they are used strictly as a last resort so that units needed for reliability receive reasonable compensation.”).
131 OATT § 113.2; OATT Attachment M § IV.1.
132 OATT § 113.2.
133 Id.
134 OATT § 113.1.
135 OATT Attachment DD § 6.6(g).
136 Id.

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Under the current rules, a unit providing RMR service can recover its costs
under either the deactivation avoidable cost rate (DACR), which is a formularate, or the cost of service recovery rate. The deactivation avoidable cost
rate is designed to permit the recovery of the costs of the unit’s “continued
operation,” termed “avoidable costs,” plus an incentive adder.137 Avoidable
costs are defined to mean “incremental expenses directly required for theoperation of a generating unit.”138 The incentives escalate for each year ofservice (first year, 10 percent; second year, 20 percent; third year, 35 percent;fourth year, 50 percent).139 The rules provide terms for early termination of
RMR service and for the repayment of project investment by owners of units
that choose to keep units in service after the RMR period ends.140 Project
investment is capped at $2 million, above which FERC approval is required.141
The cost of service rate is designed to permit the recovery of the unit’s “costof service rate to recover the entire cost of operating the generating unit” if
the generation owner files a separate rate schedule at FERC.142
Table 5-27 shows units that have provided RMR service to PJM.

Only two of seven owners have used the deactivation avoidable cost rate
approach. The other five owners used the cost of service recovery rate, despite
the greater administrative expense.
In each of the cost of service recovery rate filings for RMR service, the scopeof recovery permitted under the cost of service approach defined in Section
119 has been a significant issue. Owners have sought to recover fixed costs,
incurred prior to the noticed deactivation date, in addition to the cost ofoperating the generating unit. Owners have cited the cost of service reference
to mean that the unit is entitled to file to recover costs that it was unable torecover in the competitive markets, in addition to recovery of costs of actuallyproviding the RMR service.
The cost of service recovery rate approach has been interpreted by thecompanies using that approach to allow the company to establish a rate baseincluding investment in the existing plant and new investment necessary
to provide RMR service and to earn a return on that rate base and receive

Table 5-27 RMR service summary
Unit Names
B.L. England 2
Yorktown 1
Yorktown 2
B.L. England 3
Ashtabula
Eastlake 1
Eastlake 2
Eastlake 3
Lakeshore
Elrama 4
Niles 1
Cromby 2 and Diesel
Eddystone 2
Brunot Island CT2A, CT2B, CT3 and CC4
Hudson 1
Sewaren 1-4

Owner
RC Cape May Holdings, LLC
Dominion Virginia Power
Dominion Virginia PowerRC Cape May Holdings, LLC
FirstEnergy Service Company
FirstEnergy Service Company
FirstEnergy Service Company
FirstEnergy Service Company
FirstEnergy Service Company
GenOn Power Midwest, LP
GenOn Power Midwest, LP
Exelon Generation Company, LLC
Exelon Generation Company, LLC
Orion Power MidWest, L.P.
PSEG Energy Resources & Trade LLC and PSEG Fossil LLC
PSEG Energy Resources & Trade LLC and PSEG Fossil LLC

ICAP (MW) Cost Recovery Method
150.0 Cost of Service Recovery Rate
159.0 Deactivation Avoidable Cost Rate
164.0 Deactivation Avoidable Cost Rate
148.0 Cost of Service Recovery Rate
210.0 Deactivation Avoidable Cost Rate
109.0 Deactivation Avoidable Cost Rate
109.0 Deactivation Avoidable Cost Rate
109.0 Deactivation Avoidable Cost Rate
190.0 Deactivation Avoidable Cost Rate
171.0 Cost of Service Recovery Rate
109.0 Cost of Service Recovery Rate
203.7 Cost of Service Recovery Rate
309.0 Cost of Service Recovery Rate
244.0 Cost of Service Recovery Rate
355.0 Cost of Service Recovery Rate
453.0 Cost of Service Recovery Rate

Docket Numbers Start of Term
ER17-1083
01-May-17
ER17-750
06-Jan-17
ER17-750
06-Jan-17
ER17-1083
01-May-17
ER12-2710
01-Sep-12
ER12-2710
01-Sep-12
ER12-2710
01-Sep-12
ER12-2710
01-Sep-12
ER12-2710
01-Sep-12
ER12-1901
01-Jun-12
ER12-1901
01-Jun-12
ER10-1418
01-Jun-11
ER10-1418
01-Jun-11
ER06-993
16-May-06
ER05-644, ER11-2688
25-Feb-05
ER05-644
25-Feb-05

End of Term
30-Apr-19
08-Mar-19
08-Mar-19
24-Jan-18
11-Apr-15
15-Sep-14
15-Sep-14
15-Sep-14
15-Sep-14
01-Oct-12
01-Oct-12
01-Jan-12
01-Jun-12
05-Jul-07
08-Dec-11
01-Sep-08

137 OATT § 114 (Deactivation Avoidable Credit = ((Deactivation Avoidable Cost Rate + Applicable Adder) * MW capability of the unit *Number of days in the month) – Actual Net Revenues).
138 OATT § 115.
139 Id.
140 OATT § 118.
141 OATT §§ 115, 117.
142 OATT § 119.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June319

2021 Quarterly State of the Market Report for PJM: January through June

depreciation of that rate base. Companies developing the cost of service
recovery rate have ignored the tariff’s limitation to the costs of operating theunit during the RMR service period and have included costs incurred prior
to the decision to the deactivate and costs associated with closing the unitthat would have been incurred regardless of the RMR service period.143 In
one cost of service recovery rate, the filing included costs that already had
been written off on the company’s public books.144 Unit owners have filed forrevenues under the cost of service method that substantially exceed the actual
incremental costs of providing RMR service.
Because an RMR unit is needed by PJM for reliability reasons, and theprovision of RMR service is voluntary in PJM, owners of RMR service havesignificant market power in establishing the terms of RMR service.
RMR service should be provided to PJM customers at reasonable rates, whichreflect the riskless nature of providing such service to owners, the reliability
need for such service and the opportunity for owners to be guaranteed
recovery of 100 percent of the actual incremental costs incurred to provide
the service plus an incentive markup.
The cost of service recovery rates have been excessive compared to the actual
incremental costs of providing RMR service. The DACR method also provides
excessive incentives for service longer than a year, given that customers bear
the risks.
The MMU recommends elimination of the cost of service recovery rate in OATT
Section 119, and that RMR service should be provided under the deactivation
avoidable cost rate in Part V.

143 See, e.g., FERC Dockets Nos. ER10-1418-000, ER12-1901-000 and ER17-1083-000.
144 See GenOn Filing, Docket No. ER12-1901-000 (May 31, 2012) at Exh. No. GPM-1 at 9:16–21.

320

Section 5 Capacity

The MMU also recommends, based in part on its experience with applicationof the deactivation avoidable cost rate and proceedings filed under Section
119, the following improvements to the DACR provisions:• Revise the applicable adders in Section 114 to be 15 percent for the second
year of RMR service and 20 percent for the provision of RMR service inexcess of two years.

• Add true up provisions that ensure that the RMR service provider isreimbursed for, and consumers pay for, the actual incremental costs
associated with the RMR service, plus the applicable adder.

• Eliminate the $2 million cap on project investment expenditures.
• Clearly distinguish operating expenses and project investment costs.
• Clarify the tariff language in Section 118 regarding the refund of project

investment in the event the RMR unit continues operation beyond the
RMR term.

Generator Performance
Generator performance results from the interaction between the physicalcharacteristics of the units and the level of expenditures made to maintain thecapability of the units, which in turn is a function of incentives from energy,
ancillary services and capacity markets. Generator performance indicesinclude those based on total hours in a period (generator performance factors)
and those based on hours when units are needed to operate by the system
operator (generator forced outage rates).

Capacity Factor
Capacity factor measures the actual output of a power plant over a period oftime compared to the potential output of the unit had it been running at full
nameplate capacity for every hour during that period. Table 5-28 shows thecapacity factors by unit type for January through June, 2020 through 2021.
In the first six months of 2021, nuclear units had a capacity factor of 90.6
percent, compared to 92.1 percent in the first six months of 2020; combined
cycle units had a capacity factor of 48.6 percent in the first six months of© 2021 Monitoring Analytics, LLC

Section 5 Capacity

145 The capacity factors in this table are based on nameplate capacity values, and are calculated based on when the units come on line.
146 The subcategories of steam units are consolidated consistent with confidentiality rules. Coal is comprised of coal and waste coal.
Natural gas is comprised of natural gas and propane. Oil is comprised of both heavy and light oil. Biomass is comprised of biomass,
landfill gas, and municipal solid waste.

© 2021 Monitoring Analytics, LLC

Figure 5-10 Outages (MW): 2012 through June 2021
80,00070,00060,00050,00040,00030,00020,000ForcedMaintenanceJan-21

Jul-20Jan-20Jul-19Jan-19Jul-18Jan-18

Jul-17Jan-17

Jul-16

Jan-16

Jul-15Jan-15

Jul-140

Jan-1410,000Jul-13

Change in
2021 from2020
0.2%(3.3%)(1.6%)(11.3%)
0.8%
0.7%
1.1%
2.7%
3.0%
1.4%
(2.3%)(2.5%)(1.5%)
0.1%(4.2%)(0.8%)
8.4%
3.9%
9.5%
9.0%
16.9%
(1.5%)(0.7%)(3.5%)(0.1%)(1.5%)
1.8%

Jan-132021 (Jan-Jun)
Generation(GWh) Capacity Factor
19.9
1.3%
135,855.4
48.6%
120,092.5
52.0%
15,762.9
32.6%
6,960.0
4.7%
5,105.9
4.9%
1,854.1
4.3%
150.3
6.7%
143.7
7.7%
6.5
1.7%
740.5
41.9%
110.2
79.4%
133,383.6
90.6%
2,627.8
9.1%
5,763.2
33.3%
3,440.2
19.7%
99,686.8
28.4%
2,866.7
55.8%
94,813.1
31.6%
91,955.6
32.0%
2,857.5
23.9%
2,006.8
32.2%
260.6
38.9%
1,746.2
15.2%
0.3
0.0%
14,967.0
29.9%
403,708.0
38.6%

Jul-12

Unit Type
Battery
Combined Cycle
Single Fuel
Dual Fuel
Combustion Turbine
Single Fuel
Dual Fuel
DieselSingle Fuel
Dual Fuel
Diesel (Landfill gas)
Fuel Cell
Nuclear
Pumped Storage Hydro
Run of River Hydro
Solar
Steam
Biomass
Coal
Single Fuel
Dual Fuel
Natural Gas
Single Fuel
Dual Fuel
Oil
Wind
Total

2020 (Jan-Jun)
Generation(GWh) Capacity Factor
17.1
1.1%
143,222.5
52.0%
122,567.8
53.6%
20,654.7
43.9%
5,742.5
3.8%
4,357.3
4.1%
1,385.2
3.2%
90.3
4.0%
89.1
4.8%
1.2
0.3%
822.2
44.2%
114.2
81.8%
136,376.3
92.1%
2,624.5
9.0%
6,531.3
37.5%
1,855.4
20.5%
73,587.8
20.1%
2,731.8
51.9%
69,065.8
22.2%
68,024.6
22.9%
1,041.2
7.0%
1,772.6
33.7%
192.9
39.6%
1,579.7
18.7%
17.6
0.1%
14,496.4
31.4%
385,483.8
36.8%

Generator outages fall into three categories: planned, maintenance, andforced. The MW on outage vary throughout the year. For example, the MW
on planned outage are generally highest in the spring and fall, as shown in
Figure 5-10, due to restrictions on planned outages during the winter andsummer. The effect of the seasonal variation in outages can be seen in themonthly generator performance metrics in Figure 5-14.

Jan-12

Table 5-28 Capacity factor (By unit type (GWh)): January through June, 2020
and 2021145 146

Generator Performance Factors

MW2021, compared to a capacity factor of 52.0 percent in the first six monthsof 2020; all steam units had a capacity factor of 28.4 percent in the first six
months of 2021, compared to 20.1 percent in the first six months of 2020;
coal units had a capacity factor of 31.6 percent in the first six months of 2021,
compared to 22.2 percent in the first six months of 2020.

PlannedIn 2020, planned, maintenance and forced outages were lower than in 2019
(Figure 5-11). The MWh of planned outages were 26 percent lower than in
2019. The MWh of maintenance outages were 7 percent lower than in 2019.
The MWh of forced outages were 20 percent lower than in 2019. In 2021,
planned outages were 15 percent lower, maintenance outages were 9 percent

2021 Quarterly State of the Market Report for PJM: January through June321

2021 Quarterly State of the Market Report for PJM: January through Junehigher, and forced outages were 57 percent higher in the first six months of2021 than in the first six months of 2020.

outages and planned deratings. The EFOF is the proportion of hours in a year
when a unit is unavailable because of forced outages and forced deratings.

Figure 5-11 Outages (MW): Forced, maintenance and planned outages 2018
through June 2021

The PJM aggregate EAF, EFOF, EPOF, and EMOF are shown in Figure 5-12.
Metrics by unit type are shown in Table 5-29.

20,000Figure 5-12 Equivalent outage and availability factors: January through June,2007 to 2021

12,000
8,000

92%

4,000

0
20,000Equivalent Forced Outage Factor

8,000
4,000
0
50,00030,00020,000

8%

76%

4%

72%

0%

2021

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

Mar-21

Planned

Performance factors include the equivalent availability factor (EAF), theequivalent maintenance outage factor (EMOF), the equivalent planned outage
factor (EPOF) and the equivalent forced outage factor (EFOF). These four
factors add to 100 percent for any generating unit. The EAF is the proportionof hours in a year when a unit is available to generate at full capacity while
the three outage factors include all the hours when a unit is unavailable.
The EMOF is the proportion of hours in a year when a unit is unavailable
because of maintenance outages and maintenance deratings. The EPOF is the
proportion of hours in a year when a unit is unavailable because of planned

Section 5 Capacity80%

May-21

Jan-21

Nov-20

Sep-20Jul-20May-20Jan-20Mar-20Nov-19Jul-19Maintenance

12%

2009

Forced

Sep-19

May-19Jan-19Mar-19

Nov-18

Jul-18

Sep-18May-18Jan-18Mar-1810,000

16%

84%

2008

MW

40,000Equivalent Maintenance Outage Factor

Outage factors: Dashed lines

Equivalent availability factor: Solid lineMW

12,000322

Equivalent Planned Outage Factor

88%

16,000020%Equivalent Availability Factor

2007

MW

16,000Jan - Jun

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Table 5-29 EFOF, EPOF, EMOF and EAF by unit type: January through June, 2007 through 2021
Coal
JanJun
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

EFOF EPOF EMOF
EAF
6.3% 12.1% 2.4% 79.2%
7.7% 8.7% 2.5% 81.1%
7.1% 9.4% 3.1% 80.4%
7.5% 10.9% 3.7% 77.9%
8.2% 12.1% 4.0% 75.7%
6.8% 11.0% 7.1% 75.1%
7.2% 13.9% 4.5% 74.3%
10.1% 11.3% 5.2% 73.4%
8.2% 10.9% 3.9% 77.1%
7.5% 11.5% 5.5% 75.5%
9.6% 10.9% 6.5% 73.0%
10.3% 12.9% 5.9% 70.9%
6.8% 10.6% 7.3% 75.2%
4.2% 7.7% 10.1% 77.9%
8.2% 11.0% 9.3% 71.5%

Combined Cycle

Combustion Turbine

EFOF EPOF EMOF
EAF EFOF
1.8% 7.8% 1.6% 88.8% 5.0%
1.7% 7.3% 1.6% 89.4% 3.4%
3.1% 7.1% 3.6% 86.2% 1.5%
2.8% 9.5% 4.1% 83.6% 2.1%
2.5% 10.2% 2.8% 84.5% 1.5%
2.2% 8.7% 2.1% 87.0% 1.9%
1.9% 11.5% 3.1% 83.4% 5.2%
3.2% 12.3% 2.4% 82.1% 10.0%
2.4% 11.5% 2.0% 84.0% 3.3%
3.2% 11.7% 1.9% 83.2% 2.0%
2.1% 11.2% 1.6% 85.1% 1.1%
1.6% 10.9% 1.3% 86.2% 2.0%
1.8% 11.0% 1.7% 85.5% 1.2%
5.5% 7.5% 2.3% 84.7% 5.5%
2.1% 9.8% 2.6% 85.5% 1.7%

EPOF EMOF
EAF EFOF
3.2% 2.6% 89.2% 9.1%
5.6% 2.4% 88.6% 9.2%
3.7% 2.6% 92.3% 6.8%
2.7% 1.8% 93.4% 4.1%
4.0% 1.9% 92.6% 2.4%
3.2% 1.8% 93.1% 3.9%
4.0% 1.5% 89.4% 4.2%
4.5% 1.8% 83.8% 14.8%
5.5% 2.1% 89.2% 9.5%
5.8% 2.3% 89.9% 5.8%
5.3% 2.2% 91.4% 5.5%
5.9% 1.8% 90.4% 5.9%
7.1% 1.9% 89.8% 7.2%
4.0% 1.8% 88.7% 8.4%
6.3% 3.6% 88.4% 7.3%

DieselHydroelectric

EPOF EMOF
EAF EFOF EPOF EMOF
EAF
0.8% 2.3% 87.8% 1.6% 5.9% 2.1% 90.4%
1.8% 1.4% 87.7% 1.5% 6.9% 2.4% 89.3%
0.4% 1.5% 91.4% 2.1% 10.3% 3.1% 84.5%
0.7% 1.0% 94.1% 0.6% 10.5% 2.2% 86.7%
0.0% 2.7% 94.9% 1.1% 13.7% 1.6% 83.6%
0.1% 1.9% 94.1% 3.7% 4.2% 1.6% 90.6%
0.4% 1.7% 93.7% 0.5% 7.5% 2.1% 89.9%
0.8% 2.4% 82.0% 1.9% 11.1% 3.7% 83.3%
0.6% 2.7% 87.2% 2.1% 10.4% 1.6% 86.0%
0.3% 3.5% 90.4% 2.2% 8.0% 3.8% 86.0%
0.3% 2.0% 92.2% 2.3% 6.9% 3.2% 87.7%
1.2% 2.8% 90.1% 2.7% 5.6% 3.4% 88.4%
1.3% 2.7% 88.8% 1.1% 4.7% 4.0% 90.2%
0.2% 2.6% 88.8% 6.1% 2.3% 2.6% 89.0%
0.8% 4.3% 87.6% 10.2% 3.7% 3.3% 82.8%

Nuclear
EFOF
1.2%
1.0%
4.0%
1.3%
2.0%
1.1%
1.1%
1.8%
1.1%
0.9%
0.4%
0.5%
0.5%
2.0%
0.8%

Other

EPOF EMOF
EAF EFOF EPOF EMOF
EAF
5.0% 0.2% 93.5% 6.0% 10.8% 2.4% 80.8%
6.9% 0.5% 91.6% 3.9% 11.9% 3.2% 81.0%
5.6% 0.8% 89.6% 3.9% 11.2% 5.9% 79.0%
6.4% 0.6% 91.7% 3.8% 10.3% 3.1% 82.7%
6.7% 2.0% 89.3% 4.5% 11.4% 2.9% 81.2%
8.2% 0.7% 90.0% 4.5% 11.0% 3.8% 80.8%
6.7% 0.4% 91.8% 7.2% 12.8% 3.6% 76.4%
7.0% 0.8% 90.5% 7.9% 14.7% 5.7% 71.7%
6.0% 1.2% 91.7% 7.2% 20.4% 4.7% 67.7%
6.3% 1.2% 91.6% 3.2% 23.4% 4.0% 69.4%
6.3% 0.7% 92.7% 3.1% 10.6% 4.7% 81.6%
6.5% 0.3% 92.8% 4.0% 11.4% 7.6% 77.0%
6.5% 0.9% 92.2% 3.0% 14.1% 6.8% 76.2%
5.0% 0.7% 92.3% 11.7% 8.4% 4.1% 75.8%
5.8% 1.2% 92.2% 8.4% 8.2% 6.3% 77.1%

Generator Forced Outage Rates
The most fundamental forced outage rate metric is the equivalent demand forced outage rate (EFORd). EFORd is a measure of the probability that a generating
unit will fail, either partially or totally, to perform when it is needed to operate. EFORd measures the forced outage rate during periods of demand, and does notinclude planned or maintenance outages. A period of demand is a period during which a generator is running or needed to run. EFORd calculations use historicalperformance data, including equivalent forced outage hours, service hours, average forced outage duration, average run time, average time between unit starts,
available hours and period hours.147 The EFORd metric includes all forced outages, regardless of the reason for those outages.
The average PJM EFORd in the first six months of 2021 was 6.8 percent, an increase from 5.9 percent in the first six months of 2020. Figure 5-13 shows theaverage EFORd since 1999 for all units in PJM.148

147 Equivalent forced outage hours are the sum of all forced outage hours in which a generating unit is fully inoperable and all partial forced outage hours in which a generating unit is partially inoperable prorated to represent full hours.
148 The universe of units in PJM changed as the PJM footprint expanded and as units retired from and entered PJM markets. See the 2020 State of the Market Report for PJM, Appendix A: “PJM Overview” for details.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June323

2021 Quarterly State of the Market Report for PJM: January through June

Figure 5-13 Trends in the equivalent demand forced outage rate (EFORd): January through June, 1999 through 2021
14%

12%

10%

8%

6%

4%

Jan-Jun

2021

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

2009

2008

2007

2006

2005

2004

2003

2002

2001

2000

0%

1999

2%

AnnualTable 5-30 shows the class average EFORd by unit type.
Table 5-30 EFORd by unit type: January through June, 2007 through 2021
Coal
Combined Cycle
Combustion Turbine
DieselHydroelectric
Nuclear
Other
Total

324

2007
7.7%
4.0%
17.9%
10.6%
2.2%
1.3%
11.4%
7.6%

Section 5 Capacity

2008
8.9%
3.6%
15.0%
10.0%
2.2%
1.1%
10.5%
7.5%

2009
8.8%
5.3%
10.5%
8.5%
2.5%
4.0%
10.1%
7.6%

2010
9.3%
4.5%
15.6%
5.8%
1.0%
1.5%
7.4%
7.7%

2011
10.5%
3.6%
9.3%
6.2%
1.5%
2.3%
10.5%
7.6%

2012
10.0%
2.9%
8.8%
5.1%
5.2%
1.3%
8.5%
7.0%

2013
9.7%
2.8%
14.6%
4.4%
0.8%
1.3%
13.0%
7.9%

Jan-Jun
2014
13.0%
5.6%
23.9%
15.9%
3.2%
2.2%
16.3%
11.5%

2015
10.0%
3.3%
14.0%
10.8%
2.6%
1.2%
14.5%
8.0%

2016
9.4%
4.5%
7.5%
7.6%
3.2%
1.1%
7.2%
6.1%

2017
12.2%
2.8%
6.8%
6.3%
3.2%
0.4%
13.9%
7.1%

2018
13.4%
2.8%
8.9%
6.2%
3.6%
0.6%
11.1%
7.5%

2019
9.7%
2.6%
6.3%
8.0%
1.4%
0.6%
8.4%
5.5%

2020
7.2%
5.5%
5.5%
8.4%
6.1%
2.0%
11.7%
5.9%

2021
11.5%
2.9%
4.9%
8.4%
11.6%
0.9%
16.7%
6.8%

© 2021 Monitoring Analytics, LLC

Section 5 Capacity

Other Forced Outage Rate Metrics
Under the capacity performance modifications to RPM, effective with the 2018/2019 Delivery Year, neither XEFORd nor EFORp are relevant.

Forced Outage Analysis
The MMU analyzed the causes of forced outages for the entire PJM system. The metric used was lost generation, which is the product of the duration of theoutage and the size of the outage reduction. Lost generation can be converted into lost system equivalent availability.149 On a system wide basis, the resultant
lost equivalent availability from the forced outages is equal to the equivalent forced outage factor (EFOF).
PJM EFOF was 4.4 percent in the first six months of 2021. This means there was 4.4 percent lost availability because of forced outages. Table 5-31 shows thatforced outages for boiler tube leaks, at 13.2 percent of the systemwide EFOF, were the second largest single contributor to EFOF.
Table 5-31 Contribution to EFOF by unit type by cause: January through June, 2021
Generator
Boiler Tube Leaks
TurbineFeedwater System
Controls
Electrical
Miscellaneous (Steam Turbine)
Boiler Air and Gas Systems
Condensing System
Economic
Unit TestingHigh Pressure Turbine
Auxiliary Systems
ValvesMiscellaneous (Generator)
Fuel Quality
Boiler Piping System
Boiler Fuel Supply from Bunkers to Boiler
Slag and Ash Removal
All Other Causes
Total

Coal
19.0%
20.0%
0.0%
12.6%
0.5%
8.0%
4.2%
5.2%
3.1%
0.2%
0.9%
3.3%
1.0%
2.8%
2.1%
2.3%
1.9%
1.7%
0.7%
10.4%
100.0%

Combined Combustion
Cycle
Turbine
34.8%
4.6%
5.2%
0.0%
1.6%
16.9%
1.5%
0.0%
3.6%
1.2%
1.6%
15.5%
12.7%
0.0%
0.0%
0.0%
2.1%
0.0%
2.7%
3.3%
1.3%
20.8%
0.2%
0.0%
8.6%
10.9%
0.5%
0.0%
0.1%
1.0%
0.2%
0.0%
1.9%
0.0%
0.2%
0.0%
0.0%
0.0%
21.1%
26.0%
100.0%
100.0%

Diesel Hydroelectric
9.4%
1.7%
0.0%
0.0%
0.0%
90.7%
0.0%
0.0%
6.4%
0.1%
2.6%
0.2%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
2.3%
1.6%
24.8%
3.5%
0.0%
0.0%
0.0%
0.3%
0.0%
0.0%
1.2%
0.0%
10.4%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
42.8%
1.8%
100.0%
100.0%

Nuclear
0.0%
0.0%
0.0%
8.7%
0.0%
0.0%
0.0%
0.0%
30.7%
0.0%
0.0%
0.0%
0.0%
0.8%
5.3%
0.0%
0.0%
0.0%
0.0%
54.5%
100.0%

Other
0.2%
3.4%
0.0%
0.2%
50.8%
0.3%
2.5%
0.3%
0.3%
18.7%
1.7%
0.0%
0.3%
0.4%
0.1%
0.3%
0.2%
0.7%
4.8%
14.8%
100.0%

System
15.1%
13.2%
8.6%
8.2%
7.1%
6.0%
3.9%
3.2%
3.2%
3.0%
2.4%
2.1%
2.0%
1.8%
1.6%
1.5%
1.3%
1.2%
1.0%
13.6%
100.0%

149 For any unit, lost generation can be converted to lost equivalent availability by dividing lost generation by the product of the generating units’ capacity and period hours. This can also be done on a systemwide basis.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June325

2021 Quarterly State of the Market Report for PJM: January through June

Performance by Month
On a monthly basis, unit availability as measured by the equivalent availability factor is shown in Figure 5-14.
Figure 5-14 Monthly generator performance factors: January through June, 2021
100%

40%
Equivalent Availability Factor
Equivalent Forced Outage Factor
Equivalent Planned Outage Factor
Equivalent Maintenance Outage Factor

35%

90%

30%

85%

25%

80%

20%

75%

15%

70%

10%

65%

5%

60%

326

Jan

Feb

Mar

Section 5 Capacity

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Outage factors: Dashed lines

Equivalent availability factor: Solid line

95%

0%

© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

Demand Response
Markets require both a supply side and a demand side to function effectively.
The demand side of wholesale electricity markets is underdeveloped. Wholesale
power markets will be more efficient when the demand side of the electricity
market becomes fully functional without depending on special programs as aproxy for full participation.

Overview• Demand Response Activity. Demand response activity includes economic

demand response (economic resources), emergency and pre-emergency
demand response (demand resources), synchronized reserves andregulation. Economic demand response participates in the energy
market. Emergency and pre-emergency demand response participatesin the capacity market and energy market.1 Demand response resources
participate in the synchronized reserve market. Demand response
resources participate in the regulation market.
Total demand response revenue increased by $9.7 million, 5.2 percent,from $185.1 million in the first six months of 2020 to $194.8 million
in the first six months of 2021. Emergency demand response revenue
accounted for 98.4 percent of all demand response revenue, economic
demand response for 0.1 percent, demand response in the synchronizedreserve market for 1.2 percent and demand response in the regulation
market for 0.4 percent.
Total emergency demand response revenue increased by $7.8 million, 4.2
percent, from $183.8 million in the first six months of 2020 to $191.6
million in the first six months of 2021.2
Economic demand response revenue increased by $0.2 million, 327.7
percent, from $0.06 million in the first six months of 2020 to $0.2
million in the first six months of 2021.3 Demand response revenue in thesynchronized reserve market increased by $1.7 million, 282.7 percent,1 Emergency demand response refers to both emergency and pre-emergency demand response. With the implementation of the Capacity
Performance design, there is no functional difference between the emergency and pre-emergency demand response resource.
2 The total credits and MWh numbers for demand resources were calculated as of July 26, 2021 and may change as a result of continued
PJM billing updates.
3 Economic credits are synonymous with revenue received for reductions under the economic load response program.

© 2021 Monitoring Analytics, LLC

from $0.6 million in the first six months of 2020 to $2.3 million in thefirst six months of 2021. Demand response revenue in the regulation
market increased by $0.1 million, 9.5 percent, from $0.6 million in thefirst six months of 2020 to $0.7 million in the first six months of 2021.

• Demand Response Energy Payments are Uplift. Energy payments toemergency and economic demand response resources are uplift. LMP does
not cover energy payments although emergency and economic demand
response can and does set LMP. Energy payments to emergency demand
resources are paid by PJM market participants in proportion to their net
purchases in the real-time market. Energy payments to economic demand
resources are paid by real-time exports from PJM and real-time loads ineach zone for which the load-weighted, average real-time LMP for thehour during which the reduction occurred is greater than or equal to thenet benefits test price for that month.4• Demand Response Market Concentration. The ownership of economic

load response resources was highly concentrated in 2020 and the firstsix months of 2021. The HHI for economic resource reductions decreasedby 399 points from 9065 for 2020 to 8667 in the first six months of2021. The ownership of emergency load response resources was highly
concentrated in 2020. The HHI for emergency load response committed
MW was 2523 for the 2020/2021 Delivery Year. In the 2020/2021 Delivery
Year, the four largest CSPs owned 88.4 percent of all committed demand
response UCAP MW. The HHI for emergency demand response committed
MW is 2584 for the 2021/2022 Delivery Year. In the 2021/2022 Delivery
Year, the four largest CSPs own 89.0 percent of all committed demand
response UCAP MW.

• Limited Locational Dispatch of Demand Resources. With full implementationof the Capacity Performance rules in the capacity market in the 2020/2021
Delivery Year, PJM should be able to individually dispatch any capacity
performance resource, including demand resources. But PJM cannot
dispatch demand resources by node with the current rules because
demand resources are not registered to a node. Demand resources canbe dispatched by subzone only if the subzone is defined before dispatch.

4 “PJM Manual 28: Operating Agreement Accounting,” § 11.2.2, Rev. 84 (Dec. 17, 2020).

2021 Quarterly State of the Market Report for PJM: January through June 327

2021 Quarterly State of the Market Report for PJM: January through June

Aggregation rules allow a demand resource that incorporates many small
end use customers to span an entire zone, which is inconsistent withnodal dispatch.

Recommendations• The MMU recommends, as a preferred alternative to including demand

resources as supply in the capacity market, that demand resources be on
the demand side of the markets, that customers be able to avoid capacityand energy charges by not using capacity and energy at their discretion,that customer payments be determined only by metered load, and thatPJM forecasts immediately incorporate the impacts of demand side
behavior. (Priority: High. First reported 2014. Status: Not adopted.)• The MMU recommends that the option to specify a minimum dispatch price(strike price) for demand resources be eliminated and that participating
resources receive the hourly real-time LMP less any generation componentof their retail rate. (Priority: Medium. First reported 2010. Status: Not
adopted.)• The MMU recommends that the maximum offer for demand resources• The MMU recommends that demand resources be required to provide

their nodal location, comparable to generation resources. (Priority: High.
First reported 2011. Status: Not adopted.)• The MMU recommends that PJM require nodal dispatch of demand
resources with no advance notice required or, if nodal location is not
required, subzonal dispatch of demand resources with no advance noticerequired. (Priority: High. First reported 2015. Status: Not adopted.)• The MMU recommends that PJM not remove any defined subzones andmaintain a public record of all created and removed subzones. (Priority:
Low. First reported 2016. Status: Not adopted.)• The MMU recommends that PJM eliminate the measurement ofcompliance across zones within a compliance aggregation area (CAA).
The multiple zone approach is less locational than the zonal and subzonal
approach and creates larger mismatches between the locational need forthe resources and the actual response. (Priority: High. First reported 2015.
Status: Not adopted.)be the same as the maximum offer for generation resources. (Priority:
Medium. First reported 2013. Status: Not adopted.)• The MMU recommends that measurement and verification methods forresources, responding to economic price signals like other capacity
resources. The MMU recommends that demand resources not be treatedas emergency resources, not trigger a PJM emergency and not trigger
a Performance Assessment Interval. (Priority: High. First reported 2012.
Status: Not adopted.)• The MMU recommends that compliance rules be revised to include• The MMU recommends that the demand resources be treated as economic• The MMU recommends that the Emergency Program Energy Only option

be eliminated because the opportunity to receive the appropriate energy
market incentive is already provided in the economic program. (Priority:
Low. First reported 2010. Status: Not adopted.)• The MMU recommends that, if demand resources remain in the capacity

market, a daily energy market must offer requirement apply to demand

328

resources, comparable to the rule applicable to generation capacity
resources.5 (Priority: High. First reported 2013. Status: Not adopted.)

Section 6 Demand Responsedemand resources be modified to reflect compliance more accurately.
(Priority: Medium. First reported 2009. Status: Not adopted.)

submittal of all necessary hourly load data, and that negative values
be included when calculating event compliance across hours andregistrations. (Priority: Medium. First reported 2012. Status: Not adopted.)• The MMU recommends that PJM adopt the ISO-NE five-minute metering

requirements in order to ensure that operators have the necessary
information for reliability and that market payments to demand resources
be calculated based on interval meter data at the site of the demand
reductions.6 (Priority: Medium. First reported 2013. Status: Not adopted.)

5 See “Complaint and Motion to Consolidate of the Independent Market Monitor for PJM,” Docket No. EL14-20-000 (January 27, 2014) at
1.
6 See ISO-NE Tariff, Section III, Market Rule 1, Appendix E1 and Appendix E2, “Demand Response,” <http://www.iso-ne.com/regulatory/
tariff/sect_3/mr1_append-e.pdf>. (Accessed October 17, 2017) ISO-NE requires that DR have an interval meter with five-minute datareported to the ISO and each behind the meter generator is required to have a separate interval meter. After June 1, 2017, demand
response resources in ISO-NE must also be registered at a single node.

© 2021 Monitoring Analytics, LLC

Section 6 Demand Response• The MMU recommends demand response event compliance be calculated

on a five minute basis for all capacity performance resources and that thepenalty structure reflect five minute compliance. (Priority: Medium. First
reported 2013. Status: Partially adopted.)• The MMU recommends that load management testing be initiated by PJM

with limited warning to CSPs in order to more accurately represent theconditions of an emergency event. (Priority: Low. First reported 2012.
Status: Not adopted.)• The MMU recommends that shutdown cost be defined as the cost to curtailload for a given period that does not vary with the measured reduction or,
for behind the meter generators, be the start cost defined in Manual 15
for generators. (Priority: Low. First reported 2012. Status: Not adopted.)• The MMU recommends that the Net Benefits Test be eliminated and thatdemand response resources be paid LMP less any generation componentof the applicable retail rate. (Priority: Low. First reported 2015. Status:
Not adopted.)• The MMU recommends that the tariff rules for demand response clarify
that a resource and its CSP, if any, must notify PJM of material changes
affecting the capability of the resource to perform as registered and mustterminate or modify registrations that are no longer capable of responding
to PJM dispatch directives at defined levels because load has been reduced
or eliminated, as in the case of bankrupt and/or out of service facilities.
(Priority: Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that there be only one demand response productin the capacity market, with an obligation to respond when called forany hour of the delivery year. (Priority: High. First reported 2011. Status:
Partially adopted.7)• The MMU recommends that the lead times for demand resources be
shortened to 30 minutes with an hour minimum dispatch for all resources.
(Priority: Medium. First reported 2013. Status: Partially adopted.)• The MMU recommends setting the baseline for measuring capacity

compliance under winter compliance at the customers’ PLC, similar

to GLD, to avoid double counting. (Priority: High. First reported 2010.
Status: Partially adopted.)• The MMU recommends the Relative Root Mean Squared Test be required
for all demand resources with a CBL. (Priority: Low. First reported 2017.
Status: Partially adopted.)• The MMU recommends that PRD be required to respond during a PAI to
be consistent with all CP resources. (Priority: High. First reported 2017.
Status: Not adopted.)• The MMU recommends that the limits imposed on the pre-emergency andemergency demand response share of the synchronized reserve market beeliminated. (Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that 30 minute pre-emergency and emergency
demand response be considered to be 30 minute reserves. (Priority:
Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that energy efficiency MW not be included in the

PJM Capacity Market and that PJM should ensure that the impact of EE
measures on the load forecast is incorporated immediately rather thanwith the existing lag. (Priority: Medium. First reported 2018. Status: Not
adopted.)• The MMU recommends that demand reductions based entirely on behindthe meter generation be capped at the lower of economic maximum or
actual generation output. (Priority: High. First reported 2019. Status: Not
adopted.)• The MMU recommends that all demand resources register as PreEmergency Load Response and that the Emergency Load Response
Program be eliminated. (Priority: High. First reported Q1 2020. Status:
Not adopted.)Conclusion
A fully functional demand side of the electricity market means that end use
customers or their designated intermediaries will have the ability to see realtime energy price signals in real time, will have the ability to react to real-

7 PJM’s Capacity Performance design requires resources to respond when called for any hour of the delivery year, but demand resources
still have a limited mandatory compliance window.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 329

2021 Quarterly State of the Market Report for PJM: January through Junetime prices in real time and will have the ability to receive the direct benefits
or costs of changes in real-time energy use. In addition, customers or theirdesignated intermediaries will have the ability to see current capacity prices,
will have the ability to react to capacity prices and will have the ability toreceive the direct benefits or costs of changes in the demand for capacity inthe same year in which demand for capacity changes. A functional demandside of these markets means that customers will have the ability to makedecisions about levels of power consumption based both on how customers
value the power and on the actual cost of that power.
In the energy market, if there is to be a demand side program, demand
resources should be paid the value of energy, which is LMP less any generation
component of the applicable retail rate. There is no reason to have the net
benefits test. The necessity for the net benefits test is an illustration of theillogical approach to demand side compensation embodied in paying full
LMP to demand resources. The benefit of demand side resources is not thatthey suppress market prices, but that customers can choose not to consume
at the current price of power, that individual customers benefit from theirchoices and that the choices of all customers are reflected in market prices.
If customers face the market price, customers should have the ability to notpurchase power and the market impact of that choice does not require a test
for appropriateness.
If demand resources are to continue competing directly with generation
capacity resources in the PJM Capacity Market, the product must be definedsuch that it can actually serve as a substitute for generation. This is aprerequisite to a functional market design. Demand resources do not have amust offer requirement into the day-ahead energy market, are able to offer
above $1,000 per MWh without providing a fuel cost policy, or any rationale
for the offer. PJM automatically, and inappropriately, triggers a PAI when
demand resources are dispatched and demand resources do not have telemetry
requirements similar to other Capacity Performance resources.
In order to be a substitute for generation, demand resources should be definedin PJM rules as an economic resource, as generation is defined. Demand

330

Section 6 Demand Response

resources should be required to offer in the day-ahead energy market andshould be called when the resources are required and prior to the declarationof an emergency. Demand resources should be available for every hour of
the year. The fact that PJM currently defines demand resources as emergency
resources and the fact that calling on demand resources triggers a performanceassessment interval (PAI) under the Capacity Performance design, both serve
as a significant disincentive to calling on demand resources and meanthat demand resources are underused. Demand resources should be treatedas economic resources like any other capacity resource. Demand resources
should be called when economic and paid the LMP rather than an inflated
strike price up to $1,849 per MWh that is set by the seller.
In order to be a substitute for generation, demand resources (DR) should be
subject to robust measurement and verification techniques to ensure thattransitional DR programs incent the desired behavior. The methods used in
PJM programs today are not adequate to determine and quantify deliberateactions taken to reduce consumption.
In order to be a substitute for generation, demand resources should provide a
nodal location and should be dispatched nodally to enhance the effectivenessof demand resources and to permit the efficient functioning of the energy
market. Both subzonal and multi-zone compliance should be eliminatedbecause they are inconsistent with an efficient nodal market.
In order to be a substitute for generation, compliance by demand resources
with PJM dispatch instructions should include both increases and decreases
in load. The current method applied by PJM simply ignores increases in load
and thus artificially overstates compliance.
In order to be a substitute for generation, reductions should be calculated
hourly for dispatched DR. The current rules use the average reduction forthe duration of an event. The average reduction across multiple hours does
not provide an accurate metric for each hour of the event and is inconsistent
with the measurement of generation resources. Measuring compliance hourly
would provide accurate information to the PJM system. Under the new CP© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

rules, the performance of demand response during Performance Assessment
Interval (PAI) will be measured on a five-minute basis.
In order to be a substitute for generation, any demand resource and its
Curtailment Service Provider (CSP), should be required to notify PJM
of material changes affecting the capability of the resource to perform as
registered and to terminate or modify registrations that are no longer capableof responding to PJM dispatch directives at the specified level, such as in
the case of bankrupt and out of service facilities. Generation resources are
required to inform PJM of any change in availability status, including outages
and shutdown status.
As a preferred alternative to being a substitute for generation in the capacityand energy markets, demand response resources should be on the demand sideof the capacity market rather than on the supply side. Rather than detailed
demand response programs with their attendant complex and difficult toadminister rules, customers would be able to avoid capacity and energy
charges by not using capacity and energy at their discretion and the level ofusage paid for would be defined by metered usage rather than a complex andinaccurate measurement protocol.
The MMU peak shaving proposal at the Summer-Only Demand Response
Senior Task Force (SODRSTF) is an example of how to create a demand sideproduct that is on the demand side of the market and not on the supply
side.8 The MMU proposal was based on the BGE load forecasting program
and the Pennsylvania Act 129 Utility Program.9 10 Under the MMU proposal,
participating load would inform PJM prior to an RPM auction of the MW
participating, the months and hours of participation and the temperaturehumidity index (THI) threshold at which load would be reduced. PJM would
reduce the load forecast used in the RPM auction based on the designatedreductions. Load would agree to curtail demand to at or below a defined FSL,
less than the customer PLC, when the THI exceeds a defined level or load
8 See the MMU package within the SODRSTF Matrix, <http://www.pjm.com/-/media/‌committees-groups/task-forces/
sodrstf/20180802/20180802-item-04-sodrstf-matrix.ashx>.
9 Advance signals that can be used to foresee demand response days, BGE, <https://www.pjm.com/-/media/committees-groups/taskforces/sodrstf/20180309/20180309-item-05-bge-load-curtailment-programs.ashx> (Accessed March 6, 2019).
10 Pennsylvania ACT 129 Utility Program, CPower, <https://www.pjm.com/-/media/committees-groups/task-forces/
sodrstf/20180413/20180413-item-03-pa-act-129-program.ashx> (Accessed March 6, 2019).

© 2021 Monitoring Analytics, LLC

exceeds a specified threshold. By relying on metered load and the PLC, load
can reduce its demand for capacity and that reduction can be verified withoutcomplicated and inaccurate metrics to estimate load reductions. Under PJM’s
weakened version of the program, performance will be measured under thecurrent economic demand response CBL rules which means relying on load
estimates rather than actual metered load.11 PJM’s proposal includes only a
THI curtailment trigger and not an overall load curtailment trigger.
The long term appropriate end state for demand resources in the PJM markets
should be comparable to the demand side of any market. Customers should
use energy as they wish, accounting for market prices in any way they like,and that usage will determine the amount of capacity and energy for which
each customer pays. There would be no counterfactual measurement andverification.
Under this approach, customers that wish to avoid capacity payments would
reduce their load during expected high load hours. Capacity costs would be
assigned to LSEs and by LSEs to customers, based on actual load on the system
during these critical hours. Customers wishing to avoid high energy prices
would reduce their load during high price hours. Customers would pay forwhat they actually use, as measured by meters, rather than relying on flawedmeasurement and verification methods. No measurement and verification
estimates are required. No promises of future reductions which can only beverified by inaccurate and biased measurement and verification methods are
required. To the extent that customers enter into contracts with CSPs or LSEs
to manage their payments, measurement and verification can be negotiated aspart of a bilateral commercial contract between a customer and its CSP or LSE.
But the system would be paid for actual, metered usage, regardless of which
contractual party takes that obligation.
This approach provides more flexibility to customers to limit usage at theirdiscretion. There is no requirement to be available year round or every hour of
every day. There is no 30 minute notice requirement. There is no requirement
to offer energy into the day-ahead market. All decisions about interrupting
11 The PJM proposal from the SODRSTF weakened the proposal but was approved at the October 25, 2018 Members Committee meeting and
PJM filed Tariff changes on December 7, 2018. See “Peak Shaving Adjustment Proposal,” Docket No. ER19-511-000 (December 7, 2018).

2021 Quarterly State of the Market Report for PJM: January through June 331

2021 Quarterly State of the Market Report for PJM: January through June

are up to the customers only and they may enter into bilateral commercial
arrangements with CSPs at their sole discretion. Customers would pay forcapacity and energy depending solely on metered load.
A transition to this end state should be defined in order to ensure thatappropriate levels of demand side response are incorporated in PJM’s load
forecasts and thus in the demand curve in the capacity market. That transition
should be defined by the PRD rules, modified as proposed by the MMU.
This approach would work under the CP design in the capacity market. Thisapproach is entirely consistent with the Supreme Court decision in EPSA as it
does not depend on whether FERC has jurisdiction over the demand side.12 Thisapproach will allow FERC to more fully realize its overriding policy objective
to create competitive and efficient wholesale energy markets. The decisionof the Supreme Court addressed jurisdictional issues and did not address the
merits of FERC’s approach. The Supreme Court’s decision has removed theuncertainty surrounding the jurisdictional issues and created the opportunity
for FERC to revisit its approach to demand side.

FERC Order No. 719 required PJM and other RTOs to amend their market
rules to accept bids from aggregators of retail customers of utilities unlessthe laws or regulations of the relevant electric retail regulatory authority(“RERRA”) do not permit the customers aggregated in the bid to participate.14
PJM implemented rules that require PJM to verify with EDCs that no law
or regulation of a RERRA prohibits end use customers’ participation.15 EDCs
and their end use customers are categorized as small and large based onwhether the EDC distributed more or less than 4 million MWh in the previous
fiscal year. End use customers within a large EDC must provide verificationof any other contractual obligations or laws or regulations that prohibit
participation, but end use customers within a small EDC do not need toprovide additional verification.16 RERRAs have permitted EDCs, in a numberof cases, to participate in the PJM Economic Load Response Program.

PJM Demand Response Programs
All PJM demand response programs can be grouped into economic, emergency
and pre-emergency programs, or Price Responsive Demand (PRD). Table 6-1
provides an overview of the key features of PJM demand response programs.
Demand response activity includes economic demand response (economic
resources), emergency and pre-emergency demand response (demand
resources), synchronized reserves and regulation. Economic demand response
participates in the energy market. Emergency and pre-emergency demand
response participate in the capacity market and energy market.13 Demand
response resources participate in the synchronized reserve market. Demand
response resources participate in the regulation market.

12 577 U.S. 260 (2016).
13 Emergency demand response refers to both emergency and pre-emergency demand response. With the implementation of the Capacity
Performance design, there is no functional difference between the emergency and pre-emergency demand response resource.

332

Section 6 Demand Response

14 Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 154 (2008), order on
reh’g, Order No. 719-A, FERC Stats. & Regs. ¶ 31,292, order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009).
15 The evidence supplied by LDCs must take the form of an order, resolution or ordinance of the RERRA, an opinion of the RERRA’s legal
counsel attesting to existence of an order, resolution, or ordinance, or an opinion of the state attorney general on behalf of the RERRA
attesting to existence of an order, resolution or ordinance.
16 PJM Operating Agreement Schedule 1 § 1.5A.3.1.

© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

Table 6-1 Overview of demand response programs
Emergency and Pre-Emergency Load Response Program
Load Management (LM)
Limited, Annual, Base, Capacity
Limited, Annual, Base, Capacity
Performance, Summer-Period Capacity
Performance,Summer-Period Capacity
Performance
Performance
OATT Attachmend DD § 5.5A
OATT Attachmend DD § 5.5A

Product Types

MarketCapacity Market
Dispatch Requirement
Capacity Payments
Capacity Measurement andVerification
CBL

Capacity Only
OATT Attachemnt K § 8.1
DR cleared in RPM
Mandatory Curtailment
Capacity payments based on RPM clearing
price
Firm Service Level
Guaranteed Load DropNA

Energy Payments

Penalties

Associate Manuals

No energy payment

RPM event
OATT Attachment DD § 10A
RAA Schedule 6.K
Test compliance penalties
OATT Attachment DD § 11A
Manual 18

Full Program Option(Capacity and Energy)
OATT Attachemnt K § 8.1
DR cleared in RPM
Mandatory Curtailment
Capacity payments based on RPM clearing
price
Firm Service Level
Guaranteed Load Drop
Yes, as described
OATT Attachment K § 3.3A
Energy payment based on submitted
higher of “minimum dispatch price” andLMP. Energy payment during PJM declared
Emergency Event mandatory curtailments.
RPM event
OATT Attachment DD § 10A
RAA Schedule 6.K
Test compliance penalties
OATT Attachment DD § 11A
Manual 11
Manual 18

Economic Load Response Program
Economic Demand Response
OATT Attachment K § 1.5A

Price Responsive Demand

Energy Only
OATT Attachemnt K § 8.1

Energy Only

Capacity Only

Not included in RPM
Voluntary Curtailment
NA

Not included in RPM
Dispatched Curtailment
NA

NA

NA

PRD cleared in RPM
Price Threshold
LSE PRD Credit
RAA Schedule 6.1.G
Firm Service Level

Yes, as described
OATT Attachment K § 3.3A
Energy payment based on submitted
higher of “minimum dispatch price”
and LMP. Energy payment only forvoluntary curtailments.
NA

Yes, as described
OATT Attachment K § 3.3A
Energy payment based on full
LMP. Energy payment for hours ofdispatched curtailment.
OATT Attachment K § 3.3A
NA

Manual 11
Manual 18

Manual 11

NANA

RPM eventRAA Schedule 6.1.G
Test compliance penalties
RAA Schedule 6.1.L
Manual 18

Non-PJM Demand Response Programs
Within the PJM footprint, states may have additional demand response programs as part of a Renewable Portfolio Standard (RPS) or a separate program. Indiana,
Ohio, Pennsylvania and North Carolina include demand response in their RPS. If demand response is dispatched by a state run program, the demand response
resources are ineligible to receive payments from PJM during the state dispatch.

PJM Demand Response Programs
Figure 6-1 shows all revenue from PJM demand response programs by market for January through June beginning with 2008. Since the implementation of
the RPM Capacity Market on June 1, 2007, the capacity market (demand resources) has been the primary source of demand response revenue.17 In the first six
months of 2021, total demand response revenue increased by $9.7 million, 5.2 percent, from $185.1 million in the first six months of 2020 to $194.8 million in
the first six months of 2021. Total emergency demand response revenue increased by $7.8 million, 4.2 percent, from $183.8 million in the first six months of 2020
17 This includes both capacity market revenue and emergency energy revenue for capacity resources.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 333

2021 Quarterly State of the Market Report for PJM: January through June

Economic demand response revenue increased by $0.2 million, 327.7 percent,from $0.06 million in the first six months of 2020 to $0.2 million in thefirst six months of 2021.19 Demand response revenue in the synchronizedreserve market increased by $1.7 million, 282.7 percent, from $0.6 million in
the first six months of 2020 to $2.3 million in the first six months of 2021.
Demand response revenue in the regulation market increased by $0.1 million,
9.5 percent, from $0.6 million in the first six months of 2020 to $0.7 million
in the first six months of 2021.
Higher demand resource revenues were in part a result of higher capacity
market prices in the 2020/2021 RPM and 2021/2022 RPM auctions comparedto capacity market prices in 2019/2020.

Figure 6-1 Demand response revenue by market: January through June, 2008
to 2021$450
Regulation$400

Synchronized Reserve
Energy Economic
Energy Emergency$350

Capacity$300$250
Millions ($)

to $191.6 million in the first six months of 2021. This decrease consisted of
capacity market revenue.18 In the first six months of 2021, emergency demand
response revenue, which includes capacity and emergency energy revenue,
accounted for 98.4 percent of all revenue received by demand response
providers, the economic program for 0.1 percent, synchronized reserve for 1.2
percent and the regulation market for 0.4 percent.

$200
$150
$100
$50
$0

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

Emergency and Pre-Emergency Load Response
Programs
Demand resources participate in the capacity market within the Emergency
and Pre-Emergency Load Response Programs.

18 The total credits and MWh for demand resources were calculated as of July 25, 2021 and may change as a result of continued PJM billing
updates.
19 Economic credits are synonymous with revenue received for reductions under the economic load response program.

334

Section 6 Demand Response

All demand resources must register as pre-emergency unless the participant
relies on behind the meter generation and the resource has environmental
restrictions that limit the resource’s ability to operate only in emergency
conditions.20 Under current rules, PJM will declare an emergency if preemergency or emergency demand response is dispatched. In all demand
response programs, CSPs are companies that sign up customers that have the
20 OA Schedule 1 § 8.5.

© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

ability to reduce load. CSPs satsify cleared RPM commitments registerting
customers as Nominated MW. After a demand response event occurs, PJM
compensates CSPs for their participants’ load reductions and CSPs in turncompensate their participants. Only CSPs are eligible to participate in the PJM
demand response programs, but a participant can register as a PJM special
member and become a CSP without any additional cost.
The emergency and pre-emergency load response programs consist of the baseand capacity performance demand response products. Full implementation of
the Capacity Performance design in the 2020/2021 Delivery Year requires all
emergency or pre-emergency demand resources to be registered as annual
capacity resources. Summer period demand response resources are allowed
to aggregate with winter period capacity resources to fulfill the annual
requirement of the CP design.21
All capacity resources must respond during a Performance Assessment
Interval (PAI). Demand resources are the only capacity performance resourcethat create a PAI when dispatched by PJM. PJM eliminated any substantive
difference between pre-emergency and emergency by making the dispatch ofeither type trigger a PAI.
The rules applied to demand resources in the current market design do not treat
demand resources in a manner comparable to generation capacity resources,even though demand resources are sold in the same capacity market, aretreated as a substitute for other capacity resources and displace other capacity
resources in RPM auctions. PJM will not measure compliance for DR, and theresources will not face penalties, in a PAI unless the product type and leadtime type are dispatched by PJM. PJM will not measure compliance for DR,
and the resources will not face penalties, in a PAI if the area dispatched is nota defined subzone or control zone. Demand resources are not required to meetthe same requirements as other capacity resources for the PAI.

21 Summer period demand response must be available for June through October and the following May between 10:00AM and 10:00PM.
See PJM OATT RAA Article 1.

© 2021 Monitoring Analytics, LLC

Demand resources are also not required to meet the same must offer
requirements a other capacity resources. All other capacity resources must
offer daily into the day-ahead energy market.
The MMU recommends that if demand resources remain on the supply sideof the capacity market, a daily must offer requirement in the day-aheadenergy market apply to demand resources, comparable to the rule applicableto generation capacity resources. This will help to ensure comparability andconsistency for demand resources.
The MMU recommends that the option to specify a minimum dispatch priceunder the Emergency and Pre-Emergency Program Full option be eliminatedand that participating resources receive the hourly real-time LMP less any
generation component of their retail rate.22

Market Structure
The HHI for demand resources showed that ownership was highly concentrated
for the 2020/2021 Delivery Year, with an HHI value of 2523. In the 2020/2021
Delivery Year, the four largest companies contributed 88.4 percent of allcommitted demand resources UCAP MW. The HHI for demand resourcesshows that ownership is highly concentrated for the 2021/2022 Delivery Year,with an HHI value of 2584. In the 2021/2022 Delivery Year, the four largest
companies own 89.0 percent of all committed demand response UCAP MW.
Table 6-2 shows the HHI value for committed UCAP MW by LDA by delivery
year. The HHI values are calculated by the committed UCAP MW in eachdelivery year for demand resources.

22 See “Complaint and Motion to Consolidate of the Independent Market Monitor for PJM,” Docket No. EL14-20-000 (January 28, 2014),“Comments of the Independent Market Monitor for PJM,” Docket No. ER15-852-000 (February 13, 2015).

2021 Quarterly State of the Market Report for PJM: January through June 335

2021 Quarterly State of the Market Report for PJM: January through June

Table 6-2 HHI value for committed UCAP MW by LDA by delivery year:
2020/2021 and 2021/2022 Delivery Years23
Delivery Year
2020/2021

2021/2022

LDA
ATSI
ATSI-CLEVELAND
BGE
COMED
DAY
DEOK
DPL-SOUTH
EMAAC
MAAC
PEPCO
PPL
PS-NORTH
PSEG
RTO
ATSI
ATSI-CLEVELAND
BGE
COMED
DAY
DEOK
DPL-SOUTH
EMAAC
MAAC
PEPCO
PPL
PS-NORTH
PSEG
RTO

Committed
UCAP MW
719.8
231.9
249.5
1,657.3
241.5
184.7
72.6
757.3
557.8
236.3
616.6
152.7
186.3
3,581.4
924.0
272.8
279.0
2,073.7
227.7
220.5
66.3
904.7
750.0
345.9
697.7
188.6
221.9
4,254.9

HHI Value HHI Concentration
2488
High
4438
High
2344
High
2819
High
3648
High
3727
High
3807
High
2676
High
2905
High
2921
High
2694
High
3213
High
2501
High
2681
High
2873
High
5910
High
2363
High
2769
High
3042
High
2167
High
5289
High
2365
High
2539
High
2625
High
2747
High
3641
High
2412
High
2874
High

Table 6-3 Cleared Demand Resource UCAP MW: 2007/2008 through2021/2022 Delivery Years
2007/2008
2008/20092009/20102010/20112011/20122012/20132013/20142014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021
2021/2022

UCAP (MW)DR RPM Cleared
Total RPM Cleared
127.6
129,409.2
559.4
130,629.8
892.9
134,030.2
962.9
134,036.2
1,826.6
134,139.6
8,740.9
141,061.8
10,779.6
159,830.5
14,943.0
161,092.4
15,453.7
173,487.4
13,265.3
179,749.0
11,870.5
180,590.3
11,435.4
175,957.4
10,703.1
177,040.6
9,445.7
173,688.5
11,427.7
174,713.0

DR Percent Cleared
0.1%
0.4%
0.7%
0.7%
1.4%
6.2%
6.7%
9.3%
8.9%
7.4%
6.6%
6.5%
6.0%
5.4%
6.5%

Table 6-4 shows zonal monthly capacity market revenue to demand resources
for the first six months of 2021. Capacity market revenue increased in thefirst six months of 2021 by $2.0 million, 1.1 percent, from $183.8 million
in the first six months of 2020 to $185.8 million in the first six months of2021. The capacity revenue amounts for 2020 include five months from the
2019/2020 Delivery Year and one month from the 2020/2021 Delivery Yearand the capacity revenue amounts for 2021 include five months from the2020/2021 Delivery Year and one month from the 2021/2022 Delivery Year.

Market Performance
Table 6-3 shows the cleared Demand Resource UCAP MW by delivery year.
Total cleared demand response UCAP MW in PJM increased by 1,982.0 MW,
or 21.0 percent, from 9,445.7 MW in the 2020/2021 Delivery Year to 11,427.7
MW in the 2021/2022 Delivery Year. The DR percent of capacity decreased by
1.1 percentage points, from 5.4 percent in the 2020/2021 Delivery Year to 6.5
percent in the 2021/2022 Delivery Year.

23 The RTO LDA refers to the rest of RTO.

336

Section 6 Demand Response© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

Table 6-4 Zonal monthly demand resource capacity revenue: January throughJune, 2021
Zone
ACEC
AEP, EKPC
APS
ATSI
BGE
COMED
DAY
DUKE
DUQ
DOM
DPL
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
Total

January
February
March
April
May
June
Total
$364,810$329,506$364,810$353,042$364,810$414,657$2,191,636$3,309,544 $2,989,265 $3,309,544 $2,885,206 $2,981,379 $7,085,832$22,560,770$1,790,204 $1,616,959 $1,790,204 $1,732,456 $1,790,204 $4,296,522$13,016,549$1,882,518 $1,700,339 $1,882,518 $1,821,792 $1,882,518 $5,909,358$15,079,043$468,186$422,877$468,186$453,083$468,186 $1,170,553$3,451,070$8,465,782 $7,646,513 $8,465,782 $8,192,693 $8,465,782 $10,830,893 $52,067,445$465,983$420,888$465,983$450,951$465,983$956,340$3,226,128$972,021$877,954$972,021$940,665$972,021 $1,004,324$5,739,006$383,237$346,149$383,237$370,874$383,237$568,680$2,435,414$465,983$420,888$465,983$450,951$465,983$956,340$3,226,128$972,021$877,954$972,021$940,665$972,021 $1,004,324$5,739,006$817,686$738,555$817,686$791,309$817,686$846,714$4,829,635$644,939$582,525$644,939$624,134$644,939 $1,519,890$4,661,366$644,939$582,525$644,939$624,134$644,939 $1,519,890$4,661,366$2,133,013 $1,926,593 $2,133,013 $2,064,206 $2,133,013 $2,219,456 $12,609,295$644,939$582,525$644,939$624,134$644,939 $1,519,890$4,661,366$432,443$390,594$432,443$418,494$432,443$947,100$3,053,518$1,594,416 $1,440,118 $1,594,416 $1,542,983 $1,594,416 $2,884,710$10,651,060$1,901,994 $1,717,930 $1,901,994 $1,840,639 $1,901,994 $2,503,407$11,767,959$22,613$20,424$22,613$21,883$22,613$28,837$138,983$28,377,271 $25,631,083 $28,377,271 $27,144,296 $28,049,106 $48,187,718 $185,766,745

Pre-Emergency and Emergency Load Response resources must register all
resources to respond within 30, 60 or 120 minutes of a PJM dispatched event.
The quick lead time, or 30 minute lead time, is the default lead time, unlessa CSP submits an exception request for 60 or 120 minute notification time
based on a physical constraint.24 The exception requests must clearly state
why the resource is unable to respond within 30 minutes based on the definedreasons for exception listed in Manual 18.25 Once a location is granted alonger lead time, the resource does not need to resubmit for a longer leadtime each delivery year. Resources that request longer lead times without aphysical constraint are rejected.
Table 6-5 shows the amount of nominated MW and locations by producttype and lead time for the 2020/2021 Delivery Year. Nominated MW are PreEmergency or Emergency Load Response registrations used to satisfy a CSP’s
committed MW position for a delivery year. PJM approved 3,096 locations,24 See “PJM Manual 18: PJM Capacity Market,” § 4.3.1, Rev. 49 (Aug. 2021).
25 See “PJM Manual 18: PJM Capacity Market,” § 4.3.1, Rev. 49 (Aug. 2021).

© 2021 Monitoring Analytics, LLC

or 21.2 percent of all locations, which have 3,548.6.0 nominated MW, or 45.0
percent of all nominated MW, for exceptions to the 30 minute lead time rule
for the 2020/2021 Delivery Year.
Table 6-5 Nominated MW and locations by product type and lead time:
2020/2021 Delivery Year
Lead Type
Quick Lead (30 Minutes)
Short Lead (60 Minutes)
Long Lead (120 Minutes)
Total

Lead Type
Quick Lead (30 Minutes)
Short Lead (60 Minutes)
Long Lead (120 Minutes)
Total

Pre-Emergency MW
Capacity Pre-Emergency
Performance
Total
4,097.2
4,097.2
326.9
326.9
3,043.0
3,043.0
7,467.1
7,467.1
Pre-Emergency Locations
Capacity Pre-Emergency
Performance
Total
11,025
11,025
316
316
2,466
2,466
13,807
13,807Emergency MW
Capacity
Emergency
Performance
Total
240.6
240.6
28.8
28.8
150.0
150.0
419.4
419.4
Emergency Locations
Capacity
Emergency
Performance
Total
473
473
39
39
275
275
787
787

Total
4,337.9355.7
3,192.9
7,886.5

Total
11,498355
2,741
14,594

Table 6-6 shows the amount of nominated MW and locations by product typeand lead time for the 2020/2021 Delivery Year. PJM approved 3,208 locations,or 20.9 percent of all locations, which have 3,645.6 nominated MW, or 45.7
percent of all nominated MW, for exceptions to the 30 minute lead time rule
for the 2021/2022 Delivery Year.
Table 6-6 Nominated MW and locations by product type and lead time:
2021/2022 Delivery Year
Lead Type
Quick Lead (30 Minutes)
Short Lead (60 Minutes)
Long Lead (120 Minutes)
Total

Lead Type
Quick Lead (30 Minutes)
Short Lead (60 Minutes)
Long Lead (120 Minutes)
Total

Pre-Emergency MW
Capacity Pre-Emergency
Performance
Total
4,115.5
4,115.5285.5
285.5
3,198.2
3,198.2
7,599.2
7,599.2
Pre-Emergency Locations
Capacity Pre-Emergency
Performance
Total
11,699
11,699
334
334
2,650
2,650
14,683
14,683

Emergency MW
Capacity
Emergency
Performance
Total
214.8
214.8
21.0
21.0
140.8
140.8
376.6
376.6
Emergency Locations
Capacity
Emergency
Performance
Total
458
458
37
37
187
187
682
682

Total
4,330.2
306.5
3,339.1
7,975.8

Total
12,157371
2,837
15,3652021 Quarterly State of the Market Report for PJM: January through June 337

2021 Quarterly State of the Market Report for PJM: January through June

There are two ways to measure load reductions of demand resources. The
Firm Service Level (FSL) method, applied to the summer, measures thedifference between a customer’s peak load contribution (PLC) and its real-timeload, multiplied by the loss factor (LF).26 The Guaranteed Load Drop (GLD)
method measures the minimum of: the comparison load minus real-time load
multiplied by the loss factor; or the PLC minus the real-time load multipliedby the loss factor. The comparison load estimates what the load would havebeen if PJM did not declare a Load Management Event, similar to a CBL, byusing a comparable day, same day, customer baseline, regression analysis
or backup generation method. Limiting the GLD method to the minimum of
the two calculations ensures reductions occur below the PLC, thus avoiding
double counting of load reductions.27 With the introduction of the Winter PeakLoad (WPL) concept, effective for the 2017/2018 Delivery Year, both the FSL
and GLD methods are modified for the non-summer period. The FSL methodmeasures compliance during the non-summer period as the difference between
a customer’s WPL multiplied by the Zonal Winter Weather Adjustment Factor(ZWWAF) and the LF, rather than the PLC, and real-time load, multiplied by
the LF. PJM calculates and posts on the PJM website the ZWWAF as the zonal
winter weather normalized peak divided by the zonal average of the fivecoincident peak loads in December through February.28 The Winter Peak Loadis adjusted up for transmission and distribution line loss factors because one
MW of load would be served by more than one MW of generation to accountfor transmission losses. The Winter Peak Load is normalized based on thewinter conditions during the five coincident peak loads in winter using theZWWAF to account for an extreme temperatures or a mild winter. The GLD
method measures compliance during the non-summer period as the minimumof: the comparison load minus real-time load multiplied by the loss factor; or
the WPL multiplied by the ZWWAF and the LF, rather than the PLC, minus thereal-time load multiplied by the LF.29
The capacity market is an annual market. A Capacity Performance resource hasan annual commitment. Load is allocated capacity obligations based on theannual peak load which is a summer load. The amount of MW allocated to load
26 Real-time load is hourly metered load.
27 135 FERC ¶ 61,212.
28 “PJM Manual 18: PJM Capacity Market,” § 4.3.7, Rev. 49 (Aug. 2021).
29 “PJM Manual 18: PJM Capacity Market,” § 8.7A, Rev.49 (Aug. 2021).

338

Section 6 Demand Response

does not vary based on winter demand. The principle is that a customer’s actualuse of capacity should be compared to the level of capacity that a customer
is required to pay for. Capacity costs are allocated to LSEs by PJM based on
the single coincident peak load method. In PJM, the single coincident peakoccurs in the summer.30 LSEs generally allocate capacity costs to customers
based on the five coincident peak method.31 The allocation of capacity costs
to customers uses each customer’s PLC. Customers pay for capacity basedon the PLC, not the WPL. If an end customer has 3 MW of load during thecoincidental peak load hour, but only 1 MW during the coincidental winterpeak load hour, the end use customer must pay for 3 MW of capacity for theentire delivery year, but can only participate as a 1 MW demand response
resource. Using PLC to measure compliance the entire delivery year would
allow the customer to fully participate as a 3 MW demand response resource.
FERC allowed the use of the WPL for calculating compliance for non-summer
months effective June 1, 2017.32 The MMU recommends setting the baseline
for measuring capacity compliance under summer and winter compliance at
the customer’s PLC, similar to GLD, to avoid double counting, to avoid undercounting and to ensure that a customer’s purchase of capacity is calculated
correctly. The FSL and GLD equations for calculating load reductions are:Table 6-7 shows the MW registered by measurement and verification method
and by technology type for the 2021/2022 Delivery Year. For the 2021/2022
Delivery Year, 99.98 percent use the FSL method and 0.02 percent use the GLD
measurement and verification method.

30 OATT Attachment DD.5.11.
31 OATT Attachment M-2.
32 162 FERC ¶ 61,159 (2018).

© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

Table 6-7 Reduction MW by each demand response method: 2021/2022
Delivery Year
Measurement andVerification Method
Firm Service Level
Guaranteed Load Drop
Total
Percent by method

On-siteGeneration MW
1,225.2
0.3
1,225.5
15.4%

HVAC MW
1,954.3
1.0
1,955.3
24.5%

Refrigeration
MW
196.0
0.0
196.0
2.5%

Technology Type
Manufacturing
Lighting MW
MW
689.4
3,851.0
0.0
0.0
689.4
3,851.0
8.6%
48.3%

Water Heating Other, Batteries orMW
Plug Load MW
17.7
40.6
0.0
0.3
17.7
40.9
0.2%
0.5%

Total
7,974.3
1.5
7,975.8
100.0%

Percent by
type
100.0%
0.02%
100.0%

Table 6-8 shows the fuel type used in the onsite generators for the 2021/2022
Delivery Year in the emergency and pre-emergency programs. For the2021/2022 Delivery Year, 1,225.5 MW of the 7,975.8 nominated MW, 15.4
percent, used onsite generation. Of the 1,225.5 MW, 84.0 percent used diesel
and 16.0 percent used natural gas, gasoline, oil, propane or waste products.

Table 6-10 shows the fuel type used in the onsite generators for the 2020/2021
Delivery Year in the emergency and pre-emergency programs. For the
2020/2021 Delivery Year, 1,219.7 MW of the 7,886.5 nominated MW, 15.5
percent, use onsite generation. Of the 1,219.7 MW, 87.0 percent use diesel and13.0 percent use natural gas, gasoline, oil, propane or waste products.

Table 6-8 Onsite generation fuel type (MW): 2021/2022 Delivery Year

Table 6-10 Onsite generation fuel type (MW): 2020/2021 Delivery Year

Fuel Type
DieselNatural Gas, Gasoline, Oil, Propane, Waste Products
Total

2021/2022
MW
1,029.9
195.6
1,225.5

Percent
84.0%
16.0%
100.0%

Fuel Type
DieselNatural Gas, Gasoline, Oil, Propane, Waste Products
Total

2020/2021
MW
1,061.4
158.3
1,219.7

Percent87.0%
13.0%
100.0%

Table 6-9 shows the MW registered by measurement and verification method
and by technology type for the 2020/2021 Delivery Year. For the 2020/2021
Delivery Year, 99.9 percent use the FSL method and 0.1 percent use the GLD
measurement and verification method.
Table 6-9 Reduction MW by each demand response method: 2020/2021
Delivery Year
Measurement andVerification Method
Firm Service Level
Guaranteed Load Drop
Total
Percent by method

On-siteGeneration MW
1,219.5
0.3
1,219.7
15.5%© 2021 Monitoring Analytics, LLC

HVAC MW
1,877.5
1.1
1,878.6
23.8%

Refrigeration
MW
196.4
0.0
196.4
2.5%

Technology Type
Manufacturing
Lighting MW
MW
689.8
3,790.6
0.0
4.4
689.8
3,795.1
8.7%
48.1%

Water Heating
MW
61.6
0.0
61.6
0.8%

Batteries andPlug Load MW
44.9
0.3
45.2
0.6%

Total
7,880.4
6.1
7,886.5
100.0%

Percent by
type
99.9%
0.1%
100.0%

2021 Quarterly State of the Market Report for PJM: January through June 339

2021 Quarterly State of the Market Report for PJM: January through June

Emergency and Pre-Emergency Event Reported Compliance
Capacity Performance resources measure performance nodally, except for
demand resources. PJM cannot dispatch demand resources by node with thecurrent rules because demand resources are not registered to a node. Demand
resources can be dispatched by subzone only if the subzone is defined before
dispatch. Aggregation rules allow a demand resource that incorporates manysmall end use customers to span an entire zone, which is inconsistent withnodal dispatch.
Subzonal dispatch became mandatory for emergency demand resources in
the 2014/2015 Delivery Year, if the subzone was defined by PJM no later
than the day before the dispatch.33 A subzone is defined by zip code, not by
nodal location. If a registration has any location in the dispatched subzone,
the entire registration must respond. PJM does not measure compliance when
demand response is dispatched in a subzone created on the same day as thedispatch. Subzonal dispatch creates a PAI for the subzone, even if PJM does
not measure compliance for demand resources.

any defined subzones and maintain a public record of all created and removed
subzones.
The subzone design and closed loop interfaces are related. PJM implemented
closed loop interfaces with the stated purpose of improving the incorporationof reactive constraints into energy prices and to allow emergency DR to set
price.36 PJM applies closed loop interfaces so that it can use units needed forreactive support to set the energy price when they would not otherwise set
price under the LMP algorithm. PJM also applies closed loop interfaces sothat it can use emergency DR resources to set the real-time LMP when DR
would not otherwise set price under the fundamental LMP logic. Of the 20
closed loop interface definitions, 11 (55 percent) were created for the purposeof allowing emergency DR to set price.37 The closed loop interfaces created
for the purpose of allowing emergency DR to set price are located in the RTO,
MAAC, EMAAC, SWMAAC, DPL-SOUTH, ATSI, ATSI-CLEVELAND and BGE
LDAs.

There are 13 dispatchable subzones in PJM last updated September 21, 2018:
AEP_CANTON, ATSI_CLE, DPL_SOUTH, PS_NORTH, ATSI_NEWCASOE, PPL_WESCO, ATSI_BLKRIVER, PENELEC_ERIC, APS_EAST, DOM_CHES, DOM_YORKTOWN, AECO_ENGLAND, and JCPL_REDBANK.34 Effective with the2020/2021 Delivery Year, PJM will procure a single capacity product, Capacity
Performance, which does not require predefined subzones for mandatory
dispatch.35

Demand resources can be dispatched for voluntary compliance during any
hour of any day, but dispatched resources are not measured for complianceoutside of the mandatory compliance window for each demand product. A
demand response event during a product’s mandatory compliance window
also may not result in a compliance score. When demand response eventsoccur for partial hours under 30 minutes or for a subzone dispatch that was
not defined one business day before dispatch, the events are not measured forcompliance.

PJM can remove a defined subzone, and make changes to the subzone, at theirdiscretion. Subzones should not be removed once defined, as the subzone
may need to be dispatched again in the future. The METED_EAST, PENELEC_
EAST, PPL_EAST and DOM_NORFOLK subzones were removed by PJM. Moresubzones may have been removed by PJM but PJM does not keep a record ofcreated and removed subzones. The MMU recommends that PJM not remove

Capacity Performance demand resources currently estimate five minutecompliance with an hourly interval meter during PAIs. To accurately measurecompliance on a five minute basis, a five minute interval meter is required. Allother Capacity Performance resources require five minute interval meters, anddemand resources should be no different. Demand resources are paid basedon the average performance by registration for the duration of a demand

33 OATT Attachment DD, Section 11.
34 See “Load Management Subzones,” <http://www.pjm.com/~/media/markets-ops/demand-response/subzone-definition-workbook.ashx>(Accessed January 21, 2020).
35 OATT Attachment DD, Section 10A.

340

Section 6 Demand Response

36 See PJM/Alstom. “Approaches to Reduce Energy Uplift and PJM Experiences,” presented at the FERC Technical Conference: Increasing
Real-Time and Day-Ahead Market Efficiency Through Improved Software, Docket No. AD10-12-006 (June 23, 2015) <http://www.ferc.
gov/june-tech-conf/2015/presentations/m2-3.pdf>.
37 See the 2018 State of the Market Report for PJM, Volume 2, Section 4, Energy Uplift, for additional information regarding all closed loop
interfaces and the impacts to the PJM markets.

© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

response event. Each capacity performance demand response product shouldmeasure compliance on a five minute basis to accurately report reductions
during demand response events. The current rules for demand response use
the average reduction for the duration of an event. The average duration
across multiple hours does not provide an accurate metric for each five minuteinterval of the event and is inconsistent with the measurement of generation
resources. Measuring compliance on a five minute basis would provide
accurate information to the PJM system. The MMU recommends demand
response event compliance be calculated on an hourly basis for noncapacity
performance resources and on a five minute basis for all capacity performance
resources and that the penalty structure reflect five minute compliance.38
Under the capacity performance design of the PJM Capacity Market,
compliance for potential penalties will be measured for DR only duringperformance assessment intervals (PAI).39 When pre-emergency or emergency
demand response is dispatched, a PAI is triggered for PJM. PJM cannot
dispatch pre-emergency or emergency demand response without triggeringa PAI and measuring compliance. Before PJM created PAI to measurecompliance, pre-emergency demand response could be dispatched without
calling an emergency event. As a result, PJM now effectively classifies all
demand response as an emergency resource.
The MMU recommends that demand response resources be treated as economic
resources like all other capacity resources and therefore that the dispatchof demand response resources not automatically trigger a performanceassessment interval (PAI) for CP compliance. Emergencies should be triggered
only when PJM has exhausted all economic resources including demand
response resources. Table 6-11 shows the amount of nominated demand
response MW, the required reserve margin and actual reserve margin for the
2020/2021 and 2021/2022 Delivery Years. There are 10,283.9 nominated MWof demand response for the 2021/2022 Delivery Year, 51.0 percent of therequired reserve margin and 36.7 percent of the actual reserve margin for the2021/2022 Delivery Year.40
38 “PJM Manual 18: PJM Capacity Market,” § 8.7A, Rev. 48 (May 26, 2021).
39 OATT § 1 (Performance Assessment Hour).
40 2021 State of the Market Report for PJM: January through June, Section 5: Capacity, Table 5-7.

© 2021 Monitoring Analytics, LLC

Table 6-11 Demand response nominated MW compared to reserve margin:
2020/2021 and 2021/2022 Delivery Years41
Delivery Year
2020/2021
2021/2022

DemandDemand Response
Response
Required Percent of Required Actual Reserve
Nominated MW Reserve Margin
Reserve Margin
Margin8,524.2
21,127.9
40.3%
33,039.8
10,283.9
20,176.5
51.0%
28,005.0

Demand Response
Percent of Actual
Reserve Margin
25.8%
36.7%

PJM will dispatch demand resources by zone or subzone for demand resources,
or within a PAI area for Capacity Performance resources. When PJM dispatches
all demand resources in multiple connecting zones, PJM further degrades thenodal design of electricity markets. PJM allows compliance to be measured
across zones within a compliance aggregation area (CAA) or Emergency Action
Area (EAA).42 43 A CAA, or EAA, is an electrically connected area that has thesame capacity market price. This changes the way CSPs dispatch resources
when multiple electrically contiguous areas with the same RPM clearing prices
are dispatched. The compliance rules determine how CSPs are paid and thus
create incentives that CSPs will incorporate in their decisions about how to
respond to PJM dispatch. The multiple zone approach is even less locational
than the zonal and subzonal approaches and creates larger mismatches between
the locational need for the resources and the actual response. If multiple zones
within a CAA are called by PJM, a CSP will dispatch the least cost resources
across the zones to cover the CSP’s obligation. This can result in more MW
dispatched in one zone that are locationally distant from the relief needed
and no MW dispatched in another zone, yet the CSP could be considered 100
percent compliant and pay no penalties. More locational deployment of load
management resources would improve efficiency. With full implementationof capacity performance, demand response will be dispatched by registrations
within an area for which an Emergency Action is declared by PJM. PJM does
not have the nodal location of each registration, meaning PJM will need toguess as to the useful demand response registration by registered location. The
41 Nominated MW totals are Demand Response ICAP corresponding to Demand Response UCAP cleared in RPM auctions for each delivery
year. The total nominated MW values do not reflect replacement transactions.
42 CAA is “a geographic area of Zones or sub-Zones that are electrically contiguous and experience for the relevant Delivery Year, based on
Resource Clear Prices of, for Delivery Years through May 31, 2018, Annual Resources and for the 2018/2019 Delivery Year and subsequent
Delivery Years, Capacity Performance Resources, the same locational price separation in the Base Residual Auction, the same locational
price separation in the First Incremental Auction, the same locational price separation in the Second Incremental Auction, or the same
locational price separation in the Third Incremental Auction.” OATT § 1.
43 PJM. “Manual 18: Capacity Market,” § 8.7.2, Rev. 48 (May 26, 2021).

2021 Quarterly State of the Market Report for PJM: January through June 341

2021 Quarterly State of the Market Report for PJM: January through June

MMU recommends that demand resources be required to provide their nodal
location. Nodal dispatch of demand resources would be consistent with thenodal dispatch of generation.

Definition of Compliance
Currently, the calculation methods of event and test compliance do not provide
reliable results. PJM’s interpretation of load management event rules allows
over compliance to be reported when there is no actual over compliance.
Settlement locations with a negative load reduction value (load increase) are
not netted by PJM within registrations or within demand response portfolios.
A resource that has load above their baseline during a demand response event
has a negative performance value. PJM limits compliance shortfall values
to zero MW. This is not explicitly stated in the Tariff or supporting Manuals
and the compliance formulas for FSL and GLD customers do allow negativevalues.44
Limiting compliance to only positive values incorrectly calculates compliance.
For example, if a registration had two locations, one with a 50 MWh loadincrease when called, and another with a 75 MWh load reduction when called,
PJM calculates compliance for that registration as a 75 MWh load reduction
for that event hour. Negative settlement MWh are not netted across hours or
across registrations for compliance purposes. A location with a load increase is
set to a zero MW reduction. For example, in a two hour event, if a registration
showed a 15 MWh load increase in hour one, but a 30 MWh reduction in hour
two, the registration would have a calculated 0 MWh reduction in hour one
and a 30 MWh reduction in hour two. This has compliance calculated at an
average hourly 15 MWh load reduction for that two hour event, compared toa 7.5 MWh observed reduction. Reported compliance is greater than observed
compliance, as locations with load increases, i.e. negative reductions, aretreated as zero for compliance purposes.
Changing a demand resource compliance calculation from a negative value
to 0 MW inaccurately values event performance and capacity performance.
Inflated compliance numbers for an event overstates the true value and
44 OA Schedule 1 § 8.9.

342

Section 6 Demand Response

capacity of demand resources. A demand response capacity resource that
performs negatively is also displacing another capacity resource that could
supply capacity during a delivery year. By setting the negative compliancevalue to 0 MW, PJM is inaccurately calculating the value of demand resources.
Load increases are not netted against load decreases for dispatched demand
resources across hours or across registrations within hours for compliancepurposes, but are treated as zero. This skews the compliance results towards
higher compliance since poorly performing demand resources are not used in
the compliance calculation. When load is above the peak load contribution
during a demand response event, the load reduction is negative; it is a loadincrease rather than a decrease. PJM ignores such negative reduction values
and instead replaces the negative values with a zero MW reduction value. The
PJM Tariff and PJM Manuals do not limit the compliance calculation value toa zero MW reduction value.45 The compliance values PJM reports for demand
response events are different than the actual compliance values accounting
for both increases and decreases in load from demand resources that are calledon and paid under the program.
The MMU recommends that compliance rules be revised to include submittalof all necessary hourly load data, and that negative values be included whencalculating event compliance across hours and registrations.
Demand resources that are also registered as economic resources have acalculated CBL for the emergency event days. Demand resources that are
not registered as Economic Resources use the three day CBL type with thesymmetrical additive adjustment for measuring energy reductions without therequirements of a Relative Root Mean Squared Error (RRMSE) Test required
for all economic resources.46 The CBL must use the RRMSE test to verify that
it is a good approximation for real-time load usage. The MMU recommends
the RRMSE test be required for all demand resources with a CBL.
The CBL for a customer is an estimate of what load would have been if thecustomer had not responded to LMP and reduced load. The difference between
45 OA Schedule 1 § 8.9.
46 157 FERC ¶ 61,067 (2016).

© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

the CBL and real-time load is the energy reduction. When load responds to
LMP by using a behind the meter generator, the energy reduction should becapped at the generation output. Any additional energy reduction is a resultof inaccuracy in the CBL estimate rather than an actual reduction. The MMU
recommends that demand reductions based entirely on behind the meter
generation be capped at the lower of economic maximum or actual generation
output.
An extreme example makes clear the fundamental problems with the use ofmeasurement and verification methods to define the level of power that would
have been used but for the DR actions, and the payments to DR customers that
result from these methods. The current rules for measurement and verification
for demand resources make a bankrupt company, a customer that no longer
exists due to closing of a facility or a permanently shut down company, or acompany with a permanent reduction in peak load due to a partial closing of a
facility, an acceptable demand response customer under some interpretationsof the tariff, although it is the view of the MMU that such customers should
not be permitted to be included as registered demand resources. Companies
that remain in business, but with a substantially reduced load, can maintaintheir pre-bankruptcy FSL (firm service level to which the customer agrees toreduce in an event) commitment, which can be greater than or equal to thepost-bankruptcy peak load. The customer agrees to reduce to a level whichis greater than or equal to its new peak load after bankruptcy. When demand
response events occur the customer would receive credit for 100 percent
reduction, even though the customer took no action and could take no action
to reduce load. This problem exists regardless of whether the customer is still
paying for capacity. To qualify and participate as a demand resource, thecustomer must have the ability to reduce load. “A participant that has theability to reduce a measurable and verifiable portion of its load, as meteredon an EDC account basis.”47 Such a customer no longer has the ability to
reduce load in response to price or a PJM demand response event. CSPs in
PJM have and continue to register bankrupt customers as emergency or preemergency load response customers. PJM finds acceptable the practice of CSPs
maintaining the registration of customers with a bankruptcy related reduction
47 OA Schedule 1 § 8.2.

© 2021 Monitoring Analytics, LLC

in demand that are unable, as a result, to respond to emergency events. Three
proposals that included language to remove bankrupt customers from a CSP’s
portfolio failed at the June 7, 2017, Market Implementation Committee.48 The
registered customers that are bankrupt and the amount of registered MW
cannot be released for reasons of confidentiality.
The metering requirement for demand resources is outdated, and has not
kept up with the changes to PJM’s market design. PJM moved to five minutesettlements, but the metering requirement for demand resources remained at
an hourly interval meter. It is impossible to measure energy usage on a fiveminute basis using an hourly interval meter. PJM will estimate real-time usage
by prorating the hourly interval meter and assume if load is less than the CBL,
that the reduction occurred during the required dispatch window. The meterreading is not telemetered to PJM in real time. The resource is allowed up to
60 days to report the data to PJM. The MMU recommends that PJM adopt the
ISO-NE five-minute metering requirements in order to ensure that dispatchers
have the necessary information for reliability and that market payments todemand resources be calculated based on interval meter data at the site of thedemand reductions so that they can accurately measure compliance.49
When demand resources are not dispatched during a mandatory response
window, each CSP must test their portfolio to the levels of capacity
commitment.50 A CSP picks the testing day, for one hour, on any non-holiday
weekday during the applicable mandatory window. A CSP is able to retest if
a resource fails to provide the required reduction by less than 25 percent. The
ability of CSPs to pick the test time does not simulate emergency conditions.
As a result, test compliance is not an accurate representation of the capabilityof the resource to respond to an actual PJM dispatch of the resource. Given
that demand resources are now an annual product, multiple tests are required
to ensure reduction capability year round. The MMU recommends that load
48 There was one proposal from PJM, one proposal from a market participant and one proposal from the MMU. See Approved Minutes
from the Market Implementation Committee, <http://www.pjm.com/-/media/committees-groups/committees/mic/20170607/20170607minutes.ashx>.
49 See ISO-NE Tariff, Section III, Market Rule 1, Appendix E1 and Appendix E2, “Demand Response,” <http://www.iso-ne.com/regulatory/
tariff/sect_3/mr1_append-e.pdf>. (Accessed October 17, 2017) ISO-NE requires that DR have an interval meter with five-minute datareported to the ISO and each behind the meter generator is required to have a separate interval meter. After June 1, 2017, demand
response resources in ISO-NE must also be registered at a single node.
50 The mandatory response time for Capacity Performance DR is June through October and the following May between 10:00AM to
10:00PM EPT and November through April between 6:00AM through 9:00PM EPT. See PJM. “Manual 18: PJM Capacity Market,” Rev. 46(Nov. 19 2020).

2021 Quarterly State of the Market Report for PJM: January through June 343

2021 Quarterly State of the Market Report for PJM: January through Junemanagement testing be initiated by PJM with limited warning to CSPs inorder to more accurately represent the conditions of an emergency event.
Table 6-12 shows the test penalties by delivery year by product type for the
2015/2016 Delivery Year through the 2019/2020 Delivery Year.51 The shortfall
MW are calculated for each CSP by zone. The weighted rate per MW is theaverage penalty rate paid per MW. The total penalty column is the sum of
the daily test penalties by delivery year and type. The testing window is open
through the end of the delivery year.
Table 6-12 Test penalties by delivery year by product type: 2015/2016
through 2019/2020
Product Type
LimitedExtended Summer
AnnualBase DR and EE
Capacity Performance
Total

2015/2016
Shortfall
WeightedTotal
MW Rate per MW
Penalty
96.4$165.35 $5,836,255
1.9$163.70$113,775
3.7$184.67 $250,621

102.0$166.02 $6,200,651

2016/2017
Shortfall
WeightedTotal
MW Rate per MW
Penalty48.9$166.41 $2,967,158
7.3$138.14 $370,290
4.8$137.45 $241,406
2.1
63.1

2017/2018
Shortfall
Weighted
MW Rate per MW
13.9$124.0810.5$142.8616.3$144.00$160.80 $124,310$160.72 $3,703,163

0.6
41.3

Emergency and Pre-Emergency Load Response Energy
Payments
Emergency and pre-emergency demand response dispatched during a load
management event by PJM are eligible to receive emergency energy payments
if registered under the full program option. The full program option includes
an energy payment for load reductions during a pre-emergency or emergency
event for demand response events and capacity payments.52 There are 98.1
percent of nominated MW for the 2021/2022 Delivery Year registered under thefull program option. There are 1.9 percent of nominated MW for the 2021/2022
Delivery Year registered as capacity only option. Demand resources clear thecapacity market like all other capacity resources and the dispatch of demand
resources should not trigger a scarcity event. The strike price is set by the CSP
before the delivery year starts and cannot be changed during the delivery year.
51 Not all products received penalties or existed in every delivery year. For example, the Base and Capacity Performance products were notan option for the 2015/2016 Delivery Year.
52 Id.

344

Section 6 Demand Response

The demand resource energy payments are equal to the higher of hourly zonal
LMP or a strike price energy offer made by the participant, including a dollar
per MWh minimum dispatch price and an associated shutdown cost. Demand
resources should not be permitted to offer above $1,000 per MWh without
cost justification or to include a shortage penalty in the offer. FERC has statedclearly that demand resources in the capacity market must verify costs above$1,000 per MWh, unless they are capacity only: “We clarify, however, thatreforms adopted in this Final Rule, which provide that resources are eligible
to submit cost-based incremental energy offers in excess of $1,000/MWh andrequire that those offers be verified, do not apply to capacity-only demand

Total
Penalty$631,665$547,928$855,940$181.80$40,146$137.54 $2,075,678

2018/2019
Shortfall
Weighted
MW Rate per MW
0.03$179.80

16.3
2.6
18.9

Total
Penalty$2,100$186.80 $1,110,134$188.55 $178,795$187.03 $1,291,030

2019/2020
Shortfall
Weighted
MW Rate per MW

Total
Penalty30.2$154.69 $1,712,177

30.2$154.69 $1,712,177

response resources that do not submit incremental energy offers in energy
markets.”53 PJM interprets the scarcity pricing rules to allow a maximum DR
energy price of $1,849 per MWh for the 2021/2022 Delivery Year.54 55 Demand
resources registered with the full option should be required to verify energy
offers in excess of $1,000 per MWh. PJM does not require such verification.56
The MMU recommends that the maximum offer for demand resources be thesame as the maximum offer for generation resources.
Shutdown costs for demand response resources are not adequately defined in
Manual 15. PJM’s Cost Development Subcommittee (CDS) approved changes
to Manual 15 to eliminate shutdown costs for demand response resources
53 161 FERC ¶ 61,153 at P 8 (2017).
54 139 FERC ¶ 61,057 (2012).
55 FERC accepted proposed changes to have the maximum strike price for 30 minute demand response to be $1,000/MWh + 1*Shortage
penalty - $1.00, for 60 minute demand response to be $1,000/MWh + (Shortage Penalty/2) and for 120 minute demand response to be$1,100/MWh from ER14-822-000.
56 OATT Attachment K Appendix Section 1.10.1A Day-Ahead Energy Market Scheduling (d) (x).

© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

participating in the synchronized reserve market, but not demand resources
or economic resources.57

Table 6-14 Distribution of registrations and associated MW in the full option
across ranges of minimum dispatch: 2021/2022 Delivery Year

Table 6-13 shows the distribution of registrations and associated MW in
the emergency full option across ranges of minimum dispatch prices for the
2020/2021 Delivery Year. The majority of participants, 76.2 percent of locations
and 52.8 percent of nominated MW, had a minimum dispatch price between$1,550 and $1,849 per MWh, the maximum price allowed for the 2020/2021
Delivery Year. Almost all registrations, 98.3 percent of locations and 97.1
percent of nominated MW have a dispatch price above $1,000 per MWh. The
shutdown cost of resources with $1,000 to $1,275 per MWh strike prices had
the highest average at $156.16 per location and $137.58 per nominated MW.

Ranges of Strike
Prices ($/MWh)$0-$1,000$1,000-$1,275$1,275-$1,550$1,550-$1,849
Total

Table 6-13 Distribution of registrations and associated MW in the full option
across ranges of minimum dispatch: 2020/2021 Delivery Year
Ranges of Strike
Prices ($/MWh)$0-$1,000$1,000-$1,275$1,275-$1,550$1,550-$1,849
Total

Locations
243
2,763
356
10,792
14,154

Percent of
Total
1.7%
19.5%
2.5%
76.2%
100.0%

Nominated
MW (ICAP)
222.4
3,102.7
345.0
4,099.2
7,769.3

Percent of
Total
2.9%
39.9%
4.4%
52.8%
100.0%

Shutdown
Cost perLocation$68.14$156.16$53.78$55.80$75.55

Shutdown Cost
Per Nominated
MW (ICAP)$30.96$137.58$55.49$146.91$137.65

Table 6-14 shows the distribution of registrations and associated MW in
the emergency full option across ranges of minimum dispatch prices forthe 2021/2022 Delivery Year. The majority of participants, 77.4 percent oflocations and 52.2 percent of nominated MW, have a minimum dispatch pricebetween $1,550 and $1,849 per MWh, the maximum price allowed for the2021/2022 Delivery Year. Almost all registrations, 99.3 percent of locations
and 97.3 percent of nominated MW have a dispatch price above $1,000 per
MWh. The shutdown cost of resources with $1,000 to $1,275 per MWh strikeprices have the highest average at $162.68 per location and $143.75 per
nominated MW.

57 “PJM Manual 15: Cost Development Guidelines,” § 8.1, Rev. 37 (Dec. 9, 2020).

© 2021 Monitoring Analytics, LLC

Locations
107
2,898
370
11,52914,904

Percent of
Total
0.7%
19.4%
2.5%
77.4%
100.0%

Nominated
MW (ICAP)
207.8
3,214.4295.3
4,059.1
7,776.7

Percent of
Total
2.7%
41.3%
3.8%
52.2%
100.0%

Shutdown
Cost perLocation$97.45$162.68$43.71$50.71$72.64

Shutdown Cost
Per Nominated
MW (ICAP)$20.58$143.75$54.76$144.03$139.22PRD
The PRD rules are more aligned with the Capacity Performance constructeffective December 30, 2019, although the rules still fall short.58 PJM’s
initial filing was rejected by the Commission based on the MMU’s comments
and PJM’s modified filing was accepted.59 PJM’s final filing adopted the
MMU’s recommendation to exclude the use of Winter Peak Load (WPL)
when calculating the nominated MW for PRD resources used to satisfy RPM
commitments. Load is allocated capacity obligations based on the annual peakload within PJM. The amount of capacity allocated to load is a function solelyof summer coincident peak demand and is unaffected by winter demand. Useof the WPL to calculate the nominated MW for PRD resources to satisfy RPM
commitments, would incorrectly restrict PRD to less than the total capacity
the customer is required to buy. PJM’s adoption of the MMU recommendation
will correctly value PRD nominated MW. FERC required and PJM’s filing also
adopted, the MMU’s recommendation that PRD should be eligible for bonus
performance payments during Performance Assessment Intervals (PAI) only
when PRD resources respond above their nominated MW value. Allowing
PRD resources to collect bonus payments at times when they are not evenrequired to meet their basic obligation would be inconsistent with the basic
CP construct as it applies to all other CP resources.60
PJM’s filing still fell short of completely aligning PRD with the Capacity
Performance product. PRD resources will not have to respond during a PAI
if the PAI’s trigger price is above LMP during the PAI. All other CP resources
58 See “Compliance Filing Regarding Price Responsive Demand Rules,” Docket No. ER20-271-001 (February 28, 2020).
59 See “Order Rejecting Tariff Revisions,” Docket No. ER19-1012-000 (June 27, 2019).
60 October 31 Filing, Attachment B, Proposed Revised OATT § 10A (c).

2021 Quarterly State of the Market Report for PJM: January through June 345

2021 Quarterly State of the Market Report for PJM: January through June

have the obligation to perform during a PAI, regardless of the real-time LMP,
subject to instructions from PJM. PRD should be held to the same standard
during a PAI event.
PRD does not receive direct capacity or energy payments. PRD reduces theamount of capacity that must be purchased by the LSE and therefore reduces
the LSE’s payments for capacity. When PRD load is not on the system, thatload also avoids paying for the associated energy. PRD meets its obligation by
responding when LMP is at or above price thresholds defined in the PRD plan.61
PRD does not have to respond during performance assessment intervals (PAI)and therefore is inferior to other capacity resources and is not a substitutefor other capacity resources in the capacity performance construct. The MMU
recommends that PRD be required to respond during a PAI to be consistent
with all CP resources. PRD first cleared the capacity market in the BRA forthe 2020/2021 Delivery Year, and cleared for the 2021/2022 Delivery Year and2022/2023 Delivery Year.62

Economic Load Response Program
The Economic Load Response Program is for demand response customers
that offer into the day-ahead or real-time energy market. The estimated load
reduction is paid the zonal LMP, as long as the zonal LMP is greater than themonthly Net Benefits Test threshold.

six months of 2021. The annual HHI for economic demand response decreasedby 399 from 9065 for 2020 to 8667 for the first six months of 2021.
Table 6-15 Average hourly MWh HHI and market concentration in theeconomic program: January 2020 through June 202164

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

Average Hourly MWh HHI
Percent
2020
2021
Change
8983
9305
3.6%
9652
7604
(21.2%)
9857
9700(1.6%)
10000
9339(6.6%)
9926
9732(2.0%)
8976
8493(5.4%)
8442
8344
8893
9400
8121
7745
9065
8667
(4.4%)Top Four CSPs Share of
Reduction
Change in
2020
2021
Percent
98.1%
99.3%
1.2%
100.0%
92.8%(7.2%)
100.0%

100.0%
88.8%
93.5%
100.0%

100.0%
94.1%(5.9%)

100.0%
82.3%

Top Four CSPs Share of Credit
Change in
2020
2021
Percent
98.3%
98.6%
0.3%
100.0%
90.5%(9.5%)
100.0%

99.9%
90.2%
93.1%
100.0%

100.0%
96.3%(3.6%)

64.3%(18.5%)

100.0%
77.2%(5.0%)

82.8%

Market Performance

Table 6-15 shows the average hourly HHI for each month and the averagehourly HHI for January 1, 2020, through June 30, 2021. The ownership ofeconomic demand response resources was highly concentrated in 2020 and
2021.63 Table 6-15 lists the share of reported reductions provided by, and theshare of credits claimed by the four largest CSPs in each year. In the first six
months of 2021, 77.2 percent of all economic DR reported reductions and 64.3
percent of economic DR revenue were attributable to the four largest CSPs.
The HHI for economic demand response was highly concentrated for the first

Table 6-16 shows the total MW reported reductions made by participants inthe economic program and the total credits paid for these reported reductionsin the first six months of 2010 through 2021. The average credits per MWhpaid increased by $32.30 per MWh, 131.1 percent, from $24.64 per MWh in
the first six months of 2020 to $56.94 per MWh in the first six months of2021. The PJM real-time, load-weighted, average LMP in the first six monthsof 2021 increased 57.8 percent from the first six months of 2020, from $19.40
per MWh to $30.62 per MWh. Curtailed energy for the economic program
increased by 2,013 MWh, 155.2 percent, from 1,297 MWh in the first six
months of 2020 to 3,311 MWh in the first six months of 2021. Total credits
paid for the economic load response program in the first six months of 2021
increased by $0.18 million, 667.2 percent, from $0.03 million in the first six
months of 2020 to $0.2 million in the first six months of 2021.

61 The Demand Response Subcommittee (DRS) is currently working to align PRD with the CP designed products.
62 There were a total of 558 MW of cleared PRD in the 2020/2021 Delivery Year. See PJM Auction Results, <https://www.pjm.com/-/media/
markets-ops/rpm/rpm-auction-info/2020-2021-base-residual-auction-results.ashx?la=en>.
63 All HHI calculations in this section are at the parent company level.

64 April, May, October and December 2020 reduction and credit share values, and March and April 2021 reduction and credit share values
are redacted based on confidentiality rules.

Market Structure

346

Section 6 Demand Response© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

Figure 6-2 shows monthly economic demand response credits and MWh, fromJanuary 1, 2010, through June 30, 2021.

45.0
Economic Credits

40.0

Economic MWh

Jul-20Jan-21

Jul-190.0

Jan-20$0.0

Jul-185.0

Jan-19$1.0

Jul-17

10.0

Jan-18$2.0

Jul-16

15.0

Jan-17$3.0

Jul-1520.0

Jan-16$4.0

Jul-1425.0

Jan-15$5.0

Jul-1330.0

Jan-14$6.0

Jul-12

35.0

Jan-13$7.0

MWh (Thousands)$8.0

Jul-11

Economic demand response resources that are dispatched by PJM in both theeconomic and emergency programs are paid the higher price defined in theemergency rules.65 For example, assume a demand resource has an economic
offer price of $100 per MWh and an emergency strike price of $1,800 per MWh.
If this resource were scheduled to reduce in the day-ahead energy market, thedemand resource would receive $100 per MWh, but if an emergency event
were called during the economic dispatch, the demand resource would receive
its emergency strike price of $1,800 per MWh instead. The rationale for thisrule is not clear.66 All other resources that clear in the day-ahead market are
financially firm at the clearing price. Payment at a guaranteed strike price andthe ability to set energy market prices at the strike price effectively grant theseller the right to exercise market power.

$9.0

Jan-12$/MWh$37.67$160.84$56.15$52.55$173.79$84.93$38.86$41.41$53.74$42.55$24.64$56.94Jul-10Total Credits$761,854$1,456,324$2,172,454$2,559,831$14,298,502$5,576,152$1,381,972$1,281,762$1,566,879$548,928$57,078$310,165

Jan-11

Total MWh
20,225
9,055
38,692
48,711
82,27365,65335,55930,95429,155
12,902
2,316
5,447

Jan-10(Jan-Jun)
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Figure 6-2 Economic program credits and MWh by month: 2010 through June
2021

Credits (Millions)

Table 6-16 Credits paid to economic program participants: January throughJune, 2010 through 2021

Table 6-17 shows performance for the first six months of 2020 and 2021 in
the economic program by control zone. Total reported reductions under the
economic program increased by 2,013 MWh, 155.2 percent, from 1,297 MWhin the first six months of 2020 to 3,311 MWh in the first six months of 2021.
Total revenue under the economic program increased by $0.18 million, 667.2
percent, from $0.03 million in the first six months of 2020 to $0.2 million in
the first six months of 2021.67
Emergency and economic demand response energy payments are uplift andnot compensated by LMP revenues. Economic demand response energy costs
are assigned to real-time exports from the PJM Region and real-time loads in

65 PJM. “Manual 11: Energy & Ancillary Services Market Operations,” § 10.4.5, Rev. 115 (June 1, 2021).
66 Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 831, 157 FERC ¶61,115 (2016) (“Order No. 831”).

© 2021 Monitoring Analytics, LLC

67 Economic demand response reductions that are submitted to PJM for payment but have not received payment are not included in Table
6-17. Payments for Economic demand response reductions are settled monthly.

2021 Quarterly State of the Market Report for PJM: January through June 347

2021 Quarterly State of the Market Report for PJM: January through Juneeach zone for which the load-weighted average real-time LMP for the hour during which the reduction occurred is greater than the price determined under the
net benefits test for that month.68 The zonal allocation is shown in Table 6-17.
Table 6-17 Economic program participation by zone: January through June, 2020 and 2021
Zones
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DUQ
DOM
DPL
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
Total

Credits
2020
2021
Percent(Jan-Jun)(Jan-Jun)
Change
$0.00
$0.00
NA
$0.00
$0.00
NA
$972.50 $11,908.84 1,124.6%$0.00$8,015.61
NA$0.00$5,143.02
NA$365.44$7,627.21 1,987.1%
$0.00
$0.00
NA
$0.00
$0.00
NA
$0.00
$0.00
NA
$0.00
$3,333.94
NA$0.00$7,138.76
NA
$0.00
$0.00
NA
$0.00
$0.00
NA
$0.00
$0.00
NA
$3,509.34 $70,159.54 1,899.2%
$0.00
$0.00
NA
$16.26$0.00
NA$136.91 $51,331.62 37,393.0%$21,444.79 $38,221.62
78.2%
$0.00
$0.00
NA
$26,445.24 $202,880.16
667.2%

MWh Reductions
2020
2021
Percent(Jan-Jun) (Jan-Jun)
Change
0
0
NA
0
0
NA
48
165
245.4%
0
80
NA
0
48
NA
291
156
(46.2%)
0
0
NA
0
0
NA
0
0
NA
0
21
NA
0
81
NA
0
0
NA
0
0
NA
0
0
NA
86
1,268 1,374.1%
0
0
NA
0
0
NA
6
1,031 18,130.7%
867
460(46.9%)
0
0
NA
1,297
3,311
155.2%

Credits per MWh Reduction
2020
2021
Percent(Jan-Jun) (Jan-Jun)
Change
NA
NA
NA
NA
NA
NA
$20.42$72.39254.5%
NA$99.75NANA$106.41NA$1.26$48.75 3,782.8%
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
$156.29NANA$88.64
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
$40.80$55.33
35.6%
NA
NA
NA
$89.05NANA$24.21$49.79105.7%$24.75$83.11235.8%
NA
NA
NA$20.39$61.28200.6%

Table 6-18 shows average reported MWh reductions and credits by hour for the first six months of 2020 and 2021. The average LMP during Load Responseis the reduction weighted average hourly DA or RT load weighted LMP during the economic load response hour. In the first six months of 2020, 95.0 percentof the reported reductions and 91.8 percent of credits occurred in hours ending 0900 to 2100, and in the first six months of 2021, 84.9 percent of the reported
reductions and 86.3 percent of credits occurred in hours ending 0900 to 2100.

68 “PJM Manual 28: Operating Agreement Accounting,” § 11.2.2, Rev. 84 (Dec. 17, 2020).

348

Section 6 Demand Response© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

Table 6-18 Hourly frequency distribution of economic program reported MWh
reductions and credits: January through June, 2020 and 2021
Hour Ending (EPT)
1 through 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23 through 24
Total

MWh Reductions
2020
2021
Percent(Jan-Jun)(Jan-Jun)
Change($0.50)277(55,165%)
11
106
836%
83
138
66%
118
319
172%
124
336
170%
138
337
144%
145
312
115%
169
292
73%
191
411
115%
210
389
86%
203
416
105%
231
425
84%
258
471
82%
234
454
94%
135
289
114%
44
172
291%
18
133
651%
5
169
3,506%
2,316
5,447
135%

Program Credits
2020
2021
Percent(Jan-Jun)(Jan-Jun)
Change($11.66)$13,119 (112,609%)$447$5,237
1,071%$3,629$7,767114%$3,450$14,883331%$3,396$14,953
340%$3,430$15,310346%$3,468$15,354
343%$3,530$14,044298%$4,609$24,533432%$4,856$21,793349%$3,559$25,569
619%$4,545$29,592551%$6,548$35,857448%$6,062$32,123430%$3,565$14,256300%$1,391$9,340572%$543$7,437
1,269%$62$9,00014,507%$57,078$310,165
443%

Table 6-19 shows the distribution of economic program reported MWh reductions
and credits by ranges of real-time zonal, load-weighted, average LMP in the firstsix months of 2020 and 2021. In the first six months of 2021, 1.9 percent ofreported MWh reductions and 5.0 percent of program credits occurred during
hours when the applicable zonal LMP was higher than $175 per MWh.

Economic Load Response revenues are paid by real-time loads and real-timescheduled exports as an uplift charge. Table 6-20 shows the sum of real-timeand day-ahead Economic Load Response charges paid in each zone and paidby exports. Real-time loads in AEP paid the highest Economic Load Response
charges in the first six months of 2021.
Table 6-20 Zonal Economic Load Response charge: 202169
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DEOK
DUQ
DOM
DPL
EKPC
JCPLC
MEC
OVEC
PECO
PENELEC
PEPCO
PPL
PSEG
RECO
EXPORTS
Total

January$142$2,443$980$1,214$586$1,578
$329
$499
$241
$2,135
$313
$273
$298
$243
$2
$606
$333
$488
$658
$785
$25
$681
$14,851

February$2,082$30,173$12,123$14,678$7,600$21,412$4,140$6,349$2,937$25,913$4,634$3,854$4,851$3,719$28$9,083$4,001$6,970$10,063$9,360$292$18,547$202,811

March$75$1,562
$672
$878
$635
$829
$268
$326
$140
$1,612
$199
$161
$186
$153
$1
$315
$197
$510
$335
$425
$14
$931
$10,424April$28$1,987$476$1,092$494$1,115
$348
$427
$212
$1,655
$584
$190
$68
$151
$2
$132
$130
$405
$284
$133
$4
$2,184$12,098

May
$34
$683
$262
$357
$156
$484
$95
$146
$77
$554
$66
$62
$104
$79
$0
$144
$90
$149
$200
$198
$8
$175
$4,122

June$934$9,223$3,725$5,106$2,735$6,954$1,324$2,165$1,109$8,664$1,571$969$2,403$1,278$6$3,440$1,233$2,489$3,186$4,076$171$3,099$65,859

Total$3,295$46,071$18,237$23,325$12,207$32,372$6,503$9,912$4,716$40,533$7,367$5,510$7,909$5,623$40$13,719$5,983$11,010$14,726$14,976$515$25,616$310,165

Table 6-19 Frequency distribution of economic program zonal, load-weighted,
average LMP (By hours): January through June, 2020 and 2021
LMP
$0 to $25
$25 to $50$50 to $75$75 to $100
$100 to $125
$125 to $150
$150 to $175
> $175Total

MWh Reductions
2020
2021
(Jan-Jun)(Jan-Jun)
1,495
865
665
2,712
89
760
31
501
22
383
0
94
15
26
0
106
2,316
5,447

© 2021 Monitoring Analytics, LLC

Percent
Change
(42%)
308%
751%
1,537%
100%
100%
100%
100%
135%

Program Credits
2020
2021
(Jan-Jun)(Jan-Jun)$34,600$23,726$22,593$113,323$1,450$46,703-$827$52,799-$179$44,337$9$10,826-$568$2,792$0$15,659$57,078$310,165

Percent
Change(31%)
402%
3,121%(6,485%)
100%
100%
100%
100%
443%

69 Load response charges were calculated as of August 6, 2021 and may change as a result of continued PJM billing updates.

2021 Quarterly State of the Market Report for PJM: January through June 349

2021 Quarterly State of the Market Report for PJM: January through June

Table 6-21 shows the total zonal Economic Load Response charge per GWh ofreal-time load and exports in the first six months of 2021.
Table 6-21 Zonal economic load response charge per GWh of load andexports: January through June, 2021
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DEOK
DUQ
DOM
DPL
EKPC
JCPLC
MEC
OVEC
PECO
PENELEC
PEPCO
PPL
PSEG
RECO
EXPORTSMonthly Average

January$0.000$0.211$0.212$0.216$0.208$0.201$0.216$0.216$0.216$0.220$0.183$0.200$0.000$0.000$0.194$0.178$0.217$0.194$0.171$0.221$0.223$0.216$0.178February$0.000$2.800$2.837$2.768$2.907$2.814$2.848$2.883$2.839$2.887$2.903$2.952$0.000$0.000$2.667$2.875$2.825$2.955$2.853$2.854$2.854$3.660$2.499March$0.000$0.156$0.170$0.172$0.271$0.118$0.203$0.164$0.141$0.198$0.142$0.158$0.000$0.000$0.131$0.105$0.140$0.242$0.099$0.134$0.138$0.280$0.144April$0.000$0.722$0.726$0.726$0.784$0.696$0.756$0.748$0.739$0.756$0.787$0.760$0.000$0.000$0.658$0.708$0.708$0.779$0.706$0.725$0.753$0.942$0.644May$0.000$0.072$0.072$0.072$0.071$0.070$0.074$0.073$0.075$0.070$0.050$0.069$0.000$0.000$0.058$0.051$0.071$0.073$0.067$0.064$0.075$0.063$0.059June$0.000$0.875$0.930$0.895$1.007$0.800$0.904$0.920$0.939$0.936$0.966$0.974$0.000$0.000$0.732$0.989$0.890$0.993$0.947$1.027$1.185$0.708$0.801

Zonal
Average$0.000$0.806$0.825$0.808$0.875$0.783$0.833$0.834$0.825$0.845$0.838$0.852$0.000$0.000$0.740$0.818$0.809$0.873$0.807$0.838$0.871$0.978$0.721

Table 6-22 shows the monthly day-ahead and real-time Economic Load
Response charges for 2020 through June 2021. The day-ahead Economic Load
Response charges increased by $165.4 thousand, 347.4 percent, from $47.6
thousand in the first six months of 2020 to $213.0 thousand in the first six
months of 2021. The real-time Economic Load Response charges increased$87.7 thousand, 926.6 percent, from $9.5 thousand in the first six months of2020 to $97.1 thousand in the first six months of 2021.

350

Section 6 Demand Response

Table 6-22 Monthly day-ahead and real-time economic load response charge:
2020 through June 2021
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

Day-ahead Economic Load Response Charge
Percent
2020
2021
Change$28,908$14,204(50.9%)$2,317$160,337
6,821.1%$936$10,287
999.3%$0$8,332NA$4,315$2,060(52.3%)$11,138$17,795
59.8%$87,384$70,100$10,140$1,694$10,064$25,410$252,407$213,016(15.6%)

Real-time Economic Load Response Charge
Percent
2020
2021
Change$1,391$648(53.5%)$335$42,474
12,591.2%$237$136(42.6%)$197$3,766
1,814.3%$1,846$2,062
11.7%$5,458$48,064780.7%$49,176$14,727$525$331$1,596$894$76,712$97,149
26.6%

Table 6-23 shows registered sites and MW for the last day of each monthfor the period January 1, 2015, through June 30, 2020. Registration is aprerequisite for CSPs to participate in the economic program. Average monthly
registrations decreased by 44, 12.6 percent, from 347 in the first six months of2020 to 303 in the first six months of 2021. Average monthly registered MW
decreased by 1,003 MW, 37.8 percent, from 2,653 MW in the first six monthsof 2020 to 1,650 MW in the first six months of 2021.
Most economic demand response resources are registered in the emergency
demand response program. Resources registered in both programs do not needto register for the same amount of MW. There are 89 economic registrations
and 95 capacity registrations in the emergency program that share the same
location ids in both programs. There are 950 nominated economic MW and
737 nominated capacity MW in the emergency program that share the same
location ids in both programs© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

Table 6-23 Economic program registrations on the last day of the month: 2015 through June 202170
2015
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Avg

Registrations
1,078
1,076
1,075
1,076
980
871
870
869
867
858
851
850
974

2016
Registered
MW
2,960
2,956
2,949
2,938
2,846
2,614
2,609
2,609
2,608
2,568
2,566
2,566
2,788

Registrations
838
835
834
832
829
518
519
805
831
822
820
807
774

2017
Registered
MW
2,557
2,557
2,556
2,556
2,545
2,500
2,421
2,569
2,608
2,564
2,564
2,561
2,547

Registrations
871
842
850
897
977
577
589
590
588
574
559
556
706

2018
Registered
MW
2,603
2,578
2,576
2,574
2,626
1,305
1,548
1,541
1,663
1,660
1,662
1,659
2,000

Registrations
537
537
519
501
471
397
374
382
378
382
381
392
438

2019
Registered
MW
2,570
2,628
2,641
2,624
2,615
2,576
2,591
2,609
2,580
2,584
2,581
2,671
2,606

Registrations
374
370
378
366
372
370
376
360
368
375
379
383
373

2020
Registered
MW
2,651
2,640
2,648
2,594
3,193
2,768
2,899
2,885
2,954
2,909
3,051
3,070
2,855

Registrations
377
382
380
350
308
285
283
292
297
275
280
282
316

2021
Registered
MW
2,909
2,912
2,941
2,917
2,824
1,418
1,453
1,482
1,566
1,361
1,375
1,327
2,040

Registrations
282
280
295
304
332
326

Registered
MW
1,519
1,527
1,545
1,567
1,697
2,045

303

1,650

The registered MW in the economic load response program are not a good measure of the MW available for dispatch in the energy market. Economic resources
can dispatch up to the amount of MW registered in the program, but are not required to offer any MW. Table 6-24 shows the sum of peak economic MW
dispatched by registration each month from January 1, 2010, through June 30, 2021. The monthly peak is the sum of each registration’s monthly noncoincident
peak dispatched MW and annual peak is the sum of each registration’s annual noncoincident peak dispatched MW. The peak dispatched MW for all economic
demand response registered resources increased by 79 MW, 124.5 percent, from 63 MW in the first six months of 2020 to 142 MW in the first six months of2021.71 The largest monthly peak MW reduction in the first six months of 2021, 86 MW in February, was 1,564 MW less than the average MW registered in thefirst six months of 2021, 1,650 MW.
Table 6-24 Sum of peak MW reported reductions for all registrations per month: 2010 through June 2021
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Annual

2010
183
121
115
111
172
209
999
794
276
118
111
114
1,202

2011
132
89
81
80
98
561
561
161
84
81
86
88
840

Sum of Peak MW Reductions for all Registrations per Month
2012
2013
2014
2015
2016
2017
2018
2019
110
193
446
169
139
123
142
88
101
119
307
336
128
83
70
58
72
127
369
198
120
111
71
38
108
133
146
143
118
54
71
41
143
192
151
161
131
169
70
22
954
433
483
833
121
240
105
26
1,631
1,088
665
1,362
1,316
936
518
770
952
497
358
272
249
141
581
33
451
530
795
816
263
140
112
76
242
168
214
136
150
88
69
29
165
155
166
127
116
81
54
35
98
168
155
122
147
83
11
31
1,942
1,486
1,739
1,858
1,451
1,217
758
830

2020
28
11
12
3
12
38
135
99
31
9
12
14
196

2021
21
86
20
22
9
62

142

70 Data for years 2010 through 2014 are available in the 2018 State of the Market Report for PJM.
71 The total credits and MWh numbers for demand resources were calculated as of August 6, 2021 and may change as a result of continued PJM billing updates.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 351

2021 Quarterly State of the Market Report for PJM: January through June

Table 6-25 shows total settlements submitted for the first six months of 2010
through 2021. A settlement is counted for every day on which a registration
is dispatched in the economic program.

resources. The MMU recommends that the rules for maximum offer forthe emergency and pre-emergency program match the maximum offer for
generation resources.

Table 6-25 Settlements submitted in the economic program: 2010 throughJune 2021

On April 1, 2012, FERC Order No. 745 was implemented in the PJM economic
program, requiring payment of full LMP for dispatcheddemand resources when a net benefits test (NBT) price
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Number of Settlements
1,345
317
1,348
820
1,806
1,091
652
800
737
426
193
289
threshold is exceeded. This approach replaced the payment
of LMP minus the charges for wholesale power andtransmission
includedin customers’ tariff rates. Following FERC Order No.
Table 6-26 shows the number of CSPs, and the number of participants in their745,
all
ISO/RTOsarerequired
to calculate an NBT threshold price each month
portfolios, submitting settlements for the first six months of 2010 throughabove which the net benefits of DR are deemed to exceed the cost to load. PJM
2021. The number of active participants increased by 13, 76.5 percent, from
calculates the NBT price threshold by first taking the generation offers from
17 in the first six months of 2020 to 30 in the first six months of 2021. All
the same month of the previous year. For example, the NBT price calculation
participants must be registered through a CSP.
for February 2017 was calculated using generation offers from February 2016.
PJM then adjusts these offers to account for changes in fuel prices and uses
Table 6-26 Participants and CSPs submitting settlements in the economic
these adjusted offers to create an average monthly supply
program by year: 2010 through June 2021
curve. PJM estimates a function that best fits this supply(Jan-Jun)
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Active CSPs
10
9
18
12
17
12
6
8
11
9
8
9
curve and then finds the point on this curve where theActive Participants
131
129
331
85
144
68
20
42
30
24
17
30
elasticity is equal to one.74 The price at this point is the NBT
threshold price.

IssuesFERC Order No. 831 requires that each RTO/ISO market monitoring unit verify
all energy offers above $1,000 per MWh.72 Economic resources offer into theenergy market and must provide supporting documentation to offer above$1,000 per MWh. FERC stated, “[t]he offer cap reforms, however, do not apply
to capacity-only demand response resources that do not submit incremental
energy offers into energy markets.”73 Demand resources participate in boththe capacity and energy markets and are not capacity only resources. It is
not clear whether FERC intended to exclude demand resources with highstrike prices from the requirements of FERC Order No. 831. Demand resources
should not be permitted to make offers above $1,000 per MWh without thesame verification requirements applied to economic resources or generation
72 157 FERC ¶ 61,115 at P 139 (2016).
73 Id. at 8.

352

Section 6 Demand Response

The NBT test is a crude tool that is not based in market logic. The NBT
threshold price is a monthly estimate calculated from a monthly supply
curve that does not incorporate real-time or day-ahead prices. In addition,
it is a single threshold price used to trigger payments to economic demand
response resources throughout the entire RTO, regardless of their location andregardless of locational prices.
The necessity for the NBT test is an illustration of the illogical approach to
demand side compensation embodied in paying full LMP to demand resources.
The benefit of demand side resources is not that they suppress market prices,
but that customers can choose not to consume at the current price of power,that individual customers benefit from their choices and that the choices of
all customers are reflected in market prices. If customers face the market price,
74 “PJM Manual 11: Energy & Ancillary Services Market Operations,” §10.3.1, Rev. 115 (June 1, 2021).

© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

customers should have the ability to not purchase power and the market
impact of that choice does not require a test for appropriateness.
When the zonal LMP is above the NBT threshold price, economic demand
response resources that reduce their power consumption are paid the fullzonal LMP. When the zonal LMP is below the NBT threshold price, economic
demand response resources are not paid for any load reported reductions.
Table 6-27 shows the NBT threshold price for the historical test from August2010 through July 2011, and April 2012, when FERC Order No. 745 was
implemented in PJM, through June 2021. The historical test was used asjustification for the method of calculating the NBT for future months. The
NBT threshold price has never exceeded the lowest historical test result of$34.07 per MWh.

Table 6-28 shows the number of hours that at least one zone in PJM had dayahead LMP or real-time LMP higher than the NBT threshold price. In the firstsix months of 2021, the highest zonal LMP in PJM was higher than the NBT
threshold price 3,952 hours out of 4,343 hours, or 91.0 percent of all hours.
Reductions occurred in 991 hours, 25.1 percent, of those 3,952 hours in thefirst six months of 2021. The last three columns illustrate how often economic
demand response activity occurred when LMPs exceeded NBT threshold prices
for January 1, 2020, through June 30, 2021. There are no economic payments
when demand response occurs and zonal LMP is below the NBT threshold.
Demand response reported reductions occurred in none of the hours in which
LMP was below the NBT threshold price in the first six months of 2021, and
0.2 percent (1 hour) of the hours in which LMP was below the NBT thresholdprice in the first six months of 2020.

Table 6-27 Net benefits test threshold prices: August 2010 through June 2021
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Average

Historical Test($/MWh)2010
2011$40.27$40.49$38.48$36.76$34.68$35.09$36.78$35.57$34.07$38.10$36.83$37.04$36.32$37.51© 2021 Monitoring Analytics, LLC

2012$25.89$23.46$23.86$22.99$24.47$24.93$25.96$25.63$25.97$24.802013$25.72$26.27$25.60$26.96$27.73$28.44$29.42$28.58$28.80$29.13$31.63$28.82$28.092014$29.51$30.44$34.93$32.59$32.08$31.62$31.62$29.85$29.83$30.20$29.17$29.01$30.91Net Benefits Test Threshold Price ($/MWh)
2015
2016
2017
2018
$29.63$23.67$32.60$26.27$26.52$26.71$31.57$24.65$24.99$22.10$30.56$25.50$24.92$19.93$30.45$25.56$23.79$20.69$29.77$25.52$23.80$20.62$27.14$23.59$23.03$20.73$24.42$23.57$23.17$23.24$22.75$23.53$21.69$24.70$21.51$22.23$21.48$26.50$21.70$23.84$22.28$29.27$26.41$23.89$22.31$29.71$29.16$26.35$23.97$23.99$27.34$24.542019$29.44$23.49$22.15$22.36$21.01$20.20$19.76$19.57$18.19$20.20$21.11$22.24$21.642020$20.04$19.29$17.44$15.91$14.69$15.56$14.66$14.58$15.16$17.25$18.35$19.47$16.872021$18.11$18.70$20.82$23.47$21.40$22.35$20.812021 Quarterly State of the Market Report for PJM: January through June 353

2021 Quarterly State of the Market Report for PJM: January through June

Table 6-28 Hours with price higher than NBT and economic load response
occurrences in those hours: 2020 through June 2021
Number of Hours
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

2020
744
696
743
720
744
720
744
744
720
744
721
744
8,784

2021
744
672
743
720
744
720

4,343

Number of Hours with LMPHigher than NBTPercent
2020
2021
Change
569
741
30.2%
513
667
30.0%
558
698
25.1%
606
618
2.0%
635
636
0.2%
495
592
19.6%
675
695
648
676
607
712
7,389
3,952

Percent of NBT Hours with
Economic Load Response
Percent
2020
2021
Change38.1%
11.9%(26.3%)
15.0%
50.2%
35.2%
9.0%
12.5%
3.5%
2.0%
21.4%
19.4%
19.5%
24.4%
4.8%
36.4%
32.8%
(3.6%)
50.1%
24.9%
7.4%
3.3%
14.2%
18.7%
19.8%
25.1%

Energy Efficiency

efficiency MW were 86.5 percent of all energy efficiency MW and HVAC,
new construction and appliances were 13.5 percent in the 2019/2020 Delivery
Year. Prescriptive energy efficiency MW were 85.1 percent and HVAC, newconstruction and appliances were 14.9 percent in the 2020/2021 Delivery
Year. The measurement and verification method for prescriptive energy
efficiency projects relies on neither measurement or verification but instead
relies on unverified assumptions and is too imprecise to rely on as a sourceof capacity comparable to capacity from a power plant. The nonprescriptive
measurement and verification methods are also inadequate and rely on
samples and assumptions for limited periods.76 There is no evidence that the
programs result in changed behavior or increases in savings.
The MMU recommends that energy efficiency MW not be included in the
PJM Capacity Market. The measurement and verification protocols for energy
efficiency are too imprecise to rely on as a source of capacity. Effective energy
efficiency measures reduce energy usage and capacity usage directly. The
reduced market payments are the appropriate compensation.

Calculating the Nominated MW value for Energy Efficiency (EE) resources
is different than calculating the Nominated MW value for other capacity
resources. The maximum amount of Nominated MW a generator can offer
into the capacity market is based on the maximum output of a generator.
EE resources do not produce power, but reduce power consumption. The
Nominated MW for EE resources are not measured, although they could be,
but a calculated value based on a set of largely unverified and unverifiableassumptions.
Figure 6-3 shows the installed EE MW in PJM by technology for the 2019/2020
and 2020/2021 Delivery Years. An installed EE resource may participate as acapacity resource for up to four consecutive delivery years.75
Prescriptive energy efficiency MW have an assumed savings calculated basedon an assumed installation rate and the difference between the assumed
electricity usage of what is being replaced and the assumed electricity
usage of the new product. All lighting EE is prescriptive. Prescriptive energy
75 PJM. “Manual 18: PJM Capacity Market,” § 4.4, Rev. 46 (Nov. 19, 2020).

354

Section 6 Demand Response

76 PJM. “Manual 18B: Energy Efficiency Measurement & Verification,” § 2.2 Rev. 04 (August 22, 2019).

© 2021 Monitoring Analytics, LLC

Section 6 Demand Response

Figure 6-3 Installed energy efficiency MW by type: 2019/2020 and2020/2021 Delivery Years

Table 6-29 Energy efficiency resources (MW): Delivery Years 2011/2012
through 2022/2023

2,500
2019/2020 Residential
2019/2020 Commercial
2020/2021 Residential

2,000

2020/2021 Commercial

MW

1,500

1,000

EE Percent Cleared
0.1%
0.5%
0.6%
0.7%
0.7%
1.0%
1.1%
1.3%
1.4%
2.1%
2.8%
3.3%

Distributed Energy Resources

50002011/20122012/20132013/20142014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021
2021/2022
2022/2023

UCAP (MW)EE RPM Cleared
Total RPM Cleared
76.4
134,139.6
666.1
141,061.8
904.2
159,830.5
1,077.7
161,092.4
1,189.6
173,487.4
1,723.2
179,749.0
1,922.3
180,590.3
2,296.3
175,957.4
2,528.5
177,040.6
3,569.5
173,688.5
4,806.2
174,713.0
4,810.6
144,477.3

Lighting

HVAC, New Construction,
Appliances
Residential

Lighting, Prescriptive

HVAC, Small Business,
Construction, Other

Commercial

Energy efficiency resources are included in the PJM Capacity Market. Table
6-29 shows the amount of energy efficiency (EE) resources in PJM on
June 1 for the 2011/2012 through 2022/2023 Delivery Years. EE resources
may participate in PJM without restrictions imposed by a state unless theCommission authorizes a state to impose restrictions.77 Only Kentucky has
been authorized by the Commission.78 The total MW of energy efficiency
resources committed increased by 34.6 percent from 3,569.5 MW in the2020/2021 Delivery Year to 4,806.2 MW in the 2021/2022 Delivery Year.79

77 See 161 FERC ¶ 61,245 at P 57 (2017); 107 FERC ¶ 61,272 at P 8 (2008).
78 The Commission made an exception for Kentucky when it determined that RERRAs must obtain FERC approval prior to excluding EE,
explaining that “the Commission accepted such condition at the time the Kentucky Commission approved the integration of Kentucky
Power into PJM.” 161 FERC ¶ 61,245 at P 67.
79 See the 2019 State of the Market Report for PJM, Vol. 2, Section 5: Capacity Market, Table 5-13.

© 2021 Monitoring Analytics, LLC

Distributed Energy Resources (DER) are not well defined, but generally include
small scale generation directly connected to the grid, generation connected
to distribution level facilities and behind the meter generation.80 For example,
Table 6-10 shows the fuel mix of behind the meter generation participating
as emergency demand response in the 2019/2020 Delivery Year. Clear rules
for defining DERs and for defining the ways in which DERs will interact
with the wholesale power markets do not yet exist, although the developmentof those rules is under active discussion.81 82 DERs should be treated likeother resources. Creating preferential treatment for DERs could create an
incentive to move resources behind the meter in a manner inconsistent withefficiency and competitive markets. FERC directed that DER aggregation be as
geographically broad as technically feasible.83
The current demand response rules appropriately restrict demand response
from injecting power into the grid and receiving demand response revenue. At
80 Some energy storage facilities may be DERs. FERC Order No. 841 requires that energy storage resources have access to capacity, energy
and ancillary service markets. See Electric Storage Participation in Markets Operated by Regional Transmission Organizations andIndependent System Operators, Order No. 841, 162 FERC ¶ 61,127 at P 1 (2018).
81 In PJM, the Distributed Energy Resources Subcommittee (DERSC) is currently discussing these issues. Distributed Energy Resources
Subcommittee, PJM, <http://www.pjm.com/‌committees-and-groups/subcommittees/ders.aspx>.
82 See “Notice of Technical Conference,” Docket No. RM18-9-000 and AD18-10-000 (February 15, 2018); “Technical Conference Distributed
Energy Resources,” Docket No. RM18-9-000 and AD18-10-000 (April 10, 2018).
83 162 FERC ¶ 32,718 at P 139 (2016).

2021 Quarterly State of the Market Report for PJM: January through June 355

2021 Quarterly State of the Market Report for PJM: January through June

the January 30, 2019, Demand Response Subcommittee meeting, PJM, withouta stakeholder process or FERC approval, decided to allow some economic
load response payments when economic load response resources injects power
into the grid. PJM’s test compares the total benefits of running the generator
which includes generation payments and assumed retail rate savings against
the total cost of the generator. If the total cost of the generator is greaterthan the benefits, then the resource would receive economic load response
payments while injecting. The use of a retail rate in calculating wholesale
power market benefits raises significant issues analogous to net meteringthat require discussion and tariff changes. PJM should not include retail rate
benefits in the definition of demand response without approval of FERC.
Aggregation to a single node is technically feasible. Allowing DER aggregation
across nodes is not necessary and is not consistent with the nodal market
design. Getting the rules correct at the beginning of DER development isessential to the active and effective participation of DER in the wholesale
power markets in a manner that enhances rather than undercuts the efficiency
and competitiveness of the power markets.

356

Section 6 Demand Response© 2021 Monitoring Analytics, LLC

Section 7 Net Revenue

Net Revenue
The Market Monitoring Unit (MMU) analyzed measures of PJM energy market
structure, participant conduct and market performance. As part of the review
of market performance, the MMU analyzed the net revenues earned by
combustion turbine (CT), combined cycle (CC), coal plant (CP), diesel (DS),
nuclear, solar, and wind generating units.

Overview
Net Revenue• Energy market net revenues are significantly affected by energy prices

and fuel prices. Energy prices and gas prices were higher in the first six
months of 2021 than in the first six months of 2020.

• In the first six months of 2021, average energy market net revenues

increased by 69 percent for a new combustion turbine (CT), 53 percent
for a new combined cycle (CC), 3,288 percent for a new coal plant (CP),57 percent for a new nuclear plant, 542 percent for a new diesel (DS),33 percent for a new onshore wind installation, 63 percent for a newoffshore wind installation and 48 percent for a new solar installationcompared to the first six months of 2020.

• The price of natural gas increased by significantly more than the price ofcoal in the first six months of 2021, as a result of very high gas prices in
mid February. As a result, the marginal costs of a new CC and a new CT
were greater than the marginal cost of a new CP in February 2021 but
lower in all other months in the first six months of 2021.

• Based on Western Hub prices, the spark spread in the first six months of2021 increased by 34 percent while the spark spread standard deviation
increased by 125 percent and the dark spread increased by 125 percent
while the dark spread standard deviation decreased by 145 percent.

Recommendations• The MMU recommends that the net revenue calculation used by PJM tocalculate the net Cost of New Entry (CONE) and net ACR be based on a

© 2021 Monitoring Analytics, LLC

forward looking estimate of expected energy and ancillary services net
revenues using forward prices for energy and fuel. (Priority: Medium.
First reported 2019. Status: Adopted 2020.)

Conclusion
Wholesale electric power markets are affected by externally imposed
reliability requirements. A regulatory authority external to the market makes
a determination as to the acceptable level of reliability which is enforced
through a requirement to maintain a target level of installed or unforced
capacity. The requirement to maintain a target level of installed capacity canbe enforced via a variety of mechanisms, including government constructionof generation, full-requirement contracts with developers to constructand operate generation, state utility commission mandates to constructcapacity, or capacity markets of various types. Regardless of the enforcement
mechanism, the exogenous requirement to construct capacity in excess ofwhat is constructed in response to energy market signals has an impact onenergy markets. The reliability requirement results in maintaining a level ofcapacity in excess of the level that would result from the operation of anenergy market alone. The result of that additional capacity is to reduce thelevel and volatility of energy market prices and to reduce the duration of highenergy market prices. This, in turn, reduces net revenue to generation owners
which reduces the incentive to invest. The exact level of both aggregate andlocational excess capacity is a function of the calculation methods used by
RTOs and ISOs.

Net Revenue
When compared to annualized fixed costs and avoidable costs, net revenue
is an indicator of generation investment profitability, and thus is a measureof overall market performance as well as a measure of the incentive to invest
in new generation and to maintain existing generation in PJM markets.
Net revenue equals total revenue received by generators from PJM energy,
capacity and ancillary service markets and from the provision of black startand reactive services, less the short run marginal costs of energy production.
In other words, net revenue is the amount that remains, after the short

2021 Quarterly State of the Market Report for PJM: January through June 357

2021 Quarterly State of the Market Report for PJM: January through Juneboth increased significantly. Coal prices were relatively unchanged for theentire time period and across PJM. The price of eastern natural gas was 77.2
percent higher and the price of western natural gas was 168.1 percent higher;
the price of Northern Appalachian coal was 10.4 percent higher; the price ofCentral Appalachian coal was 32.8 percent higher; the price of Powder River
Basin coal was 1.2 percent lower (Figure 7-1).2

In a perfectly competitive, energy only market in long run equilibrium, net
revenue from the energy market would be expected to equal the annualized
fixed and avoidable costs for the marginal unit, including a competitive returnon investment. The PJM market design includes other markets that contributeto the payment of fixed and avoidable costs. In PJM, the energy, capacity andancillary service markets are all significant sources of revenue to cover the
fixed and avoidable costs of generators, as are payments for the provision of
black start and reactive services. Thus, in a perfectly competitive market inlong run equilibrium, with energy, capacity and ancillary service revenues,
net revenue from all sources would be expected to equal the annualized fixed
and avoidable costs of generation for the marginal unit. Net revenue is ameasure of whether generators are receiving competitive returns on invested
capital and of whether market prices are high enough to encourage entryof new capacity and to encourage maintaining existing capacity. In actual
wholesale power markets, where equilibrium seldom occurs, net revenue is
expected to fluctuate above and below the equilibrium level based on actual
conditions in all relevant markets.

Figure 7-1 Energy market net revenue factor trends: 2014 through June 2021

1 Avoidable costs are sometimes referred to as going forward costs.

358

Section 7 Net Revenue

$20
$10
$0

Average Monthly Coal Prices by LDA

$8
$6

$4
$2
$0

RTO

EMAAC

Jan-21

Jan-20Jan-19Jan-17Jan-18Average Monthly RT LMP by LDA

Jan-16

$200
$160
$120
$80
$40
$0

Jan-15

Coal Price ($/MMBtu)

RT LMP ($/MWh)

Average Monthly Gas Prices by LDA$30

Jan-14

Net revenues are significantly affected by energy prices, fuel prices andcapacity prices. PJM real-time energy market prices increased significantly inthe first six months of 2021. The load-weighted, average, real-time LMP was
57.8 percent higher in the first six months of 2021 than in the first six monthsof 2020, $30.62 per MWh versus $19.40 per MWh. Gas prices increased in
the first six months of 2021 compared to the first six months of 2020, as aresult of very high gas prices in mid February. Gas price volatility increased
and gas price differences among regions increased. Western PJM gas prices
were much higher in mid February than eastern PJM gas prices although

Gas Price ($/MMBtu)

run marginal costs of energy production have been subtracted from grossrevenue. Net revenue is the contribution to fixed costs, which include areturn on investment, depreciation and income taxes, and to avoidable costs,
which include long term and intermediate term operation and maintenanceexpenses.1 Net revenue is the contribution to total fixed and avoidable costs
received by generators from all PJM markets.

SWMAAC

Spark Spreads and Dark Spreads
The spark or dark spread is defined as the difference between the LMP received
for selling power and the cost of fuel used to generate power, converted toa cost per MWh. The spark spread compares power prices to the cost of gas
and the dark spread compares power prices to the cost of coal. The spread is a
2 Average daily gas prices in COMED were above $129/MMBTU from February 13 through February 16, 2021.

© 2021 Monitoring Analytics, LLC

Section 7 Net Revenue

measure of the approximate difference between revenues and marginal costs
and is an indicator of net revenue and profitability.

Figure 7-2 shows the hourly spark spread for peak hours for BGE, COMED,
PSEG, and Western Hub.
Figure 7-2 Hourly spark spread (gas) for peak hours ($/MWh): 2018 throughJune 20213

$500
$250
$0

Western Hub

BGE

COMED

Apr-21

Jan-21

Oct-20($250)

Jul-20Western Hub
Spark
Dark
$24.00$59.98$20.75$30.36$19.43$18.00$13.28$13.09$14.58$24.72$10.42$10.63$10.30$7.93$13.78$17.84$0($250)$750

Apr-20Dark$67.29$34.42$11.39$10.40$15.96
$3.31
$3.44
$8.52

$250

Jan-20PSEG
Spark$18.81$11.78$11.41$11.39
$2.10
$8.00
$7.65
$9.91

$500

Oct-19

COMED
Spark
Dark
$12.20$54.10$14.39$29.34$13.79$22.89$10.94$24.93$12.58$25.30$9.07$20.89$8.63$13.65($3.05)$25.76$0($250)$750

Jul-19Dark$77.06$39.96$26.95$15.89$30.62$13.24$9.63$25.07$250

Apr-19BGE
Spark$33.99$21.61$26.11$14.82$13.64$13.07$11.80$20.78$500

Jan-19Jan-Jun
2014
2015
2016
2017
2018
2019
2020
2021

$0
($250)$750

Oct-18

Table 7-1 Peak hour spreads ($/MWh): January through June, 2014 through
2021

$250

Jul-18

Table 7-1 shows average peak hour spreads for January through June, by year
and Table 7-2 shows the associated standard deviations.

$500

Apr-18Spark spreads increased in the first six months of 2021 compared to the firstsix months of 2020 with the exception of COMED, and the volatility of sparkspreads increased. Dark spreads increased significantly in the first six monthsof 2021 compared to the very low levels in the first six months of 2020.

$750

Jan-18Spread volatility is a result of fluctuations in LMP and the price of fuel.
Spreads can be positive or negative.

PSEG

Table 7-2 Peak hour spread standard deviation ($/MWh): January throughJune, 2014 through 2021
Jan-Jun
2014
2015
2016
2017
2018
2019
2020
2021

BGE
Spark
$121.7
$48.4
$29.1
$16.9
$67.7
$24.3
$14.9
$39.4

Dark
$162.2
$52.5
$29.3
$17.9
$46.7
$24.9
$14.8
$40.4

© 2021 Monitoring Analytics, LLC

COMED
Spark
$95.2
$23.0
$12.9
$12.6
$18.6
$18.9
$10.5
$104.0

Dark
$94.1
$25.9
$12.9
$12.6
$20.5
$19.0
$10.5
$28.7

PSEG
Spark
$108.9
$40.1
$14.8
$14.7
$70.9
$21.5
$7.8
$22.8

Dark
$126.8
$50.9
$16.3
$15.9
$43.5
$25.6
$8.0
$26.0

Western Hub
Spark
Dark
$116.2$118.2
$37.2
$39.7
$16.5
$16.8
$13.6
$13.8
$56.7
$38.5
$20.2
$20.0
$11.7
$11.7
$26.4
$28.6

3 Spark spreads use a combined cycle heat rate of 7,000 Btu/kWh, zonal hourly LMPs and daily gas prices; Chicago City Gate for COMED,
Zone 6 non-NY for BGE, Zone 6 NY for PSEG, and Texas Eastern M3 for Western Hub.

2021 Quarterly State of the Market Report for PJM: January through June 359

2021 Quarterly State of the Market Report for PJM: January through June

Figure 7-3 Hourly dark spread (coal) for peak hours ($/MWh): 2018 throughJune 20214$700

Analysis of energy market net revenues for a new entrant includes eight
power plant configurations:• The CT plant is a single GE Frame 7HA.02 CT with an installed capacityof 360.1 MW, equipped with evaporative coolers, and selective catalytic
reduction (SCR) for NOx reduction.

$450
$200

• The CC plant includes two GE Frame 7HA.02 CTs and a single steam

($50)
$700

turbine generator with an installed capacity of 1,137.2 MW, equippedwith evaporative cooling, duct burners, a heat recovery steam generator(HRSG) for each CT, with steam reheat, and SCR for NOx reduction.

$450
$200

• The CP is a subcritical steam unit with an installed capacity of 600.0 MW,

($50)
$700

equipped with selective catalytic reduction system (SCR) for NOx control,a flue gas desulphurization (FGD) system with chemical injection for SOx
and mercury control, and a bag-house for particulate control.

$450
$200

($50)
$700

• The DS plant is a single oil fired CAT 2 MW unit with an installed capacity$450

of 2.0 MW using New York Harbor ultra low sulfur diesel.

$200

Western Hub

BGE

COMED

Apr-21

Jan-21

Oct-20Jul-20

Apr-20Jan-20

Oct-19Jul-19Apr-19Jan-19Oct-18

Jul-18Apr-18Jan-18

($50)

PSEG

• The nuclear plant includes two units and related facilities using theWestinghouse AP1000 technology with an installed capacity of 2,200
MW.

• The onshore wind installation includes 37 Siemens 2.7 MW wind turbineswith an installed capacity of 99.9 MW.

Theoretical Energy Market Net Revenue
The net revenues presented in this section are theoretical as they arebased on explicitly stated assumptions about how a new unit with specificcharacteristics would operate under economic dispatch. The economic
dispatch uses technology specific operating constraints in the calculation of a
new entrant’s operations and potential net revenue in PJM markets.

4 Dark spreads use a heat rate of 10,000 Btu/kWh, zonal hourly LMPs and daily coal prices; Powder River Basin coal for COMED, Northern
Appalachian coal for BGE and Western Hub, and Central Appalachian coal for PSEG.

360

Section 7 Net Revenue• The offshore wind installation includes of 43 Siemens 7.0 MW windturbines with an installed capacity of 301.0 MW.

• The solar installation is a 35.5 acre ground mounted fixed tilt solar farmwith an installed AC capacity of 10 MW.

Net revenue calculations for the CT, CC and CP include the hourly effect of
actual local ambient air temperature on plant heat rates and generator output
for each of the three plant configurations.5 6 Plant heat rates account for theefficiency changes and corresponding cost changes resulting from ambient
air temperatures.
5 Hourly ambient conditions supplied by DTN.
6 Heat rates provided by Pasteris Energy, Inc. No load costs are included in the dispatch price since each unit type is dispatched at full load
for every economic hour resulting in a single offer point.

© 2021 Monitoring Analytics, LLC

Section 7 Net Revenue

CO2, NOx and SO2 emission allowance costs are included in the hourly plantdispatch cost, the short run marginal cost.7 CO2, NOx and SO2 emission
allowance costs were obtained from daily spot cash prices.8
The class average equivalent availability factor for each type of plant wascalculated from PJM data and incorporated into all revenue calculations.9 In
addition, each CT, CC, CP, and DS plant was assumed to take a continuous 14
day annual planned outage in the fall season.
Zonal net revenues reflect average zonal LMP and fuel costs based on
locational fuel indices and zone specific delivery charges.10 The delivered fuelcost for natural gas reflects the zonal, daily delivered price of natural gas
from a specific pipeline and is from published commodity daily cash prices,with a basis adjustment for transportation costs.11 The delivered cost of coalreflects the zone specific, delivered price of coal and was developed from thepublished prompt month prices, adjusted for rail transportation costs.12 Net
revenues are calculated for all zones except OVEC.13
Short run marginal cost includes fuel costs, emissions costs, and the short run
marginal component of VOM costs.14 15 Average short run marginal costs areshown, including all components, in Table 7-3 and the short run marginalcomponent of VOM is also shown separately.

Table 7-3 Average short run marginal costs: January through June, 2021
Short Run Marginal Costs($/MWh)$31.74$21.70$30.05$156.12
$0.00
$0.00
$0.00
$0.00

Unit Type
CT
CC
CP
DS
NuclearWindWind (off shore)
Solar

Heat Rate(Btu/kWh)
9,241
6,296
9,250
9,660
NA
NA
NA
NA

VOM
($/MWh)
$0.36
$1.41
$4.21
$0.25
$0.00
$0.00
$0.00
$0.00

A comparison of the monthly average short run marginal cost of the theoretical
CT, CC and CP plants since 2014 shows that, on average, the short run marginal
costs of the CC plant have been less than those of the CP plant but the costs of
the CC plant have been more volatile than the costs of the CP plant as a resultof the higher volatility of gas prices compared to coal prices (Figure 7-4). The
marginal costs of a new CC and a new CT were greater than the marginal costof a new CP in February 2021 as a result of higher gas prices.
Figure 7-4 Average short run marginal costs: 2014 through June 2021
$160
$140
$120

$/MWh

$100
$80
$60

© 2021 Monitoring Analytics, LLC$40

Combustion Turbine

Combined Cycle

Jan-21

Jul-20Jan-20Jul-19Jan-19Jul-18Jan-18

Jul-17Jan-17

Jul-16

Jan-16

Jul-15Jan-15$0Jul-14$20

Jan-14

7 CO2 emission allowance costs only included for states participating in RGGI, including New Jersey.
8 CO2, NOx and SO2 emission daily prompt prices obtained from Evolution Markets, Inc.
9 Outage figures obtained from the PJM eGADS database.
10 Startup fuel burns and emission rates provided by Pasteris Energy, Inc. Startup station power consumption costs were obtained from thestation service rates published quarterly by PJM and netted against the MW produced during startup at the preceding applicable hourly
LMP. All starts associated with combined cycle units are assumed to be hot starts.
11 Gas daily cash prices obtained from Platts.
12 Coal prompt month prices obtained from Platts.
13 The Ohio Valley Electric Corporation (OVEC) includes a generating plant in Ohio and a generating plant in Indiana, and high voltage
transmission lines, but does not occupy a single geographic footprint like the other control zones.
14 Fuel costs are calculated using the daily spot price and may not equal what individual participants actually paid.
15 VOM rates provided by Pasteris Energy, Inc.

Coal Plant

2021 Quarterly State of the Market Report for PJM: January through June 361

2021 Quarterly State of the Market Report for PJM: January through June

The net revenue measure does not include the potentially significant
contribution from the explicit or implicit sale of the option value of physicalunits or from bilateral agreements to sell output at a price other than the PJM
day-ahead or real-time energy market prices, e.g., a forward price.
Gas prices, coal prices, and energy prices are reflected in new entrant capacity
factors. The new entrant coal plant ran for significantly more hours in the firstsix months of 2021 than in the first six months of 2020, returning to levels
consistent with years prior to 2020. Table 7-4 shows the average capacity
factor by a new entrant unit.

entrant CT energy market net revenue results must therefore be interpreted
carefully when comparing to existing CTs which are generally smaller andless efficient than the newest CT technology used by the new entrant CT.
New entrant CT plant energy market net revenues were higher in all zones
in the first six months of 2021 as a result of significantly higher and morevariable energy prices (Table 7-5).
Table 7-5 Energy net revenue for a new entrant gas fired CT under economic
dispatch: January through June, 2014 through 2021 (Dollars per installed
MW-year)17

Table 7-4 Average capacity factor: January through June, 2014 through202116
2014
2015
2016
2017
2018
2019
2020
2021

CT
44%
64%
73%
51%
61%
48%
50%
40%

CC
73%
75%
78%
72%
81%
79%
79%
79%

CP
68%
59%
44%
40%
42%
20%
5%
38%

DS
3%
2%
1%
0%
2%
0%
0%
1%

Nuclear
91%
91%
91%
93%
93%
92%
92%
92%

On Shore Wind
28%
28%
27%
31%
30%
31%
29%
27%

Solar
16%
17%
18%
18%
17%
17%
17%
17%

New Entrant Combustion Turbine
Energy market net revenue was calculated for a new CT plant economicallydispatched by PJM. It was assumed that the CT plant had a minimum run timeof two hours. The unit was first committed day ahead in profitable blocks ofat least two hours, including start costs. If the unit was not already committed
day ahead, it was run in real time in standalone profitable blocks of at least
two hours, or any profitable hours bordering the profitable day-ahead or realtime block.

Jan-Jun

Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
PE
PECO
PEPCO
PPL
PSEG
REC
PJM

2014
2015
$51,479 $26,005$62,250 $42,653$77,468 $66,162$43,857 $36,924$61,495 $38,350$27,876 $17,159$39,225 $33,094$50,208 $35,840$46,937 $19,150$35,780 $30,718$25,207 $36,035$55,492 $32,527$54,318 $26,878$53,343 $46,578$99,087 $88,025$54,579 $44,710$56,325 $28,133$168,527 $112,259$69,311 $53,948$46,017 $29,502$58,381 $42,233

2016$23,746$32,990$26,197$29,695$43,159$17,212$29,593$37,800$8,613$27,633$31,440$29,305$20,974$29,477$43,327$27,284$25,534$34,885$31,736$23,026$28,6812017$12,124$15,429$13,892$16,281$16,980$10,209$14,867$16,537$6,051$12,647$13,360$13,006$14,647$19,969$19,656$15,780$11,650$19,740$19,066$14,601$14,8252018$15,705$49,925$53,671$59,503$33,675$18,727$55,365$36,928$12,651$63,049$30,735$36,197$16,763$22,832$57,431$21,488$27,918$63,060$24,585$17,078$35,8642019$11,586$18,287$9,176$19,174$12,140$8,739$20,595$15,356$5,848$17,926$9,497$15,150$10,532$10,980$16,612$9,561$8,266$11,728$11,108$10,506$12,6382020$2,430$16,225$5,274$16,436$7,875$8,040$18,965$12,237$1,247$16,284$10,554$14,392$3,218$11,571$14,917$8,883$4,586$8,042$2,589$2,690$9,3232021$4,773$18,688$12,994$18,702$19,847$9,364$27,300$20,838$14,544$25,936$14,701$17,786$4,566$16,851$22,732$8,957$11,358$21,447$8,368$15,004$15,738

Change in
2021
from 2020
96%
15%
146%
14%
152%
16%
44%
70%
1,067%
59%
39%
24%
42%
46%
52%
1%
148%
167%
223%
458%
69%

The new entrant CT is larger and more efficient than most CTs currently
operating in PJM. The economically dispatched new entrant CT ran for morethan twice as many hours as large CTs currently operating in PJM. The new
16 Previous year run hours changed slightly since 2020 Quarterly State of the Market report for PJM: January through June. Run hours andnet revenues are fully recalculated for the previous year when calculating for the annual 2020 State of the Market Report for PJM andmay change slightly due to parameter updates or changes in market settlements data.

362

Section 7 Net Revenue

17 The energy net revenues presented for the PJM area in this section are calculated using the zonal average LMP.

© 2021 Monitoring Analytics, LLC

Section 7 Net Revenue

New Entrant Combined Cycle

New Entrant Coal Plant

Energy market net revenue was calculated for a new CC plant economicallydispatched by PJM. It was assumed that the CC plant had a minimum run
time of four hours. The unit was first committed day ahead in profitable
blocks of at least four hours, including start costs.18 If the unit was not alreadycommitted day ahead, it was run in real time in standalone profitable blocks
of at least four hours, or any profitable hours bordering the profitable dayahead or real-time block.

Energy market net revenue was calculated for a new CP plant economicallydispatched by PJM. It was assumed that the CP plant had a minimum run
time of eight hours. The unit was first committed day ahead in profitable
blocks of at least eight hours, including start costs. If the unit was not alreadycommitted day ahead, it was run in real time in standalone profitable blocks
of at least eight hours, or any profitable hours bordering the profitable dayahead or real-time block.

New entrant CC plant energy market net revenues were higher in all zones in
the first six months of 2021 as a result of significantly higher energy prices(Table 7-6).

New entrant CP plant energy market net revenues were higher in all zones asa result of significantly higher energy prices and flat coal prices (Table 7-7).

Table 7-6 Energy net revenue for a new entrant CC under economic dispatch:
January through June, 2014 through 2021 (Dollars per installed MW-year)19

Table 7-7 Energy net revenue for a new entrant CP: January through June,2014 through 2021 (Dollars per installed MW-year)20
Jan-JunJan-Jun

Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
PE
PECO
PEPCO
PPL
PSEG
REC
PJM

2014
2015
$77,910 $41,482$80,667 $58,043$104,178 $87,007$57,323 $53,578$91,855 $60,469$34,099 $28,538$51,222 $50,146$71,328 $53,013$67,969 $31,170$45,485 $46,921$39,767 $43,861$71,520 $48,587$82,534 $42,377$76,482 $59,458$121,100 $91,427$80,280 $59,612$81,839 $51,074$175,856 $108,381$102,122 $69,749$74,533 $43,573$100,026 $56,423

2016$31,979$42,244$47,376$40,087$63,095$27,354$40,077$47,832$18,750$38,033$40,020$38,818$29,333$36,630$48,581$34,590$46,260$40,752$39,136$30,982$39,0962017$24,589$28,036$29,989$28,503$33,489$18,715$27,717$29,620$10,594$24,761$25,555$25,152$26,977$31,426$31,696$27,836$26,783$31,196$31,203$26,899$27,0372018$30,979$66,703$75,987$74,616$56,746$28,545$71,699$52,076$20,437$78,100$48,213$53,811$32,182$38,973$72,200$39,705$48,646$73,559$43,334$31,720$51,9122019$26,876$35,491$29,233$36,249$33,233$20,690$38,031$32,586$7,843$34,977$24,360$31,741$26,191$27,049$33,796$24,598$27,318$26,478$27,699$26,709$28,557

2020$12,713$26,921$21,172$27,227$25,065$16,429$29,891$23,763$2,527$27,166$22,093$25,425$13,412$22,132$25,296$19,210$18,126$18,716$14,041$14,345$20,2832021$14,922$35,692$35,239$36,426$43,630$20,462$45,809$38,093$18,110$43,407$30,329$35,091$15,621$32,887$40,536$23,966$27,920$36,886$19,812$24,904$30,987

18 All starts associated with combined cycle units are assumed to be warm starts.
19 The energy net revenues presented for the PJM area in this section represent the zonal average energy net revenues.

© 2021 Monitoring Analytics, LLC

Change in
2021
from 2020
17%
33%
66%
34%
74%
25%
53%
60%
617%
60%
37%
38%
16%
49%
60%
25%
54%
97%
41%
74%
53%

Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
PE
PECO
PEPCO
PPL
PSEG
REC
PJM

2014
$110,016$91,742$96,402$101,926$147,786$86,470$93,750$131,449$145,222$85,996$80,681$84,338$115,034$138,008$112,535$107,549$111,094$106,670$156,341$152,005$112,751

2015$42,712$34,840$36,188$37,524$63,487$25,325$34,959$67,595$60,730$31,681$28,093$27,191$42,984$57,486$47,624$41,133$36,225$40,128$66,278$66,876$44,453

2016$4,765$15,141$4,518$12,382$21,365$7,835$11,559$24,256$7,811$9,947$10,715$8,667$3,186$6,811$10,013$2,890$5,616$2,923$6,066$5,755$9,1112017$1,541$16,617$7,754$17,184$7,201$14,107$15,367$10,217$5,227$12,461$15,267$11,519$1,956$7,991$5,951$1,569
$1,480$1,807$5,086$5,017$8,2662018$28,258$41,080$34,050$41,261$42,449$15,391$39,867$49,068$37,255$45,652$40,954$27,602$29,053$37,085$31,933$28,219$28,166$27,687$33,449$31,819$34,5152019$3,223$7,238$3,177$6,331$4,664$7,121$6,677$7,354$4,958$5,164$5,159$3,736$2,994$5,199$4,373$2,862$2,108$1,754$4,364$5,092$4,677

2020
$0
$701
$472
$821
$600
$313
$530
$1,630$6$326$1,081$370$292$1,131
$469
$0
$200
$0
$0
$0
$447

2021
$4,207$26,429$9,213$18,726$15,256$18,923$30,105$25,394$14,897$27,885$17,873$23,158$4,097$14,813$14,559$6,172$8,161$7,276$5,658$10,264$15,153

Change in
2021
from 2020
NA
3,668%
1,853%
2,180%
2,442%
5,942%
5,581%
1,458%
236,766%
8,462%
1,553%
6,156%
1,301%
1,209%
3,003%
NA
3,982%
NA
NA
NA
3,288%

20 The energy net revenues presented for the PJM area in this section represent the zonal average energy net revenues.

2021 Quarterly State of the Market Report for PJM: January through June 363

2021 Quarterly State of the Market Report for PJM: January through June

New Entrant Nuclear Plant

New Entrant Diesel

Energy market net revenue was calculated assuming that the nuclear plant
was dispatched day ahead by PJM for all available plant hours. The unit
runs for all hours and output reflects the class average equivalent availability
factor.21

Energy market net revenue was calculated for a DS plant economicallydispatched by PJM in real time.

New entrant nuclear plant energy market net revenues were higher in allzones as a result of significantly higher energy prices (Table 7-8).
Table 7-8 Energy net revenue for a new entrant nuclear plant: January
through June, 2014 through 2021 (Dollars per installed MW-year)22 23

New entrant DS plant energy market net revenues were higher in all zones
in the first six months of 2021 as a result of significantly higher and morevariable energy prices (Table 7-9).
Table 7-9 Energy market net revenue for a new entrant DS: January throughJune, 2014 through 2021
Jan-JunJan-Jun

Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
PE
PECO
PEPCO
PPL
PSEG
REC
PJM

2014
$291,903$219,655$241,956$230,792$314,365$195,097$220,842$277,170$310,128$211,557$205,396$209,562$297,424$284,391$254,203$287,466$307,444$285,412$316,811$311,648$263,661

2015$172,604$143,288$163,260$146,504$200,861$118,244$142,586$184,228$188,601$138,819$135,212$133,500$172,994$168,312$159,652$169,441$190,801$168,746$181,357$182,253$163,063

2016$94,039$104,839$108,416$105,198$139,198$94,979$105,296$119,020$107,363$103,047$103,024$101,485$90,785$90,886$100,433$88,661$126,466$90,878$93,735$93,272$103,051

2017$112,950$117,268$119,009$120,297$129,188$110,771$119,311$124,737$119,242$115,571$117,900$114,339$115,975$117,468$116,219$112,915$126,128$114,532$117,175$117,435$117,921

2018$150,493$150,899$161,430$157,947$182,670$110,502$154,673$177,476$162,082$161,868$157,284$138,300$151,690$149,789$151,515$150,482$178,183$146,136$155,462$154,317$155,160

2019$104,009$108,947$109,819$110,870$118,718$98,594$112,862$114,364$105,652$109,398$108,584$106,788$103,222$104,233$107,207$101,467$116,051$99,342$105,298$106,997$107,621

2020$68,807$77,798$77,653$78,768$82,967$70,455$81,786$78,456$70,275$78,710$79,153$77,581$69,725$71,096$74,385$67,727$79,873$67,845$69,789$71,176$74,701

2021$103,451$121,269$118,891$118,664$136,385$112,064$129,260$129,548$120,481$126,544$116,931$120,786$104,066$111,790$113,568$101,970$128,862$106,164$109,054$117,892$117,382

Change in
2021
from 2020
50%
56%
53%
51%
64%
59%
58%
65%
71%
61%
48%
56%
49%
57%
53%
51%
61%
56%
56%
66%
57%

Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
PE
PECO
PEPCO
PPL
PSEG
REC
PJM

2014
$32,410$14,425$17,985$14,091$49,408$11,311$14,235$42,515$36,404$13,404$12,963$14,441$32,656$31,729$15,964$31,976$51,102$32,671$32,232$29,776$29,7872015$11,338$2,986$6,292$2,731$12,649$1,685$2,832$9,746$13,289$2,256$2,211$2,182$11,922$11,759$5,425$11,253$9,734$11,908$11,410$12,635$7,8122016$2,081
$492
$580
$458
$4,557$242$454$1,765$1,679
$561
$423
$664
$553
$529
$407
$553
$2,227
$470
$629
$663
$999

2017
$288
$93
$184
$298
$987
$0
$80
$662
$965
$122
$286
$34
$433
$376
$331
$526
$516
$455
$427
$378
$372

2018
$9,957$3,909$6,358$6,617$12,227$609$3,469$14,172$11,609$5,860$7,435$1,701$11,080$10,929$5,355$9,794$11,950$8,756$10,267$9,466$8,0762019$1,359
$801
$780
$746
$1,351$686$856$1,172$1,764
$789
$713
$787
$1,360$741$487$1,307$1,199$373$1,710$1,632$1,031

2020
$183
$336
$491
$422
$767
$239
$382
$771
$114
$327
$1,110
$372
$659
$408
$269
$123
$490
$140
$117
$120
$392

2021
$880
$1,559$1,289$1,135$4,253$1,692$2,706$4,773$11,107$2,403$1,441$2,313$761$1,650$933$893$2,394$1,129$1,293$5,762$2,518Change in
2021
from 2020
380%
364%
163%
169%
455%
608%
608%
519%
9,661%
635%
30%
522%
15%
304%
247%
627%
388%
709%
1,004%
4,715%
542%

21 The annual class average equivalent availability factor was used in the calculation of energy market net revenues.
22 The energy net revenues presented for the PJM area in this section represent the zonal average energy net revenues because fuel costs
for nuclear units are included in the NEI nuclear costs.
23 The net revenues have changed since the 2018 State of the Market Report for PJM. The marginal cost of the nuclear plant has been
reduced from $8.50/MWh to $0/MWh. Unit fuel costs have been moved to ACR.

364

Section 7 Net Revenue© 2021 Monitoring Analytics, LLC

Section 7 Net Revenue

New Entrant Onshore Wind Installation
Energy market net revenues for an onshore wind installation were calculated
hourly assuming the unit generated at the average capacity factor of all
operating wind units in the zone with an installed capacity greater than 3
MW.24 The unit is credited with wind RECs for its generation and is assumed tohave taken a 1603 payment instead of either the Investment Tax Credit (ITC)or Production Tax Credit (PTC).25
Onshore wind energy market net revenues were higher as a result ofsignificantly higher energy prices.
Table 7-10 Energy market net revenue for an onshore wind installation(Dollars per installed MW-year): January through June, 2014 through 2021
Jan-Jun

Zone
AEP
APS
COMED
PE

2014
$71,059$73,063$62,869$89,2392015$45,467$47,789$37,130$59,5222016$37,474$31,619$29,490$32,895

2017$41,392$42,647$40,419$43,4252018$58,702$59,279$36,688$59,833

2019$40,125$34,603$35,376$34,277

2020$24,558$25,860$20,066$22,7262021$32,726$29,577$32,378$27,715

Change in
2021
from 2020
33%
14%
61%
22%

New Entrant Offshore Wind Installation
Energy market net revenues for an offshore wind installation were calculated
hourly assuming the unit generated at a 45 percent capacity factor. The unit
is credited with wind RECs for its generation and is assumed to have taken a1603 payment instead of either the Investment Tax Credit (ITC) or Production
Tax Credit (PTC).
Offshore wind energy market net revenues were higher as a result of higher
energy prices.

24 Net revenues are calculated for zones in which there are sufficient operating units to determine capacity factor for a new entrant unit.
25 The 1603 payment is a direct payment of 30 percent of the project cost. The use of the 1603 option is based on observed behavior in the
PJM markets.

© 2021 Monitoring Analytics, LLC

Table 7-11 Energy market net revenue for an offshore wind installation(Dollars per installed MW-year): January through June, 2014 through 2021
Jan-Jun

Zone
ACEC
DPL
DOM

2014
$134,418$143,956$141,540

2015$81,270$87,857$84,985

2016$46,240$50,057$56,7912017$53,639$56,721$58,9492018$72,276$78,227$86,670

2019$50,462$51,262$53,9712020$34,017$34,149$38,406

2021$48,785$61,406$63,283

Change in
2021
from 2020
43%
80%
65%

New Entrant Solar Installation
Energy market net revenues for a solar installation were calculated hourly
assuming the unit was generating at the average hourly capacity factor ofoperating solar units in the zone with an installed capacity greater than 3
MW.26 The unit is credited with SRECs for its generation and is assumed tohave taken a 1603 payment instead of either the Investment Tax Credit (ITC)or Production Tax Credit (PTC).27
Solar energy market net revenues were higher as a result of significantly
higher energy prices.
Table 7-12 Energy market net revenue for a solar installation (Dollars per
installed MW-year): January through June, 2014 through 2021
Jan-Jun

Zone
ACEC
DOM
DPL
JCPLC
PSEG

2014
$41,502$39,801$37,132

2015$28,041$23,113$27,3902016$16,764$32,557$19,854$14,984$17,6322017$18,900$35,050$26,389$17,766$19,7512018$22,066$43,202$29,708$20,413$22,6102019$16,681$27,655$21,191$15,354$17,4872020$11,376$20,529$13,800$10,866$12,1332021$15,530$34,028$19,318$15,329$18,899

Change in
2021
from 2020
37%
66%
40%
41%
56%

26 Net revenues are calculated for zones in which there are sufficient operating units to determine capacity factor for a new entrant unit.
27 The 1603 payment is a direct payment of 30 percent of the project cost.

2021 Quarterly State of the Market Report for PJM: January through June 365

2021 Quarterly State of the Market Report for PJM: January through June

Historical New Entrant CC Revenue Adequacy
Total unit net revenues include energy and capacity revenues. Analysis of
the total unit revenues of theoretical new entrant CCs for three representative
locations shows that CC units that entered the PJM markets in 2007 havecovered 86 percent of their total costs in the BGE Zone, 87 percent in the
PSEG Zone, and 45 percent of total costs in the COMED Zone, including
the return on and of capital, on a cumulative basis. The analysis also showsthat theoretical new entrant CCs that entered the PJM markets in 2012 havecovered their total costs on a cumulative basis in the PSEG Zone, 97 percent
of total costs in the BGE Zone and 56 percent of total costs in the COMED
Zone. Energy market revenues alone were not sufficient to cover total costs
in any scenario, which demonstrates the critical role of the capacity market
revenue in covering total costs.

Figure 7-5 Historical new entrant CC revenue adequacy: 2007 through June
2021 and 2012 through June 202128$2,500,000$2,000,000$1,500,000$1,000,000$500,000
$0

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

$1,500,000$1,200,000$900,000$600,000

Under cost of service regulation, units are guaranteed that they will cover
their total costs, assuming that the costs were determined to be reasonable. To
the extent that units built in the PJM markets did not cover their total costs,
investors were worse off and customers were better off than under cost ofservice regulation.
Figure 7-5 compares cumulative energy market net revenues and energy
market net revenues plus capacity market revenues to cumulative levelized
costs for a new entrant CC that began operation on January 1, 2007, and a
new entrant CC that began operation on January 1, 2012. The solid black line
shows the total net revenue required to cover total costs. The solid coloredlines show net energy revenue by zone. The dashed colored lines show thesum of net energy and capacity revenue by zone.

$300,000
$0

2012

2013

2014

2015

2016

2017

2018

BGE Energy

BGE Energy + Capacity

PSEG Energy

COMED Energy

COMED Energy + Capacity

Levelized Cost

2019

2020

2021

PSEG Energy + Capacity

Table 7-13 shows the percent of levelized total costs recovered.
Table 7-13 Percent of levelized total costs recovered
BGE
COMED
PSEG

2007 CC
86%
45%
87%

2012 CC
97%
56%
100%

28 The gas pipeline pricing points used in this analysis are Zone 6 non-NY for BGE, Chicago City Gate for COMED, and Texas Eastern M3 for
PSEG.

366

Section 7 Net Revenue© 2021 Monitoring Analytics, LLC

Section 7 Net Revenue

Assumptions used for this analysis are shown in Table 7-14.
Table 7-14 Assumptions for analysis of new entry in 2007 and 2012
Project Cost
Fixed O&M ($/MW-Year)End of Life Value
Loan Term
Percent Equity (%)
Percent Debt (%)
Loan Interest Rate (%)
Cost of Equity (%)
Federal Income Tax Rate (%)
State Income Tax Rate (%)
General Escalation (%)
Technology
ICAP (MW)
Depreciation MACRS 150% declining balance
IRR (%)

2007 CC$658,598,000$20,016$0
20 years
50%
50%
7%
12.0%
35%
9%
2.5%
GE Frame 7FA.04
601
20 years
12.0%

2012 CC$665,995,000$20,126$0
20 years
50%
50%
7%
12.0%
35%
9%
2.5%
GE Frame 7FA.05
655
20 years
12.0%

Nuclear Net Revenue Analysis
The analysis of nuclear plants includes annual avoidable costs andincremental capital expenditures from the Nuclear Energy Institute (NEI)
based on NEI’s calculations of average costs for all U.S. nuclear plants.29 30
The analysis includes the most recent operating cost data and incremental
capital expenditure data for single unit plants and multi unit plants publishedby NEI, for 2019.31 This is likely to result in conservatively high costs for theforward looking analysis. NEI average operating costs have decreased since

29 Operating costs from: Nuclear Energy Institute (October, 2020). “Nuclear Costs in Context,” <https://www.nei.org/CorporateSite/media/
filefolder/resources/reports-and-briefs/Nuclear-Costs-in-Context.pdf>. Individual plants may vary from the average due to factors suchas geographic location, local labor costs, the timing of refueling outages and other unit specific factors. This is the most current NEI data
available.
30 The NEI costs for Hope Creek were treated as that of a two unit configuration because the unit is located in the same area as Salem 1 &2. The net surplus of Hope Creek is sensitive to the accuracy of this assumption.
31 NEI also provides average costs by plant run by operators with one plant or multiple plants, by market, and by type of nuclear
reactor. Plants run by operators with multiple plants have lower average costs than plants run by operators with a single plant. Plants
participating in wholesale markets have lower average costs than plants in regulated markets. PWR reactors have lower average costs
than BWR reactors.

© 2021 Monitoring Analytics, LLC

their peak in 2012 (11.5 percent decrease from 2012 through 2019 for all plants
including single and multiple unit plants).32 NEI average incremental capital
expenditures have decreased since their peak in 2012 (45.6 percent decrease
from 2012 through 2019 for all plants including single and multiple unit
plants).33 NEI’s incremental capital expenditures peaked in 2012 as a result of
regulatory requirements following the 2011 accident at the Fukushima nuclear
plant in Japan.
The results for nuclear plants are sensitive to small changes in PJM energy
and capacity prices, both actual and forward prices.34 When gas prices arehigh and LMPs are high as a result, net revenues to nuclear plants increase.
In 2014, the polar vortex resulted in a significant increase in net revenues
to nuclear plants. When gas prices are low and LMPs are low as a result, net
revenues to nuclear plants decrease. In 2016, PJM energy prices were thenat the lowest level since the introduction of competitive markets on April 1,
1999, and remained low in 2017. As a result, in 2016 and 2017, a significant
proportion of nuclear plants did not cover annual avoidable costs based on
current year prices.35 In 2018, high gas prices and high LMPs resulted in asignificant increase in net revenues for nuclear plants in PJM. Energy prices
in 2018 were significantly higher than in 2017. Although energy prices in2019 were lower than in 2016, higher capacity market revenues more thanoffset the difference. Energy prices in 2020 were lower than 2019 prices, but
forward energy prices for 2021 through 2023 are above 2019 energy prices.
The result is that nuclear plant energy revenues based on forward period
prices are expected to be higher than 2019 energy revenues. The results fornuclear plants are also sensitive to changes in costs and whether actual unit
costs are less than or greater than the benchmark NEI data.

32 Operating costs in this paragraph are operating costs as specified by NEI and do not include fuel costs or capital expenditures. Operating
costs for single unit plants decreased by $3.22/MWh, or 11.6 percent, from 2018 to 2019, a likely result of both cost reductions and theexclusion of recently retired single unit plants. Operating costs for single unit plants decreased by $2.01/MWh or 7.6 percent from 2012
to 2019. Operating costs for multiple unit plants decreased by $0.44/MWh, or 2.5 percent, from 2018 to 2019, and decreased by $2.21/
MWh, or 11.5 percent, from 2012 to 2019.
33 Capital expenditures have decreased 46.0 percent since 2012 for single unit plants and 44.5 percent for multiple unit plants.
34 A change in the capacity market price of $24 per MW-day translates into a change in capacity revenue of $1.00 per MWh for a nuclear
power plant operating at a capacity factor of 100 percent. A change in the capacity market price of $24 per MW-day translates into achange in capacity revenue of $1.08 per MWh for a nuclear power plant operating at a capacity factor of 0.929 percent.
35 The MMU submitted testimony in New Jersey on the same issues of nuclear economics. Establishing Nuclear Diversity Certificate
Program. Bill No. S-877 New Jersey Senate Environment and Energy Committee. (2018). Revised Statement of Joseph Bowring.

2021 Quarterly State of the Market Report for PJM: January through June 367

2021 Quarterly State of the Market Report for PJM: January through June

Table 7-15 includes the publicly available data on energy market prices, Table 7-16 and Table 7-17 show capacity market prices and Table 7-18 shows nuclear
cost data for the 16 nuclear plants in PJM in addition to Oyster Creek, which retired September 17, 2018, and Three Mile Island, which retired September 20,
2019.36 The analysis excludes the Cook nuclear units, the Catawba 1 nuclear unit, and the Surry nuclear units. The Cook nuclear units are designated FRR andreceive cost of service revenues and are not subject to PJM market revenues.37 Catawba 1 is not in PJM but is pseudo tied to PJM. Surry 1 and 2 are part of
Dominion FRR for the 2022/2023 Delivery Year.
For nuclear plants, all calculations are based on publicly available data in order to avoid revealing confidential information. Nuclear unit revenue is based on
day-ahead LMP at the relevant node. Nuclear unit capacity revenue assumes that the unit cleared its full unforced capacity at the BRA locational clearing price.
Unforced capacity is determined using the annual class average EFORd rate.
Table 7-15 Nuclear unit day-ahead LMP: 2008 through 2020
Beaver Valley
Braidwood
Byron
Calvert Cliffs
Davis Besse
Dresden
Hope Creek
LaSalleLimerickNorth Anna
Oyster Creek
Peach Bottom
Perry
Quad Cities
Salem
Surry
Susquehanna
Three Mile Island

ICAP
(MW)
1,808
2,337
2,300
1,708
894
1,797
1,172
2,271
2,242
1,892
608
2,347
1,240
1,819
2,328
1,676
2,520
803

2008
$49.46$48.10$47.61$78.63$48.76$73.34$47.96$73.49$75.14$75.49$73.09$47.28$73.41$71.96$69.96$72.462009$31.51$27.76$23.98$41.05$28.27$39.43$27.71$39.49$39.89$40.43$39.32$24.81$39.51$39.02$38.24$39.11

2010$35.59$31.48$28.49$51.27$32.73$48.03$31.53$48.23$50.59$49.29$47.70$36.99$27.53$48.02$49.30$45.95$46.72

2011$37.43$32.02$28.09$46.53$39.68$33.07$45.52$31.93$45.27$45.47$46.74$44.73$38.76$26.79$45.50$45.01$44.78$44.152012$30.34$27.51$24.25$35.19$31.68$28.42$33.07$27.56$33.09$33.87$33.69$32.81$31.68$20.43$33.06$33.62$32.10$32.43

Average DA LMP ($/MWh)
2013
2014
2015
$34.24$41.86$30.35$30.26$37.34$25.97$29.22$35.05$21.00$40.27$57.88$40.30$36.10$47.21$31.94$31.82$39.22$27.45$37.43$51.99$32.41$30.94$37.88$26.28$37.28$51.71$32.65$38.55$53.37$38.05$38.62$52.85$33.10$37.37$51.52$31.98$36.69$46.14$32.77$25.94$30.71$19.47$37.40$51.96$32.37$37.98$51.75$37.91$36.76$50.93$32.47$36.83$50.47$30.942016$27.07$24.30$17.94$32.64$27.80$25.89$23.20$23.95$23.37$30.50$23.79$23.07$27.84$18.04$23.18$30.08$23.66$22.962017$29.11$24.99$23.79$31.57$28.85$26.35$26.78$24.71$26.99$31.27$27.52$26.76$29.91$23.09$26.76$31.08$27.14$27.12

2018$36.35$27.11$26.96$38.79$34.44$28.25$32.93$27.19$33.08$38.44$34.03$32.63$37.24$25.54$32.90$38.50$32.42$31.762019$26.22$22.88$22.19$28.00$26.33$23.41$22.45$22.75$22.68$27.39$23.68$21.58$26.76$21.13$22.43$26.65$21.08$23.472020$20.33$18.23$17.66$21.88$20.54$18.73$17.32$18.14$17.31$21.06$18.07$16.93$20.49$15.95$17.32$20.41$16.03$19.0736 Installed capacity is from NEI, “Map of U.S. Nuclear Plants,” <https://www.nei.org/‌resources/map-of-us-nuclear-plants>.
37 See “Resources Designated in 2021/2022 FRR Capacity Plans as of May 1, 2018,” <https://www.pjm.com/-/media/markets-ops/rpm/rpm-auction-info/2021-2022/2021-2022-resources-designated-in-frr-plans.ashx?la=en>.

368

Section 7 Net Revenue© 2021 Monitoring Analytics, LLC

Section 7 Net Revenue

Table 7-16 BRA capacity market clearing prices ($/MW-Day): 2008 through 202238
Beaver Valley
Braidwood
Byron
Calvert Cliffs
Davis Besse
Dresden
Hope Creek
LaSalleLimerickNorth Anna
Oyster Creek
Peach Bottom
Perry
Quad Cities
Salem
Surry
Susquehanna
Three Mile Island

ICAP
(MW)
1,808
2,337
2,300
1,708
894
1,797
1,172
2,271
2,242
1,892
608
2,347
1,240
1,819
2,328
1,676
2,520
803

07/08
$41
$41
$41
$189
$41
$198
$41
$198
$41
$198
$198
$41
$198
$41
$41
$41

08/09
$112
$112
$112
$210
$112
$149
$112
$149
$112
$149
$149
$112
$149
$112
$112
$112

09/10
$102
$102
$102
$237
$102
$191
$102
$191
$102
$191
$191
$102
$191
$102
$191
$191

10/11
$174
$174
$174
$174
$174
$174
$174
$174
$174
$174
$174
$174
$174
$174
$174
$174

11/12
$110
$110
$110
$110
$109
$110
$110
$110
$110
$110
$110
$110
$109
$110
$110
$110
$110
$110

12/13
$16
$16
$16
$133
$20
$16
$140
$16
$140
$16
$140
$140
$20
$16
$140
$16
$133
$133

BRA Capacity Price ($/MW-Day)
13/14
14/15
15/16
16/17
$28
$126
$136
$59
$28
$126
$136
$59
$28
$126
$136
$59
$226
$137
$167
$119
$28
$126
$357
$114
$28
$126
$136
$59
$245
$137
$167
$119
$28
$126
$136
$59
$245
$137
$167
$119
$28
$126
$136
$59
$245
$137
$167
$119
$245
$137
$167
$119
$28
$126
$357
$114
$28
$126
$136
$59
$245
$137
$167
$119
$28
$126
$136
$59
$226
$137
$167
$119
$226
$137
$167
$119

17/18
$120
$120
$120
$120
$120
$120
$120
$120
$120
$120
$120
$120
$120
$120
$120
$120
$120
$120

18/19
$165
$215
$215
$165
$165
$215
$225
$215
$225
$165
$225
$225
$165
$215
$225
$165
$165
$165

19/20
$100
$203
$203
$100
$100
$203
$120
$203
$120
$100
$120
$120
$100
$203
$120
$100
$100
$100

20/21
$77
$188
$188
$86
$77
$188
$188
$188
$188
$77
$188
$188
$77
$188
$188
$77
$86
$86

21/22
$140
$196
$196
$140
$171
$196
$166
$196
$166
$140
$166
$171
$196
$166
$140
$140
$140

2018
$6.42
$7.71
$7.71
$6.42
$6.42
$7.71
$7.98
$7.71
$7.98
$6.42
NA
$7.98
$6.42
$7.71
$7.98
$6.42
$6.42
$6.42

2019
$5.61
$9.20
$9.20
$5.62
$5.61
$9.20
$7.24
$9.20
$7.24
$5.61
NA
$7.24
$5.61
$9.20
$7.24
$5.61
$5.61
$5.61

2020
$3.84
$8.63
$8.63
$4.09
$3.84
$8.63
$7.09
$8.63
$7.09
$3.84
NA
$7.09
$3.84
$8.63
$7.09
$3.84
$4.08
$4.08

2021
$5.06
$8.56
$8.56
$5.23
$5.87
$8.56
$7.77
$8.56
$7.77
$5.06
NA
$7.77
$5.87
$8.56
$7.77
$5.06
$5.23
$5.23

2022
$3.88
$5.39
$5.39
$5.07
$4.45
$5.39
$5.60
$5.39
$5.60
$3.88
NA
$5.60
$4.45
$5.39
$5.60
NA
$5.07
NA

22/23
$50
$69
$69
$96
$50
$69
$98
$69
$98
$50
$98
$50
$69
$98
$96
-

Table 7-17 Nuclear unit capacity market revenue ($/MWh): 2008 through 202239 40
Beaver Valley
Braidwood
Byron
Calvert Cliffs
Davis Besse
Dresden
Hope Creek
LaSalleLimerickNorth Anna
Oyster Creek
Peach Bottom
Perry
Quad Cities
Salem
Surry
Susquehanna
Three Mile Island

ICAP
(MW)
1,808
2,337
2,300
1,708
894
1,797
1,172
2,271
2,242
1,892
608
2,347
1,240
1,819
2,328
1,676
2,520
803

2008
$3.57
$3.57
$3.57
$8.73
NA
$3.57
$7.33
$3.57
$7.33
$3.57
$7.33
$7.33
NA
$3.57
$7.33
$3.57
$3.57
$3.57

2009
$4.50
$4.50
$4.50
$9.59
NA
$4.50
$7.37
$4.50
$7.37
$4.50
$7.37
$7.37
NA
$4.50
$7.37
$4.50
$6.72
$6.72

2010
$6.23
$6.23
$6.23
$8.64
NA
$6.23
$7.82
$6.23
$7.82
$6.23
$7.82
$7.82
NA
$6.23
$7.82
$6.23
$7.82
$7.82

2011
$5.87
$5.87
$5.87
$5.87
NA
$5.87
$5.87
$5.87
$5.87
$5.87
$5.87
$5.87
NA
$5.87
$5.87
$5.87
$5.87
$5.87

2012
$2.41
$2.41
$2.41
$5.38
$2.49
$2.41
$5.54
$2.41
$5.54
$2.41
$5.54
$5.54
$2.49
$2.41
$5.54
$2.41
$5.38
$5.38

2013
$1.01
$1.01
$1.01
$8.21
$1.08
$1.01
$8.81
$1.01
$8.81
$1.01
$8.81
$8.81
$1.08
$1.01
$8.81
$1.01
$8.21
$8.21

Capacity Revenue ($/MWh)
2014
2015
2016
$3.70
$5.75
$3.96
$3.70
$5.75
$3.96
$3.70
$5.75
$3.96
$7.53
$6.74
$6.04
$3.70
$11.40
$9.33
$3.70
$5.75
$3.96
$7.87
$6.74
$6.04
$3.70
$5.75
$3.96
$7.87
$6.74
$6.04
$3.70
$5.75
$3.96
$7.87
$6.74
$6.04
$7.87
$6.74
$6.04
$3.70
$11.40
$9.33
$3.70
$5.75
$3.96
$7.87
$6.74
$6.04
$3.70
$5.75
$3.96
$7.53
$6.74
$6.04
$7.53
$6.74
$6.04

2017
$4.17
$4.17
$4.17
$5.26
$5.17
$4.17
$5.26
$4.17
$5.26
$4.17
$5.26
$5.26
$5.17
$4.17
$5.26
$4.17
$5.26
$5.26

38 Oyster Creek retired September 17, 2018. Exelon. “Oyster Creek Generating Station Retires from Service,” (September 17, 2018) <http://www.exeloncorp.com/newsroom/oyster-creek-retires>. Three Mile Island retired September 20, 2019. Exelon. “Three Mile Island Generating Station Unit 1
Retires from Service After 45 Years,” (September 20, 2019) <https://www.exeloncorp.com/newsroom/three-mile-island-generating-station-unit-1-retires>. For the 2022/2023 Delivery Year, Surry is part of Dominion FRR.
39 Capacity revenue calculated by adjusting the BRA Capacity Price for calendar year, by the class average EFORd, and by the 2019 class average capacity factor of 0.933 percent. Class average capacity factor is from 2019 State of the Market Report for PJM, Volume 2, Section 5: Capacity
Market.
40 Oyster Creek retired September 17, 2018. Exelon. “Oyster Creek Generating Station Retires from Service,” (September 17, 2018) <http://www.exeloncorp.com/newsroom/oyster-creek-retires>. Three Mile Island retired September 20, 2019. Exelon. “Three Mile Island Generating Station Unit 1
Retires from Service After 45 Years,” (September 20, 2019) <https://www.exeloncorp.com/newsroom/three-mile-island-generating-station-unit-1-retires>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 369

2021 Quarterly State of the Market Report for PJM: January through June

Table 7-18 Nuclear unit costs: 2008 through 201941 42
Beaver Valley
Braidwood
Byron
Calvert Cliffs
Davis Besse
Dresden
Hope Creek
LaSalleLimerickNorth Anna
Oyster Creek
Peach Bottom
Perry
Quad Cities
Salem
Surry
Susquehanna
Three Mile Island

ICAP
(MW)
1,808
2,337
2,300
1,708
894
1,797
1,172
2,271
2,242
1,892
608
2,347
1,240
1,819
2,328
1,676
2,520
803

2008
$26.73$26.73$26.73$26.73$35.31$26.73$26.73$26.73$26.73$26.73$35.31$26.73$35.31$26.73$26.73$26.73$26.73$35.31

2009$29.76$29.76$29.76$29.76$39.36$29.76$29.76$29.76$29.76$29.76$39.36$29.76$39.36$29.76$29.76$29.76$29.76$39.362010$31.34$31.34$31.34$31.34$41.23$31.34$31.34$31.34$31.34$31.34$41.23$31.34$41.23$31.34$31.34$31.34$31.34$41.232011$34.51$34.51$34.51$34.51$45.45$34.51$34.51$34.51$34.51$34.51$45.45$34.51$45.45$34.51$34.51$34.51$34.51$45.452012$36.06$36.06$36.06$36.06$47.41$36.06$36.06$36.06$36.06$36.06$47.41$36.06$47.41$36.06$36.06$36.06$36.06$47.41NEI Costs ($/MWh)
2013
2014
$33.84$33.84$33.84$33.84$33.84$33.84$33.84$33.84$44.16$44.32$33.84$33.84$33.84$33.84$33.84$33.84$33.84$33.84$33.84$33.84$44.16$44.32$33.84$33.84$44.16$44.32$33.84$33.84$33.84$33.84$33.84$33.84$33.84$33.84$44.16$44.32

2015$32.90$32.90$32.90$32.90$44.51$32.90$32.90$32.90$32.90$32.90$44.51$32.90$44.51$32.90$32.90$32.90$32.90$44.51

2016$31.63$31.63$31.63$31.63$41.39$31.63$31.63$31.63$31.63$31.63$41.39$31.63$41.39$31.63$31.63$31.63$31.63$41.392017$30.89$30.89$30.89$30.89$42.66$30.89$30.89$30.89$30.89$30.89$42.66$30.89$42.66$30.89$30.89$30.89$30.89$42.662018$29.07$29.07$29.07$29.07$42.00$29.07$29.07$29.07$29.07$29.07NA$29.07$42.00$29.07$29.07$29.07$29.07$42.002019$28.38$28.38$28.38$28.38$38.40$28.38$28.38$28.38$28.38$28.38NA$28.38$38.40$28.38$28.38$28.38$28.38NA

Table 7-19 shows the surplus or shortfall in $/MWh for the 16 nuclear plants in PJM and Oyster Creek and Three Mile Island calculated using historic LMP
and cost data. In 2016, 13 nuclear plants, with a total capacity of 25,075 MW, in addition to Oyster Creek and Three Mile Island, did not recover all their fuelcosts, operating costs, and capital expenditures. In 2017, seven nuclear plants with a total capacity of 12,658 MW, in addition to Oyster Creek and Three Mile
Island, did not recover all their fuel costs, operating costs, and capital expenditures. In 2018, one nuclear plant, with a total capacity of 894 MW, in addition to
Oyster Creek and Three Mile Island, did not recover all its fuel costs, operating costs, and capital expenditures. In 2019, two nuclear plants, with a total capacityof 4,654 MW, in addition to Three Mile Island, did not recover all their fuel costs, operating costs, and capital expenditures. Although Susquehanna shows ashortfall in 2019, cost reductions mean that Susquehanna did cover their fuel costs, operating costs, and capital expenditures.43 The surplus or shortfall assumes
that the unit cleared its full unforced capacity at the BRA locational clearing price.44 Unforced capacity is determined using the annual class average EFORd rate.
The market revenues are based in part on the sale of capacity. Some nuclear plants did not clear the capacity market as a result of decisions by plant owners
about how to offer the plants. When nuclear plants do not clear in the capacity market, it is a result of the offer behavior of the plants and does not reflect
the economic viability of the plants unless the plants offer accurate net avoidable costs and fail to clear. This analysis is intended to define whether the plants
are receiving a retirement signal from the PJM markets. If the plants are viable including both energy and capacity market revenues based on actual clearing
prices, then the PJM markets indicate that the plant is economically viable. If plant owners decide to offer so as to not clear in the capacity market, that does
not change the market signals to the plants. Such decisions may reflect a variety of considerations. Three Mile Island did not clear in the 2018/2019 Auction45
41 Operating costs from: Nuclear Energy Institute (October, 2020). “Nuclear Costs in Context,” <https://www.nei.org/resources/reports-briefs/nuclear-costs-in-context>.
42 Oyster Creek retired on September 17, 2018. Exelon. “Oyster Creek Generating Station Retires from Service,” (September 17, 2018) <http://www.exeloncorp.com/newsroom/oyster-creek-retires>. Three Mile Island retired September 20, 2019. Exelon. “Three Mile Island Generating Station
Unit 1 Retires from Service After 45 Years,” (September 20, 2019) <https://www.exeloncorp.com/newsroom/three-mile-island-generating-station-unit-1-retires>.
43 Talen Energy Investor Day, February 12, 2019.
44 Installed capacity is from NEI. “Maps of U.S. Nuclear Plants,” <https://www.nei.org/‌resources/map-of-us-nuclear-plants>.
45 Exelon. “Exelon Announces Outcome of 2019-2020 PJM Capacity Auction,” (May 25, 2016) <http://www.exeloncorp.com/newsroom/pjm-auction-results-2016>.

370

Section 7 Net Revenue© 2021 Monitoring Analytics, LLC

Section 7 Net Revenue

and Three Mile Island, Quad Cities, and a portion of Byron’s capacity did not clear in the 2019/2020 Auction.46 Three Mile Island and Quad Cities did not clear
in the 2020/2021 Auction.47 Three Mile Island, Dresden, and most of Byron did not clear in the 2021/2022 Auction.48 Beaver Valley, Davis Besse, and Perry did
not clear in the 2021/2022 Auction.49
Nuclear unit revenue is a combination of energy market revenue, ancillary market revenue and capacity market revenue. Negative energy market prices do nothave a significant impact on nuclear unit revenue. Since 2014, negative energy market prices have affected nuclear plants’ annual total revenues by an averageof 0.1 percent. Negative LMPs reduced nuclear plant total revenues by an average of 0.0 percent and a maximum of 0.6 percent in 2014, an average of 0.2
percent and a maximum of 1.2 percent in 2015, an average of 0.1 percent and a maximum of 0.7 percent in 2016, an average of 0.0 percent and a maximumof 0.6 percent in 2017, an average of 0.0 percent and a maximum of 0.0 percent in 2018, an average of 0.0 percent and a maximum of 0.2 percent in 2019, andan average of 0.1 percent and a maximum of 1.7 percent in 2020.50
In 2020, no nuclear plants covered their fuel costs, operating costs, and capital expenditures as a result of lower energy prices, based on current year (2020)
prices.
Table 7-19 Nuclear unit surplus (shortfall) based on public data: 2008 through 202051
Beaver Valley
Braidwood
Byron
Calvert Cliffs
Davis Besse
Dresden
Hope Creek
LaSalleLimerickNorth Anna
Oyster Creek
Peach Bottom
Perry
Quad Cities
Salem
Surry
Susquehanna
Three Mile Island

ICAP
(MW)
1,808
2,337
2,300
1,708
894
1,797
1,172
2,271
2,242
1,892
608
2,347
1,240
1,819
2,328
1,676
2,520
803

2008
$26.3
$24.9
$24.5
$60.6
NA
$25.6
$54.0
$24.8
$54.1
$52.0
$47.5
$53.7
NA
$24.1
$54.0
$48.8
$46.8
$40.7

2009
$6.3
$2.5
($1.3)
$20.9
NA
$3.0
$17.0
$2.5
$17.1
$14.6
$8.4
$16.9
NA
($0.4)
$17.1
$13.8
$15.2
$6.5

2010
$10.5
$6.4
$3.4
$28.6
NA
$7.6
$24.5
$6.4
$24.7
$25.5
$15.9
$24.2
NA
$2.4
$24.5
$24.2
$22.4
$13.3

2011
$8.8
$3.4
($0.6)
$17.9
NA
$4.4
$16.9
$3.3
$16.6
$16.8
$7.2
$16.1
NA
($1.8)
$16.9
$16.4
$16.1
$4.6

2012
($3.3)($6.1)($9.4)$4.5($13.2)($5.2)$2.6($6.1)$2.6$0.2($8.2)$2.3($13.2)($13.2)$2.6($0.0)$1.4($9.6)

Surplus (Shortfall) ($/MWh)
2013
2014
2015
$1.4
$11.7
$3.2
($2.6)$7.2($1.2)($3.6)$4.9($6.1)
$14.6
$31.6
$14.1
($7.0)$6.6($1.2)($1.0)
$9.1
$0.3
$12.4
$26.0
$6.3
($1.9)$7.7($0.9)
$12.2
$25.7
$6.5
$5.7
$23.2
$10.9
$3.3
$16.4
($4.7)
$12.3
$25.5
$5.8
($6.4)$5.5($0.3)($6.9)$0.6($7.7)
$12.4
$26.0
$6.2
$5.1
$21.6
$10.8
$11.1
$24.6
$6.3
$0.9
$13.7
($6.8)

2016($0.4)($3.1)($9.5)$7.2($4.0)($1.5)($2.0)($3.5)($2.1)$3.0($11.6)($2.2)($4.0)($9.5)($2.3)$2.6($1.6)($12.4)2017$2.6($1.5)($2.7)$6.1($8.4)($0.0)$1.6($1.8)$1.5$4.7($9.9)$1.4($7.3)($3.5)
$1.3
$4.5
$1.8
($10.3)

2018
$13.9
$6.0
$5.8
$16.3
($0.9)
$7.2
$12.3
$6.0
$12.1
$16.0
NA
$11.8
$1.9
$4.4
$11.9
$16.0
$10.0
($3.8)

2019
$3.7
$3.9
$3.2
$5.4
($6.2)
$4.6
$1.7
$3.8
$1.7
$4.8
NA
$0.7
($5.8)
$2.1
$1.4
$4.1
($1.4)
NA

2020($4.0)($1.3)($1.9)($2.2)($13.8)($0.7)($3.5)($1.4)($3.8)($3.3)
NA($4.1)($13.8)($3.6)($3.8)($4.0)($8.0)
NA

46 Exelon. “Exelon Announces Outcome of 2019-2020 PJM Capacity Auction,” (May 25, 2016) <http://www.exeloncorp.com/newsroom/pjm-auction-results-2016>.
47 Exelon, “Exelon Announces Outcome of 2020-2021 PJM Capacity Auction,” (May 24, 2017) <http://www.exeloncorp.com/newsroom/pjm-auction-results-release-2017>.
48 Exelon, “Exelon Announces Outcome of 2021-2022 PJM Capacity Auction,” (May 24, 2018) <http://www.exeloncorp.com/newsroom/exelon-announces-outcome-of-2021-2022-pjm-capacity-auction>.
49 PRNewswire. “FirstEnergy Solutions Comments on Results of PJM Capacity Auction,“ (May 24, 2018) <https://www.prnewswire.com/news-releases/firstenergy-solutions-comments-on-results-of-pjm-capacity-auction-300654549.html>.
50 Analysis is based on actual unit generation and received energy market and capacity market revenues. Negative prices in the DA and RT market were set to zero for comparison. Results round to 0.0 percent.
51 The values for 2016 through 2019 have changed slightly from previous values to account for reactive supply and voltage control revenues.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 371

2021 Quarterly State of the Market Report for PJM: January through June

In order to evaluate the expected viability of nuclear plants, analysis was performed based on forward energy market prices for 2021, 2022 and 2023 and known
capacity market prices for 2021 and 2022. The purpose of the forward analysis is to evaluate whether current forward prices are consistent with nuclear plants
covering their annual avoidable costs over the next three years. While the forward capacity market prices are known, actual energy prices will vary from forward
values. Nuclear plants may sell their output at a range of forward prices and for a range of future years.
Table 7-20 shows PJM energy prices (LMP), annual fuel, and operating and capital expenditures used for the analysis of the period 2021 through 2023. Capacity
revenues are not presented for calendar year 2023 because the 2023/2024 BRA has not been run. The LMPs are based on forward prices with a basis adjustment
for the specific plant locations.52 Forward prices are as of July 1, 2021. The 2021 energy prices include actual day-ahead market prices through June 30, 2021,
and forward prices for July through December 2021.The capacity prices are known based on PJM capacity auction results.
Table 7-20 Forward prices in PJM energy markets, capacity revenue, and annual costs53

Beaver Valley
Braidwood
Byron
Calvert Cliffs
Davis Besse
Dresden
Hope Creek
LaSalleLimerickNorth Anna
Peach Bottom
Perry
Quad Cities
Salem
Surry
Susquehanna

ICAP
(MW)
1,808
2,337
2,300
1,708
894
1,797
1,172
2,271
2,242
1,892
2,347
1,240
1,819
2,328
1,676
2,520

Ancillary
Average Forward LMP
Revenue($/MWh)($/MWh)
2021
2022
2023
Reactive$30.77$32.46$29.58$0.24$28.70$29.43$26.81$0.24$28.05$28.44$25.92$0.21$33.87$33.96$30.96$0.20$31.09$32.76$29.86$0.24$29.57$30.23$27.55$0.32$26.96$29.07$26.46$0.43$28.62$29.32$26.71$0.18$26.84$29.01$26.40$0.14$32.87$33.08$30.16$0.17$26.48$28.70$26.12$0.29$31.23$32.69$29.79$0.24$26.28$26.09$23.77$0.18$26.93$29.07$26.46$0.12$32.32$31.87$29.07$0.17$25.44$26.52$24.17$0.28

Capacity Revenue($/MWh)
2021
2022
$5.06
$3.88
$8.56
$5.39
$8.56
$5.39
$5.23
$5.07
$5.87
$4.45
$8.56
$5.39
$7.77
$5.60
$8.56
$5.39
$7.77
$5.60
$5.06
$3.88
$7.77
$5.60
$5.87
$4.45
$8.56
$5.39
$7.77
$5.60
$5.06
NA
$5.23
$5.07

2019 NEI Costs($/MWh)Fuel Operating$6.06$17.00$6.06$17.00$6.06$17.00$6.06$17.00$6.50$24.60$6.06$17.00$6.06$17.00$6.06$17.00$6.06$17.00$6.06$17.00$6.06$17.00$6.50$24.60$6.06$17.00$6.06$17.00$6.06$17.00$6.06$17.00Capital
$5.32
$5.32
$5.32
$5.32
$7.30
$5.32
$5.32
$5.32
$5.32
$5.32
$5.32
$7.30
$5.32
$5.32
$5.32
$5.32

The MMU also calculates the capacity price that would be required to cover the net avoidable costs for each nuclear plant. Under the Commission’s December
19, 2019, MOPR Order, a competitive offer in the capacity market for a subsidized nuclear plant is defined to be net avoidable costs.54 As a result, subsidized
nuclear plants could make offers in the capacity market as low as but no lower than net avoidable costs. The capacity price required to cover net avoidable
costs, when compared to recent capacity market prices, is an indicator of whether nuclear plants subject to the MOPR rules would clear in a capacity auction.

52 Forward prices on July 1, 2021. Forward prices are reported for PJM trading hubs which are adjusted to reflect the historical differences between prices at the trading hub and prices at the relevant plant locations. The basis adjustment is based on 2020 data.
53 Oyster Creek retired on September 17, 2018. Exelon. “Oyster Creek Generating Station Retires from Service,” (September 17, 2018) <http://www.exeloncorp.com/newsroom/oyster-creek-retires>. Three Mile Island retired September 20, 2019. Exelon. “Three Mile Island Generating Station
Unit 1 Retires from Service After 45 Years,” (September 20, 2019) <https://www.exeloncorp.com/newsroom/three-mile-island-generating-station-unit-1-retires>.
54 See 169 FERC ¶ 61,239 at P 148.

372

Section 7 Net Revenue© 2021 Monitoring Analytics, LLC

Section 7 Net Revenue

Based on the FERC order about inclusion of maintenance expense in energy
In Table 7-21, for 2022, using forward prices as of July 1, 2021, the capacity
offers, major maintenance costs can no longer be included in gross ACR values.55
price required to cover avoidable costs ranges from $0/MW-day for a multiple
The MMU calculates the capacity price that would be required to cover the net
unit plant to $121.91/MW-day for a single unit plant for NEI data as reported
avoidable costs for each nuclear plant with major maintenance included inincluding capital expenditures, and is $0/MW-day for all plants, excluding
avoidable costs and with major maintenance excluded from avoidable costs.
capital expenditures as a proxy for major maintenance.57
For the case including major maintenance, gross ACR is NEI total cost including
Table 7-21 Net ACR
fuel, operating cost, and capital expenditures. For the
Net ACRNet ACRNet ACR Excluding Capitalcase excluding major maintenance, gross ACR is NEI total($/MWh)($/MW-Day)($/MW-Day)
cost including fuel and operating cost, excluding capital
ICAP (MW)
2021
2022
2023
2021
2022
2023
2021
2022
2023
Beaver Valley
1,808
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
expenditures as a proxy for fixed VOM, given that NEI
Braidwood
2,337
$0.00
$0.00
$1.33
$0.00
$0.00
$29.64
$0.00
$0.00
$0.00
does not provide a breakout of major maintenance. NEI
Byron
2,300
$0.11
$0.00
$2.25
$2.55
$0.00
$50.22
$0.00
$0.00
$0.00
capital expenditures are likely to be a conservatively low
Calvert Cliffs
1,708
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
Davis Besse
894
$7.07
$5.40
$8.30
$157.60$120.41$185.06$0.00$0.00$22.30estimate of major maintenance expense.
While the FERC order on major maintenance defines acompetitive offer under the MOPR order, all generating
plants including nuclear plants must cover their gross
avoidable costs, including major maintenance, to remain
economically viable. All of the MMU analysis of nuclear
plant economics includes gross avoidable costs asreported by NEI unless explicitly stated otherwise.

Dresden
Hope Creek
LaSalleLimerickNorth Anna
Peach Bottom
Perry
Quad Cities
Salem
Surry
Susquehanna

In Table 7-21, the capacity price required to cover avoidable costs in $ per
MWh is calculated by taking the total NEI costs in $ per MWh and subtracting
the total expected energy and ancillary services revenues in $ per MWh.
Total expected energy revenue is the unit’s ICAP multiplied by the average
forward LMP multiplied by the class average equivalent availability factor.
Total expected ancillary services revenue is reactive capability revenue.56 The
capacity price required to cover avoidable costs in $ per MW-day is calculated
by multiplying the required price in $ per MWh by 24. Plants may have actual
operating costs higher or lower than the NEI average.

55 See 167 FERC ¶ 61,030 at P 41.
56 Reactive Supply & Voltage Control Revenue Requirements available from PJM <https://www.pjm.com/markets-and-operations/billingsettlements-and-credit.aspx>.

© 2021 Monitoring Analytics, LLC

1,797
1,172
2,271
2,242
1,892
2,347
1,240
1,819
2,328
1,676
2,520

$0.00
$0.99
$0.00
$1.40
$0.00
$1.62
$6.92
$1.93
$1.32
$0.00
$2.66

$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$5.47
$2.11
$0.00
$0.00
$1.58

$0.51
$1.49
$1.49
$1.84
$0.00
$1.98
$8.37
$4.43
$1.80
$0.00
$3.93

$0.00
$22.07$0.00$31.17$0.00$36.01$154.39$42.94$29.47$0.00$59.25

$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$121.91$47.14$0.00$0.00$35.21$11.41$33.30$33.13$40.96$0.00$44.10$186.53$98.80$40.11$0.00$87.53

$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00

$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00

$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$23.77
$0.00
$0.00
$0.00
$0.00

Table 7-22 shows the surplus or shortfall that would be received net of
avoidable costs and incremental capital expenditures by year, based on
forward prices, on a per MWh basis. The fuel and operating costs are the 2019
NEI fuel, operating, and capital costs. Plants may have operating costs higher
or lower than the NEI average. Table 7-22 shows the total dollar surplus orshortfall and adjusts energy revenues and operating costs using the annualclass average capacity factor.
Changes in forward energy market prices can significantly affect expected
profitability of nuclear plants in PJM. The current analysis, based on forward
prices for energy and known forward prices for capacity, shows that only twoplants, Davis Besse and Perry would not cover their annual avoidable costs
57 PJM’s tariff definition of avoidable costs excludes major maintenance. PJM includes major maintenance costs in the definition of short
run marginal costs in energy offers.

2021 Quarterly State of the Market Report for PJM: January through June 373

2021 Quarterly State of the Market Report for PJM: January through Junein 2021 and 2022.58 Both of these plants are single unit sites which havehigher operating costs per MWh than multiple unit plants and show an annual
shortfall of $1.20 and $1.05 per MWh in 2021. In March 2018, Davis Besse
and Perry requested deactivation in 2021 but reversed the decision based on
new subsidies in Ohio. On March 31, 2021, Ohio repealed the subsidies fornuclear units.59
Hope Creek, Quad Cities, and Salem all currently receive subsidies. Based on
forward prices as of July 1, 2021 and NEI average costs, none of these units
need a subsidy.
Table 7-22 Nuclear unit forward annual surplus (shortfall)60 61

Beaver Valley
Braidwood
Byron
Calvert Cliffs
Davis Besse
Dresden
Hope Creek
LaSalleLimerickNorth Anna
Peach Bottom
Perry
Quad Cities
Salem
Surry
Susquehanna

ICAP (MW)
1,808
2,337
2,300
1,708
894
1,797
1,172
2,271
2,242
1,892
2,347
1,240
1,819
2,328
1,676
2,520

Surplus (Shortfall)
Subsidy($/MWh)($/MWh)
2021
2022
2021
$7.69
$8.20
$9.12
$6.69
$8.44
$5.67
$10.92$10.84($1.20)($0.95)$10.07
$7.56
$6.79
$6.72
$10.00
$8.98
$6.52
$6.38
$6.37
$9.71
$8.75
$6.16
$6.21
($1.05)($1.01)$6.63$3.28$16.50$6.45$6.42$10.00
$9.17
NA
$2.57
$3.49

Surplus (Shortfall)Excluding Subsidy($ in millions)
2021
2022
$114.4$120.6$174.9$127.2$159.5$106.1$153.1$150.7($8.1)($6.9)$148.5$110.6$65.4$64.1$167.4$120.5$117.7$116.2$150.9$134.7$119.0$118.5($9.7)($10.2)$99.2$48.6$123.7$121.5$126.2
NA
$54.2
$71.6

Surplus (Shortfall)
Including Subsidy($ in millions)
2021
2022
$114.4$120.6$174.9$127.2$159.5$106.1$153.1$150.7($8.1)($6.9)$148.5$110.6$160.8$159.5$167.4$120.5$117.7$116.2$150.9$134.7$119.0$118.5($9.7)($10.2)$343.5$292.8$313.1$311.0$126.2
NA
$54.2
$71.6

58 Susquehanna has reduced its operating costs below the NEI average costs and is operating at a higher surplus when the unit specificinformation is accounted for. (Bank of America Global Research, October 26, 2020.)
59 See Ohio S.B. 44/H.B. 128; see also Ohio Governor Mike DeWine’s Website, News Release: “Governor DeWine Signs Ohio Transportation
Budget,” which can be accessed at: <https://governor.ohio.gov/wps/portal/gov/governor/media/news-and-media/transportation-budgetsigned-03312021>.
60 Report to the General Assembly in Compliance with Section 1-75(d-5) of the Illinois Power Agency Act 20 ILCS 3855/1-75(d-5)(F)(2).
Illinois Commerce Commission. August 2019. The report finds that while total ZECs payments are limited by rate impact caps and volume
caps, the law’s limitation does not unduly constrain the procurement of ZECs.
61 Application of PSEG Nuclear, LLC for the Zero Emission Certificate Program – Hope Creek, Order Determining the Eligibility of Hope Creek
Nuclear Generator to Receive ZECs, BPU Docket No. ER20080559 (April 27, 2021). Application of PSEG Nuclear, LLC for the Zero Emission
Certificate Program – Salem 1, Order Determining the Eligibility of Salem Unit 1 Nuclear Generator to Receive ZECs, BPU Docket No.
ER20080557 (April 27, 201). Application of PSEG Nuclear, LLC for the Zero Emission Certificate Program – Salem 2, Order Determining
the Eligibility of Salem Unit 2 Nuclear Generator to Receive ZECs. BPU Docket No. ER20080557 (April 27, 2021).

374

Section 7 Net Revenue© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Environmental and Renewable Energy
Regulations

Overview
Federal Environmental Regulation• MATS. The U.S. Environmental Protection Agency’s (EPA) Mercury and Air

Environmental requirements and renewable energy mandates have asignificant impact on PJM markets.

Toxics Standards rule (MATS) applies the Clean Air Act (CAA) maximum
achievable control technology (MACT) requirement to new or modified
sources of emissions of mercury and arsenic, acid gas, nickel, selenium
and cyanide.1 On May 22, 2020, the EPA published its determination that
MATS is not appropriate and necessary based on a cost-benefit analysis.2
The list of coal steam units subject to MATS, however, remains in place.3
All coal steam units in PJM are compliant with the state and federal
emissions limits established by MATS. The EPA’s May 22, 2020, finding isunder review pursuant to Executive Order 13990.

The investments required for environmental compliance have affected offer
behavior in the capacity market. Expectations about the cost and life ofsuch investments and about future capacity and energy prices have affected
retirement decisions. The markets have also provided incentives for new,lower emissions units to enter.
Environmental requirements and initiatives at both the federal and state levels,and state renewable energy mandates and associated incentives have resulted
in the construction of substantial amounts of renewable capacity in the PJM
footprint, especially wind and solar resources. Renewable energy credit (REC)markets created by state programs, and federal tax credits have significant
impacts on PJM wholesale markets. But state renewables programs in PJM are
not coordinated with one another, are generally not consistent with the PJM
market design or PJM prices, have widely differing objectives, have widelydiffering implied prices of carbon and are not transparent on pricing andquantities. The effectiveness of state renewables programs would be enhanced
if they were coordinated with one another and with PJM markets, and if they
increased transparency. States could evaluate the impacts of a range of carbon
prices if PJM would provide a full analysis of the impact of carbon pricing on
PJM generating units and carbon pricing revenues to the PJM states in orderto permit the states to consider a potential agreement on the developmentof a multistate framework for carbon pricing and the distribution of carbon
revenues. A single carbon price across PJM, established by the states, would
be the most efficient way to reduce carbon output, if that is the goal.

• Air Quality Standards (NO and SO Emissions). The CAA requires eachX

• NSR. On August 1, 2019, the EPA proposed to reform the New Source

Review (NSR) permitting program.6 NSR requires new projects and existing
projects receiving major overhauls that significantly increase emissions
to obtain permits. Recent EPA proposals would reduce the number ofprojects that require permits.

• RICE. Stationary reciprocating internal combustion engines (RICE) areelectrical generation facilities like diesel engines typically used for backup,

1
2
3
4
5
6

© 2021 Monitoring Analytics, LLC

2state to attain and maintain compliance with fine particulate matter (PM)and ozone national ambient air quality standards (NAAQS). The CAA
also requires that each state prohibit emissions that significantly interferewith the ability of another state to meet NAAQS.4 On March 15, 2021, theEPA finalized decreases to allowable emissions under the Cross-State Air
Pollution Rule (CSAPR) and the 2008 ozone NAAQS for 10 PJM states.5

National Emission Standards for Hazardous Air Pollutants From Coal and Oil-Fired Electric Utility Steam Generating Units and Standardsof Performance for Fossil Fuel Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional
Steam Generating Units, EPA Docket No. EPA-HQ-OAR-2009-0234, 77 Fed. Reg. 9304 (Feb. 16, 2012).
See National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—
Reconsideration of Supplemental Finding and Residual Risk and Technology Review, Docket No. EPA–HQ–OAR–2018–0794, 85 Fed. Reg.
31286.
Id. at 31291.
CAA § 110(a)(2)(D)(i)(I).
Revised Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS, Docket No. EPA–HQ–OAR–2020–0272; FRL–10013–42– OAR,
85 Fed. Reg. 23054 (Apr. 30, 2021).
Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR): Project Emissions Accounting, EPA Docket
No. EPA–HQ–OAR–2018–0048; FRL–9997–95–OAR, 84 Fed. Reg. 39244 (Aug. 9, 2019).

2021 Quarterly State of the Market Report for PJM: January through June 375

2021 Quarterly State of the Market Report for PJM: January through Juneemergency or supplemental power. RICE must be tested annually.7 RICE
do not have to meet the same emissions standards if they are emergency
stationary RICE. Environmental regulations allow emergency stationary
RICE participating in demand response programs to operate for up to
100 hours per calendar year when providing emergency demand responsewhen there is a PJM declared NERC Energy Emergency Alert Level 2 orthere are five percent voltage/frequency deviations.

•

PJM does not prevent emergency stationary RICE that cannot meet its
capacity market obligations as a result of EPA emissions standards fromparticipating in PJM markets as DR. Some emergency stationary RICE
that cannot meet its capacity market obligations as a result of emissions
standards are now included in DR portfolios. Emergency stationary RICE
should be prohibited from participation as DR either when registeredindividually or as part of a portfolio if it cannot meet its capacity market
obligations as a result of emissions standards.
Greenhouse Gas Emissions. On January 19, 2021, the U.S. Court of Appeals
for the District of Columbia Circuit vacated the EPA’s Affordable Clean
Energy (ACE) rule which would have permitted more CO2 emissions thanunder the Clean Power Plan (CPP), which ACE had replaced.8 Neither the
ACE nor CPP is currently effective.

• Cooling Water Intakes. An EPA rule implementing Section 316(b) of the
Clean Water Act (CWA) requires that cooling water intake structures reflect
the best technology available for minimizing adverse environmental
impacts.9• Waters of the United States. On June 9, 2021, the EPA and the Departmentof the Army concluded their review pursuant to Executive Order 13990
and announced their intention to initiate a new rulemaking process anddevelop a new definition of Waters of the United States that restores theprotections in place prior to the 2015.

78
9

See 40 CFR § 63.6640(f).
American Lung Association et al. v. EPA, No. 19-1140.
See EPA, National Pollutant Discharge Elimination System—Final Regulations to Establish Requirements for Cooling Water Intake
Structures at Existing Facilities and Amend Requirements at Phase I Facilities, EPA-HQ-OW-2008-0667, 79 Fed. Reg. 48300 (Aug. 15,
2014).

376

Section 8 Environmental and Renewables• Coal Ash. The EPA administers the Resource Conservation and Recovery
Act (RCRA), which governs the disposal of solid and hazardous waste.10 The
EPA has proposed significant changes to the implementing regulations.

State Environmental Regulation• Regional Greenhouse Gas Initiative (RGGI). The Regional Greenhouse

Gas Initiative (RGGI) is a CO2 emissions cap and trade agreement among
Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire,
New Jersey, New York, Rhode Island, Vermont and Virginia that applies
to power generation facilities. New Jersey rejoined on January 1, 2020.11
Virginia joined RGGI on January 1, 2021, and Pennsylvania is preparing
to join.12 13 The auction price in the June 2, 2021, auction was $7.97 perton, or $8.79 per metric tonne.

• Carbon Price. If the price of carbon were $50.00 per metric tonne, short
run marginal costs would increase by $24.52 per MWh or 77.3 percent for
a new combustion turbine (CT) unit, $16.71 per MWh or 77.0 percent for
a new combined cycle (CC) unit and $43.15 per MWh or 143.6 percent for
a new coal plant (CP) for January through June, 2021.

State Renewable Portfolio Standards• RPS. In PJM, ten of 14 jurisdictions have enacted legislation requiringthat a defined percentage of retail suppliers’ load be served by renewable
resources, for which definitions vary. These are typically known as
renewable portfolio standards, or RPS. As of June 30, 2021, Delaware,
Illinois, Maryland, Michigan, New Jersey, North Carolina, Ohio,
Pennsylvania, Virginia and Washington, DC have renewable portfolio
standards. Virginia had a voluntary RPS in 2020, but a new mandatory
RPS became effective on January 1, 2021. Indiana has voluntary renewable
portfolio standards. Kentucky, Tennessee and West Virginia do not haverenewable portfolio standards.

10 42 U.S.C. §§ 6901 et seq.
11 ”Statement on New Jersey Greenhouse Gas Rule,” RGGI Inc., (June 17, 2019) <https://www.rggi.org/sites/default/files/Uploads/PressReleases/2019_06_17_NJ_‌Announcement_Release.pdf>.
12 “Statement on Virginia Greenhouse Gas Rule,” RGGI, (July 8, 2020) <https://www.rggi.org/news-releases/rggi-releases>.
13 Executive Order–2019-07. Commonwealth Leadership in Addressing Climate Change through Electric Sector Emissions Reductions, Tom
Wolf, Governor, October 3, 2019, <https://www.governor.pa.gov/newsroom/executive-order-2019-07-commonwealth-leadership-inaddressing-climate-change-through-electric-sector-emissions-reductions/>.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables• RPS Cost. The cost of complying with RPS, as reported by the states, is• The MMU recommends that the Commission reconsider its disclaimer

Emissions Controls in PJM Markets• The MMU recommends that PJM provide a full analysis of the impact$5.6 billion over the six year period from 2014 through 2019, an averageannual RPS compliance cost of $936.7 million. The compliance cost for
2019, the most recent year with almost complete data, was $1.2 billion.14••

Regulations. Environmental regulations affect decisions about emission
control investments in existing units, investment in new units anddecisions to retire units. As a result of environmental regulations andagreements to limit emissions, many PJM units burning fossil fuels haveinstalled emission control technology.
Emissions Controls. In PJM, as of June 30, 2021, 93.5 percent of coalsteam MW had some type of flue-gas desulfurization (FGD) technology
to reduce SO2 emissions, while 99.8 percent of coal steam MW had some
type of particulate control, and 94.6 percent of fossil fuel fired capacity
had NOX emission control technology. All coal steam units in PJM arecompliant with the state and federal emissions limits established by MATS.

Renewable Generation• Renewable Generation. Wind and solar generation was 4.6 percent of total
generation in PJM in the first six months of 2021. RPS Tier I generation
was 6.2 percent of total generation in PJM and RPS Tier II generation was
2.1 percent of total generation in PJM in the first six months of 2021.
Only Tier I generation is defined to be renewable but Tier 1 includes somecarbon emitting generation.

Recommendations• The MMU recommends that renewable energy credit markets based onstate renewable portfolio standards be brought into PJM markets as they
are an increasingly important component of the wholesale energy market.
(Priority: Medium. First reported 2010. Status: Not adopted.)

14 The 2019 compliance cost value for PJM states does not include Illinois, Michigan or North Carolina. Based on past data these states
generally account for 3.0 percent of the total RPS compliance cost of PJM states.

© 2021 Monitoring Analytics, LLC

of jurisdiction over RECs markets because, given market changes sincethat decision, it is clear that RECs materially affect jurisdictional rates.
(Priority: High. First reported 2018. Status: Not adopted.)of carbon pricing on PJM generating units and carbon pricing revenues
to the PJM states in order to permit the states to consider a potential
agreement on the development of a multistate framework for carbon
pricing and the distribution of carbon revenues. (Priority: High. First
reported 2018. Status: Not adopted.)• The MMU recommends that jurisdictions with a renewable portfolio
standard make the price and quantity data on supply and demand moretransparent. (Priority: Low. First reported 2018. Status: Not adopted.)• The MMU recommends that load and generation located at separate

nodes be treated as separate resources in order to ensure that load andgeneration face consistent incentives throughout the markets. (Priority:
High. First reported 2019. Status: Not adopted.)• The MMU recommends that emergency stationary RICE be prohibitedfrom participation as DR either when registered individually or as part ofa portfolio if it cannot meet the capacity market requirements to be DR
as a result of emissions standards that impose environmental run hour
limitations. (Priority: Medium. First reported 2019. Status: Not adopted.)Conclusion
Environmental requirements and renewable energy mandates at both thefederal and state levels have a significant impact on the cost of energy andcapacity in PJM markets. Renewable energy credit (REC) markets are markets
related to the production and purchase of wholesale power, but FERC hasdetermined that RECs are not regulated under the Federal Power Act unlessthe REC is sold as part of a transaction that also includes a wholesale saleof electric energy in a bundled transaction.15 The MMU recommends that
15 See 139 FERC ¶ 61,061 at PP 18, 22 (2012) (“[W]e conclude that unbundled REC transactions fall outside of the Commission’s jurisdiction
under sections 201, 205 and 206 of the FPA. We further conclude that bundled REC transactions fall within the Commission’s jurisdiction
under sections 201, 205 and 206 of the FPA,… [A]lthough a transaction may not directly involve the transmission or sale of electricenergy, the transaction could still fall under the Commission’s jurisdiction because it is ’in connection with’ or ’affects’ jurisdictional rates
or charges.”).

2021 Quarterly State of the Market Report for PJM: January through June 377

2021 Quarterly State of the Market Report for PJM: January through June

the Commission reconsider its disclaimer of jurisdiction over RECs markets
because, given market changes since that decision, it is clear that RECs
materially affect jurisdictional rates.
RECs clearly affect prices in the PJM wholesale power market. Some resources
are not economic except for the ability to purchase or sell RECs. RECs provide
out of market payments to qualifying renewable resources, primarily windand solar. The credits provide an incentive to make negative energy offers
and more generally provide an incentive to enter the market, to remain in
the market and to operate whenever possible. These subsidies affect the offer
behavior and the operational behavior of these resources in PJM markets andin some cases the existence of these resources and thus the market prices andthe mix of clearing resources. FERC’s recent MOPR order addressed these
impacts.
RECs markets are, as an economic fact, integrated with PJM markets including
energy and capacity markets, but are not formally recognized as part of PJM
markets. It would be preferable to have a single, transparent market forRECs operated by the PJM RTO on behalf of the states that would meet thestandards and requirements of all states in the PJM footprint including thosewith no RPS. This would provide better information for market participants
about supply and demand and prices and contribute to a more efficient andcompetitive market and to better price formation. This could also facilitate
entry by qualifying renewable resources by reducing the risks associated withlack of transparent market data. The MMU recommends that PJM provide afull analysis of the impact of carbon pricing on PJM generating units andcarbon pricing revenues to states in order to permit states to consider thedevelopment of a multistate framework: for RECs markets; for potential
agreement on carbon pricing including the distribution of carbon revenues;
and for coordination with PJM wholesale markets.
REC markets are not consistently or adequately transparent. Data on REC
prices, clearing quantities and markets are not publicly available for all PJM
states. The provision of more complete data would facilitate competition toprovide energy from renewable sources.

378

Section 8 Environmental and Renewables

The economic logic of RPS programs and the associated REC and SREC prices
is not always clear. The price of carbon implied by REC prices ranges from
$8.14 per tonne in Washington, DC to $18.38 per tonne in New Jersey. The
price of carbon implied by SREC prices ranges from $67.29 per tonne in
Pennsylvania to $879.12 per tonne in Washington, DC. The effective prices forcarbon compare to the RGGI clearing price in June 2021 of $8.79 per tonne
and to the social cost of carbon which is estimated in the range of $50 per
tonne.16 The impact on the cost of generation from a new combined cycle unitof a $50 per tonne carbon price would be $16.71 per MWh.17 The impact ofan $800 per tonne carbon price would be $267.30 per MWh. This wide rangeof implied carbon prices is not consistent with an efficient, competitive, least
cost approach to the reduction of carbon emissions.
In addition, even the explicit environmental goals of RPS programs are notclear. While RPS is frequently considered to target carbon emissions, Tier
1 resources include some carbon emitting generation and Tier 2 resources
include additional carbon emitting generation.
PJM markets provide a flexible mechanism for incorporating the costs ofenvironmental controls and meeting environmental requirements in a costeffective manner. Costs for environmental controls are part of offers forcapacity resources in the PJM Capacity Market. The costs of emissions credits
are included in energy offers. PJM markets also provide a flexible mechanismthat incorporates renewable resources and the impacts of renewable energy
credit markets, and ensures that renewable resources have access to a broad
market. PJM markets provide efficient price signals that permit valuationof resources with very different characteristics when they provide the same
product.
PJM markets could also provide a flexible mechanism to limit carbon output,
for example by incorporating a consistent carbon price in unit offers which
would be reflected in PJM’s economic dispatch. If there is a social decision
16 “Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis – Under Executive Order 12899,” Interagency Working
Group on the Social Cost of Greenhouse Gases, United States Government, (Aug. 2016), <https://19january2017snapshot.epa.gov/‌sites/
production/files/2016-12/documents/sc_co2_tsd_august_2016.pdf>.
17 The cost impact calculation assumes a heat rate of 6.296 MMBtu per MWh and a carbon emissions rate of 0.053070 tonne per MMBtu.
The $800 per tonne carbon price represents the approximate upper end of the carbon prices implied by the 2019 REC and SREC prices in
the PJM jurisdictions with RPS. Additional cost impacts are provided in Table 8-18.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

to limit carbon output, a consistent carbon price would be the most efficient
way to implement that decision. The states in PJM could agree, if they decided
it was in their interests, with the appropriate information, on a carbon priceand on how to allocate the revenues from a carbon price that would make allstates better off. A mechanism like RGGI leaves all decision making with thestates. The carbon price would not be FERC jurisdictional or subject to PJM
decisions. The MMU continues to recommend that PJM provide modelinginformation to the states adequate to inform such a decision making process.
Such modeling information would include the impact on the dispatch of every
unit, the impact on energy prices and the carbon pricing revenues that would
flow to each state. This would permit states to make critical decisions aboutcarbon pricing. For example, states receiving high levels of revenue could shiftrevenue to states disproportionately hurt by a carbon price if they believedthat all states would be better off as a result. A carbon price would also be
an alternative to specific subsidies to individual nuclear power plants and tothe current wide range of implied carbon prices embedded in RPS programs
and instead provide a market signal to which any resource could respond. The
imposition of specific and prescriptive environmental dispatch rules would, in
contrast, pose a threat to economic dispatch and efficient markets and create
very difficult market power monitoring and mitigation issues. The provisionof subsidies to individual units creates a discriminatory regime that is notconsistent with competition. The use of inconsistent implied carbon prices bystate is also inconsistent with an efficient market and inconsistent with theleast cost approach to meeting state environmental goals.

be approximately $2.6 billion per year if the carbon price were $7.97 per short
ton and emissions levels were five percent below 2020 emission levels. If all
the PJM states participated in a regional carbon market, the estimated revenue
returned to the states/customers from selling carbon allowances would beapproximately $16.6 billion if the carbon price were $50 per short ton andemission levels were five percent below 2020 levels. If only the current RPS
states participated in a regional carbon market, the estimated revenue returnedto the states/customers from selling carbon allowances at $7.97 per short ton
would be about $1.8 billion. The costs of a carbon price are the impact onenergy market prices, net of the revenue returned to states/customers.

The annual average cost of complying with RPS over the six year period from2014 through 2019 for the nine jurisdictions that had RPS was $936.7 million,
or a total of $5.6 billion over six years. The RPS compliance cost for 2019, themost recent year for which there is almost complete data, was $1.2 billion.18
RPS costs are payments by customers to the sellers of qualifying resources.
The revenues from carbon pricing flow to the states.

The Resource Conservation and Recovery Act (RCRA) regulates the disposalof solid and hazardous waste.22 Regulation of coal ash or coal combustion
residuals affects coal fired power plants.

If all the PJM states participated in a regional carbon market, the estimatedrevenue returned to the states/customers from selling carbon allowances would
18 The 2019 compliance cost value for PJM states does not include Illinois, Michigan or North Carolina. Based on past data these states
generally account for 3.0 percent of the total RPS compliance cost of PJM states.

© 2021 Monitoring Analytics, LLC

Federal Environmental Regulation
The U.S. Environmental Protection Agency (EPA) administers the Clean Air
Act (CAA), the Clean Water Act (CWA) and the Resource Conservation andRecovery Act (RCRA), all of which address pollution created by electric power
production. The administration of these statutes is relevant to the operationof PJM markets.19
The CAA regulates air emissions by providing for the establishment of acceptablelevels of emissions of hazardous air pollutants. The EPA issues technology based
standards for major sources and area sources of emissions.20 21
The CWA regulates discharges from point sources that affect water quality
and temperature.

19 For more details, see the 2019 State of the Market Report for PJM, Vol. II, Appendix H: “Environmental and Renewable Energy
Regulations.”
20 42 U.S.C. § 7401 et seq. (2000).
21 The EPA defines a “major source” as a stationary source or group of stationary sources that emit or have the potential to emit 10 tons
per year or more of a hazardous air pollutant or 25 tons per year or more of a combination of hazardous air pollutants. An “area source”
is any stationary source that is not a major source.
22 42 U.S.C. §§ 6901 et seq.

2021 Quarterly State of the Market Report for PJM: January through June 379

2021 Quarterly State of the Market Report for PJM: January through June

The EPA’s actions have affected and will continue to affect the cost to buildand operate generating units in PJM, which in turn affects wholesale energy
prices and capacity prices.

CAA: NESHAP/MATS
Section 112 of the CAA requires the EPA to promulgate emissions control
standards, known as the National Emission Standards for Hazardous Air
Pollutants (NESHAP), from both new and existing area and major sources.
On December 21, 2011, the EPA issued its Mercury and Air Toxics Standards
rule (MATS), which applies the CAA maximum achievable control technology(MACT) requirement to new or modified sources of emissions of mercury andarsenic, acid gas, nickel, selenium and cyanide.
On May 22, 2020, the EPA published a rule finalizing its Supplemental Cost
Finding for the MATS, and the risk and technology review required by the
CAA.23 The EPA determined that the estimated cost to coal and oil fired power
plants of complying with the MATS rule in 2015 outweighed the estimatedquantifiable benefits attributable to regulating hazardous air pollutant(HAP) emissions in 2015.24 The EPA determined that based on analysis ofcosts versus benefits it is not “appropriate and necessary” to regulate HAP
emissions from power plants under Section 112 of the Clean Air Act.25 26 The
immediate practical effect is limited because the emission standards and otherrequirements of the 2012 MATS rule remain in place and the list of coal and oil
fired power plants regulated under Section 112 of the Act remains in place.27
Removal of the appropriate and necessary finding creates the possibility of achallenge to the MATS rule if applied to the proposed construction or upgradeof a power plant.

23 See National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—
Reconsideration of Supplemental Finding and Residual Risk and Technology Review, Docket No. EPA–HQ–OAR–2018–0794, 85 Fed. Reg.
31286.
24 Id. at 31299.
25 Michigan v. EPA, 135 S.Ct. 2699 (2015) (reversed EPA determination that cost does not have to be read into the definition of“appropriate”).
26 85 Fed. Reg. at 31288.
27 Id. at 31291. The EPA explains (id.): “The Court’s holding in New Jersey [517 F.3d 574 (D.C. Cir. 2008)] plainly states that CAA section 112(c)(9) ’unambiguously limit[s] EPA’s discretion to remove sources, including EGUs, from the section 112(c)(1) list once they have been added
to it.’ 517 F.3d 574, 583 (D.C. Cir. 2008).”

380

Section 8 Environmental and Renewables

On January 20, 2021, an executive order was issued stating national
objectives “to listen to the science; to improve public health and protect ourenvironment; to ensure access to clean air and water; to limit exposure todangerous chemicals and pesticides; to hold polluters accountable, including
those who disproportionately harm communities of color and low-income
communities; to reduce greenhouse gas emissions; to bolster resilience to theimpacts of climate change; to restore and expand our national treasures andmonuments; and to prioritize both environmental justice and the creation of
the well-paying union jobs necessary to deliver on these goals” (“Executive
Order 13990”).28 The order directs government agencies to immediately
review, and as appropriate and consistent with applicable law, “take action
to address the promulgation of Federal regulations and other actions during
the last 4 years that conflict with these important national objectives, and to
immediately commence work to confront the climate crisis.”29 The May 22,
2021, supplemental finding on MATS is an action specified for review.30
On April 9, 2020, the EPA finalized a rule establishing a new sub category
in the MATS with less stringent requirements for units fueled by eastern
bituminous refuse coal, waste coal.31 The rule allows four refuse coal plants,
Grant Town Power Plant (Unit 1A and 1 B (40 MW each)) in West Virginia;
and Colver Power Project (110 MW), Ebensburg Power Plant (50 MW), andScrubgrass Generating Co. (Units 1 and 2 (42 MW each)) in Pennsylvania;
to emit higher levels of acid gases and SO2.32 The EPA stated that it wasconcerned that units would close and leave coal refuse piles, which are prone
to smoldering and emit uncontrolled acid gases and other HAP.33

CAA: NAAQS/CSAPR
The CAA requires each state to attain and maintain compliance with fineparticulate matter and ozone national ambient air quality standards (NAAQS).
Under NAAQS, the EPA establishes emission standards for six air pollutants,
28 See President Joseph R. Biden Jr., Executive Order 13990 re “Protecting Public Health and the Environment and Restoring Science to
Tackle the Climate Crisis” (“Executive Order 13990”).
29 Id. (Sec. 1).
30 Id. at Sec. 2(iv).
31 See National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—Subcategoryof Certain Existing Electric Utility Steam Generating Units Firing Eastern Bituminous Coal Refuse for Emissions of Acid Gas Hazardous
Air Pollutants, Docket No. EPA–HQ–OAR–2018–0794, 85 Fed. Reg. 20838 (April 15, 2020).
32 Id. at 20841.
33 Id. at 20847.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

including NOX, SO2, O3 at ground level, PM, CO, and Pb, and approves stateplans to implement these standards, known as State Implementation Plans(SIPs).
In January 2015, the EPA began implementation of the Cross-State Air
Pollution Rule (CSAPR) to address the CAA’s requirement that each stateprohibit emissions that significantly interfere with the ability of another state
to meet NAAQS. CSAPR requires specific states in the eastern and central
United States to reduce power plant emissions of SO2 and NOX that cross statelines and contribute to ozone and fine particle pollution in other states. CSPAR
requires reductions to levels consistent with the 1997 ozone and fine particle
and 2006 fine particle NAAQS. CSAPR covers 28 states, including all of the
PJM states except Delaware, and also excluding the District of Columbia.34
On March 15, 2021, in response to a court holding in Wisconsin v. EPA, theEPA finalized increases to the good neighbor obligations (i.e. reduced allowable
emissions) under the 2008 ozone NAAQS for 12 states.36 Eleven of the affectedstates are PJM states: Illinois, Indiana, Kentucky, Maryland, Michigan, New
Jersey, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia. The EPA
determined that Tennessee’s emissions budget “fully eliminated the state’s
significant contribution to downwind nonattainment and interference withmaintenance of the 2008 ozone NAAQS.”37 For the remaining PJM states,
projected 2021 emissions were found to contribute at or above a thresholdof 1 percent of the NAAQS (0.75 ppb) to the identified nonattainment and/or maintenance problems in downwind states.38 Starting with the 2021 ozone
season for emissions trading under CSAPR, the new FIPs require power plants
35

34 Section 126 of the CAA permits a downwind state to file a petition with the EPA to regulate the emissions from particular resourcesin another state. On October 5, 2018, EPA denied petitions filed under this provision filed by Delaware and Maryland. See Response to
Clean Air Act Section 126(b) Petitions From Delaware and Maryland, EPA Docket No. EPA-HQ-OAR-2018-0295, 83 Fed. Reg. 50444 (Oct.
5, 2018). Delaware filed a petition requesting that the EPA regulate emissions from the Brunner Island coal plant in Pennsylvania, theHarrison coal plant in West Virginia, the Homer City coal plant in Pennsylvania and the Conemaugh coal plant in Pennsylvania. Maryland
filed a petition requesting that the EPA regulate 36 generating units at coal plants located in Indiana, Kentucky, Ohio, Pennsylvania
and West Virginia. U.S. Court of Appeals for the D.C. Circuit Case No. 18-1285. On May 15, 2020, the Court denied an appeal of the
EPA decision filed by Maryland, except that the Court agreed that EPA did not sufficiently support its rejection based on the costeffectiveness of Maryland’s request that two waste coal plants, Cambria Cogeneration (Pa.) and Grant Town Cogen (W.Va.), be required
to operate selective noncatalytic reduction (SNCR) controls, and remanded the decision. Maryland v. Wheeler, Case No. 18-1285 (D.C. Cir
May 19, 2020).
35 Wisconsin v. EPA, 938 F.3d 303, 318–20 (D.C. Cir. 2019).
36 Revised Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS, Docket No. EPA–HQ–OAR–2020–0272; FRL–10013–42– OAR,
85 Fed. Reg. 23054 (Apr. 30, 2021).
37 Id. at 23066.
38 Id. at 23085–23086.

© 2021 Monitoring Analytics, LLC

in the affected states (also including Louisiana and New York) to participate ina new CSAPR NOx Ozone Season Group 3 Trading Program.39 Participation in
the more stringent new program would replace the obligation to participate in
the existing CSAPR NOx Ozone Season Group 2 Trading Program.40 41
The EPA’s new emissions budgets for each PJM state for each ozone season
for 2021 through 2024, and beyond are shown in Table 8-1. Table 8-1 also
includes the states budgets that would have been in effect had the rules notbeen revised.
Table 8-1 CSAPR NOX ozone season group 3 state budgets: 2021 through202442 43
PJM State
Illinois
Indiana
Kentucky
MarylandMichigan
New Jersey
Ohio
Pennsylvania
Virginia
West Virginia

Emissions Budget (Tons)
Budget without revised rule
2021
2022
2023
2024+
2021
9,368
9,368
8,413
8,292
9,102
15,856
15,383
15,357
12,232
13,051
15,58815,58815,58815,58815,300
1,501
1,267
1,267
1,350
1,499
13,89813,45911,182
10,96812,727
1,346
1,346
1,346
1,346
1,253
15,82915,927
15,927
15,927
9,690
11,896
11,896
11,896
11,896
8,379
4,664
4,274
4,361
4,025
4,516
15,165
15,165
15,165
15,165
13,334

Revised Budget
2022
2023
9,102
8,179
12,582
12,553
14,051
14,051
1,266
1,266
12,290
9,975
1,253
1,253
9,773
9,773
8,373
8,373
3,897
3,980
12,884
12,884

2024+
8,059
9,564
14,051
1,348
9,786
1,253
9,773
8,373
3,663
12,884

Figure 8-1 shows average, monthly settled prices for NOX and SO2 emissions
allowances including CSAPR related allowances for 2020 and the first six
months of 2021. Figure 8-1 also shows the average, monthly settled price for
the Regional Greenhouse Gas Initiative (RGGI) CO2 allowances.

39 Id. at 23121.
40 Id.
41 On April 30, 2021, the MMU sent a market message to PJM market participants explaining how to account for the changes in cost-based
offers. See “CSAPR Ozone Season Changes,” <https://www.monitoringanalytics.com/reports/Market_Messages/Messages/IMM_CSAPR_
Ozone_Season_Changes_20210430.pdf>
42 Id. at 23123–23124 (Table VII.C.2–1–4).
43 See “State Budgets under the Revised Cross-State Air Pollution Rule Update,” EPA, <https://www.epa.gov/csapr/state-budgets-underrevised-cross-state-air-pollution-rule-update>.

2021 Quarterly State of the Market Report for PJM: January through June 381

2021 Quarterly State of the Market Report for PJM: January through June

In the first six months of 2021, CSAPR annual NOX prices were 2.0 percent
higher than in the first six months of 2020. In the first six months of 2020,
CSAPR Seasonal NOX prices were on average $64.44 per credit. The CSAPR
Seasonal NOX price for group 2 states averaged $244.28 in the first six monthsof 2021, a 279.1 percent increase over the CSAPR Seasonal NOX price for the
first six months of 2020.44 The CSAPR Seasonal NOX price for group 3 states
averaged $2,728.41 in the first six months of 2021, a 4,149.9 percent increaseover the CSAPR Seasonal NOX price for the first six months of 2020.45
Figure 8-1 Spot monthly average emission price comparison: January 2020
through June 2021
$3,000$15
CSAPR Seasonal NOx$2,500

CSAPR Seasonal NOx Group 2
CSAPR Seasonal NOx Group 3
CSAPR SO2 Group 1$2,000RGGI CO2$10$1,500$1,000$5

Average price ($/Ton) - Solid Lines

Average price ($/Ton) - Dashed Line

CSAPR Annual NOx

$500

$0
Jan-20Mar-20May-20Jul-20

Sep-20Nov-20Jan-21

Mar-21

May-21$0

CAA: NSR
Parts C and D of Title I of the CAA provide for New Source Review (NSR) in
order to prevent new projects and projects receiving major modifications fromincreasing emissions in areas currently meeting NAAQS or from inhibiting
44 Tennessee is the only PJM state that remains in the CSAPR NOX Ozone Season Group 2 Trading Program.
45 Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, Ohio, Pennsylvania, Virginia, and West Virginia participate in the CSAPRNOX Ozone Season Group 3 Trading Program.

382

Section 8 Environmental and Renewables

progress in areas that do not.46 NSR requires permits before constructioncommences. In PJM, permits are issued by state environmental regulators, orin a process involving state and regional EPA regulators.47
NSR review applies a two part analysis to projects at facilities such as power
plants, some of which involve multiple units and combinations of new andexisting units. The first part considers whether a modification would cause a“significant emission increase” of a regulated NSR pollutant. The second partconsiders whether any identified increase is also a “significant net emission
increase.”
On August 1, 2019, the EPA proposed revisions to the NSR permitting program
under which, both emissions increases and decreases from a major modification
would be considered in the first part of the NSR applicability test.48 Under therevised rule the need for a permit and associated investments in pollution
controls would be more frequently avoided than under the current rule.
On March 25, 2020, the EPA released a memorandum changing the EPA’s
longstanding interpretation of “begin actual construction” under the NSR
preconstruction permitting regulations.49 50 EPA policy has been to preclude
almost every physical onsite construction activity that is of a permanent
nature prior to issuance of a permit. Under the new interpretation, which
focuses on the statutory meaning of “emissions unit,”51 the policy precludes
only the construction of the emissions unit. The EPA clarified that the costs andconsequences of pre permit construction are risks born by the owner/operators
if no permit issues, or issues without the expected terms or conditions. The
new interpretation significantly expands the scope of activity that an owner/
46 42 U.S.C § 7470 et seq.
47 CAA permitting in EPA Region 2 (New Jersey) is the responsibility of the state’s environmental regulatory authority; CAA permitting
in Region 3 (Delaware, District of Columbia, Maryland, Pennsylvania, Virginia, West Virginia) is the shared responsibility of each state’s
environmental regulatory authority and EPA Region 3; CAA permitting in Region 4 (Kentucky and North Carolina) is the shared
responsibility of each state’s environmental regulatory authority and EPA Region 4; CAA permitting in EPA Region 5 (Illinois, Indiana,
Michigan and Ohio) is the responsibility of each state’s environmental regulatory authority.
48 Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR): Project Emissions Accounting, EPA Docket
No. EPA–HQ–OAR–2018–0048; FRL–9997–95–OAR, 84 Fed. Reg. 39244 (Aug. 9, 2019).
49 See Anne L. Idsal, Principal Deputy Assistant Administrator, Memorandum re Interpretation of “Begin Actual Construction” Under the
New Source Review Preconstruction Permitting Regulations” (“March 25th Memo”).
50 See 40 CFR § 52.21(b)(11); 40 CFR § 52.21(a)(2)(iii).
51 40 CFR § 52.21(b)(7) (“any part of a stationary source that emits or would have the potential to emit any regulated NSR pollutant andincludes an electric utility steam generating unit…”).

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

operator willing to assume the risks may undertake prior to receiving an NSR
permit when constructing a project that will include an emissions unit.

CAA: RICEOn January 14, 2013, the EPA signed a final rule amending its rules regulating
emissions from a wide variety of stationary reciprocating internal combustion
engines (RICE). RICE include certain types of electrical generation facilities like
diesel engines typically used for backup, emergency or supplemental power,
including facilities located behind the meter. These rules include: National
Emission Standard for Hazardous Air Pollutants (NESHAP) for Reciprocating
Internal Combustion Engines (RICE); New Source Performance Standards(NSPS) of Performance for Stationary Spark Ignition Internal Combustion
Engines; and Standards of Performance for Stationary Compression Ignition
Internal Combustion Engines (collectively RICE Rules). The RICE Rules apply
to emissions such as formaldehyde, acrolein, acetaldehyde, methanol, CO,
NOX, volatile organic compounds (VOCs) and PM.
EPA regulations require that RICE that do not meet EPA emissions standards(emergency stationary RICE) may operate for only 100 hours per year andonly to provide emergency DR during an Energy Emergency Alert 2 (EEA2),
or if there are five percent voltage/frequency deviations.52 Under PJM rules,
an EEA2 is automatically triggered when PJM initiates an emergency load
response event. Demand resources that rely on RICE to provide load reductions
are constrained to a maximum of 100 hours.
PJM does not prevent emergency stationary RICE that does not meet emissions
standards from participating in PJM markets as DR. Some emergency
stationary RICE that does not meet emissions standards are now included in DR
portfolios. Emergency stationary RICE should be prohibited from participation
as DR either when registered individually or as part of a portfolio if it does
not meet emissions standards. Emergency RICE with a limit of 100 hours per
year cannot comply with the requirement to be available during the entire
delivery year to be a capacity resource. PJM should not allow locations that
rely upon emergency stationary RICE to register individually or in portfolios.
52 Emergency Operations, EOP-011-1, North American Electric Reliability Corporation, <https://www.nerc.com/pa/Stand/Reliability%20
Standards/EOP-011-1.pdf> (Accessed March 2, 2020).

© 2021 Monitoring Analytics, LLC

Registration of DR should be based on a finding that registered locations arecapable of providing load reductions without an hourly limit. Reliance on theprospect of penalties to deter registration of ineligible resources as DR in lieu
of a substantive ex ante review is not appropriate.

CAA: Greenhouse Gas Emissions
The EPA regulates CO2 as a pollutant using CAA provisions that apply topollutants not subject to NAAQS.53 54
The U.S. Court of Appeals for the Seventh Circuit has determined that agovernment agency can reasonably consider the global benefits of carbon
emissions reduction against costs imposed in the U.S. by regulations inanalyses known as the “Social Costs of Carbon.”55 The Court rejected claims
raised by petitioners that raised concerns that the Social Cost of Carbon
estimates were arbitrary, were not developed through transparent processes,
and were based on inputs that were not peer reviewed.56 Although the decisionapplies only to the Department of Energy’s regulations of manufacturers, itbolsters the ability of the EPA and state regulators to rely on Social Cost of
Carbon analyses.
Executive Order 13990, Section 6, establishes an Interagency Working Groupon the Social Cost of Greenhouse Gases. The group is tasked to develop
estimates in the form of monetized damages for the “social cost of carbon”(SCC), the “social cost of nitrous oxide” (SCN), and the “social cost of methane”(SCM), associated with incremental increases in greenhouse gas emissions.
The cost estimates would be used by EPA and other agencies to determine thesocial benefits of reducing greenhouse gas emissions when conducting costbenefit analyses of regulatory and other actions.
53 See CAA § 111.
54 On April 2, 2007, the U.S. Supreme Court overruled the EPA’s determination that it was not authorized to regulate greenhouse gas
emissions under the CAA and remanded the matter to the EPA to determine whether greenhouse gases endanger public health andwelfare. Massachusetts v. EPA, 549 U.S. 497. On December 7, 2009, the EPA determined that greenhouse gases, including carbon
dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride, endanger public health and welfare. See
Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, 74 Fed. Reg. 66496,
66497 (Dec. 15, 2009). In a decision dated June 26, 2012, the U.S. Court of Appeals for the D.C. Circuit upheld the endangerment finding,rejecting challenges brought by industry groups and a number of states. Coalition for Responsible Regulation, Inc., et al. v. EPA, No 091322.
55 See Zero Zone, Inc., et al., v. U.S. Dept. of Energy, et al., Case Nos. 14-2147, et al., Slip Op. (Aug. 8, 2016).
56 Id.

2021 Quarterly State of the Market Report for PJM: January through June 383

2021 Quarterly State of the Market Report for PJM: January through June

Effective October 23, 2015, the EPA placed national limits on the amount of
CO2 that new, modified or reconstructed fossil fuel fired steam power plants
would be allowed to emit based on the best system of emission reductions(BSER) determined by the EPA (2015 GHG NSR Rule).57 On December 12,
2018, the EPA proposed to revise the 2015 GHG NSR Rule by increasing theallowable emissions and eliminating the requirement for carbon capture for
new coal units.58
On January 19, 2021, the U.S. Court of Appeals for the District of Columbia
Circuit vacated the EPA’s Affordable Clean Energy (ACE) rule which would
have permitted more CO2 emissions than under the Clean Power Plan, which
ACE had replaced. On February 12, 2021, the EPA issue a memo stating thatas a result of the court vacating ACE without reinstating the Clean Power
Plan (“CPP”), there are no effective regulations under CAA section 111(d) withrespect to greenhouse gas emissions from electric generating units at thistime, and states are not currently required to submit plans.59 The memo also
noted: “ongoing changes in electricity generation mean that the emission
reduction goals that the CPP set for 2030 have already been achieved.”60

CWA: WOTUS Definition and Effluents
WOTUS
The Clean Water Act (CWA) applies to the navigable waters, which are defined
as waters of the United States (WOTUS).61 62
On October 22, 2019, the EPA issued a final rulemaking to rescind thedefinition of WOTUS proposed in the 2015 Clean Water Rule. The rule prevents
the potential implementation of a broader definition of WOTUS included in
57 Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units, Proposed Rule,
EPA-HQ-OAR-2013-0495, 90 Fed. Reg. 205 (October 23, 2015) (“2015 GHG NSR Rule”); 40 CFR Part 60, subpart TTTT.
58 Review of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric
Utility Generating Units, EPA–HQ–OAR–2013–0495; FRL–9987–85– OAR, 83 Fed. Reg. 65424, 65427 (Dec. 20, 2018) (“2018 Proposed Rev.
GHG NSR”).
59 See Joseph Goffman, Acting Assistant Administrator, EPA, Memo re Status of Affordable Clean Energy Rule and Clean Power Plan
(February 12, 2021).
60 Id., citing “Regulatory Impact Analysis for the Repeal of the Clean Power Plan, and the Emission Guidelines for Greenhouse Gas Emissions
from Existing Electric Utility Generating Units,” EPA-452/R-19-003 (June 2019), at 2-14 to 2-15.
61 33 U.S.C. 1251 et seq.; 33 U.S.C. § 1362(7) (“The term “navigable waters” means the waters of the United States, including the territorial
seas.”).
62 For more details, see the 2019 State of the Market Report for PJM, Volume II, Appendix H: “Environmental and Renewable Energy
Regulations.”

384

Section 8 Environmental and Renewables

the 2015 rule that was never implemented as the result of a stay issued bya reviewing Court.63 The U.S. Supreme Court reversed the stay, but the EPA
amended the 2015 Clean Water Rule to establish an applicability date of
February 6, 2020.64
On April 21, 2020, the EPA and the Department of the Army published a final
rule to define WOTUS, the Navigable Waters Protection Rule (“NWPR”).65 TheNWPR became effective in PJM states on June 22, 2020. The replacement rulesignificantly narrowed the scope of federal jurisdiction. The replacement rule
does not include coal ash ponds in the definition of WOTUS.66 On June 9, 2021,
the EPA and the Department of the Army concluded their review pursuant toOrder 13990 of the NWPR and announced their intention to initiate a newrulemaking process that restores the protections in place prior to the 2015
WOTUS implementation and develops a new definition of WOTUS.67
The scope of the CWA has expanded and the precise definition of WOTUS
has become less important as a result of a decision of the U.S. Supreme Courtin County of Maui v. Hawaii Wildlife Fund, which held that the discharge ofpollutants via groundwater requires a CWA permit.68 Groundwater is not itself
WOTUS. However, if pollutants pass through groundwater from a point source
to WOTUS, a permit may be required.69 This holding invalidates the EPA’s
recent interpretive statement intended to establish a bright line rule excluding
all releases of pollutants to groundwater from the permitting program.70 The
EPA may not interpret the CWA to require a direct discharge.71 The Court
held that discharge into groundwater “is the functional equivalent of a directdischarge.”72 The existence of a functional discharge will depend on an
63 The stay was issued by the U.S. Court of Appeals for the Sixth Circuit on October 9, 2015.
64 See Definition of ‘‘Waters of the United States’’—Addition of an Applicability Date to 2015 Clean Water Rule, Final Rule, EPA Docket No.
EPA-HQ-OW-2017-0644, 83 Fed. Reg. 5200 (Feb. 6, 2018); National Assoc. of Mfg. v Dept. of Defense, No. 16-299 (S. Ct. Jan. 22, 2018).
65 See The Navigable Waters Protection Rule: Definition of “Waters of the United States,” EPA Docket No. EPA–HQ–OW–2018–0149, 85 Fed.
Reg. 22250.
66 Id. at 22251–22252.
67 EPA News Release, “EPA, Army Announce Intent to Revise Definition of WOTUS.”
68 Slip. Op. No. 18–260 (April 23, 2020).
69 Id.
70 See Interpretive Statement on Application of the Clean Water Act National Pollutant Discharge Elimination System Program to Releasesof Pollutants From a Point Source to Groundwater, 84 Fed. Reg. 16810 (April 23, 2019).
71 Slip. Op. No. 18–260 at 5.
72 Id. at 1.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

analysis including time and distance, and other factors.73 Additional litigation
or administrative action may clarify the functional discharge analysis.74
County of Maui reduces the importance of the precise definition of WOTUS
because WOTUS is generally part of the watershed.75

Discharges and Intakes
The EPA regulates discharges from and intakes to power plants, including
water cooling systems at steam electric power generating stations, under theCWA.76

RCRA: Coal Ash
The EPA administers the Resource Conservation and Recovery Act (RCRA),
which governs the disposal of solid and hazardous waste.77 Solid waste isregulated under subtitle D. Subtitle D criteria are not directly enforced by the
EPA. Subtitle C governs the disposal of hazardous waste. Hazardous waste is
subject to direct regulatory control by the EPA from the time it is generated
until its ultimate disposal.
In April 2015, the EPA issued a rule under RCRA, the Coal Combustion
Residuals rule (2015 CCRR), which sets criteria for the disposal of coal
combustion residues (CCRs), or coal ash, produced by electric utilities andindependent power producers.78 CCRs include fly ash (trapped by air filters),
bottom ash (scooped out of boilers) and scrubber sludge (filtered using wet
limestone scrubbers). These residues are typically stored on site in ponds(surface impoundments) or sent to landfills.
73 Id. at 16 (“The difficulty with this approach, we recognize, is that it does not, on its own, clearly explain how to deal with middle
instances. But there are too many potentially relevant factors applicable to factually different cases for this Court now to use more
specific language. Consider, for example, just some of the factors that may prove relevant (depending upon the circumstances of aparticular case): (1) transit time, (2) distance traveled, (3) the nature of the material through which the pollutant travels, (4) the extent towhich the pollutant is diluted or chemically changed as it travels, (5) the amount of pollutant entering the navigable waters relative tothe amount of the pollutant that leaves the point source, (6) the manner by or area in which the pollutant enters the navigable waters,(7) the degree to which the pollution (at that point) has maintained its specific identity. Time and distance will be the most importantfactors in most cases, but not necessarily every case.”).
74 Id.
75 See id. at 5 (“Virtually all water, polluted or not, eventually makes its way to navigable water. This is just as true for groundwater.”).
76 For more details, see the 2019 State of the Market Report for PJM, Volume II, Appendix H: “Environmental and Renewable Energy
Regulations.”
77 42 U.S.C. §§ 6901 et seq.
78 See Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities, 80 Fed. Reg. 21302(April 17, 2015).

© 2021 Monitoring Analytics, LLC

In 2016, RCRA was amended to establish a permitting scheme allowing states
to apply to the EPA for approval to operate a permit program that implements
the CCR rule. Such state programs could include alternative state standards,
provided that EPA determines that they are ‘‘at least as protective as’’ the EPA
CCR regulations.79
Effective August 9, 2018, the EPA approved certain revisions to the 2015
CCRR (“2018 CCRR Revisions”) partly in response to the 2016 amendments.80
The 2018 CCRR Revisions provide for two types of alternative performancestandards. The first type of standards allows a state director (if a state has EPA
approved CCR permit program) or the EPA (if no state program) to suspend
groundwater monitoring requirements if there is evidence that there is nopotential for migration of hazardous constituents to the uppermost aquifer
during the active life of the unit and during post closure care. The second
type allows issuance of technical certifications by a state director in lieu of aprofessional engineer.
The 2018 CCRR Revisions revised the groundwater protection standards forhealth-based levels for four contaminants: cobalt at 6 mg/L; lithium at 40
mg/L; molybdenum at 100 mg/L and lead at 15 mg/L. Standards for othermonitored contaminants follow the Maximum Contaminant Level (MCL)
established under the Safe Water Drinking Act.
The 2018 CCRR Revisions extended the deadline for closing coal ash units
in two situations: (i) detection of a statistically significant increase above agroundwater protection standard from an unlined surface impoundment; or(ii) inability to comply with the location restriction regarding placement above
the uppermost aquifer. The exceptions in the 2018 CCRR to the standards inthe 2015 CCRR and relaxation of the deadlines create a less stringent federal
rule.

79 The Water Infrastructure Improvements for the Nation Act (WIIN Act).
80 See Hazardous and Solid Waste Management System: Disposal of Coal Combustion Residuals From Electric Utilities; Amendments to the
National Minimum Criteria (Phase One, Part One), EPA Docket No. EPA–HQ–OLEM–2017–0286, 83 Fed. Reg. 36435 (July 30, 2018).

2021 Quarterly State of the Market Report for PJM: January through June 385

2021 Quarterly State of the Market Report for PJM: January through June

The U.S. Court of Appeals for the D.C. Circuit invalidated certain provisions of
the 2015 CCRR and remanded it to the EPA.81 On July 29, 2020, the EPA finalized
revisions to CCRR in compliance with the court orders (“Revised CCRR”).82 The
Revised CCRR requires (i) unlined surface impoundments (ponds) and ponds
failing restrictions on the minimum depth to or interaction with an aquifer
to cease receiving waste as soon as technically feasible and no later than
April 11, 2021; and (ii) removal of compacted soil lined and clay lined ponds
from classification as lined and exempt from CCRR.83 Impoundment facilities
unable to meet the earliest deadline would be able to obtain extensions until
an alternative can be “technically feasibly implemented.”84 Utilities had until
November 30, 2020, to obtain an automatic extension upon certification ofneed for additional time.85 86 Upon receipt of required documentation satisfying
certain criteria, the EPA could grant certain extensions, including to as lateas October 17, 2028, for a facility with a surface impoundment of 40 acres orgreater that commits to a deadline for ending operations of its boiler.87
In response to the RCRA amendments, the EPA proposed a new rule toimplement a federal CCR permit program in non participating states, noticed
February 20, 2020.88 This proposal includes requirements for federal CCR permit
applications, content and modification, as well as procedural requirements.
The EPA would implement this permit program at CCR units located in statesthat have not submitted their own CCR permit program for approval. No PJM
state has yet applied for EPA approval of a coal ash permitting program.
In Virginia, the Waste Management Board amended the Virginia Solid Waste
Management Regulations in December 2015, to incorporate the EPA’s 2015
CCRR, and did not adopt the less stringent 2018 CCRR Revisions.89 In 2019,
Virginia enacted legislation directing the closure of coal ash ponds located in
81 Utility Solid Waste Activities Group, et al. v. EPA, No. 15-1219 (D.C. Cir. August 21, 2018); Waterkeeper Alliance Inc. et al. v. EPA, No.
18–1289 (D.C. Cir. March 13, 2019).
82 See Hazardous and Solid Waste Management System: Disposal of Coal Combustion Residuals From Electric Utilities; A Holistic Approachto Closure Part A: Deadline To Initiate Closure, EPA–HQ–OLEM–2019–0172; FRL–10002– 02–OLEM, 85 Fed. Reg. 53516 (August 28, 2020).
83 Id. at 53516–53517, 53536.
84 Id. at 53546.
85 Id. at 65942.
86 A number of plants in PJM timely filed for extensions.
87 Id.
88 See Hazardous and Solid Waste Management System: Disposal of Coal Combustion Residuals From Electric Utilities; Federal CCR Permit
Program, 85 Fed. Reg. 9940 (Feb. 20, 2020).
89 The following Virginia power stations host coal ash ponds: Bremo Power Station, Chesapeake Energy Center, Chesterfield Power Station,
Clinch River Plant and Possum Point Power Station, owned by Dominion Energy; and Glen Lyn Plant, owned by Appalachian Power.

386

Section 8 Environmental and Renewables

the Chesapeake Bay Watershed and owned by Dominion Energy.90 Effective
July 1, 2019, coal ash ponds at power stations in the Chesapeake Bay Watershed
had to be closed by removal of coal ash. The removed coal ash either had tobe recycled (at least 6.8 million cubic yards) or disposed of in a modern, lined
landfill. The Virginia DEQ is addressing closing ash ponds under two types ofenvironmental permits: wastewater discharge permits covering the removal oftreated water from the ponds; or solid waste permits covering the permanent
closure of the ponds.
On March 30, 2020, in response to a statutory mandate,91 the Illinois
Environmental Protection Agency (Illinois EPA) proposed rules for coal
combustion residual surface impoundments with the Illinois Pollution Control
Board.92 The proposed rules contain standards for the storage and disposalof coal combustion residuals in surface impoundments. The proposed rules
include a permitting program and are intended to meet federal standards.93
Presumably the rules, once finalized, would be the basis for an application
under RCRA allowing the Illinois EPA to also administer the federal regulatory
program. The Illinois EPA has identified 73 coal combustion residuals surface
impoundments at power stations, some lined with impermeable materials
and some not.94 The Illinois EPA believes that as many as six lined surface
impoundments may comply with the federal liner standards.95
The North Carolina Department of Environmental Quality (NCDEQ) has
initiated a rule making on rules for the disposal or recycling of coal combustion
residuals. None of the affected power stations or power station impoundments
are located in the PJM Dominion Zone (which includes a portion of northeast
coastal North Carolina).
The Maryland Department of Environment (MDE) indicated in April 2020, that
it would require GenOn Holdings Inc. to meet a November 1, 2020, deadline
for compliance with effluent guidelines at Chalk Point Generating Station,
90
91
92
93

Va. Code § 10.1-1402.03.
Ill. Public Act 101-171 (a.k.a. SB 09).
The proposed rule amends the Illinois Administrative Code to create a new Part 845 in Title 35.
See In the Matter of Standards for the Disposal of Coal Combustion Residuals in Surface Impoundments, No. R 2020-019 (March 30,2020) at 1 (Proposed New 35 Ill. Adm. Code 845) (“Proposed Illinois CCR Rules”).
94 Proposed Illinois Rules at 3.
95 Id. at 3.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Dickerson Generating Station and Morgantown Generating Station.96 On May
15, 2020, GenOn announced its decision to retire the Dickerson Generating
Station.97 Dickerson Generating Station was retired effective August 13, 2020.
The Chalk Point coal units were retired effective June 1, 2021. On June 9,
2021, GenOn reported that it would retire its Morgantown coal fired unit by
October 1, 2027, five years earlier than previously announced.98

State Environmental Regulation
State Emissions Regulations
States have in some cases enacted emissions regulations more stringent or
potentially more stringent than federal requirements:99• New Jersey HEDD. Units that run only during peak demand periods have•relatively low annual emissions, and have less reason to make suchinvestments under the EPA transport rules. New Jersey addressed the issueof NOX emissions on peak energy demand days with a rule that defines
peak energy usage days, referred to as high electric demand days or HEDD,
and imposes operational restrictions and emissions control requirements
on units responsible for significant NOX emissions on such high energy
demand days. New Jersey’s HEDD rule, which became effective May
19, 2009, applies to HEDD units, which include units that have a NOX
emissions rate on HEDD equal to or exceeding 0.15 lbs/MMBtu and lack
identified emission control technologies.
Illinois Air Quality Standards (NOX, SO2 and Hg). The State of Illinois has
promulgated its own standards for NOX, SO2 and Hg (mercury) known
as Multi-Pollutant Standards (MPS) and Combined Pollutants Standards(CPS). MPS and CPS establish standards that are more stringent and takeeffect earlier than comparable Federal regulations, such as the EPA’s
MATS.

96 See Potomac Riverkeeper Network, Press Release, “Maryland Proposes to Reject Effort to Delay Pollution Reductions” (Posted April 4,2020), <https://www.‌potomacriverkeepernetwork.org/maryland-proposes-to-reject-effort-to-delay-pollution-reductions/>.
97 See “GenOn Holdings, Inc. Announces Retirement of Dickerson Coal Plant” (May 15, 2020) <https://www.genon.com/genon-news/genonholdings-inc-announces-retirement-of-dickerson-coal-plant>.
98 See “GenOn Holdings, LLC Announces Retirement of Three Coal-Fired Power Plants” (June 9, 2021) <https://www.genon.com/genonnews/genon-holdings-llc-announces-retirement-of-three-coal-fired-power-plants>.
99 For more details, see the 2019 State of the Market Report for PJM, Volume 2, Appendix H: “Environmental and Renewable Energy
Regulations.”© 2021 Monitoring Analytics, LLC

State Regulation of Greenhouse Gas Emissions
Clean Energy Standards
In April 2020, Virginia enacted the Virginia Clean Economy Act, which orders
the closure of most coal generation in state by 2024, most fossil fuel generation
by 2045, and adopts a 100 percent clean energy standard by 2045.100 The
legislation mandates Chesterfield Power Station Units 5 & 6 and Yorktown
Power Station Unit 3 to be retired by the end of 2024, Altavista, Southamptonand Hopewell to be retired by the end of 2028 and Virginia Power’s remaining
fossil fuel units to be retired by the end of 2045, unless the retirement of suchgenerating units will compromise grid reliability or security.101 The legislation
also imposes a temporary moratorium on Certificates of Public Convenienceand Necessity for fossil fuel generation, unless the resources are needed forgrid reliability.102

RGGI
The Regional Greenhouse Gas Initiative (RGGI) is a cooperative effort by
Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire,
New Jersey (as of January 1, 2020), New York, Rhode Island, Vermont andVirginia (as of January 1, 2021) to cap CO2 emissions from power generation
facilities.103
Delaware, Maryland, New Jersey and Virginia are the only PJM states thatare members of RGGI. New Jersey, a founding member of RGGI, opted out
in 2011 but rejoined RGGI in 2020.104 Virginia joined RGGI on January 1,
2021. Pennsylvania has also expressed interest in joining RGGI. Pennsylvania
Governor Tom Wolf issued an executive order on October 3, 2019, directing
the Pennsylvania Department of Environmental Protection (DEP) to develop
a proposal to limit carbon emissions from fossil fuel generators that is
100 Va. HB 1526/SB 851.
101 See Dominion Energy, Inc., et al., SEC Form 10-Q (Quarter ending June 30, 2020).
102 Id.
103 RGGI provides a link on its website to state statutes and regulations authorizing its activities, which can be accessed at: <http://www.
rggi.org/design/regulations>.
104 “Statement on New Jersey Greenhouse Gas Rule,” RGGI Inc., (June 17, 2019) <https://www.rggi.org/sites/default/files/Uploads/PressReleases/2019_06_17_NJ_‌Announcement_Release.pdf>.

2021 Quarterly State of the Market Report for PJM: January through June 387

2021 Quarterly State of the Market Report for PJM: January through Juneconsistent with RGGI.105 The Pennsylvania Environmental Quality Board(EQB), on September 15, 2020, approved a draft regulation developed by thePennsylvania Department of Environmental Protection (DEP) that governs
Pennsylvania’s entry into RGGI in 2022. The draft regulation will be subject
to public comment and then the DEP will hold a series of hearings prior to
submitting a final regulation to the EQB.106 The order also directs DEP to“engage with PJM Interconnection to promote the integration of this programin a manner that preserves orderly and competitive economic dispatch within
PJM and minimizes emissions leakage.”
Table 8-2 shows the RGGI CO2 auction clearing prices and quantities, in shorttons and metric tonnes, for the 3rd control period, the 4th control period, andthe first two auctions of the 5th control period.107 108 The clearing price for theauction held June 2, 2021 was $7.97 per allowance (equal to one short tonof CO2).109 The June auction clearing price increased 4.9 percent over the lastauction clearing price of $7.60 in March 2021.

105 Executive Order No. 2019-07- Commonwealth Leadership in Addressing Climate Change through Electric Sector Emissions Reductions,
Tom Wolf, Governor (Oct. 3, 2019), <https://www.governor.pa.gov/newsroom/executive-order-2019-07-commonwealth-leadership-inaddressing-climate-change-through-electric-sector-emissions-reductions/>.
106 “Environmental Quality Board Approves Proposed Climate Change Regulation,” DEP Newsroom, (September 15, 2020) <https://www.ahs.
dep.pa.gov/NewsRoomPublic/‌articleviewer.aspx?id=21865&typeid=1>.
107 Each control period is three years in duration. The 3rd control period covers 2015 through 2017. The 4th control period covers 2018
through 2020. The 5th control period covers 2021 through 2023.
108 The September 3, 2015, auction included additional Cost Containment Reserves (CCRs) since the clearing price for allowances was above
the CCR trigger price of $6.00 per ton in 2015. The auctions on March 5, 2014, and September 3, 2015, were the only auctions to use
CRRs.
109 RGGI measures carbon in short tons (short ton equals 2,000 pounds) while world carbon markets measure carbon in metric tonnes(metric tonne equals 1,000 kilograms or 2,204.6 pounds).

388

Section 8 Environmental and Renewables

Table 8-2 RGGI CO2 allowance auction prices and quantities in short tons andmetric tonnes: 3rd, 4th and 5th Control Periods110
Auction Date
March 11, 2015
June 3, 2015
September 3, 2015
December 2, 2015
March 9, 2016
June 1, 2016
September 7, 2016
December 7, 2016
March 8, 2017
June 7, 2017
September 8, 2017
December 8, 2017
March 14, 2018
June 13, 2018
September 9, 2018
December 5, 2018
March 13, 2019
June 5, 2019
September 4, 2019
December 4, 2019
March 11, 2020
June 3, 2020
September 2, 2020
December 2, 2020
March 3, 2021
June 2, 2021

Clearing
Price
$5.41
$5.50
$6.02
$7.50
$5.25
$4.53
$4.54
$3.55
$3.00
$2.53
$4.35
$3.80
$3.79
$4.02
$4.50
$5.35
$5.27
$5.62
$5.20
$5.61
$5.65
$5.75
$6.82
$7.41
$7.60
$7.97

Short Tons
Quantity
Offered15,272,670
15,507,571
25,374,294
15,374,274
14,838,732
15,089,652
14,911,315
14,791,315
14,371,300
14,597,470
14,371,585
14,687,989
13,553,767
13,771,025
13,590,107
13,360,649
12,883,436
13,221,453
13,116,447
13,116,444
16,208,347
16,336,298
16,192,785
16,237,495
23,467,261
22,987,719

Quantity
Sold
15,272,670
15,507,571
25,374,294
15,374,274
14,838,732
15,089,652
14,911,315
14,791,315
14,371,300
14,597,470
14,371,585
14,687,989
13,553,767
13,771,025
13,590,107
13,360,649
12,883,436
13,221,453
13,116,447
13,116,444
16,208,347
16,336,298
16,192,785
16,237,495
23,467,261
22,987,719

Clearing
Price
$5.96
$6.06
$6.64
$8.27
$5.79
$4.99
$5.00
$3.91
$3.31
$2.79
$4.80
$4.19
$4.18
$4.43
$4.96
$5.90
$5.81
$6.19
$5.73
$6.18
$6.23
$6.34
$7.52
$8.17
$8.38
$8.79

Metric Tonnes
Quantity
Offered
13,855,137
14,068,236
23,019,179
13,947,311
13,461,475
13,689,106
13,527,321
13,418,459
13,037,428
13,242,606
13,037,686
13,324,723
12,295,774
12,492,867
12,328,741
12,120,580
11,687,660
11,994,304
11,899,044
11,899,041
14,703,969
14,820,045
14,689,852
14,730,412
21,289,147
20,854,114

Quantity
Sold
13,855,137
14,068,236
23,019,179
13,947,311
13,461,475
13,689,106
13,527,321
13,418,459
13,037,428
13,242,606
13,037,686
13,324,723
12,295,774
12,492,867
12,328,741
12,120,580
11,687,660
11,994,304
11,899,044
11,899,041
14,703,969
14,820,045
14,689,852
14,730,412
21,289,147
20,854,114

The RGGI auction held on June 2, 2021, generated $183.2 million in auction
revenue. RGGI auctions have generated $4.1 billion in auction revenue since2008.111 RGGI auction revenue is returned to the states. RGGI reported that
the RGGI states, cumulative through the 2019 reporting year, have spentapproximately 54 percent of the revenue on energy efficiency, 14 percent on
clean and renewable energy, 10 percent on greenhouse gas abatement and 15
percent on direct bill assistance.112
110 See Regional Greenhouse Gas Initiative, “Auction Results,” <http://www.rggi.org/market/‌co2_auctions/results> (Accessed April 14, 2021).
111 See Auction Results at <https://www.rggi.org/>.
112 The Investment of RGGI Proceeds in 2019, The Regional Greenhouse Gas Initiative (RGGI), June 2021, <https://www.rggi.org/investments/
proceeds-investments>.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

If all PJM states joined RGGI, the total RGGI revenue to the PJM states would
be significant. The estimated allowance revenue for PJM states based on 2020
CO2 emission levels and the RGGI clearing price for the June 2021 auction
ranges from $1.4 billion per year to $2.6 billion per year depending on
associated reductions in carbon emission levels (Table 8-3).113 Table 8-3 showsthe estimated carbon allowance revenue for each PJM state based on the latest
RGGI auction price and reductions below 2020 CO2 emission levels ranging
from five to 50 percent. A power plant owner must acquire an allowance foreach ton of CO2 emissions and the revenue values in Table 8-3 are computedby multiplying the carbon price by the emission cap level which is expressed
as a reduction below the 2020 actual emissions level. States that participate in
RGGI choose their emission cap. For example, New Jersey chose an emission
cap of 18,000,000 short tons for reentry into RGGI in 2020, 5.3 percent below
New Jersey’s 2018 CO2 emissions level; the New Jersey emission cap will be
reduced by 540,000 short tons each year through 2030.114

The RGGI emissions cap is the sum of CO2 allowances issued by each state.
Table 8-4 shows the RGGI emission cap history. Compliance with the RGGI
allowance obligation is evaluated at the end of each three year period whichis called the control period. The first control period began in 2009. The 2021
compliance year is the first year of the fifth control period.

RGGI recently announced a third adjustment to the RGGI emissions cap toaccount for banked allowances from previous control periods.117 118 The firstadjustment removed 57.5 million allowances that were banked or unused fromthe first control period. The reduction to the RGGI emissions cap was spreadover a seven year period beginning in 2014 and ending with 2020.119 A second
cap adjustment, corresponding to banked allowances for 2012 and 2013, began
in 2015 with an adjustment of 13.7 million allowances per year and was inplace through 2020.120 The third adjustment of 95.5 million allowances will be
spread over a five year period beginning in 2021.121 The base emissions cap foreach of the next five years will be reduced by 19.1
Table 8-3 Estimated CO2 allowance revenue at June 2021 RGGI price level115 116
allowances. The percent change columns in Table
Estimated CO2 allowance revenue ($ millions), carbon price $7.97 per short ton
8-4 show the year to year percent changes in the2020 power
5 percent
10 percent
15 percent
20 percent
25 percent
50 percent
generation CO2 reduction below reduction below reduction below reduction below reduction below reduction below
base RGGI cap and the adjusted RGGI cap.122 The
emissions (short2020 emission
2020 emission
2020 emission
2020 emission
2020 emission
2020 emission
adjusted emissions cap for 2021 marks the first year
Jurisdiction
tons)levelslevelslevelslevelslevelslevelsthe adjusted carbon emissions cap has increased
Delaware2,055,837.3
$15.6
$14.7
$13.9
$13.1
$12.3
$8.2
Illinois
18,801,034.9$142.4$134.9$127.4$119.9$112.4$74.9
since the start of RGGI.123 Figure 8-2 shows the
Indiana
32,618,816.1$247.0$234.0$221.0$208.0$195.0$130.0adjusted carbon budgets for the RGGI states. All
Kentucky
28,595,734.2$216.5$205.1$193.7$182.3$170.9$114.0Maryland
10,160,364.6
$76.9
$72.9
$68.8
$64.8
$60.7
$40.5
states, with the exception of New Jersey, have a
Michigan
0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
higher 2021 adjusted carbon budget relative to the
New Jersey
11,765,032.5
$89.1
$84.4
$79.7
$75.0
$70.3
$46.9
North Carolina
40,388.7
$0.3
$0.3
$0.3
$0.3
$0.2
$0.2
corresponding 2020 budget. The RGGI clearing
Ohio
Pennsylvania
Tennessee
Virginia
Washington, D.C.
West Virginia
Total

80,279,155.3
77,857,196.9
0.0
32,755,841.7
0.053,818,573.2
348,747,975.2$607.8$589.5$0.0$248.0$0.0$407.5$2,640.5$575.8$558.5$0.0$235.0$0.0$386.0$2,501.6$543.9$527.4$0.0$221.9$0.0$364.6$2,362.6$511.9$496.4$0.0$208.9$0.0$343.1$2,223.6

113 This assumes that the PJM states would implement their RGGI rules consistent with the current RGGI states where owners of fossil fuelgenerators are required to purchase emission allowances in a regional centralized auction or purchase allowances in a secondary market.
114 “Governor Murphy Announces Adoption of Rules Returning New Jersey to Regional Greenhouse Gas Initiative,” State of New Jersey,
Governor Phil Murphy Press Release, June 17, 2019 <https://nj.gov/governor/news/news/562019/approved/20190617a.shtml>.
115 The 2020 CO2 emissions data is from the EPA Continuous Emission Monitoring System (CEMS) from generators located within the PJM
footprint.
116 Power generation companies subject to a RGGI emission cap can offset up to 3.3 percent of their allowance obligation by undertaking
certain greenhouse gas emission reduction projects. The allowance revenue values in Table 8-2 do not reflect offset allowances.

© 2021 Monitoring Analytics, LLC$479.9$465.4$0.0$195.8$0.0$321.7$2,084.6$319.9$310.3$0.0$130.5$0.0$214.5$1,389.8

117 “ Third Adjustment for Banked Allowances Announcement,” Regional Greenhouse Gas
Initiative (March 15, 2021) <https://www.rggi.org/news-releases/rggi-releases>.
118 A
 banked allowance is an allowance acquired during a previous control period that was
not used to fulfill a RGGI allowance obligation.
119 “ Second Control Period Interim Adjustment for Banked Allowances Announcement,”
Regional Greenhouse Gas Initiative (March 17, 2014) at 2. Due to rounding, theadjustment is 8,207,664 allowances for years 2014 through 2018, and 8,207,663
allowances for the remaining two years <https://www.rggi.org/sites/default/‌files/Uploads/
Design-Archive/2012-Review/‌Adjustments/2014_03_17_SCP_Adjustment.pdf>.
120 Id.
121 “ Third Adjustment for Banked Allowances Announcement”, Regional Greenhouse Gas
Initiative (March 15, 2021) <https://www.rggi.org/news-releases/rggi-releases>.
122 P ercent changes for years with membership changes do not reflect the impacts of thechange in membership. For example, the percent changes from 2019 to 2020 do notreflect the impact of New Jersey rejoining RGGI.
123 The increase of 4.5 percent does not reflect the addition of Virginia as a RGGI state.

2021 Quarterly State of the Market Report for PJM: January through June 389

2021 Quarterly State of the Market Report for PJM: January through June

price since 2014 has been on average 119.2 percent higher than the prices
prior to the emission cap adjustments.

Figure 8-2 RGGI adjusted carbon budgets by state127
70

Table 8-4 RGGI emissions cap history124 125 126

2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023

1st

2nd

3rd

4th

5th

RGGI Cap(short tons)
188,076,976
188,076,976
188,076,976
165,184,246
165,184,246
91,000,000
88,725,000
86,506,875
84,344,203
82,235,598
80,363,945
96,354,847
119,767,784
116,112,784
112,457,784

Percent
Change
0.0%
0.0%
0.0%
0.0%
(44.9%)(2.5%)(2.5%)(2.5%)(2.5%)(2.3%)(2.5%)(3.9%)(3.1%)(3.1%)

RGGI
Adjusted Cap(short tons)
188,076,976
188,076,976
188,076,976
165,184,246
165,184,246
82,792,336
66,833,592
64,615,467
62,452,795
60,344,190
58,472,538
74,463,439
100,677,454
97,022,454
93,367,454

Percent
Change
0.0%
0.0%
0.0%
0.0%
(49.9%)(19.3%)(3.3%)(3.3%)(3.4%)(3.1%)(3.4%)
4.5%(3.6%)(3.8%)

Short Tons (Millions)Control
PeriodRGGI Average
Clearing Price($ per short ton)
$2.77
$1.93
$1.89
$1.93
$2.92
$4.72
$6.10
$4.47
$3.42
$4.41
$5.43
$6.41
$7.78

60

50

Connecticut

Delaware

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Rhode Island

Vermont

Virginia

40

30

20

10

0

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

If higher carbon prices were implemented in PJM, the associated revenues
flowing to states would also increase. Table 8-5 shows the estimated allowancerevenue for PJM states for carbon prices ranging from $10 per short ton to$50 per short ton and for emissions reductions ranging from five percent to
50 percent. Allowance revenues to states would be $16.6 billion if the carbon
price were $50 per short ton and emission levels were five percent below 2020
levels. Allowance revenues to states would be $1.7 billion if the carbon pricewere $10 per short ton and emission levels were 50 percent below 2020.

124 See Regional Greenhouse Gas Initiative, “Allowance Distribution” <https://www.rggi.org/allowance-tracking/allowance-distribution>(Accessed April 13, 2021).
125 RGGI budgets for 2022 and 2023 are found in a RGGI press release, “Third Adjustment for Banked Allowances Announcement,” March 15,2021 <https://www.rggi.org/news-releases/rggi-releases>.
126 The increase in the RGGI Cap and the RGGI Adjusted Cap in 2020 is due to the reentry of New Jersey. The new cap is 18 million shorttons higher than the previously published 2020 caps.

390

Section 8 Environmental and Renewables

127 Data for the figure was collected from allowance distribution reports available on the RGGI website <https://www.rggi.org/allowancetracking/allowance-distribution> (Accessed April 13, 2021).

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Table 8-5 Estimated CO2 allowance revenue at various carbon prices
Estimated CO2 allowance revenue ($ millions)10 percent reduction
15 percent reduction
20 percent reduction
below 2020 emission
below 2020 emission
below 2020 emission
levelslevelslevelsCarbon Price ($ per short ton)
$19.5
$18.5
$17.5
$16.4
$178.6$169.2$159.8$150.4$309.9$293.6$277.3$261.0$271.7$257.4$243.1$228.8
$96.5
$91.4
$86.4
$81.3
$0.0
$0.0
$0.0
$0.0
$111.8$105.9$100.0
$94.1
$0.4
$0.4
$0.3
$0.3
$762.7$722.5$682.4$642.2$739.6$700.7$661.8$622.9
$0.0
$0.0
$0.0
$0.0
$311.2$294.8$278.4$262.0
$0.0
$0.0
$0.0
$0.0
$511.3$484.4$457.5$430.5$3,313.1$3,138.7$2,964.4$2,790.0
Carbon Price ($ per short ton)
$48.8
$46.3
$43.7
$41.1
$446.5$423.0$399.5$376.0$774.7$733.9$693.1$652.4$679.1$643.4$607.7$571.9$241.3$228.6$215.9$203.2
$0.0
$0.0
$0.0
$0.0
$279.4$264.7$250.0$235.3
$1.0
$0.9
$0.9
$0.8
$1,906.6$1,806.3$1,705.9$1,605.6$1,849.1$1,751.8$1,654.5$1,557.1
$0.0
$0.0
$0.0
$0.0
$778.0$737.0$696.1$655.1
$0.0
$0.0
$0.0
$0.0
$1,278.2$1,210.9$1,143.6$1,076.4$8,282.8$7,846.8$7,410.9$6,975.0
Carbon Price ($ per short ton)
$97.7
$92.5
$87.4
$82.2
$893.0$846.0$799.0$752.0$1,549.4$1,467.8$1,386.3$1,304.8$1,358.3$1,286.8$1,215.3$1,143.8$482.6$457.2$431.8$406.4
$0.0
$0.0
$0.0
$0.0
$558.8$529.4$500.0$470.6
$1.9
$1.8
$1.7
$1.6
$3,813.3$3,612.6$3,411.9$3,211.2$3,698.2$3,503.6$3,308.9$3,114.3
$0.0
$0.0
$0.0
$0.0
$1,555.9$1,474.0$1,392.1$1,310.2
$0.0
$0.0
$0.0
$0.0
$2,556.4$2,421.8$2,287.3$2,152.7$16,565.5$15,693.7$14,821.8$13,949.9

5 percent reduction
below 2020 emission
levelsJurisdiction
DelawareIllinois
Indiana
Kentucky
MarylandMichigan
New Jersey
North Carolina
Ohio
Pennsylvania
Tennessee
Virginia
Washington, D.C.
West Virginia
Total
DelawareIllinois
Indiana
Kentucky
MarylandMichigan
New Jersey
North Carolina
Ohio
Pennsylvania
Tennessee
Virginia
Washington, D.C.
West Virginia
Total
DelawareIllinois
Indiana
Kentucky
MarylandMichigan
New Jersey
North Carolina
Ohio
Pennsylvania
Tennessee
Virginia
Washington, D.C.
West Virginia
Total© 2021 Monitoring Analytics, LLC

25 percent reduction
below 2020 emission
levels
$10.00$15.4$141.0$244.6$214.5
$76.2
$0.0
$88.2
$0.3
$602.1$583.9$0.0$245.7$0.0$403.6$2,615.6$25.00$38.5$352.5$611.6$536.2$190.5$0.0$220.6$0.8$1,505.2$1,459.8$0.0$614.2$0.0$1,009.1$6,539.0$50.00$77.1$705.0$1,223.2$1,072.3$381.0$0.0$441.2$1.5$3,010.5$2,919.6$0.0$1,228.3$0.0$2,018.2$13,078.0

50 percent reduction
below 2020 emission
levels
$10.3$94.0$163.1$143.0
$50.8
$0.0
$58.8
$0.2
$401.4$389.3$0.0$163.8$0.0$269.1$1,743.7$25.7$235.0$407.7$357.4$127.0$0.0$147.1$0.5$1,003.5$973.2$0.0$409.4$0.0$672.7$4,359.3$51.4$470.0$815.5$714.9$254.0$0.0$294.1$1.0$2,007.0$1,946.4$0.0$818.9$0.0$1,345.5$8,718.72021 Quarterly State of the Market Report for PJM: January through June 391

2021 Quarterly State of the Market Report for PJM: January through June

Table 8-6 shows the estimated impact of five different carbon prices on PJM
load-weighted LMP. For example, if the carbon price were $5.00 per tonne,
the PJM load-weighted, average LMP in the first six months of 2021 would
have increased by 3.6 percent.128
Table 8-6 Estimated impact of carbon price on LMP: January through June,
2020 and 2021

Scenario
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5

Carbon Price($/Metric
Ton)
$5.00
$10.00$15.00$25.00$50.002020 (Jan - Jun)
Estimated
Actual LMP
LMP($/MWh)($/MWh)$19.40$21.03$19.40$22.83$19.40$24.62$19.40$28.22$19.40$37.20Percent
Change
8.4%
17.7%
26.9%
45.5%
91.8%

2021 (Jan - Jun)
Estimated
Actual LMP
LMP($/MWh)($/MWh)$30.62$31.72$30.62$33.77$30.62$35.82$30.62$39.91$30.62$50.16Percent
Change
3.6%
10.3%
17.0%
30.3%
63.8%

Table 8-7 shows the impact of a range of carbon prices on the cost per MWhof producing energy from three basic unit types.129 130 For example, if theprice of carbon were $50.00 per tonne, the short run marginal costs would
increase by $24.52 per MWh for a new combustion turbine (CT) unit, $16.71
per MWh for a new combined cycle (CC) unit and $43.15 per MWh for a newcoal plant (CP).
Table 8-7 Carbon price per MWh by unit type
Unit TypeCT
CCCP

Carbon$5/tonne
$2.45
$1.67
$4.32

Carbon$10/tonne
$4.90
$3.34
$8.63

Applying this method to tier I and class I REC and SREC price histories yields
the implied carbon prices in Table 8-8. The carbon price implied by the average
REC price during the first six months of 2021 in Washington, DC is $8.14 per
tonne which is $0.65 per tonne lower than the June 2, 2021 RGGI clearing
price of $8.79 per tonne. All other carbon prices implied by renewable RECs
are well above the RGGI clearing price, and well below the social cost ofcarbon which is estimated to be in the range of $50 per tonne.131 The carbon
prices implied by SREC prices have no apparent relationship to carbon prices
implied by the REC clearing prices. The carbon prices implied by the SREC
prices all exceed the carbon prices implied by the corresponding REC prices,
and all exceed the social cost of carbon.

Carbon Price per MWh
CarbonCarbonCarbonCarbonCarbon$15/tonne $50/tonne $100/tonne $200/tonne $400/tonne$7.36$24.52$49.04$98.08$196.17$5.01$16.71$33.41$66.83$133.65$12.95$43.15$86.30$172.60$345.21128 LMPs are recalculated to account for the defined cost of carbon emissions on marginal units’ offer prices. The LMP calculation is notbased on a counterfactual redispatch of the system to determine the marginal units and the marginal costs that would have occurred
if all units had made all offers at short run marginal cost. See Technical Reference for PJM Markets, “Calculation and Use of Generator
Sensitivity/Unit Participation Factors,” <http://www.monitoringanalytics.com/reports/Technical_References/references.shtml>.
129 Heat rates from: 2021 State of the Market Report for PJM: January through June, Section 7: Net Revenue, Table 7-3.
130 Carbon emissions rates from: Table A.3. Carbon Dioxide Uncontrolled Emission Factors, Energy Information Administration, <https://www.eia.gov/electricity/annual/html/epa_a_03.html> (Accessed March 9, 2020).

392

Table 8-7 also illustrates the effective cost of carbon included in the price ofa REC or SREC. For example, the average price of an SREC in New Jersey was$188.38 per credit in the first six months of 2021. The SREC price is paid in
addition to the energy price paid at the time the solar energy is produced. If
the MWh produced by the solar resource resulted in avoiding the productionof a MWh from a CT, the value of carbon reduction implied by the SREC priceis a carbon price slightly less than $400 per tonne. This result also assumes
that the entire value of the SREC was based on reduced carbon emissions. The
SREC price consistent with a carbon price of $50.00 per tonne, assuming thata MWh from a CT is avoided, is $24.52 per MWh.

Section 8 Environmental and Renewables

131 “Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis – Under Executive Order 12899,” Interagency Working
Group on the Social Cost of Greenhouse Gases, United States Government, (Aug. 2016), <https://19january2017snapshot.epa.gov/‌sites/
production/files/2016-12/documents/sc_co2_tsd_august_2016.pdf>.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Table 8-8 Implied carbon price based on REC and SREC prices: 2009 through 2021132
Jurisdiction with Tier I or Class I REC
DelawareMarylandNew Jersey
Ohio
Pennsylvania
Washington, D.C.
Jurisdiction with Solar REC
DelawareMarylandNew Jersey
Ohio
Pennsylvania
Washington, D.C.
Regional Greenhouse Gas Initiative
RGGI clearing price

2009

2010

2011

2012

2013

$2.07
$13.34$1.92$17.74

$3.06
$8.58

$6.34
$4.74

$34.15$17.46$13.09

$6.82

$8.13

$3.33

$4.29

$15.87$1,372.37$546.11$1,352.15$494.54$1,309.00$382.57$537.08$304.54$345.94$610.05$712.98$590.57$436.28$378.67$501.62$101.80$655.52$68.34$956.55

$3.06

$2.12

$2.08

$2.13

$3.22

2014

2015
2016
2017
2018
Carbon Price ($ per tonne) Implied by REC Prices$35.17$31.91$32.91$10.26$11.57$28.45$29.18$26.09$23.12$21.28$21.04$25.29$26.93$24.01$22.01$10.16
$8.52
$5.29
$6.27
$11.17$26.66$28.88$26.35$23.35$21.47
$3.19
$4.04
$4.88
$4.68
Carbon Price ($ per tonne) Implied by Solar REC Prices$117.25$85.40$86.48$35.70$17.33$292.70$251.23$183.09$127.67$87.00$326.21$388.73$424.21$459.21$445.00$82.32$45.12$36.15$31.82$21.67$75.90$66.89$55.06$43.84$28.07$957.46$994.05$993.49$866.17$840.35
CO2 Allowance Price ($ per tonne)
$5.21
$6.72
$4.93
$3.77
$4.86

2019

2020

2021

$16.05$17.76$19.19$14.00$17.91$5.50$19.88$18.67$19.24$15.41$18.77$6.62$18.36$18.38$17.38$18.04$8.14$83.93$409.08$26.57$49.59$848.82$94.29$386.13$109.94$384.11$61.07$877.78$67.29$879.12

$5.98

$7.06

$8.58

State Renewable Portfolio Standards
Ten of 14 PJM jurisdictions have enacted legislation that requires that a defined percentage of retail load be served by renewable resources, for which there
are many standards and definitions. These requirements are known as renewable portfolio standards, or RPS. In PJM jurisdictions that have adopted an RPS,
load serving entities are required by law to meet defined shares of load using specific renewable and/or alternative energy sources commonly called eligible
technologies. Load serving entities may generally fulfill these obligations in one of two ways: they may use their own generation resources classified as
eligible technologies to produce power or they may purchase renewable energy credits (RECs) that represent a known quantity of power produced with eligible
technologies by other market participants or in other geographical locations. Load serving entities that fail to meet the percent goals set in their jurisdiction’s
RPS must pay penalties (alternative compliance payments).
Renewable energy sources replenish naturally in a short period of time but are flow limited and include solar, geothermal, wind, biomass and hydropowerfrom flowing water. Renewable energy sources are virtually inexhaustible in duration but limited in the amount of energy that is available per unit of time.
Nonrenewable energy sources do not replenish in a short period of time and include crude oil, natural gas, coal and uranium (nuclear energy).133 Some state
rules allow nonrenewable energy sources as part of their Renewable Portfolio Standard.
As of June 30, 2021, Delaware, Illinois, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Virginia and Washington, DC had mandatory
renewable portfolio standards that include penalties.

132 There were no trades in 2018 and 2019 for Ohio SRECs available in the Evomarkets data.
133 Renewable Energy Explained, U.S. Energy Information Administration, <https://www.eia.gov/‌energyexplained/index.php?page=renewable_home> (Accessed October 23, 2019).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 393

2021 Quarterly State of the Market Report for PJM: January through June

As of June 30, 2021, Indiana had voluntary renewable portfolio standards that
do not require participation and do not include noncompliance penalties.134
Incentives are offered to load serving entities to develop renewable generationor, to a more limited extent, purchase RECs. The voluntary standard wasenacted by the Indiana legislature in 2011, but no load serving entities havevolunteered to participate in the program.135
As of June 30, 2021, Kentucky, Tennessee and West
Virginia have no renewable portfolio standards.

Since a REC may be applied in years other than the year in which it was
generated, each vintage of RECs for each state has a different price. For
example, the Pennsylvania Alternative Energy Portfolio Standard allows anelectric distribution company or generation supplier to retain RECs from thecurrent reporting year for use toward satisfying their REC obligation in eitherof the two subsequent reporting years.136
134 Effective January 1, 2021 the Virginia voluntary RPS is being replaced with a mandatory RPS.
135 See the Indiana Utility Regulatory Commission’s “2020 Annual Report,” at 41 (Oct. 2020) <https://www.in.gov/iurc/2981.htm>.
136 Pennsylvania General Assembly, “Alternative Energy Portfolio Standards Act – Enactment Act of Nov. 30, 2004, P.L. 1672, No. 213,”
Section (e)(6).

Section 8 Environmental and Renewables

Table 8-9 Renewable and alternative energy standards of PJM jurisdictions:2021 to 2030137 138

Jurisdiction with RPS
DelawareIllinois
MarylandMichigan
New Jersey
North Carolina
Ohio
Pennsylvania
Virginia (Phase I utilities)
Virginia (Phase II utilities)
Washington, D.C.
Jurisdiction with Voluntary Standard
Indiana
Jurisdiction with No Standard
KentuckyTennessee
West Virginia

How each state satisfies its renewable portfolio
standard requirements should be more transparent.
While some jurisdictions publish transparent
information regarding total REC generation, how
the standard is fulfilled and the total cost to thestate, some jurisdictions do not provide the samelevel of detail and there can be a significant lag fromthe end of the compliance year to the publicationof the information. Some states provide adequate
information with respect to the total cost for the
RPS, where the RECs originated that fulfill the RPS requirements, and if thestate fulfilled the RPS goals. Pennsylvania and Maryland both provide more
information than other states and serve as a model for other states. The MMU
recommends that jurisdictions with a renewable portfolio standard make thecompliance data and cost data available in a more complete and transparent
manner.

394

Table 8-9 shows the percent of retail electric load that must be served byrenewable and/or alternative energy resources under each PJM jurisdictions’
RPS by year.

2021
21.00%
19.00%
33.30%
15.00%
23.50%
12.50%
6.00%
18.00%
6.00%
14.00%
26.25%

2022
22.00%
20.50%
32.60%
15.00%
24.50%
12.50%
6.50%
18.00%
7.00%
17.00%
32.50%

2023
23.00%
22.00%
34.40%
15.00%
29.50%
12.50%
7.00%
18.00%
8.00%
20.00%
38.75%

2024
24.00%
23.50%
36.20%
15.00%
37.50%
12.50%
7.50%
18.00%
10.00%
23.00%
45.00%

2025
25.00%
25.00%
38.00%
15.00%
40.50%
12.50%
8.00%
18.00%
14.00%
26.00%
52.00%

2026
25.50%
25.00%
40.50%
15.00%
43.50%
12.50%
8.50%
18.00%
17.00%
29.00%
59.00%

2027
26.00%
25.00%
44.00%
15.00%
46.50%
12.50%
0.00%
18.00%
20.00%
32.00%
66.00%

2028
26.50%
25.00%
45.50%
15.00%
49.50%
12.50%
0.00%
18.00%
24.00%
35.00%
73.00%

2029
27.00%
25.00%
50.00%
15.00%
52.50%
12.50%
0.00%
18.00%
27.00%
38.00%
80.00%

2030
28.00%
25.00%
52.50%
15.00%
52.50%
12.50%
0.00%
18.00%
30.00%
41.00%
87.00%

7.00%

7.00%

7.00%

7.00%

10.00%

0.00%

0.00%

0.00%

0.00%

0.00%

No Renewable Portfolio Standard
No Renewable Portfolio Standard
No Renewable Portfolio Standard

Updates to the Maryland RPS became effective on June 1, 2021. Maryland
Senate Bill 65 changed the intermediate RPS target levels while maintaining
the target of 50.0 percent renewable by 2030.139 Part of the legislation wasto eliminate resources fueled by black liquor as a Tier 1 eligible technology.
Senate Bill 65 reduced the penalty for solar non compliance from $100 per
credit to $80 per credit, and extended the Tier 2 standard which was scheduled
to expire with the 2020 compliance year.
The Delaware General Assembly passed new RPS legislation on February 10,2021. The new law updates the Delaware RPS targets from 25 percent in 2025
to 40 percent in 2035.140 Additional details are provided in Table 8-10.
137 This shows the total standard of alternative resources in all PJM jurisdictions, including Tier I and Tier II.
138 The table reflects calendar year standards for Maryland, Washington, DC, Ohio, and North Carolina. The standards for the remaining
jurisdictions are for compliance years that begin on June 1, CCYY and end on May 31 of the following year.
139 Senate Bill 65 Electricity – Renewable Energy Portfolio Standard – Tier 2 Renewable Sources, Qualifying Biomass, and Compliance Fees,
Maryland General Assemble (2021) <https://mgaleg.maryland.gov/mgawebsite/Legislation/Details/sb0065?ys=2021RS>.
140 See Senate Bill 33, Delaware General Assembly (February 10, 2021) <https://legis.delaware.gov/BillDetail?legislationId=48278>.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

On April 11, 2020, the Virginia legislature passed a new law that replaced Virginia’s current voluntary RPS with a mandatory RPS.141 The new law requires by
2050 that 100 percent of energy sold by phase I utilities must come from RPS eligible resources; and 100 percent of energy sold by phase II utilities must comefrom RPS eligible resources by 2045.142 143 Intermediate RPS targets begin in 2021 with a 6.0 percent standard for phase I utilities and a 14.0 percent standard
for phase II utilities. Eligible RPS resources include wind, solar, hydroelectric, landfill gas and biomass resources.
In 2018, New Jersey passed legislation that included provisions promoting the development of solar power in the state.144 The Board of Public Utilities is directed
to develop and provide an orderly transition to a new or modified program to support distributed solar. The Board must also design a Community Solar Energy
Pilot Program that would “permit customers of an electric public utility to participate in a solar energy project that is remotely located from their properties
but is within their electric public utility service territory to allow for a credit to the customer’s utility bill equal to the electricity generated that is attributed tothe customer’s participation in the solar energy project.” The pilot program would convert into a permanent program within three years. The statute targets thedevelopment of 600 MW of electric storage by 2021 and 2,000 MW by 2030. Table 8-10 summarizes recent rules changes in Ohio, Maryland, New Jersey, andWashington, DC.
Table 8-10 Recent changes in RPS rules145 146 147 148 149 150
Jurisdiction

Legislation

Effective Date

Maryland

Senate Bill 65

June 1, 2021

Delaware151st General Assembly
Senate Bill 33

February 1, 2021

Virginia

Virginia Clean Economy Act

April 11, 2020

Ohio

House Bill 6

October 22, 2019

Maryland

Clean Energy Jobs Act

May 25, 2019

Washington, D.C.

CleanEnergy DC Omnibus
Amendment Act of 2018

March 22, 2019

Summary of changes
Maintains theTier 1 target of 50.0 percent in 2030 with 14.5 percent solar carve out, but changes the intermediary target levels beginning in 2022. The alternatvie
compliance payment for solar was reduced and the definition of Tier 1 resource now excludes generators fueled by black liquor. Extends indefinitely the Tier 2 targetof 2.5 percent which was set to expire in 2020. Tier 2 resources are defined as hydroelectric power other than pumped storage.
Increases the RPS target from 25.0 percent in 2025 to 40.0 percent in 2035. Sets the solar carve out requirement to 10.0 percent in 2035. Establishes intermediarytarget levels for total RPS and the solar carve out for compliance years 2026 through 2034. Lowered the solar alternative compliance payment (SACP) from $400 per
credit to $150 per credit.
Replaces the voluntary RPS with a mandartory RPS beginning in January 2021. The legislation requires 100 percent clean energy by 2050 for phase I utilities and 100
percent clean energy by 2045 for phase II utilities. Intermediate target levels begin in 2021 with 6 percent for phase I utilities and 14 percent for phase II utilities.
Reduced the RPS percent for each year beginning in 2020. The 2020 standard was reduced from 6.5 percent to 5.5 percent; the 2026 standard was reduced from 12.5
percent to 8.5 percent. The legislation also removed language that had previously indicated that the standard would remain at the 2026 level for each year after
2026. The solar carve out was removed for compliance year 2020 and beyond. Prior to the recent legislation, the solar carve out was 0.26 percent for 2020, increased
to 0.50 percent for 2026, and remained at 0.50 percent for subsequent years.
Established a new Tier I target of 50.0 percent in 2030; previously the 2030 Tier I standard was 25.0 percent. The 2019 Tier I standard increased from 20.4 percent
to 20.7. The solar carve out percent for 2019 increased from 1.95 percent to 5.50 percent. The solar carve out percent for 2030 increased from 2.5 percent to 14.5
percent. The 2.5 percent Tier II standard, scheduled to end in 2018, was extended through 2020.
Established a 100 percent Tier I renewable standard by 2032. Previously, the 2032 target was 50.0 percent. Tier I increases start in 2020, going from 20.0 percent to26.25 percent. The 2020 solar carve out will increase from 1.58 percent to 2.175 percent. The 2041 target for the solar carve out is 10.0 percent.

141 See “Virginia Clean Economy Act,” (April 12, 2020) <https://www.governor.virginia.gov/‌newsroom/all-releases/2020/april/headline-856056-en.html>.
142 A phase I utility is an investor-owned incumbent electric utility that was, as of July 1, 1999, not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, and a phase II utility is an investor-owned incumbent electric utility
that was bound by such a settlement (§ 56-585.1 of the Virginia Code).
143 APCO (AEP) is a phase I utility and Dominion Energy Virginia is a phase II utility. Cooperatives are not subject to the RPS
144 N.J. S. 2314/A. 3723.
145 See “Virginia Clean Economy Act,” (April 12, 2020) <https://www.governor.virginia.gov/‌newsroom/all-releases/2020/april/headline-856056-en.html>.
146 See Ohio Legislature House, 133rd Assembly, Bill No. 6, “Ohio Clean Air Program,” effective Date October 22, 2019, <https://www.legislature.ohio.gov/legislation/legislation-summary?id‌=GA133-HB-6>.
147 See Maryland State Legislature, Senate Bill No. 516, “Clean Energy Jobs,” Passed May 25, 2019, <https://legiscan.com/md/text/sb516/2019>.
148 D.C. Law 22-257 “CleanEnergy DC Omnibus Amendment Act of 2018,” Effective March 22, 2019, <https://code.dccouncil.us/dc/council/laws/22-257.html>.
149 See Senate Bill 33, Delaware General Assembly (February 10, 2021) <https://legis.delaware.gov/BillDetail?legislationId=48278>.
150 Senate Bill 65 Electricity – Renewable Energy Portfolio Standard – Tier 2 Renewable Sources, Qualifying Biomass, and Compliance Fees, Maryland General Assemble (2021) <https://mgaleg.maryland.gov/mgawebsite/Legislation/Details/sb0065?ys=2021RS>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 395

2021 Quarterly State of the Market Report for PJM: January through June

New Jersey and Maryland have taken significant steps to promote offshore
wind. Both states enacted legislation for offshore wind renewable energy
credits (ORECs) in 2010.151 On May 24, 2018, New Jersey enacted a statutedirecting the Board of Public Utilities to create an OREC program targeting
installation of at least 3,500 MW of offshore wind capacity by 2030 (plus
2,000 MW of energy storage capacity).152 The New Jersey statute also reinstatescertain tax incentives for offshore wind manufacturing activities. Governor
Murphy has issued Executive Order No. 8, which calls for full implementationof the statute. The offshore wind target 3,500 MW by 2030 has since been
replaced by a target of 7,500 MW by 2035.153 The BPU opened a 100 day
application window for qualified offshore wind projects on September 20,
2018, and on June, 21, 2019, the first award for a 1,100 MW offshore windproject was granted to Orsted.154 155
In 2017, the Maryland Public Service Commission announced twoawards of ORECs to two commercial wind projects, DeepwaterWind’s 120-MW Skipjack Wind Farm and U.S. Wind’s 248-MW
project. Deepwater Wind has since been acquired by Orsted.156
These project awards are the first under Maryland’s 2010 OREC
program.

Each PJM jurisdiction with an RPS identifies the type of generation resourcesthat may be used for compliance. These resources are often called eligible
151 See Offshore Wind Economic Development Act of 2010, P.L. 2010, c. 57, as amended, N.J.S.A. 48:3-87 to -87.2.
152 N.J. S. 2314/A. 3723.
153 Executive Order 92, Philip D. Murphy, Governor of New Jersey (November 19, 2019) <https://nj.gov/infobank/eo/056murphy/approved/
eo_archive.html>.
154 BPU Docket No. QO18080851.
155 “New Jersey Board of Public Utilities Awards Historic 1,100 MW Offshore Wind Solicitation to Orsted’s Ocean Wind Project,” New Jersey
BPU Press Release (June 21, 2019) <https://nj.gov/bpu/newsroom/2019/approved/20190621.html>.
156 “Orsted Acquires Deepwater Wind and creates leading US Offshore Wind Platform,” ORSTED Press Release (August 10, 2018).
157 “Construction Begins on Dominion Energy Offshore Wind Project,” Dominion Energy News Release (July 1, 2019) <https://news.
dominionenergy.com/2019-07-01-Construction-Begins-on-Dominion-Energy-Offshore-Wind-Project>.
158 “Dominion Energy Announces Largest Offshore Wind Project in US,” Dominion Energy News Release (September 19, 2019) <https://news.
dominionenergy.com/2019-09-19-Dominion-Energy-Announces-Largest-Offshore-Wind-Project-in-US>.

Section 8 Environmental and Renewables

Table 8-11 Tier I / Class I renewable standards of PJM jurisdictions: 2021 to2030

Jurisdiction with RPS
MarylandNew Jersey
Pennsylvania
Washington, D.C.

On July 1, 2019, Dominion Energy announced the beginning of construction
on an offshore wind demonstration project. The project consists of two 6
MW offshore wind turbines.157 In September 2019, Dominion filed aninterconnection agreement with PJM associated with its proposal to develop
a 2,600 MW offshore wind farm.158

396

technologies. Some PJM jurisdictions with RPS group different eligible
technologies into tiers based on the magnitude of their environmental impact.
Of the nine PJM jurisdictions with mandatory RPS, Maryland, New Jersey,
Pennsylvania, and Washington, DC group the eligible technologies that must
be used to comply with their RPS programs into Tier I and Tier II resources.159
Although there are minor differences across these four jurisdictions’ definitionsof Tier I resources, technologies that use solar photovoltaic, solar thermal,
wind, ocean, tidal, biomass, low-impact hydro, and geothermal sources to
produce electricity are classified as Tier I resources. Table 8-11 shows the TierI standards for PJM states.160 All eligible technologies for the RPS standards inTable 8-11 satisfy the EIA definition of renewable energy.161

2021
30.80%
21.00%
8.00%
26.25%

2022
30.10%
22.00%
8.00%
32.50%

2023
31.90%
27.00%
8.00%
38.75%

2024
33.70%
35.00%
8.00%
45.00%

2025
35.50%
38.00%
8.00%
52.00%

2026
38.00%
41.00%
8.00%
59.00%

2027
41.50%
44.00%
8.00%
66.00%

2028
43.00%
47.00%
8.00%
73.00%

2029
47.50%
50.00%
8.00%
80.00%

2030
50.00%
50.00%
8.00%
87.00%

Delaware, Illinois, Michigan, North Carolina, Virginia and Ohio do not classify
the resources eligible for their RPS standards by tiers. In these states eligible
technologies are largely but not completely renewable resources.162
RECs do not need to be used during the year in which they are generated.
The result is that there may be multiple prices for a REC based on the year inwhich it was generated. RECs typically have a shelf life of five years during
which they can be used to satisfy a state’s RPS requirement. For example if
a load serving entity (LSE) owns renewable generation and the renewablegeneration exceeds the LSE’s RECs purchase obligation for the current year,
the LSE can either sell the REC to another LSE or hold the REC for use in a
subsequent year.
159 New Jersey separates technologies into Class I/Class II resources in a manner that is consistent with the other jurisdictions’ Tier I/Tier II
categorizations.
160 This includes New Jersey’s Class I renewable standard.
161 Renewable Energy Explained, U.S. Energy Information Administration, <https://www.eia.gov/‌energyexplained/index.
php?page=renewable_home> (Accessed October 17, 2019).
162 Michigan’s Public Act 342, effective April 20, 2017, removed nonrenewable technologies (e.g. coal gasification, industrial cogeneration,and coal with carbon capture) from the list of RPS eligible technologies.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

PJM GATS makes data available for the amount of eligible RECs by jurisdiction.
Eligible RECs are not the amount of actual RECs generated for that timeframe.
A REC that is created may be eligible in multiple jurisdictions resulting inan over representation of generated RECs. This means if one REC is retired
in Pennsylvania, the total amount of eligible RECs will reduce by more than
one REC.

Figure 8-3 Average Tier I REC price by jurisdiction: January 2009 throughJune 2021$16.00
DC Tier I REC
NJ Class I REC$14.00PA Tier I REC
MD Tier I REC$12.00Figure 8-3 shows the average Tier I REC price by jurisdiction from January 1,
2009, through June 30, 2021. Tier I REC prices are lower than SREC prices. For
example, the average SREC price in Washington, DC in the first six monthsof 2021 was $431.14 and the average Tier I price in Washington, DC in firstquarter of 2021 was $3.99.

OH Non Solar REC$10.00$/REC

The REC prices are the average price for each vintage of REC, defined by theyear in which the associated power was generated, regardless of when the REC
is consumed. REC prices are required to be publicly disclosed in Maryland,
Pennsylvania and Washington, DC, but in the other states REC prices are notpublicly available.

$8.00

$6.00

$4.00

$2.00

$0.00

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

Figure 8-4 and Table 8-12 show the fulfillment of Tier I equivalent RPS
requirement for 2016 through 2020 by state and by import and internalRECs and by carbon producing and noncarbon producing RECs.163 Dependingon the state, the RPS requirement can be fulfilled by wind, solar, hydro(“Noncarbon REC”) or with landfill gas, captured methane, wood, black liquor,
and other fuels. (“Carbon Producing REC”). States’ Tier I requirements are not
all carbon free. The Delaware (DE) New Eligible requirement and the Illinois
RPS, beginning in 2019, are fulfilled by noncarbon RECs, but all other state
Tier I equivalent RPS requirements allow carbon producing RECs to fulfill the
RPS requirements. Figure 8-4 shows the use of imported and local carbon
producing RECs and imported and local noncarbon RECs by state to meet
the RPS requirements. Table 8-12 shows the percent of imported and local
163 Retired REC information obtained through PJM GATS <https://gats.pjm-eis.com/gats2/PublicReports/
RPSRetiredCertificatesReportingYear> (Accessed July 14, 2021). The timing of the REC retirement reports varies by state and the 2020
reporting year data is incomplete for several states.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 397

2021 Quarterly State of the Market Report for PJM: January through Junecarbon producing RECs and imported and local noncarbon RECs by stateused to meet the RPS requirements. For example, Pennsylvania met its Tier I
target using 75.8 percent imported RECs, and 24.2 percent State RECs for the2019 compliance year. Pennsylvania met its Tier I target using 71.1 percent
noncarbon producing RECs, and 28.9 percent carbon producing RECs for the2019 compliance year. Illinois met its Tier I target using 29.5 percent imported
RECs, and 70.5 percent State RECs for the 2019 compliance year. Illinois met
its Tier I target using 100.0 percent noncarbon producing RECs for the 2019
compliance year.

Table 8-12 State fulfillment of Tier I equivalent RPS: 2016 through 2020
Year
2016

REC Type
DE New Eligible
DC Tier I
OH Renewable Energy Source
IL Renewable
MD Tier I
NJ Class I
PA Tier I

State Non
Carbon REC
1.0%
0.0%
12.3%
27.1%
0.8%
0.0%
15.1%

Import Non
Carbon REC
99.0%
40.5%
52.8%
30.3%
51.7%
82.5%
40.2%

State Carbon
Producing REC
0.0%
0.0%
8.7%
0.1%
12.5%
4.5%
11.1%

Import Carbon
Producing REC
0.0%
59.5%
26.2%
42.5%
35.0%
13.0%
33.7%

2017

DE New Eligible
DC Tier I
OH Renewable Energy Source
IL Renewable
MD Tier I
NJ Class I
PA Tier I

0.7%
0.0%
15.6%
22.5%
6.5%
0.1%
19.6%

99.3%
77.2%
45.8%
62.3%
48.9%
83.2%
38.9%

0.0%
0.0%
8.1%
0.0%
10.7%
3.9%
9.4%

0.0%
22.8%
30.6%
15.2%
34.0%
12.8%
32.0%

2018

DE New Eligible
DC Tier I
OH Renewable Energy Source
IL Renewable
MD Tier I
NJ Class I
PA Tier I

0.4%
0.0%
15.4%
26.1%
1.9%
0.0%
18.7%

99.6%
76.5%
57.4%
51.0%
60.1%
86.7%
48.9%

0.0%
4.5%
8.3%
0.0%
9.6%
2.3%
10.9%

0.0%
19.0%
18.9%
22.9%
28.5%
11.0%
21.4%

2019

DE New Eligible
DC Tier I
OH Renewable Energy Source
IL Renewable
MD Tier I
NJ Class I
PA Tier I

0.3%
0.0%
14.7%
70.5%
0.7%
0.1%
17.0%

99.7%
81.5%
53.0%
29.5%
53.2%
92.7%
54.2%

0.0%
2.8%
7.3%
0.0%
8.4%
2.8%
7.2%

0.0%
15.7%
25.0%
0.0%
37.8%
4.4%
21.7%

2020

DE New Eligible
DC Tier I
OH Renewable Energy Source
IL Renewable
MD Tier I
NJ Class I
PA Tier I

0.0%
10.5%
79.0%
4.1%
0.0%
15.1%

80.1%
63.5%
21.0%
61.1%
99.6%
39.9%

3.3%
5.5%
0.0%
5.3%
0.4%
3.9%

16.6%
20.5%
0.0%
29.6%
0.0%
41.0%

Figure 8-4 State fulfillment of Tier I equivalent RPS: 2016 through 2020
14,000,000
Import Carbon Producing REC

12,000,000

State Carbon Producing REC
Import Non Carbon REC
State Non Carbon REC

10,000,000

RECs

8,000,000

6,000,000

4,000,000

398

DC
DE
IL
MD
NJ
OH
PA

DC
DE
IL
MD
NJ
OH
PA

DC
DE
IL
MD
NJ
OH
PA

DC
DE
IL
MD
NJ
OH
PA

0

DC
DE
IL
MD
NJ
OH
PA

2,000,000

2016

2017

2018

2019

2020

Section 8 Environmental and Renewables© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Table 8-13 Additional renewable standards of PJM jurisdictions: 2021 to2030
Jurisdiction
Maryland
MarylandNew Jersey
North Carolina
North Carolina
Pennsylvania

Type of Standard
Off Shore Wind
Tier 2
Class II
Swine Waste
Poultry Waste (in GWh)
Tier II$8.00
DC Tier II REC$7.00

NJ Class II REC
PA Tier II REC$6.00

MD Tier II REC

$5.00

$4.00

$3.00

$2.00

$1.00

$0.00

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

Some PJM jurisdictions have specific solar resource RPS
requirements. These solar requirements are included in the
total requirements shown in Table 8-10 but must be met
by solar RECs (SRECs) only. Table 8-14 shows the percent
of retail electric load that must be served by solar energy
resources under each PJM jurisdiction’s RPS by year.
Delaware, Illinois, Maryland, New Jersey, North Carolina,
Ohio, Pennsylvania, and Washington, DC have or have had requirements forthe proportion of load to be served by solar. New Jersey closed registration
for new SRECs on April 30, 2020, having met its milestone that solar power
equal or exceed 5.1 percent of New Jersey electricity sales.166 On December
6, 2019, the New Jersey Board of Public Utilities announced a transitional
program for solar generators not eligible for New Jersey SRECs.167 The new

2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
1.37% 1.36% 2.03% 2.01% 2.01% 1.99% 1.98% 1.96% 1.94% 1.94%
2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50%
2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50%
0.14% 0.14% 0.14% 0.20% 0.20% 0.20% 0.20% 0.20% 0.20% 0.20%
900
900
900
900
900
900
900
900
900
900
10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00%

Tier II prices are lower than SREC and Tier I REC prices. Figure 8-5 shows theaverage Tier II REC price by jurisdiction for January 1, 2009, through June 30,
2021. Maryland, New Jersey and Pennsylvania are the only states with a Tier
II standard in 2021. In the first six months of 2021, the average Pennsylvania
Tier II REC price was $3.72 and the average New Jersey Class II REC price was$7.02.165
164 Public Service Commission of Maryland, Offshore Wind Projects, Order No. 88192 (May 11, 2017) at 8, Table 2, <https://www.psc.state.
md.us/wp-content/uploads/Order-No.-88192-Case-No.-9431-Offshore-Wind.pdf>.
165 Tier II REC price information obtained through Evomarkets <http://www.evomarkets.com>.

© 2021 Monitoring Analytics, LLC

Figure 8-5 Average Tier II REC price by jurisdiction: 2009 through June 2021$/REC

Table 8-13 shows the percent of retail electric load that must be served byTier II or a specific type of resource under each PJM jurisdiction’s RPS by
year. Tier II resources are generally not renewable resources. Table 8-13 also
shows specific technology requirements that PJM jurisdictions have added
to their renewable portfolio standards. The standards shown in Table 8-13
are included in the total RPS requirements presented in Table 8-9. Maryland,
New Jersey and Pennsylvania have Tier II or Class II standards, which allow
specific nonrenewable technology types, such as waste coal units locatedin Pennsylvania, to qualify for renewable energy credits. Washington, DC
previously had Tier II standards. The Washington, DC tier II standard was
discontinued at the end of the 2019 compliance year. By 2024, North Carolina’s
RPS requires that 0.2 percent of power be generated using swine waste andthat 900 GWh of power be produced by poultry waste in 2020. Maryland
established a minimum standard for offshore wind in 2017 that takes effect in
2021 with a requirement that 1.37 percent of load be served by offshore wind.
The standard increases to 2.03 percent in 2023.164

166 See Clean Energy Act of 2019 (NJ AB-2723); N.J.A.C. 14:82.4(b)6; BPU, Monthly Report on Status toward Attainment of the 5.1 percent
Milestone for Closure of the SREC Program (March 31, 2020).
167 “New Jersey Board of Public Utilities Approves Solar Transition Program, Initiates a Cost Cap Proceeding,” New Jersey Board of Public
Utilities Press Release (December 6, 2019) <https://www.bpu.state.nj.us/bpu/newsroom/2019/approved/20191206.html>.

2021 Quarterly State of the Market Report for PJM: January through June 399

2021 Quarterly State of the Market Report for PJM: January through June

program establishes a 15 year fixed priced Transition REC (TREC). Pennsylvania allows only solar photovoltaic resources to fulfill their solar requirements. Solar
thermal units like solar hot water heaters that do not generate electricity are Tier I resources in Pennsylvania. Indiana, Kentucky, Michigan, Tennessee, Virginia,
and West Virginia have no specific solar standards. The New Jersey legislature in May 2018 increased the solar standard from 3.2 percent to 4.3 percent for
2018, 5.1 percent for 2020 through 2022 and the solar standard decreases to 1.1 percent for 2032.168 Maryland legislation in 2019 increased the solar carve out
percentages from 2.5 percent to 14.5 percent in 2030. Ohio HB 6 removed the solar carve out from the Ohio RPS.169 The Delaware General Assembly passed new
RPS legislation on February 10, 2021 that increased the solar carve out target from 3.5 percent in 2025 to 10.0 percent in 2035.170
Table 8-14 Solar renewable standards by percent of electric load for PJM jurisdictions: 2021 to 2030171
Jurisdiction with RPS
DelawareIllinois (RECs)
MarylandMichigan
New Jersey
North Carolina
Ohio
Pennsylvania
Washington, D.C.
Jurisdiction with Voluntary Standard
Indiana
Virginia
Jurisdiction with No Standard
KentuckyTennessee
West Virginia

2021
2022
2023
2.50%
2.75%
3.00%
2,000,000 2,000,000 2,000,000
7.50%
5.50%
6.00%
No Minimum Solar Requirement
5.10%
5.10%
4.90%
0.20%
0.20%
0.20%
No Minimum Solar Requirement
0.50%
0.50%
0.50%
2.50%
2.60%
2.85%

2024
3.25%
2,000,000
6.50%

2025
3.50%
3,000,000
7.00%

2026
3.75%
3,000,000
8.00%

2027
4.00%
3,000,000
9.50%

2028
4.25%
3,000,000
11.00%

2029
4.50%
3,000,000
12.50%

2030
5.00%
4,000,000
14.50%

4.80%
0.20%

4.50%
0.20%

4.35%
0.20%

3.74%
0.20%

3.07%
0.20%

2.21%
0.20%

1.58%
0.20%

0.50%
3.15%

0.50%
3.45%

0.50%
3.75%

0.50%
4.10%

0.50%
4.50%

0.50%
4.75%

0.50%
5.00%

No Minimum Solar Requirement
No Minimum Solar Requirement
No Renewable Portfolio Standard
No Renewable Portfolio Standard
No Renewable Portfolio Standard

168 “Assembly, No. 3723,” State of New Jersey, 218th Legislature (March 22, 2018), <http://www.njleg.state.nj.us/2018/Bills/A4000/3723_I1.PDF>.
169 Ohio Legislature House, 133rd Assembly, Bill No. 6, “Ohio Clean Air Program,” effective Date October 22, 2019, <https://www.legislature.ohio.gov/legislation/legislation-summary?id‌=GA133-HB-6>.
170 See Senate Bill 33, Delaware General Assembly (February 10, 2021) <https://legis.delaware.gov/BillDetail?legislationId=48278>.
171 The Illinois solar standard currently requires 2 million RECs from solar photovoltaic projects energized after June 1, 2017. Illinois Public Act 099-0906, June 1, 2017.

400

Section 8 Environmental and Renewables© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Figure 8-6 shows the average solar REC (SREC) price by jurisdiction for
January 1, 2009, through June 30, 2021. The average NJ SREC prices dropped
from $673 per SREC in 2009 to $188 per SREC in the first six months of2021. The limited supply of solar facilities in Washington, DC compared to the
RPS requirement resulted in higher SREC prices. The average Washington, DC
SREC price was $431 per SREC for the first six months of 2021.172

Maryland and New Jersey met their solar requirements using 100 percent instate SRECs in 2019.
Figure 8-7 State fulfillment of Solar RPS: 2016 through 2020
3,500,000

3,000,000

Figure 8-6 Average SREC price by jurisdiction: 2009 through June 2021
$800.00

2,500,000

DC Solar REC

Non PJM
WV
OH
KY
DC
MD
DE

MI
VA
NC
IN
NJ
IL
PA

NJ Solar REC$700.00

PA Solar REC

2,000,000

OH Solar REC$600.00RECs

MD Solar REC

1,500,000

1,000,000$400.00

$0.00

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

DC
DE
IL
MD
NJ
OH
PA

DC
DE
IL
MD
NJ
OH
PA

$100.00

DC
DE
IL
MD
NJ
OH
PA

0

$200.00

DC
DE
IL
MD
NJ
OH
PA

500,000$300.00

DC
DE
IL
MD
NJ
OH
PA

$/REC

$500.00

2016

2017

2018

2019

2020

2021

Figure 8-7 and Table 8-15 shows where the SRECs originated that are used tosatisfy the states’ solar requirement by retiring RECs for 2016 through 2020.173
Depending on the state, the solar RPS requirement can be fulfilled by in stateor out of state SRECs. The SRECs purchased in some states are imported fromother PJM states and from non PJM states. Table 8-15 shows the percent
of imported and local SRECs used to meet the RPS requirements. Illinois,
172 Solar REC average price information obtained through Evomarkets, <http://www.evomarkets.com> (Accessed October 21, 2020).
173 Retired REC information obtained through PJM GATS <https://gats.pjm-eis.com/gats2/PublicReports/
RPSRetiredCertificatesReportingYear> (Accessed July 14, 2021). The timing of the REC retirement reports varies by state and the 2020
reporting year data is incomplete for several states.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 401

2021 Quarterly State of the Market Report for PJM: January through June

Table 8-15 State fulfillment of Solar RPS: 2016 through 2020
2016

DC Solar
DE Solar Eligible
IL Solar Renewable
MD Solar
NJ Solar
OH Solar Renewable Energy Source
PA SolarState SREC
49.8%
76.5%
56.1%
100.0%
100.0%
73.3%
29.1%

Import SREC
50.2%
23.5%
43.9%
0.0%
0.0%
26.7%
70.9%

2017

DC Solar
DE Solar Eligible
IL Solar Renewable
MD Solar
NJ Solar
OH Solar Renewable Energy Source
PA Solar

63.8%
61.9%
87.5%
100.0%
100.0%
69.0%
30.6%

36.2%
38.1%
12.5%
0.0%
0.0%
31.0%
69.4%

2018

DC Solar
DE Solar Eligible
IL Solar Renewable
MD Solar
NJ Solar
OH Solar Renewable Energy Source
PA Solar

67.4%
67.7%
82.8%
100.0%
100.0%
59.5%
27.1%

32.6%
32.3%
17.2%
0.0%
0.0%
40.5%
72.9%

2019

DC Solar
DE Solar Eligible
IL Solar Renewable
MD Solar
NJ Solar
OH Solar Renewable Energy Source
PA Solar

72.4%
66.4%
100.0%
100.0%
100.0%
43.5%
48.8%

27.6%
33.6%
0.0%
0.0%
0.0%
56.5%
51.2%

2020

DC Solar
DE Solar Eligible
IL Solar Renewable
MD Solar
NJ Solar
OH Solar Renewable Energy Source
PA Solar

81.5%

18.5%

100.0%
100.0%
100.0%
36.8%
100.0%

0.0%
0.0%
0.0%
63.2%
0.0%

Figure 8-8 shows the percent of retail electric load that must be served
by Tier I resources and Tier 2 resources in each PJM jurisdiction with amandatory RPS. For each state in Figure 8-8, the first number represents
the RPS percent for Tier I or renewable energy resources; the second number

402

Section 8 Environmental and Renewables

represents the RPS percent for all eligible technologies which includes bothrenewable and alternative energy resources. States with higher percent
requirements for renewable energy resources are shaded darker. Jurisdictions
with no standards or with only voluntary RPS are shaded gray. Pennsylvania’s
RPS illustrates the need to differentiate between percent requirements forrenewable and alternative energy resources. The Pennsylvania RPS identifies
solar photovoltaic, solar thermal, wind, geothermal, biomass, and low-impacthydropower as Tier I resources. The Pennsylvania RPS identifies waste coal,demand side management, large-scale hydropower, integrated gasification
combined cycle, clean coal and municipal solid waste as eligible Tier II
resources. As a result, the 18.0 percent number in Figure 8-8 overstates
the percent of retail electric load in Pennsylvania that must be served byrenewable energy resources. The 8.0 percent number in Figure 8-8 is a moreaccurate measure of the percent of retail electric load in Pennsylvania thatmust be served by renewable energy resources.
Figure 8-8 Map of retail electric load shares under RPS – Renewable /Alternative Energy resources: 2021174

174 The standards in this chart include the Tier I standards used by some states in the PJM footprint, as well as the total alternative energy
standard for states that do not classify eligible technologies into tiers.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Under the existing state renewable portfolio standards, 15.7 percent of PJM
total generation in PJM for the first six months of 2021. Tier I generationload should have been served by Tier I and Tier II renewable and alternative
was 6.2 percent of total generation in PJM and Tier II was 2.1 percent of totalenergy resources in the first six months of 2021. Tier I resources consist ofgeneration in PJM for the first six months of 2021. Biofuel, landfill gas, solid
landfill gas, run of river hydro, wind and solar resources. Tier II resources
waste and waste coal (carbon producing) were 3,477.9 GWh, or 19.7 percent
consist of pumped storage, solid waste and waste coal resources. In the first sixof the total Tier I and Tier II.
months of 2021, 68.3 percent of PJM generation was renewable and alternative
Table 8-16 Tier I and Tier II generation by jurisdiction and renewable resourceenergy resources, including carbon producing and noncarbon producing Tier
type (GWh): January through June, 2021
I and Tier II generation as shown in Table 8-16.
Tier I
Tier IIIf the proportion of load among states remains
PumpedTotal
Total
constant, 31.3 percent of PJM load must be served
Landfill Run of
Other
Total Tier Storage
Other
Solid Waste
Tier II
CreditJurisdiction
BiofuelGas
River Hydro
Solar
Wind I Credit
Hydro Hydro Waste
Coal Credit
GWhby Tier I and Tier II renewable and alternative energy
Delaware
0.0
25.3
0.0
0.0
0.0
0.0
25.3
0.0
0.0
0.0
0.0
0.0
25.3
resources in 2030 under currently defined RPS rules.
Illinois
0.0
73.0
0.0
0.0
6.8
7,191.8
7,271.5
0.0
0.0
0.0
0.0
0.0
7,271.5
Approximately 13.3 percent of PJM load should have
Indiana
0.0
10.0
0.0
12.3
21.0
3,034.8
3,078.1
0.0
0.0
0.0
0.0
0.0
3,078.1
Kentucky
0.0
0.0
152.5
53.7
0.0
0.0
206.2
0.0
0.0
0.0
0.0
0.0
206.2
been served by Tier I or renewable energy resources
Maryland
0.0
23.8
0.0
0.0
266.5
326.9
617.2
0.0
0.0
342.1
0.0
342.1
959.3
in the first six months of 2021. In the first six months
Michigan
0.0
34.2
0.0
26.0
2.9
0.0
63.1
0.0
0.0
0.0
0.0
0.0
63.1
New Jersey
0.0
66.0
12.5
0.0
447.2
5.7
531.4
105.0
0.0
688.6
0.0
793.7
1,325.1of 2021, 6.2 percent of PJM generation was Tier I or
North Carolina
0.0
0.0
439.9
0.0 1,025.9
281.2
1,746.9
0.0
0.0
0.0
0.0
0.0
1,746.9
renewable energy. The current REC production from
Ohio
0.0
169.4
550.2
0.0
253.0
1,355.0
2,327.7
0.0
0.0
0.0
0.0
0.0
2,327.7
Pennsylvania
0.0221.2 2,614.3
12.9
138.0
1,871.4
4,857.9
1,016.0
0.0
778.7 2,578.6 4,373.2
9,231.1
PJM generation resources was not enough to meet
Tennessee
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
673.0
0.0
0.0
673.0
673.0
the first quarter 2021 state renewable requirements,
Virginia
565.9
254.3
706.1
44.7 1,005.0
341.7
2,917.6
1,084.8422.1
431.7
0.0 1,938.5
4,856.1
and LSEs purchased RECs from outside the PJM
Washington, D.C.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
West Virginia
0.0
16.7
465.3
0.0
17.1
872.8
1,371.9
0.0
0.0
0.0
315.8
315.8
1,687.7
footprint. LSEs that are unable to meet the RPS with
Total
565.9
894.0 4,940.7
149.5 3,183.5 15,281.3 25,014.9
2,205.8 1,095.0 2,241.1 2,894.4 8,436.3 33,451.1
RECs may use alternative compliance payments for
unmet goals based on each state’s requirements. If
Table 8-17 shows the summer installed capacity rating of Tier I and Tier
the proportion of load among states remains constant, 28.9 percent of PJM
II resources in PJM by jurisdiction, as defined by primary fuel type. Thisload must be served by Tier I or renewable energy resources in 2030 undercapacity includes coal, natural gas and oil units that qualify as Tier II because
defined RPS rules.
they have a secondary fuel capability that satisfies the alternative energy
In jurisdictions with an RPS, load serving entities must either generate power
standards of a PJM state or jurisdiction. For example, a coal generator thatfrom eligible technologies identified in each jurisdiction’s RPS or purchasecan also burn waste coal to generate power could list the alternative fuel as
RECs from resources classified as eligible technologies. Table 8-16 shows
waste coal. A REC is only generated when using the fuel listed as Tier I or Tier
generation by jurisdiction and resource type for the first six months of 2021.
II. Virginia has the largest amount of solar capacity in PJM, 1,430.0 MW, orWind output was 15,281.3 GWh of 25,014.9 Tier I GWh, or 61.1 percent, in
33.5 percent of the total solar capacity. Wind resources are located primarily
the PJM footprint. As shown in Table 8-16, 33,451.1 GWh were generated
in western PJM, in Illinois and Indiana, which include 6,876.5 MW, or 64.4
by Tier I and Tier II resources, of which Tier I resources were 74.8 percent.
percent of the total wind capacity.
Total wind and solar generation (noncarbon producing) was 4.6 percent of© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 403

2021 Quarterly State of the Market Report for PJM: January through JunePJM has proposed new rules for determining the capacity value of intermittent
generators. There are two classes of wind based on location with class average
generators, based on the effective load carrying capability (ELCC) method.175
capacity factors of 14.7 percent and 17.6 percent.181
The Commission rejected the proposal because the transition mechanism
Table 8-17 Renewable capacity by jurisdiction (MW): June 30, 2021
which locks in ELCC for prolonged periods
176
Oil / Pumpedis unsupported. PJM filed a revised ELCC
Coal /
Landfill Natural Gas /OtherOil / Landfill Storage
Solid Waste
proposal on June 1, 2021, that eliminatedJurisdiction
Biofuel Biofuel Hydro
Gas
Landfill Gas
Gas Biofuel
Gas
Hydro
Solar Waste
Coal
Wind
Total
Delaware
0.0
0.0
0.0
8.1
1,797.0
0.0
0.0
13.0
0.0
0.0
0.0
0.0
0.0
1,818.1
the transition mechanism but was otherwise
Illinois
0.0
0.0
0.0
39.2
0.0
0.0
0.0
0.0
0.0
9.0
0.0
0.0
4,526.1
4,574.3
unchanged.177
The MMU recommended rejection of therevised PJM ELCC filing. PJM’s ELCC design
proposal, even without the transition
mechanism rejected by the Commission,is badly flawed and the current rules are
preferable.178 179

Indiana
Kentucky
MarylandMichigan
Missouri
New Jersey
North Carolina
Ohio
Pennsylvania
Tennessee
Virginia
Washington, D.C.
West Virginia
PJM Total

0.0
0.0
8.2
0.0
0.0
132.7
0.0
0.0
0.4
0.0
0.0
13.9
0.0
0.0
0.0
0.0
0.0
11.0
0.0
0.0
325.0
0.0 2,320.0
194.4
54.0
0.0 1,387.3
50.0
0.0
296.6
241.9
585.0
436.4
0.0
0.0
0.0
0.0
0.0
209.9
345.9 2,905.0 3,015.6

Under the current rules a generator’scapacity value is derated from theinstalled capacity level by multiplying thegenerator’s net maximum capability by a capacity factor. The capacity factor
is either based on the generator’s historical performance during summer peak
hours or is a class average value calculated by PJM. The intent of the current
method is to obtain a MW value the generator can reliably produce during
the summer peak hours.180 As of July 1, 2021, the derated capacity eligible
for compensation in the PJM Capacity Market totaled 1,522.9 MW for wind
generators and 1,779.5 MW for solar generators. This compares to installedwind capacity of 10,682.3 MW and installed solar capacity of 4,268.5 MW
in Table 8-17. PJM posts class average capacity factors for wind and solar
175 See FERC ER21-278-001, et al.
176 See 175 FERC ¶ 61,084 (2021).
177 Updated Effective Load Carrying Capability Construction, Effective August 1, 2022, PJM Interconnection L.L.C., Docket No. ER21-2043000 (June 1, 2021).
178 In Docket ER21-278-000, see Comments and Motions of the Independent Market Monitor for PJM, (November 20, 2020); Answer
and Motion for Leave to Answer of the Independent Market Monitor for PJM, (December 18, 2020); Comments and Motions of the
Independent Market Monitor for PJM (March 22, 2021); Answer and motion for Leave to Answer of the Independent Market Monitor for
PJM (April 29, 2021)
179 In Docket ER21-2043, see Comments of the Independent Market Monitor for PJM (June 22, 2021); Answer and Motion for Leave toAnswer of the Independent Market Monitor for PJM (July 9, 2021); Answer and Motion for Leave to Answer of the Independent Market
Monitor for PJM (July 20, 2021);
180 See Appendix B in “PJM Manual 21: Rules and Procedures for Determination of Generating Capability,” <https://pjm.com/-/media/
documents/manuals/m21.ashx>.

404

Section 8 Environmental and Renewables

3.2
0.0
22.3
12.0
0.0
61.1
0.0
58.2
125.2
0.0
127.7
0.0
8.0
465.0

0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1,300.0
0.0
0.0
0.0
0.0
3,097.0

0.0
0.0
0.0
0.0
0.0
0.0
0.0
1.0
0.0
0.0
88.0
0.0
0.0
89.0

0.0
0.0
69.0
0.0
0.0
0.0
0.0
136.0
0.0
0.0
17.0
0.0
0.0
222.0

0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
13.0

0.0
30.1
0.0
0.0
0.0
362.5
0.0
4.6
0.0
0.0
453.0
685.3
0.0 1,180.1
0.0
416.1
1,269.0
121.8
0.0
0.0
5,386.0 1,430.0
0.0
0.0
0.0
29.1
7,108.0 4,268.5

0.0
0.0
0.0
0.0
128.2
0.0
0.0
0.0
0.0
0.0
204.6
0.0
0.0
0.0
0.0
0.0
209.3 1,347.0
0.0
0.0
123.0
0.0
0.0
0.0
0.0
96.0
665.0 1,443.0

2,350.5
0.0
245.2
0.0
146.0
4.5
208.0
1,045.6
1,457.2
0.0
12.0
0.0
687.3
10,682.3

2,392.0
132.7
827.6
30.5
146.0
1,419.4
1,713.1
4,171.3
7,270.7346.6
8,446.9
0.0
1,030.2
34,319.4

There are three classes of solar generators with capacity factors ranging from
38.0 percent to 60.0 percent.182
Table 8-18 shows renewable capacity registered in the PJM generation
attribute tracking system (GATS).183 These resources are not PJM resourceseven though most are located in PJM states. For example, roof top solar panels
within the PJM footprint generate SRECs but are not PJM units. This includes
solar capacity of 7,808.2 MW of which 2,768.8 MW are in New Jersey. These
resources can earn renewable energy credits, and can be used to fulfill therenewable portfolio standards in PJM jurisdictions. There are 1,774.7 MWof capacity located in jurisdictions outside PJM that may qualify for specific181 See “Class Average Capacity Factors Wind and Solar Resources,” PJM, June 1, 2017 <https://www.pjm.com/-/media/planning/res-adeq/
class-average-wind-capacity-factors.ashx?la=en>.
182 Id.
183 PJM Environmental Information Services (EIS), an unregulated subsidiary of PJM, operates the generation attribute tracking system(GATS), which is used by many jurisdictions to track these renewable energy credits. GATS publishes details on every renewable generator
registered within the PJM footprint and aggregate emissions of renewable generation, but does not publish generation data by unit anddoes not make unit data available to the MMU.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

renewable energy credits in some PJM jurisdictions. For example, there are
54.0 MW of capacity registered with GATS located in Alabama.

markets. Revenues from RECs markets are revenues for PJM resources earnedin addition to revenues earned from the sale of the same MWh in PJM markets.

Table 8-18 Renewable capacity by jurisdiction, non-PJM units registered in
GATS (MW): June 30, 2021184

Delaware, North Carolina, Michigan and Virginia allow various types ofresources to earn multiple RECs per MWh,though typically one REC is equal to one
Solid Waste Waste
MWh. For example, Delaware provided a
Waste
Coal
Heat
Wind
Total
three MWh REC for each MWh produced
0.0
0.0
0.0
0.0
54.0
0.0
0.0
0.0
2.0
134.0
by in-state customer sited photovoltaic
0.0
0.0
0.0
0.0
179.3
generation and fuel cells using renewable
0.0
0.0
0.0
598.4
1,382.5
0.0
0.0
94.6
180.0
464.6
fuels that are installed on or before
0.0
0.0
0.0
336.8
340.5
December 31, 2014.186 This is equivalent
0.0
0.0
0.0
0.0
916.6
to providing a REC price equal to three
10.0
0.0
0.0
0.3
1,283.5
0.0
0.0
0.0
80.6
241.4
times its stated value per MWh.

Jurisdiction
Alabama
DelawareGeorgia
Illinois
Indiana
Iowa
Kentucky
MarylandMichiganMinnesota
Missouri
New Jersey
New York
North Carolina
North Dakota
Ohio
Pennsylvania
South Carolina
Tennessee
Virginia
Washington, D.C.
West Virginia
Wisconsin
Total

Biofuel
54.0
0.0
0.0
0.0
0.0
0.0
93.0
3.8
31.0
0.0
0.0
0.0
151.5
0.0
92.8
62.2
0.0
0.0
287.6
0.0
0.0
44.6
820.5

Coal /
Biofuel
0.0
0.0
0.0
0.0
0.0
0.0
600.0
65.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
109.7
0.0
0.0
0.0
0.0
0.0
0.0
774.7

Fuel
Landfill
Cell Geothermal Hydro
Gas
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2.2
0.0
0.0
0.0
27.1
0.0
0.0
21.4
55.4
0.0
0.0
0.0
48.0
0.0
0.0
0.0
1.6
0.0
0.0
164.8
20.2
0.0
2.2
0.0
14.7
0.0
0.0
1.3
16.6
0.0
0.0
36.0
0.0
0.0
0.0
0.0
5.6
0.0
0.0
0.0
45.8
0.0
0.0
0.0
0.0
0.0
0.0
520.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
6.6
19.7
0.8
0.0
31.5
45.2
0.0
0.0
0.0
30.8
0.0
0.0
99.6
0.0
0.0
0.0
30.8
11.3
0.0
0.0
0.0
0.0
0.0
0.0
102.0
0.0
0.0
0.0
0.0
0.0
0.8
2.2 1,014.4
344.1

Natural Gas /Distributed
Generation
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
20.0
0.0
0.0
0.0
0.0
0.0
0.0
20.0

Other
Gas
0.0
0.0
0.0
2.1
5.2
0.0
0.4
0.0
0.0
0.0
0.0
11.4
0.0
0.0
0.0
61.1
100.0
0.0
0.0
2.6
49.4
0.0
0.0
232.0

Solar
0.0
129.8
152.2
705.3
136.8
2.1
38.1
1,187.5
111.9
0.0
61.2
2,768.8
0.4
1,245.0
0.0
243.2
497.1
91.3
0.0
297.1
135.9
4.3
0.1
7,808.2

Renewable energy credits are related to the production and purchase ofwholesale power, but have not, when they constitute a transaction separate
from a wholesale sale of power, been found subject to FERC regulation.185
RECs markets are, as an economic fact, integrated with PJM markets including
energy and capacity markets, but are not formally recognized as part of PJM
184 See PJM–EIS (Environmental Information Services), Generation Attribute Tracking System, “Renewable Generators Registered in GATS,”<https://gats.pjm-eis.com/gats2/PublicReports/‌RenewableGeneratorsRegisteredinGATS> (Accessed January 19, 2021).
185 See WSPP, Inc., 139 FERC ¶ 61,051 at P 18 (2012) (“we conclude that unbundled REC transactions fall outside of the Commission’s
jurisdiction under sections 201, 205 and 206 of the FPA. We further conclude that bundled REC transactions fall within the Commission’s
jurisdiction under sections 201, 205 and 206 of the FPA”); citing American Ref-Fuel Company, et al., 105 FERC ¶ 61,004 at PP 23–24(2003) (“American Ref-Fuel, 105 FERC ¶ 61,004 at PP 23-24 (“RECs are created by the States. They exist outside the confines of PURPA…
And the contracts for sales of QF capacity and energy, entered into pursuant to PURPA, … do not control the ownership of RECs.”); seealso Williams Solar LLC and Allco Finance Limited, 156 FERC ¶ 61,042 (2016).

© 2021 Monitoring Analytics, LLC

0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.2
0.0
0.0
0.0
0.0
0.0
0.0
10.2

0.0
0.0
0.0
0.0
0.0
0.0
0.0
204.2
0.0
0.0
0.0
0.0
0.0
0.0
204.2

0.0
0.0
0.0
693.0
0.0
4.7
0.0
0.0
0.0
0.0
0.0
360.0
33.0
54.7
57.6
3.2
0.0
0.0
0.0
0.0
0.0
0.0
13.5
0.0
0.0
0.0
0.0
0.0
198.7 2,313.7

36.0
759.8
2,830.6
0.4
1,916.9360.0
511.1
1,131.7
122.1
99.6
629.3
198.9
106.3
44.7
13,743.9

In addition to GATS, there are several
other REC tracking systems used by statesin the PJM footprint. Illinois, Indiana
and Ohio use both GATS and M-RETS,
the REC tracking system for resources
located in the Midcontinent ISO, to track
the sales of RECs used to fulfill their
RPS requirements. Michigan and North
Carolina have created their own statewide tracking systems, MIRECS and NCRETS, through which all RECs used tosatisfy these states’ RPS requirements must ultimately be traded. Table 8-19
shows the REC tracking systems used by each state within the PJM footprint.
To ensure a REC is only used one time, REC tracking systems must keep an
account of a REC from its creation until its retirement. A REC is considered
to be retired when it has been used to satisfy an obligation associated withan RPS.

186 See DSIRE, NC Clean Energy Technology Center. Delaware Renewable Portfolio Standard, <http://programs.dsireusa.org/system/program/detail/1231> (Accessed November 3, 2018).

2021 Quarterly State of the Market Report for PJM: January through June 405

2021 Quarterly State of the Market Report for PJM: January through June

Table 8-19 REC tracking systems in PJM states with renewable portfolio standards
Jurisdiction with RPS
DelawareIllinois
MarylandMichigan
New Jersey
North Carolina
Ohio
Pennsylvania
Virginia
Washington, D.C.
Jurisdiction with Voluntary Standard
Indiana

REC Tracking System Used
PJM-GATSPJM-GATSPJM-GATS

M-RETS
MIRECSPJM-GATS
NC-RETSPJM-GATSPJM-GATSPJM-GATSPJM-GATS

M-RETSPJM-GATS

M-RETS

All PJM states with renewable portfolio standards have specified geographical restrictions governing the source of RECs to satisfy states’ standards. Table 8-20
describes these restrictions. Indiana, Illinois, Michigan, and Ohio all have provisions in their renewables standards that require all or a portion of RECs used tocomply with each state’s standards to be generated by in-state resources. North Carolina has provisions that require RECs to be purchased from in-state resources
but Dominion, the only utility located in both North Carolina and PJM, is exempt from these provisions. Pennsylvania added a provision in 2017 that requires
SRECs used to comply with Pennsylvania’s solar photovoltaics carve out standard to be sourced from resources located in Pennsylvania.
Pennsylvania and Virginia require that RECs used for RPS compliance be produced from resources located within the PJM footprint. Delaware requires that RECs
used for compliance with its RPS are produced from resources located within the PJM footprint or resources located elsewhere if these resources can demonstratethat the power they produce is directly deliverable to Delaware. The District of Columbia, Maryland and New Jersey allow RECs to be purchased from resources
located within PJM in addition to large areas that adjoin PJM for compliance with their standards.

406

Section 8 Environmental and Renewables© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Table 8-20 Geographic restrictions on REC purchases for renewable portfolio standard compliance in PJM states
State with RPS
DelawareIllinois
MarylandMichigan

RPS Contains
In-state Provision
No
Yes
No
Yes

New Jersey

No

North Carolina

Yes

Ohio

Yes

Pennsylvania

Yes

Virginia
Washington, D.C.

No
No

State with Voluntary Standard
Indiana
Yes

Geographical Requirements for RPS Compliance
RECs must be purchased from resources located either within PJM or from resources outside of PJM that are directly deliverable into Delaware.
All RECs must be purchased from resources located within Illinois or from resources located in adjacent states that meet certain public interest criteria.
RECs must come from within PJM, 10-30 miles offshore the coast of Maryland or from a control area adjacent to PJM that is capable of delivering power into PJM.
RECs must either come from resources located within Michigan or anywhere in the service territory of retail electric provider in Michigan that is not an alternative electric supplier.
There are many exceptions to these requirements (see Michigan S.B. 213).
RECs must either be purchased from resources located within PJM or from resources located outside of PJM for which the energy associated with the REC is delivered to PJM via
dynamic scheduling.
Dominion, the only utility located in both the state of North Carolina and PJM, may purchase RECs from anywhere. Other utilities in North Carolina not located in PJM are subject todifferent REC requirements (see G.S. 62-113.8).
All RECs must be generated from resources that are located in the state of Ohio or have the capability to deliver power directly into Ohio. Any renewable facility located in a statecontiguous to Ohio has been deemed deliverable into the state of Ohio. For renewable resources in noncontiguous states, deliverabilty must be demonstarted to the Public Utilities
Commission of Ohio.
RECs must be purchased from resources located within PJM. All SRECs used for compliance with the Solar PV standard must source from solar PV resources within the state ofPennsylvania.
RECs must be purchased from resources located within PJMRECs must be purchased from either a PJM state or a state adjacent with PJM. A PJM state is defined as any state with a portion of their geographical boundary within the footprintof PJM. An adjacent state is defined as a state that lies next to a PJM state, i.e. SC, GA, AL, AR, IA, NY, MO, MS, and WI.
At least 50 percent of RECs must be purchased from resources located within Indiana.

Alternative Compliance Payments
PJM jurisdictions have various methods for enforcing compliance with required renewable portfolio standards. If a retail supplier is unable to comply withthe renewable portfolio standards required by the jurisdiction, suppliers may make alternative compliance payments (ACPs), with varying standards, to cover
any shortfall between the RECs required by the state and those the retail supplier actually purchased. The ACPs, which are penalties, function as a cap on themarket value of RECs. In New Jersey, solar ACPs are currently $238.00 per MWh.187 Pennsylvania requires that solar ACPs be 200 percent of the average credit
price of Pennsylvania solar RECs sold during the reporting year plus the value of any solar rebates which was $74.00 per MWh for reporting year ending May
31, 2020. Delaware recently reduced the solar ACP from $400 per credit to $150 per credit.188 Maryland reduced the solar ACP from $100 per credit to $80 per
credit effective June 1, 2021.189
Figure 8-9 shows the historical relationship between SREC prices and ACP levels. The SREC price is represented by a solid line in the figure and the corresponding
ACP level is represented by a dashed line. For each jurisdiction, the ACP is an upper bound for the price level. In Michigan and North Carolina, there are no
defined values for ACPs. The public utility commissions in Michigan and North Carolina have discretionary power to assess what a load serving entity must
pay for any RPS shortfalls.

187 N.J. S. 2314/A. 3723.
188 See Senate Bill 33, Delaware General Assembly (February 10, 2021) <https://legis.delaware.gov/BillDetail?legislationId=48278>.
189 Senate Bill 65 Electricity – Renewable Energy Portfolio Standard – Tier 2 Renewable Sources, Qualifying Biomass, and Compliance Fees, Maryland General Assemble (2021) <https://mgaleg.maryland.gov/mgawebsite/Legislation/Details/sb0065?ys=2021RS>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 407

2021 Quarterly State of the Market Report for PJM: January through June

Table 8-21 shows the alternative compliance standards for RPS in PJM
jurisdictions.

Figure 8-9 Comparison of SREC price and solar ACP: 2009 through June 2021
$800

Table 8-21 Tier I, Tier II, and Solar alternative compliance payments in PJM
jurisdictions as of June 30, 2021190 191
Standard Alternative
Tier II Alternative
Solar Alternative
Compliance ($/MWh) Compliance ($/MWh) Compliance ($/MWh)$25.00$150.00$0.35$30.00$15.00$80.00No specific penalties$50.00$50.00$238.00
No specific penalties: At the discretion of the NC Utility Commission$53.49$45.00$45.00$74.00$50.00$10.00$500.00
Voluntary standard - No Penalties
Voluntary standard - No Penalties
No standard
No standard
No standard

$700

$600

$500
$ per MWh

Jurisdiction with RPS
DelawareIllinois
MarylandMichigan
New Jersey
North Carolina
Ohio
Pennsylvania
Washington, D.C.
Jurisdiction with Voluntary Standard
Indiana
Virginia
Jurisdiction with No Standard
KentuckyTennessee
West Virginia

$400

$300

$200

$100

$0

Load serving entities participating in mandatory RPS programs in PJM
jurisdictions must submit compliance reports to the relevant jurisdiction’s
public utility commission.

190 The Ohio standard alternative compliance payment (ACP) is updated annually <https://www.puco.ohio.gov/industry-information/industry-topics/acp-non-solar-alternative-compliance-payment-under-orc-492864/>. The Illinois Commerce Commission periodicallypublishes updates to the effective ACP amount <https://www.icc.illinois.gov/electricity/‌RPSCompliancePaymentNotices.aspx>. For
updated Maryland ACPs, see Table 3 of the 2018 Renewable Energy Portfolio Standard Report <https://www.psc.state.md.us/commissionreports/>.
191 The entry for Pennsylvania reflects the solar ACP for the compliance year ending May 31, 2020. See “Pricing,” <https://www.pennaeps.
com/reports/> (Accessed October 22, 2020).

408

Section 8 Environmental and Renewables

PA SREC
PA ACPMD SREC
MD ACPDC SREC
DC ACPNJ SREC
NJ ACP

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

In their submitted compliance reports, load serving entities must indicate
the quantity of MWh that they have generated using eligible renewable oralternative energy resources. They must also identify the quantity of RECs they
may have purchased to make up for renewable energy generation shortfalls or
to comply with RPS provisions requiring that they purchase RECs. The public
utility commissions then release RPS compliance reports to the public.
The Pennsylvania Public Utility Commission issued their 2020 compliancereport for the Pennsylvania Alternative Energy Standards Act of 2004 in
February of 2021.192 Pennsylvania reported that the 614,926 SRECs, 10,086,046
Tier I RECs and 11,203,559 Tier II RECs were retired during the 2020 reporting
year (June 1, 2019 through May 31, 2020). Supplier obligations for 1,435
192 “Alternative Energy Portfolio Standards Act of 2004 Compliance for Reporting Year 2020,” (September 2020), <https://www.puc.pa.gov/
media/1410/aeps-annreport2020.pdf>.

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

SRECs, 34,737 Tier I RECs and 37,073 Tier II RECs were resolved throughACPs.

for ComEd decreased to $74,148. The 2016-2017 ACPs for ComEd totaled$40,575,311.198

The Public Service Commission of the District of Columbia reported that
99,061 SRECs, 1,834,067 Tier I RECs and 54,953 Tier II RECs were retired
during the 2019 compliance year. ACPs decreased from $18.7 million for 2018
to $12.1 million for 2019.193

The North Carolina Utilities Commission reported that Dominion North
Carolina Power submitted its 2018 compliance report on August 13, 2019. The
compliance report stated that Dominion met its general RPS requirement bypurchasing 397,643 credits that consisted of wind and hydro RECs and energy
efficiency credits (EECs).199 Dominion also met its solar, poultry waste, andswine waste requirements by purchasing RECs.

The Public Service Commission of Maryland reported that 1,167,329 SRECs
were retired in 2019, an increase of 36.2 percent over the 2018 level. Tier 1
REC retirements increased to 10,210,275, 18.3 percent higher than in 2018,
and 55,879 Tier 2 RECs were retired in 2019, a 96.5 percent decrease below the2018 level.194 ACPs totaled $7.7 million for 2019, up from $67,797 in 2018.195
The Public Utilities Commission of Ohio reported that 6,367,089 nonsolar
RECs were retired in the 2019 compliance year, which is less than the nonsolar
REC obligation of 6,509,239RECs; and 377,665 SRECs were retired in the 2019
compliance year, exceeding the SREC obligation of 271,176 SRECs.196
Delmarva Power is the only retail electric supplier that must file a compliancereport with the Delaware Public Service Commission. Delmarva Power
reported to the Delaware Public Service Commission that they satisfied their
REC obligation of 719,261 credits for the compliance year ending May 31,
2020, with zero ACPs.197 Delmarva Power satisfied their solar REC obligationof 135,771 credits with zero alternative compliance payments.
Prior to the 2017/2018 Delivery Year, the Illinois RPS had required electricity
suppliers to satisfy at least 50 percent of their RPS obligation throughACPs. This requirement was removed for 2017/2018 Delivery Year and ACPs
193 “Renewable Energy Portfolio Standard, A Report for Compliance Year 2019,” Public Service Commission of the District of Columbia (May1, 2020), <https://dcpsc.org/Orders-and-Regulations/PSC-Reports-to-the-DC-Council/Renewable-Energy-Portfolio-Standard.aspx>.
194 “Renewable Energy Portfolio Standard Report,” Public Service Commission of Maryland (October 2020) at 9, < https://www.psc.state.
md.us/commission-reports/>.
195 Id. at 9.
196 “Renewable Portfolio Standard Report to the General Assembly for Compliance Year 2019,” Public Utilities Commission of Ohio (April
7, 2021), <https://puco.ohio.gov/‌wps/portal/gov/puco/utilities/electricity/resources/ohio-renewable-energy-portfolio-standard/pucoannual-rps-reports>.
197 “Retail Electricity Supplier’s RPS Compliance Report, Compliance Period: June 1, 2019–May 31, 2020,” Delmarva Power, (Sept. 25, 2020),<https://depsc.delaware.gov/delawares-renewable-portfolio-standard-green-power-products/>.

© 2021 Monitoring Analytics, LLC

The Michigan Public Service Commission reported that Indiana Michigan
Power Company met the 2018 standard by generating or acquiring 283,473
RECs.200
New Jersey’s Office of Clean Energy posted a summary of RPS compliancethrough the energy year ending May 31, 2020.201 Electric power suppliers
retired 10,078,927 class I RECs and 1,758,386 class II RECs. Twenty ACPs were
submitted class I credits; 135 ACPs were submitted for class II. Electric power
suppliers retired 3,287,327 solar RECs and 12 SACPs were submitted.
Table 8-22 shows the RPS compliance cost incurred by PJM jurisdictions asreported by the jurisdictions.202 The compliance costs are the cost of acquiring
RECs plus the cost of any alternative compliance payments. The cost by typein Table 8-22 is an estimate based on average REC prices and assigning thereported alternative compliance payments to the solar standard. The cost ofcomplying with RPS, as reported by the states, was $5.6 billion over the six
year period from 2014 through 2019 for the nine jurisdictions that had RPS
and reported compliance costs.203 The average RPS compliance cost per year
198 “Annual Report Fiscal Year 2018,” Illinois Power Agency (Feb. 15, 2019) at 46, <https://www2.illinois.gov/sites/ipa/Pages/IPA_Reports.
aspx>.
199 “Annual Report Regarding Renewable Energy and Energy Efficiency Portfolio Standard in North Carolina,” North Carolina Utilities
Commission (Oct. 1, 2019) at 38, <https://www.ncuc.net/Reps/reps.html>.
200 “Report on the Implementation and Cost-Effectiveness of the P.A. 295 Renewable Energy Standard,” Michigan Public Service Commission(Feb. 18, 2020), <https://www.‌michigan.gov/mpsc/0,9535,7-395-93309_93438_93459_94932---,00.html>.
201 See RPS Report Summary 2005-2020, New Jersey’s Clean Energy Program (Apr. 13, 2021), <http://www.njcleanenergy.com/renewableenergy/program-updates/rps-compliance-reports>.
202 RPS compliance cost totals for Illinois, Michigan, and North Carolina reflect the RPS compliance cost attributable to PJM load in each of
the states.
203 The actual PJM RPS compliance cost exceeds the reported $4.4 billion since this total does not include a value for Delaware in 2014 anda value for Pennsylvania in 2018.

2021 Quarterly State of the Market Report for PJM: January through June 409

2021 Quarterly State of the Market Report for PJM: January through June

based on the reported compliance cost for the six year period from 2014 through 2019 was $936.7 million. The compliance cost for 2019, the most recent yearwith almost complete data, was $1.2 billion.
Table 8-22 RPS Compliance Cost204 205 206 207 208 209 210 211 212 213 214
Jurisdiction with RPS
DelawareTotal RPS
Solar
Non-Solar
Illinois
Total RPS
Maryland
Total RPS
Solar
Tier I
Tier II
Michigan
Total RPS
New Jersey
Total RPS
Solar
Class IClass II
North Carolina
Total RPS
Ohio
Total RPS
Solar
Non-Solar
Pennsylvania
Total RPS
Solar
Tier I
Tier II
Washington D.C.
Total RPS
Solar
Tier I
Tier II
PJM
Total RPS

2014

$21,701,688$103,990,914$29,372,737$70,630,620$3,987,557$476,535$395,782,297$322,504,920$66,071,749$7,205,628$297,513$42,581,477$17,666,730$24,914,747$86,184,477$14,163,543$70,922,431$1,098,503$27,372,970$25,145,143$2,140,860$86,966$678,387,871

2015$16,013,421$7,070,254$8,943,167$24,817,068$126,727,632$39,055,714$85,054,001$2,617,917$0$524,761,382$417,359,783$98,185,431$9,216,167$358,436$42,584,233$14,843,052$27,741,181$114,586,932$19,227,690$94,339,032$1,020,210$38,540,633$36,526,662$1,899,232$114,738$888,389,738

2016$18,409,631$7,748,073$10,661,557$25,718,863$135,198,524$45,556,987$88,200,121$1,441,416$3,264,504$593,441,037$481,540,738$100,910,465$10,989,834$317,644$37,631,481$11,564,584$26,066,897$125,041,911$21,876,876$101,700,328$1,464,707$47,163,353$44,897,161$2,132,072$134,119$986,186,949

2017$18,772,855$7,105,726$11,667,129$25,919,372$72,009,070$21,275,664$50,045,621$687,785$3,961,262$606,312,461$503,797,182$91,872,615$10,642,664$234,264$39,943,836$9,435,730$30,508,106$115,585,212$17,987,722$95,370,456$2,227,034$42,678,813$38,571,061$3,960,018$147,734$925,417,144

2018$18,341,916$6,565,240$11,776,676$25,775,523$84,806,928$27,351,388$56,406,247$1,049,293$3,264,504$653,810,457$560,509,712$83,474,335$9,826,410$442,579$50,214,523$9,419,092$40,795,431$99,681,713$16,565,924$77,899,586$5,216,203$50,609,701$45,673,261$4,809,857$126,583$986,947,843

2019$19,401,476$8,121,914$11,279,562$134,545,520$55,166,116$79,320,505$58,899$763,108,366$667,975,153$85,522,028$9,611,185$67,922,688$9,578,048$58,344,639$112,691,066$20,608,103$74,780,310$17,302,653$57,300,000$51,982,914$5,262,354$54,733$1,154,969,115

204 Several states that have compliance periods that align with the PJM capacity market have not released compliance reports for the period June 1, 2019 through May 31, 2020.
205 “Delmarva Power & Light’s 2018 RPS Compliance Report,” Delmarva Power (Sept. 23, 2019), <https://depsc.delaware.gov/delawares-renewable-portfolio-standard-green-power-products/>.
206 “Fiscal Year 2018 Annual Report,” February 15, 2019, “Report on Costs and Benefits of Renewable Resource Procurement,” April 1, 2016, Illinois Power Agency (IPA), <https://www2.illinois.gov/sites/ipa/Pages/IPA_Reports.aspx>. The compliance cost entry for Illinois represents the ComEd
cost of RECs as given in Section 11, Table 2.
207 “Renewable Energy Portfolio Standard Report,” Public Service Commission of Maryland (Dec. 2019) at 8, <https://www.psc.state.md.us/commission-reports/>.
208 Appendix C in “Report on the Implementation and Cost-Effectiveness of the P.A. 295 Renewable Energy Standard,” Michigan Public Service Commission, February 18, 2020, <https://www.michigan.gov/mpsc/0,9535,7-395-93309_93438_93459_94932---,00.html>. The compliance costentry reflects the compliance cost of the Indiana Michigan Power Company, which is the only investor owned utilities whose service area is in the PJM footprint.
209 “RPS Report Summary 2005-2020,” New Jersey’s Clean Energy Program, April 13, 2021, <http://njcleanenergy.com/renewable-energy/program-updates/rps-compliance-reports>.
210 “Renewable Portfolio Standard Report to the General Assembly for Compliance Year 2019,” Public Utilities Commission of Ohio, April 7, 2021, <https://puco.ohio.gov/wps/‌portal/gov/puco/utilities/electricity/resources/ohio-renewable-energy-portfolio-standard/‌puco-annual-rps-reports>.
211 “2020 Annual Report Alternative Energy Portfolio Standards Act of 2004,” Pennsylvania Public Utility Commission, February 2021 <https://www.puc.pa.gov/media/1410/aeps-annreport2020.pdf>.
212 “Report on the Renewable Energy Portfolio Standard for Compliance Year 2018,” Public Service Commission of the District of Columbia, Executive Summary, May 1, 2019, <https://dcpsc.org/Orders-and-Regulations/PSC-Reports-to-the-DC-Council/Renewable-Energy-Portfolio-Standard.
aspx>.
213 “Application of Dominion Energy North Carolina for Approval of Cost Recovery for Renewable Energy and Energy Efficiency Portfolio Standard Compliance and Related Costs,” Docket No. E-22, Sub 557, Sub 558, August 30, 2018 <https://www.ncuc.net/>. The North Carolina compliancecost entries reflects the compliance cost of Dominion Energy North Carolina.
214 The reporting period for RPS compliance in Delaware, Illinois, New Jersey, and Pennsylvania corresponds to PJM capacity market delivery years, June 1 through May 31. The compliance cost amounts reported by these states were converted to calendar year by assuming the compliancecost was evenly spread across the months in the compliance year.

410

Section 8 Environmental and Renewables© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Emission Controlled Capacity and Emissions
Emission Controlled Capacity
Environmental regulations affect decisions about emission control investments
in existing units, investment in new units and decisions to retire units lacking
emission controls.215 Most PJM units burning fossil fuels have installedemission control technology. All coal steam units in PJM are compliant withthe state and federal emissions limits established by MATS.216 217
Table 8-23 shows SO2 emission controls by fossil fuel fired units in PJM.218 219
220
Coal has the highest SO2 emission rate, while natural gas and diesel oil havelower SO2 emission rates.221 Of the current 55,226.2 MW of coal capacity in
PJM, 51,659.9 MW of capacity, 93.5 percent, has some form of FGD (flue-gas
desulfurization) technology to reduce SO2 emissions.

55,097.2 MW of capacity, 99.8 percent, has some form of emissions controls
to reduce NOX emissions. Most units in PJM have NOX emission controls inorder to meet each state’s emission compliance standards, based on whether
a state is part of CSAPR, Acid Rain Program (ARP) or a combination of thethree. The NOX compliance standards of MATS require the use of selective
catalytic reduction (SCRs) or selective non-catalytic reduction (SCNRs) forcoal steam units, as well as SCRs or water injection technology for peaking
combustion turbine units.223
Table 8-24 NOX emission controls by fuel type (MW): As of June 30, 2021
Coal
Diesel Oil
Natural Gas
Other
Total

NOx Controlled
55,097.2
1,398.3
66,468.8
1,805.7
124,770.0

No NOx Controls
129.0
3,607.1
998.0
2,353.0
7,087.1

Total
55,226.2
5,005.4
67,466.8
4,158.7
131,857.1

Percent Controlled
99.8%
27.9%
98.5%
43.4%
94.6%

Table 8-23 SO2 emission controls by fuel type (MW): June 30, 2021222
Coal
Diesel Oil
Natural Gas
Other
Total

SO2 Controlled
51,659.9
0.0
0.0
325.0
51,984.9

No SO2 Controls
3,566.3
5,005.4
67,466.8
3,833.7
79,872.2

Total
55,226.2
5,005.4
67,466.8
4,158.7
131,857.1

Percent Controlled
93.5%
0.0%
0.0%
7.8%
39.4%

Table 8-24 shows NOX emission controls by fossil fuel fired units in PJM. Coal
has the highest NOX emission rate, while natural gas and diesel oil have lower
NOX emission rates. Of the current 55,226.2 MW of coal capacity in PJM,
215 See EPA, “National Ambient Air Quality Standards (NAAQS),” <https://www.epa.gov/‌criteria-air-pollutants/naaqs-table> (Accessed March
7, 2020).
216 On April 16, 2020, the EPA issued a revised final finding regarding the Mercury and Air Toxics Standards. See EPA. “Regulatory Actions,”<https://www.epa.gov/mats/regulatory-actions-final-mercury-and-air-toxics-standards-mats-power-plants> (Accessed May 7, 2020).
217 On April 9, 2020, the EPA created a new subcategory of six coal refuse power plants in Pennsylvania and West Virginia with reduced
limits of HCl and SO2 emissions under MATS. These units were all compliant with the previous MATS rules. “Mercury and Air Toxics
Standards,”<https://www.epa.gov/sites/production/files/2020-04/documents/frn_mats_coal_‌refuse_2060-au48_final_rule.pdf>(Accessed May 7, 2020)
218 See EPA, “Air Market Programs Data,” <http://ampd.epa.gov/ampd/> (Accessed May 7, 2020).
219 Air Markets Programs Data is submitted quarterly. Generators have 60 days after the end of the quarter to submit data, and all data is
considered preliminary and subject to change until it is finalized in June of the following year. The most recent complete set of emissions
data is from the second quarter of 2020.
220 The total MW are less than the 183,962.3 reported in Section 5: Capacity Market, because EPA data on controls could not be matched tosome PJM units. “Air Markets Program Data,” <http://ampd.epa.gov/ampd/QueryToolie.html> (Accessed May 7, 2020).
221 Diesel oil includes number 1, number 2, and ultra-low sulfur diesel. See EPA, “Electronic Code of Federal Regulations, Title 40, Chapter 1,
Subchapter C, Part 72, Subpart A, Section 72.2,” <http://www.ecfr.gov/cgi-bin/text-idx?SID=4f18612541a393473efb13acb879d470&‌mc=
true&node=se40.18.72_12&rgn=div8> (Accessed May 7, 2020).
222 The “other” category includes petroleum coke, wood, process gas, residual oil, other gas, and other oil. The EPA’s “other” category does
not have strict definitions for inclusion.

© 2021 Monitoring Analytics, LLC

Table 8-25 shows particulate emission controls by fossil fuel units in PJM.
Almost all coal units (99.8 percent) in PJM have particulate controls, as well
as a few natural gas units (4.3 percent) and units with other fuel sources (49.5
percent). Typically, technologies such as electrostatic precipitators (ESP) or
fabric filters (baghouses) are used to reduce particulate matter from coal steam
units.224 Fabric filters work by allowing the flue gas to pass through a tightly
woven fabric which filters out the particulates. Of the current 55,226.2 MW ofcoal capacity in PJM, 55,141.2 MW of capacity, 99.8 percent, have some typeof particulate emissions control technology. In order to achieve compliancewith MATS, most coal steam units in PJM have particulate emission controls
in the form of ESPs, but many units have also installed baghouse technology,
or a combination of an FGD and SCR. Currently, 106 of the 118 coal steam
units have baghouse or FGD technology installed, representing 50,359.9 MW
out of the 55,226.2 MW total coal capacity, or 91.2 percent.

223 See EPA. “Mercury and Air Toxics Standards, Cleaner Power Plants,” <https://www.epa.gov/‌mats/cleaner-power-plants#controls>(Accessed May 7, 2020).
224 See EPA, “Air Pollution Control Technology Fact Sheet,” <https://www3.epa.gov/‌ttn/catc/dir1/ff-pulse.pdf> (Accessed May 7, 2020).

2021 Quarterly State of the Market Report for PJM: January through June 411

2021 Quarterly State of the Market Report for PJM: January through June

Table 8-25 Particulate emission controls by fuel type (MW): As of June 30,
2021
Coal
Diesel Oil
Natural Gas
Other
Total

Particulate Controlled
55,141.2
0.0
2,912.0
2,058.5
60,111.7

No Particulate
Controls
85.0
5,005.4
64,554.8
2,100.2
71,745.4

Total
55,226.2
5,005.4
67,466.8
4,158.7
131,857.1

Percent Controlled
99.8%
0.0%
4.3%
49.5%
45.6%

Figure 8-10 CO2 emissions by quarter (millions of short tons), by PJM units:
January 1999 through June 2021228 229
160

1
0.9

140

0.8
120

225 Unless otherwise noted, emissions are measured in short tons. A short ton is 2,000 pounds.
226 Emissions data for the first quarter of 2021 was not yet finalized at the time of this report because generators have 60 days after the endof the quarter to submit their emissions data.
227 See the 2020 Quarterly State of the Market Report for PJM: January through March, Section 3: Energy Market, Table 3-10.

412

Section 8 Environmental and Renewables

0.6
0.5

80

0.4

60

0.3
40
0.2
Total CO2 Short Tons (Millions)

20

0.1

CO2 Short Tons per MWh

2021

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

2009

2008

2007

2006

2005

2004

2003

2002

2001

0

2000

CO2 Short Tons per Total PJM MWh

1999

Figure 8-10 shows the total CO2 emissions and the CO2 emissions per MWhwithin PJM for all CO2 emitting units, for each quarter from 1999 to thesecond quarter of 2021. Figure 8-10 also shows the CO2 emissions per MWh of
total generation within PJM for each quarter from the third quarter of 2000 to
the second quarter of 2021.225 226 For the period from the first quarter of 1999
through the second quarter of 2021, the minimum CO2 produced per MWh was
0.66 short tons per MWh in the first quarter of 2020, and the maximum was
0.96 short tons per MWh in the first quarter of 2010. Total PJM generation
increased from 184,780.2 GWh in the second quarter of 2020 to 194,087.9
GWh in the second quarter of 2021, while CO2 produced increased from 74.0
million short tons in the second quarter of 2020 to 40.0 million short tons inthe second quarter of 2021.227

100

CO2 Short Tons (Millions)

Emissions

CO2 Short Tons per MWh

0.7

0Figure 8-11 shows the total CO2 emissions on peak and off peak and theCO2 emissions per MWh for all CO2 emitting units. Since the first quarter of1999 the amount of CO2 produced per MWh during off peak hours was at
a minimum of 0.66 short tons per MWh in the first quarter of 2020, and amaximum of 0.97 short tons per MWh in the second quarter of 2010. Since
the first quarter of 1999 the amount of CO2 produced per MWh during on peak
hours was at a minimum of 0.66 short tons per MWh in the first quarter of
2020, and a maximum of 0.94 short tons per MWh in the first quarter of 2010.
228 The emissions are calculated from the continuous emission monitoring system (CEMS) data from generators located within the PJM
footprint.
229 In 2004 and 2005, PJM integrated the American Electric Power (AEP), ComEd, Dayton Power & Light Company (DAY), Dominion,
and Duquesne Light Company (DLCO) Control Zones. The large increase in total emissions from 2004 to 2005 was a result of these
integrations. In June 2011, PJM integrated the American Transmission Systems, Inc. (ATSI) Control Zone. In January 2012, PJM integrated
the Duke Energy Ohio/Kentucky (DEOK) Control Zone. In June 2013, PJM integrated the Eastern Kentucky Power Cooperative (EKPC). In
December 2018, PJM integrated the Ohio Valley Electric Corporation (OVEC).

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

In the second quarter of 2021, CO2 emissions were 0.70 short tons per MWh
for off peak hours and 0.69 for on peak hours.
Figure 8-11 Total CO2 emissions during on and off peak hours by quarter(millions of short tons), by PJM units: January 1999 through June 2021230
100

1

90

0.9

80

0.8

were 0.000414 short tons per MWh and NOX emissions were 0.000267 shorttons per MWh. The consistent decline in SO2 and NOX emissions starting in2006 is the result of a decline in the use of coal, an increase in the useof natural gas, and the installation of environmental controls from 2006 to
2021.231 232
Figure 8-12 SO2 and NOX emissions by quarter (thousands of short tons), by
PJM units: January 1999 through June 2021233
1,000

0.009

230 The emissions are calculated from the continuous emission monitoring system (CEMS) data from generators located within the PJM
footprint.

© 2021 Monitoring Analytics, LLC

2021

2020

2019

2018

2017

2016

2015

0

Emissions (Short Tons per MWh)

0.001

100

2014

Figure 8-12 shows the total SO2 and NOX emissions and the short ton emissions
per MWh for all SO2 and NOX emitting units, and the SO2 and NOX emissions
per MWh of total PJM generation. For the period from the first quarter of 1999
through the second quarter of 2021, the minimum SO2 produced per MWh was
0.000378 short tons per MWh in the first quarter of 2020, and the maximum
was 0.008141 short tons per MWh in the fourth quarter of 2003. For theperiod from the first quarter of 1999 through the second quarter of 2021, theminimum NOX produced per MWh was at a 0.000267 short tons per MWh in
the second quarter of 2021, and the maximum was 0.002215 short tons per
MWh in the first quarter of 2005. In the second quarter of 2021, SO2 emissions

0.002

200

2013

0

0.003

300

2012

2021

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

2009

2008

2007

2006

2005

2004

2003

2002

2001

2000

CO2 Short Tons per MWh On Peak

1999

0

0.1

2011

CO2 Short Tons per MWh Off Peak2010

Total CO2 Short Tons (Millions) On Peak

10

0.004
400

2009

0.2

Total CO2 Short Tons (Millions) Off Peak

2008

20

0.005
500

2007

0.3

600

2006

30

0.007
0.006

2005

0.4

700

2004

40

NOx Short Tons per Total PJM MWh

2003

0.5

NOx Short Tons per MWh

2002

50

SO2 Short Tons per Total PJM MWh

800

2001

0.6

0.008

SO2 Short Tons per MWh

2000

60

Total NOx Short Tons

900

1999

0.7

Emissions Short Tons (Thousands)

70

CO2 Short Tons per MWh

CO2 Short Tons (Millions)

Total SO2 Short Tons

0

Figure 8-13 shows the total on peak hour and off peak hour SO2 and NOX
emissions and the emissions per MWh from emitting resources for all SO2
and NOX emitting units. For the period from the first quarter of 1999 throughthe second quarter of 2021, the minimum SO2 produced per MWh during off
231 See EIA, “Changes in coal sector led to less SO2 and NOx emissions from electric power industry,”<https://www.eia.gov/todayinenergy/
detail.php?id=37752> (Accessed October 25, 2019).
232 See EIA, “Sulfur dioxide emissions from U.S. power plants have fallen faster than coal generation,” <https://www.eia.gov/todayinenergy/
detail.php?id=29812> (Accessed October 25, 2019).
233 The emissions are calculated from the continuous emission monitoring system (CEMS) data from generators located within the PJM
footprint.

2021 Quarterly State of the Market Report for PJM: January through June 413

2021 Quarterly State of the Market Report for PJM: January through June

Figure 8-13 SO2 and NOX emissions during on and off peak hours by quarter(thousands of short tons), by PJM units: January 1999 through June 2021234
500

0.009
Total SO2 Short Tons Off Peak
Total SO2 Short Tons On Peak

450

0.008

Total NOx Short Tons Off Peak
Total NOx Short Tons On Peak
SO2 Short Tons per MWh Off Peak

0.007

SO2 Short Tons per MWh On Peak350

NOx Short Tons per MWh Off Peak0.006

NOx Short Tons per MWh On Peak

300
0.005
250
0.004
200
0.003

150

Emissions (Short Tons per MWh)

400

Emissions Short Tons (Thousands)

0.002

100

2021

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

2009

2008

2007

2006

2005

2004

2003

0

2002

0

2001

0.001

2000

50

1999

peak hours was 0.000352 short tons per MWh in the second quarter of 2020,
and the maximum was 0.008239 short tons per MWh in the fourth quarter of2003. For the period from the first quarter of 1999 through the second quarterof 2021, the minimum SO2 produced per MWh during on peak hours was
0.000402 short tons per MWh in the first quarter of 2020, and the maximum
was 0.008048 short tons per MWh in the fourth quarter of 2003. For theperiod from the first quarter of 1999 through the second quarter of 2021,
the minimum NOX produced per MWh during off peak hours was 0.000267
short tons per MWh in the second quarter of 2021, and the maximum was
0.002215 short tons per MWh in the first quarter of 2005. For the period fromthe first quarter of 1999 through the second quarter of 2021, the minimum
NOX produced per MWh during on peak hours was 0.000267 short tons per
MWh in the second quarter of 2021 and the maximum was 0.002215 shorttons per MWh in the first quarter of 2005. In the second quarter of 2021, SO2
emissions were 0.000414 short tons per MWh and 0.000434 short tons per
MWh for off and on peak hours. In the second quarter of 2021, NOX emissions
were 0.000267 short tons per MWh and 0.000267 short tons per MWh for off
and on peak hours.

Renewable Energy Output
Wind and Solar Peak Hour Output
The capacity of solar and wind resources are derated from the nameplate
or installed capacity value to a level intended to reflect that the resources
are a substitute for other capacity resources in the PJM Capacity Market.
The derating percentages are intended to reflect expected performance duringhigh load hours and are based on actual historical performance. Figure 8-14
shows the wind and solar output during the top 100 load hours in PJM in
the first six months of 2021. Of the top 100 load hours in PJM in the firstsix months of 2021, 82 are PJM defined peak load hours. The hours are in
234 The emissions are calculated from the continuous emission monitoring system (CEMS) data from generators located within the PJM
footprint.

414

Section 8 Environmental and Renewables© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Figure 8-14 Wind and solar output during the top 100 load hours: January
through June, 2021
14,00012,000MW

10,000Wind Output
Wind ICAPWind ICAP Derate

8,000
6,000
4,000
2,000
0
4,500
4,000

Solar Output
Solar ICAP
Solar ICAP Derate

3,500

3,000
MW

descending order by load. The solid lines are the total ICAP of wind or solar
PJM resources. The dashed lines are the total capacity committed for each
unit, or the ICAP of wind and solar PJM resources derated to 14.7 and 38.0
percent if the unit does not participate in the capacity market.235 The actual
output of the wind and solar resources during the top 100 load hours ranges
above and below the derated capacity values. Wind output was above thederated ICAP for 73 hours and below the derated ICAP for 27 hours of the
top 100 load hours in the first six months of 2021. The wind capacity factor
for the top 100 load hours in first six months of 2021 was 13.9 percent. Wind
output was above the derated ICAP for 3,343 hours and below the derated
ICAP for 1,000 hours in the first six months of 2021. The wind capacity factor
in the first six months of 2021 was 29.9 percent. Solar output was above thederated ICAP for 66 hours and below the derated ICAP for 34 hours of the top
100 load hours in the first six months of 2021. The solar capacity factor forthe top 100 load hours in the first six months of 2021 was 46.8 percent. Solar
output was above the derated ICAP for 1,108 hours and below the derated
ICAP for 3,235 hours in the first six months of 2021. The solar capacity factor
in the first six months of 2021 was 25.0 percent.

2,500
2,000
1,500

1,000
500
0

1

11

21

31

41
51
61
PJM Peak Load Hours

71

81

91

Wind Units
Table 8-26 shows the capacity factors of wind units in PJM. In the first six
months of 2021, the capacity factor of wind units in PJM was 29.9 percent.
Wind units that were capacity resources had a capacity factor of 31.5 percent
and an installed capacity of 10,119.3 MW. Wind units that were energy only
had a capacity factor of 18.2 percent and an installed capacity of 1,447.7
MW. Wind capacity in RPM is derated to 14.7 or 17.6 percent of nameplate
capacity for the capacity market, based on the wind farm terrain, and energy
only resources are not included in the capacity market.236
235 PJM used derating factors of 13 and 38 percent until June 1, 2017. The current derating factors are 38.0 percent, 42 percent or 60.0
percent depending on installation type. PJM, Class Average Capacity Factors, <https://www.pjm.com/-/media/planning/res-adeq/classaverage-wind-capacity-factors.ashx?la=en> (Accessed July 24, 2021).

© 2021 Monitoring Analytics, LLC

236 PJM. Class Average Capacity Factors, <https://www.pjm.com/-/media/planning/res-adeq/class-average-wind-capacity-factors.
ashx?la=en> (Accessed July 24, 2021).

2021 Quarterly State of the Market Report for PJM: January through June 415

2021 Quarterly State of the Market Report for PJM: January through June

Table 8-26 Capacity factor of wind units: January through June 2021237
Type of Resource
Energy-Only Resource
Capacity Resource
All Units

Capacity Factor
18.2%
31.5%
29.9%

Installed Capacity (MW)
1,447.7
10,119.3
11,567.0

Figure 8-15 shows the average hourly real-time generation of wind units in
PJM, by month for the first six months of 2021. The hour with the highest
average output in the first six months of 2021, 5,008.3 MW, occurred in April,
and the hour with the lowest average output, 1,841.9 MW, occurred in June.
Wind output in PJM is generally higher during off peak hours and lower
during on peak hours.
Figure 8-15 Average hourly real-time generation of wind units: January
through June, 2021
5,200
4,800

3,600
MW

3,200
2,800

Table 8-27 Capacity factor of wind units in PJM by month: 2020 and January
through June, 2021
Month
January
February
March
April
May
June
July
AugustSeptember
OctoberNovember
December
Annual2020
Generation (MWh)2,588,895.7
2,564,467.7
2,739,005.2
2,679,800.9
2,261,803.9
1,662,419.6
959,774.9
925,896.4
1,604,108.9
2,322,150.1
3,271,536.3
2,851,142.4
26,431,001.9

Capacity Factor
33.3%
35.1%
34.8%
35.0%
28.6%
21.7%
12.1%
11.7%
20.8%
29.0%
41.1%
33.8%
28.1%

2021
Generation (MWh)2,486,383.6
2,595,187.7
3,399,080.7
2,684,454.5
2,110,377.3
1,691,536.1

14,967,019.9

Capacity Factor
29.4%
33.4%
39.6%
32.3%
24.5%
20.3%

29.9%

March

Wind units that are capacity resources are required, like all capacity resources
except demand resources, to offer the energy associated with their cleared
capacity in the day-ahead energy market and in the real-time energy market.
Figure 8-16 shows the average hourly day-ahead generation offers of wind
units in PJM, by month.

4,400
4,000

Table 8-27 shows the generation and capacity factor of wind units by monthfor 2020 and the first six months of 2021.

February
April

January
May
June

2,400
2,000
1,600
1,200

800
400
0

0

1

2

3

4

5

6

7

8

9

10 11 12 13 14 15 16 17 18 19 20 21 22 23
Hour Ending (EPT)237 Capacity factor is calculated based on online date of the resource.

416

Section 8 Environmental and Renewables© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Figure 8-16 Average hourly day-ahead generation of wind units: January
through June, 2021
4,000

3,800
March

3,600

Figure 8-17 Marginal fuel at time of wind generation: January through June,
2021

3,400
3,200

3,000

February

4,000

2,800
2,600

wind resources were on the margin this means that there was no displacement
for those hours, if the dispatch instruction was to lower the generation. The
level of wind displaced by wind is thus overstated.

April

January

3,500

2,400
MW

2,200
2,000
1,800

May

3,000

June

Solar

Average MW Displaced

1,600

1,400
1,200
1,000
800

600
400

Heavy Oil
Wind

2,000

Waste Coal
NuclearNatural Gas

1,500

Misc
MSW

200
0

LFG

2,500

Light Oil

1,000
1

2

3

4

5

6

7

8

9

Diesel

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour Ending (EPT)

Output from wind turbines displaces output from other generation types
because, in general, wind turbines generate power when the wind is blowing,
regardless of the price. This displacement affects the output of marginal units
in PJM. The magnitude and type of effect on marginal unit output depends on
the level of wind turbine output, its location, time and duration. One measureof this displacement is based on the mix of marginal units when wind is
producing output.238 Figure 8-17 and Table 8-28 show the hourly average
proportion of marginal units by fuel type mapped to the hourly average MWof real-time wind generation in the first six months of 2021. This is not anexact measure of displacement because it is not based on a redispatch of thesystem without wind resources. In the first six months of 2021, the dispatch
instruction for marginal wind resources was to reduce output for 57.5 percentof the unit intervals. When wind appears as the displaced fuel at times when

Coal

500
0

1

2

3

4

5

6

7

8

9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour ending (EPT)238 The measure is based on the principle that any incremental change in the wind output is balanced by the change in the output of
marginal generators, while holding everything else equal.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 417

2021 Quarterly State of the Market Report for PJM: January through June

Table 8-28 Marginal fuel MW at time of wind generation: January through June 2021
Hour
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Average

Coal
768.3
825.5
700.7
697.8
712.2
787.4
752.6
753.9
711.7
775.3
708.5
673.6
706.4
711.4
749.6
734.1
688.0
790.5
799.0
824.2
850.2
843.1
826.7
722.8
754.7

Diesel
1.0
0.5
0.0
0.0
0.0
3.9
3.0
3.9
1.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
6.0
5.5
4.4
0.0
0.0
1.2

Light
Oil
5.1
8.7
19.0
11.6
19.7
14.7
13.9
39.3
17.6
18.5
29.2
24.2
25.1
16.5
8.7
12.1
15.9
22.7
51.6
41.5
43.3
41.6
13.2
4.4
21.6

MSW
1.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1.5
1.1
0.0
0.0
1.1
0.0
4.7
0.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.4

Misc
8.4
8.5
0.0
0.0
0.7
0.5
3.3
3.1
4.1
2.7
14.3
7.5
13.2
9.0
6.9
21.5
7.1
7.8
2.8
0.0
0.0
0.4
1.5
2.5
5.2

NaturalGas Nuclear
2,454.3
21.1
2,332.4
55.7
2,417.4
72.2
2,432.6
63.1
2,357.4
68.0
2,150.3
95.1
2,130.8
77.4
2,054.7
59.2
2,014.2
44.1
1,832.5
29.6
1,895.2
13.5
1,913.2
17.2
1,935.9
20.9
2,060.3
14.3
2,067.5
15.1
2,081.7
30.1
2,190.0
25.1
2,060.9
21.4
2,090.8
29.1
2,068.9
36.8
2,078.0
23.4
2,209.5
28.8
2,363.1
25.5
2,497.5
18.3
2,153.7
37.7

Waste
Coal
4.4
3.3
3.7
1.1
2.1
3.2
1.9
5.8
1.9
3.0
1.1
4.6
2.1
3.3
1.2
0.0
1.1
2.3
1.9
1.6
4.1
5.9
4.4
4.6
2.9

Wind
469.8
474.5
466.2
429.3
409.4
424.0
453.8
496.4
458.0
429.4
382.6
457.8
486.6
517.5
625.5
663.9
652.0
683.7
577.9
521.0
454.7
409.1
443.1
481.2
494.5

Heavy
Oil
0.0
0.0
1.4
0.0
13.0
12.9
5.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1.3

LFG
0.0
0.0
0.0
0.0
0.6
1.3
0.0
0.0
0.0
0.0
0.7
0.0
1.2
0.0
0.0
0.0
0.8
0.8
1.8
2.2
2.0
0.0
0.0
2.9
0.6

Solar
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.5
51.8
113.4
128.2
129.8
143.6
141.9
111.5
101.5
92.6
44.0
12.0
0.0
0.0
0.0
0.0
0.0
44.7

Total
3,733.5
3,709.1
3,680.6
3,635.5
3,583.1
3,493.4
3,441.7
3,419.6
3,305.9
3,205.5
3,173.4
3,227.9
3,336.3
3,474.2
3,590.7
3,645.6
3,672.7
3,634.1
3,566.9
3,502.2
3,461.1
3,542.8
3,677.5
3,734.2
3,518.6

Solar Units
Solar units in PJM may be in front of or behind the meter. The data reported include all
PJM solar units that are in front of the meter. As shown in Table 8-17, there are 4,268.5
MW capacity of solar registered in GATS that are PJM units. As shown in Table 8-18,
there are 7,808.2 MW capacity of solar registered in GATS that are not PJM units. Somebehind the meter generation exists in clusters, such as community solar farms, and serves
dedicated customers. Such customers may or may not be located at the same node on thetransmission system as the solar farm. When behind the meter generation and its associatedload are at separate nodes, loads should pay for the appropriate level of transmission
service, and should not be permitted to avoid their proper financial responsibility throughbadly designed rules, such as rules for netting. The MMU recommends that load andgeneration located at separate nodes be treated as separate resources.

418

Section 8 Environmental and Renewables

Table 8-29 shows the capacity factor of solar units in PJM. The
capacity factor of solar units in PJM was 25.0 percent in the firstsix months of 2021. Solar units that were capacity resources had
a capacity factor of 25.9 percent and an installed capacity of
3,638.7 MW. Solar units that were energy only had a capacity
factor of 18.2 percent and an installed capacity of 518.5 MW.
Solar capacity in RPM is derated to 38.0, 42.0 or 60.0 percent
of nameplate capacity for the capacity market, based on the
installation type, and energy only resources are not included in
the capacity market.239
Table 8-29 Capacity factor of solar units: January through June,
2021
Type of Resource
Energy-Only Resource
Capacity Resource
All Units

Capacity Factor
18.2%
25.9%
25.0%

Installed Capacity (MW)518.5
3,638.7
4,157.2

Figure 8-18 shows the average hourly real-time generation of solar
units in PJM, by month. The hour with the highest peak average
output in the first six months of 2021, 2,711.8 MW, occurred inMay, and the hour with the lowest peak average output, 1,306.9
MW, occurred in February. Solar output in PJM is generally higher
during peak hours and lower during off peak hours.

239 PJM. Class Average Capacity Factors, <https://www.pjm.com/-/media/planning/res-adeq/class-average-windcapacity-factors.ashx?la=en> (Accessed July 24, 2019).

© 2021 Monitoring Analytics, LLC

Section 8 Environmental and Renewables

Figure 8-18 Average hourly real-time generation of solar units: January
through June, 2021

Table 8-30 shows the generation and capacity factor of solar units by monthfor 2020 and the first six months of 2021.

3,000
January
February
March

2,500

April
May
June

MW

2,000

1,500

1,000

500

0

Table 8-30 Capacity factor of solar units by month: 2020 and January
through June, 2021

0

1

2

3

4

5

© 2021 Monitoring Analytics, LLC

6

7

8

9

Month
January
February
March
April
May
June
July
AugustSeptember
OctoberNovember
December
Annual2020
Generation (MWh)172,790.6
192,610.6
268,220.8
339,791.0
371,098.3
386,657.7
419,087.1
325,962.2
289,608.7
282,855.9
272,656.3
217,925.0
3,539,264.3

Capacity Factor
14.4%
17.1%
21.7%
28.0%
29.0%
30.9%
31.6%
24.5%
18.3%
15.1%
15.7%
12.6%
21.0%

2021
Generation (MWh)274,740.5
253,062.0
525,106.6
651,744.6
729,705.9
706,570.2

3,140,929.7

Capacity Factor
14.5%
14.3%
25.5%
31.5%
33.0%
33.1%

25.9%

10 11 12 13 14 15 16 17 18 19 20 21 22 23
Hour Ending (EPT)

2021 Quarterly State of the Market Report for PJM: January through June 419

2021 Quarterly State of the Market Report for PJM: January through June

Solar units that are capacity resources are required, like all capacity resources
except demand resources, to offer the energy associated with their cleared
capacity in the day-ahead energy market and in the real-time energy market.
Figure 8-19 shows the average hourly day-ahead generation offers of solar
units in PJM, by month.240
Figure 8-19 Average hourly day-ahead generation of solar units: January
through June, 2021
2,000
January
February

1,800

March
April

1,600

May

June

1,400

MW

1,200
1,000
800
600
400
200

0

0

1

2

3

4

5

6

7

8

9

10 11 12 13 14 15 16 17 18 19 20 21 22 23
Hour Ending (EPT)240 The average day-ahead generation of solar units in PJM is greater than 0 for hours when the sun is down due to some solar units being
paired with landfill units.

420

Section 8 Environmental and Renewables© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Interchange Transactions
PJM market participants import energy from, and export energy to, external
regions continuously. The transactions involved may fulfill long-term or
short-term bilateral contracts or respond to price differentials. The external
regions include both market and nonmarket balancing authorities.

Overview
Interchange Transaction Activity• Aggregate Imports and Exports in the Real-Time Energy Market. In thefirst six months of 2021, PJM was a monthly net exporter of energy inthe real-time energy market in all months.1 In the first six months of2021, the real-time net interchange was -18,001.2 GWh. The real-time netinterchange in the first six months of 2020 was -18,655.2 GWh.

• Aggregate Imports and Exports in the Day-Ahead Energy Market. In thefirst six months of 2021, PJM was a monthly net exporter of energy in the
day-ahead energy market in all months. In the first six months of 2021,
the total day-ahead net interchange was -12,063.7 GWh. The day-ahead
net interchange in the first six months of 2020 was -4,760.2 GWh.

• Aggregate Imports and Exports in the Day-Ahead and the Real-Time

Energy Market. In the first six months of 2021, gross imports in the dayahead energy market were 121.2 percent of gross imports in the real-timeenergy market (616.2 percent in the first six months of 2020). In the firstsix months of 2021, gross exports in the day-ahead energy market were76.3 percent of the gross exports in the real-time energy market (120.3
percent in the first six months of 2020).

of PJM’s nine interface pricing points eligible for real-time transactionsin the real-time energy market.2• Interface Imports and Exports in the Day-Ahead Energy Market. In the firstsix months of 2021, there were net scheduled exports at 13 of PJM’s 19interfaces in the day-ahead energy market.

• Interface Pricing Point Imports and Exports in the Day-Ahead Energy
Market. In the first six months of 2021, there were net scheduled exports
at seven of PJM’s nine interface pricing points eligible for day-aheadtransactions in the day-ahead energy market.3• Up To Congestion Interface Pricing Point Imports and Exports in the DayAhead Energy Market. In the first six months of 2021, up to congestiontransactions were net exports at five of PJM’s nine interface pricing points
eligible for day-ahead transactions in the day-ahead energy market.4• Inadvertent Interchange. In the first six months of 2021, net scheduledinterchange was -18,001 GWh and net actual interchange was -18,008
GWh, a difference of 7 GWh. In the first six months of 2020, the difference
was 3 GWh. This difference is inadvertent interchange.

• Loop Flows. In the first six months of 2021, the Northern Indiana PublicService (NIPS) Interface had the largest loop flows of any interface with
-680 GWh of net scheduled interchange and -5,910 GWh of net actualinterchange, a difference of 5,231 GWh. In the first six months of 2021,
the SouthIMP interface pricing point had the largest loop flows of any
interface pricing point with 1,769 GWh of net scheduled interchange and10,298 GWh of net actual interchange, a difference of 8,529 GWh.

• Interface Imports and Exports in the Real-Time Energy Market. In the firstsix months of 2021, there were net scheduled exports at 15 of PJM’s 19interfaces in the real-time energy market.

• Interface Pricing Point Imports and Exports in the Real-Time Energy Market.
In the first six months of 2021, there were net scheduled exports at seven

1 Calculated values shown in Section 9, “Interchange Transactions,” are based on unrounded, underlying data and may differ from
calculations based on the rounded values in the tables.

© 2021 Monitoring Analytics, LLC

2 On June 1, 2021, PJM consolidated the SouthIMP and SouthEXP interface pricing points to one new SOUTH interface pricing point. This
reduces the number of real-time interface pricing points to eight.
3 On April 15, 2021, PJM retired the Southeast interface pricing point from the day-ahead market. The Southeast interface pricing
point can still be assigned to transactions under the VACAR reserve sharing agreement in the real-time market. On June 1, 2021, PJM
consolidated the SouthIMP and SouthEXP interface pricing points to one new SOUTH interface pricing point. This reduces the number of
day-ahead interface pricing points to seven.
4 Id.

2021 Quarterly State of the Market Report for PJM: January through June 421

2021 Quarterly State of the Market Report for PJM: January through June

Interactions with Bordering Areas
PJM Interface Pricing with Organized Markets• PJM and MISO Interface Prices. In the first six months of 2021, thedirection of the hourly flow was consistent with the real-time hourly
price differences between the PJM/MISO Interface and the MISO/PJM
Interface in 61.7 percent of the hours.

• PJM and New York ISO Interface Prices. In the first six months of 2021,
the direction of the hourly flow was consistent with the real-time hourly
price differences between the PJM/NYIS Interface and the NYISO/PJM
proxy bus in 55.3 percent of the hours.

• Neptune Underwater Transmission Line to Long Island, New York. In the•first six months of 2021, the hourly flow (PJM to NYISO) was consistent
with the real-time hourly price differences between the PJM Neptune
Interface and the NYISO Neptune bus in 67.5 percent of the hours.
Linden Variable Frequency Transformer (VFT) Facility. In the first six
months of 2021, the hourly flow (PJM to NYISO) was consistent with thereal-time hourly price differences between the PJM Linden Interface andthe NYISO Linden bus in 75.3 percent of the hours.

from 469,113 MWh per day in the first six months of 2020, to 188,479
MWh per day in the first six months of 2021.

Recommendations• The MMU recommends that PJM implement rules to prevent shamscheduling. The MMU recommends that PJM apply after the fact market
settlement adjustments to identified sham scheduling segments to ensurethat market participants cannot benefit from sham scheduling. (Priority:
High. First reported 2012. Status: Not adopted.)• The MMU recommends that PJM implement a validation method forsubmitted transactions that would prohibit market participants frombreaking transactions into smaller segments to defeat the interface pricing
rule by concealing the true source or sink of the transaction. (Priority:
Medium. First reported 2013. Status: Not adopted.)• The MMU recommends that PJM implement a validation method forsubmitted transactions that would require market participants to submit
transactions on paths that reflect the expected actual power flow in orderto reduce unscheduled loop flows. (Priority: Medium. First reported 2013.
Status: Not adopted.)• Hudson DC Line. In the first six months of 2021, the hourly flow (PJM

• The MMU recommends that PJM end the practice of maintaining outdated

Interchange Transaction Issues• The MMU recommends that transactions sourcing in the Western

to NYISO) was consistent with the real-time hourly price differences
between the PJM Hudson Interface and the NYISO Hudson bus in 67.5
percent of the hours.

• PJM Transmission Loading Relief Procedures (TLRs). PJM issued two TLRs

of level 3a or higher in the first six months of 2021, compared to zerosuch TLRs issued in the first six months of 2020.

• Up To Congestion. The average number of up to congestion bids submitted

in the day-ahead energy market decreased by 82.5 percent, from 52,781
bids per day in the first six months of 2020 to 26,781 bids per day in thefirst six months of 2021. The average cleared volume of up to congestion
bids submitted in the day-ahead energy market decreased by 59.8 percent,422

Section 9 Interchange Transactions

definitions of interface pricing points, eliminate the NIPSCO, Southeast
and Southwest interface pricing points from the day-ahead and real-timeenergy markets and, with VACAR, assign the transactions created under
the reserve sharing agreement to the SOUTH interface pricing point.
(Priority: High. First reported 2013. Status: Partially adopted, Q2 2020.)5
Interconnection be priced at either the MISO interface pricing point or
the SOUTH interface pricing point based on the locational price impact
of flows between the DC tie line point of connection with the EasternInterconnection and PJM. (Priority: High. First reported Q1, 2020. Status:
Not adopted.)

5 The grandfathered agreements associated with the Southwest interface pricing point expired in 2012. The Southwest interface pricing
point is no longer an eligible pricing point in the day-ahead or real-time energy markets. Effective June 1, 2020, PJM retired the NIPSCO
interface pricing point.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions• The MMU recommends that PJM eliminate the IMO interface pricing point,

and assign the transactions that originate or sink in the IESO balancing
authority to the MISO interface pricing point. (Priority: Medium. First
reported 2013. Status: Not adopted.)• The MMU recommends that PJM monitor, and adjust as necessary, theweights applied to the components of the interfaces to ensure that theinterface prices reflect ongoing changes in system conditions. The MMU
also recommends that PJM review the mappings of external balancing
authorities to individual interface pricing points to reflect changes to theimpact of the external power source on PJM tie lines as a result of system
topology changes. The MMU recommends that this review occur at least
annually. (Priority: Low. First reported 2009. Status: Not adopted.)• The MMU recommends that, in order to permit a complete analysis ofloop flow, FERC and NERC ensure that the identified data are madeavailable to market monitors as well as other industry entities determined
appropriate by FERC. (Priority: Medium. First reported 2003. Status: Not
adopted.)• The MMU recommends that PJM explore an interchange optimization

solution with its neighboring balancing authorities that would remove
the need for market participants to schedule physical transactions across
seams. Such a solution would include an optimized, but limited, joint
dispatch approach that uses supply curves and treats seams between
balancing authorities as constraints, similar to other constraints within an
LMP market. (Priority: Medium. First reported 2014. Status: Not adopted.)• The MMU recommends that PJM permit unlimited spot market imports aswell as unlimited nonfirm point to point willing to pay congestion imports
and exports at all PJM interfaces in order to improve the efficiency of themarket. (Priority: Medium. First reported 2012. Status: Not adopted.)• The MMU recommends that the emergency interchange cap be replacedwith a market based solution. (Priority: Low. First reported 2015. Status:
Not adopted.)

three hours prior to the requested start time, and that the minimum
duration be modified from one hour to 15 minutes. These changes would
give PJM a more flexible product that could be used to meet load in themost economic manner. (Priority: Medium. First reported 2014. Status:
Partially adopted, 2015.)• The MMU recommends modifications to the FFE calculation to ensurethat FFE calculations reflect the current capability of the transmission
system as it evolves. The MMU recommends that the Commission set a
deadline for PJM and MISO to resolve the FFE freeze date and related
issues. (Priority: Medium. First reported 2019. Status: Not adopted.)Conclusion
Transactions between PJM and multiple balancing authorities in the EasternInterconnection are part of a single energy market. While some of thesebalancing authorities are termed market areas and some are termed nonmarket
areas, all electricity transactions are part of a single energy market. Nonetheless,there are significant differences between market and nonmarket areas. Market
areas, like PJM, include essential features of an energy market including
locational marginal pricing, financial congestion offsets (FTRs and ARRs
in PJM) and transparent, least cost, security constrained economic dispatch
for all available generation. Nonmarket areas do not include these features.
Pricing in the market areas is transparent and pricing in the nonmarket areas
is not transparent.
The MMU’s recommendations related to transactions with external balancing
authorities all share the goal of improving the economic efficiency ofinterchange transactions. The standard of comparison is an LMP market. In
an LMP market, redispatch based on LMP and competitive generator offers
results in an efficient dispatch and efficient prices. The goal of designinginterface transaction rules should be to match the outcomes that would exist
in an LMP market across the interfaces.

• The MMU recommends that the submission deadline for real-time
dispatchable transactions be modified from 1800 on the day prior, to© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 423

2021 Quarterly State of the Market Report for PJM: January through June

It is not appropriate to have special pricing agreements between PJM and any external entity. The same market pricing should apply to all transactions. External
entities wishing to receive the benefits of the PJM LMP market should join PJM.
In 2020, PJM terminated a number of interface pricing points, consistent with longstanding MMU recommendations. Following the termination of the Northwest
pricing point on October 1, 2020, PJM failed to correctly map the pricing points to transactions that had been mapped to the Northwest pricing point to pricing
points that are consistent with electrical impacts on the PJM system. The MMU recommends that transactions sourcing in the Western Interconnection be priced
at either the MISO interface pricing point or the SOUTH interface pricing point based on the electrical impact of flows between the DC tie line point of connection
with the Eastern Interconnection and PJM. The MMU continues to recommend the termination of the Southeast interface pricing point and the Ontario interface
pricing point. The Southeast pricing point is inappropriately used to support a special agreement and the Ontario interface pricing point is noncontiguous to the
PJM footprint that creates opportunities for market participants to engage in sham scheduling activities.

Interchange Transaction Activity
Charges and Credits Applied to Interchange Transactions
Interchange transactions are subject to various charges and credits. These charges and credits are dependent on whether the interchange transaction is submitted
in the real-time or day-ahead energy market, the type of transaction, the transmission service used and whether the transaction is an import, export or wheel.
Table 9-1 shows the billing line items that represent the charges and credits applied to real-time and day-ahead interchange transactions.6

6 For an explanation and current rate for each billing line item, see “Quick Reference Guide to Market Settlements By Type of Business” (November 1, 2020) <https://pjm.com/markets-and-operations/~/media/0FE1D93C5E61457185BB7652F2F18668.ashx>.

424

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-1 Charges and credits applied to interchange transactions

Billing Item
Firm or Non-Firm Point-to-Point Transmission Service
Spot Import Service
Day-ahead Spot Market Energy
Balancing Spot Market Energy
Day-ahead Transmission Congestion
Balancing Transmission Congestion
Day-ahead Transmission Losses
Balancing Transmission Losses
PJM Scheduling, System Control and Dispatch Service - Control Area AdministrationPJM Scheduling, System Control and Dispatch Service - Market Support
PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center
PJM Scheduling, System Control and Dispatch Service - Market Support Offset
PJM Settlement, Inc.
Market Monitoring Unit (MMU) Funding
FERC Annual Recovery
Organization of PJM States, Inc. (OPSI) Funding
Synchronous Condensing
Transmission Owner Scheduling, System Control and Dispatch Service
Reactive Supply and Voltage Control from Generation and Other Sources Service
Day-ahead Operating Reserve
Balancing Operating Reserve
Black Start Service
Marginal Loss Surplus Allocation (for those paying for transmission service only)1
No charge if Point of Delivery is MISO
2
No charge for spot in transmission© 2021 Monitoring Analytics, LLC

Real-Time Transactions
Import(Firm or
ImportNon Firm) (Spot in)
Export
X
X1
X2

Wheel
X1

X

X

X

X

X

X

X

X
X
X
X
X
X
X
X
X

X

X
X
X
X
X
X
X
X
X
X
X
X

X
X

X
X
X
X
X

X
X
X
X

X

X
X
X

X

X
X
X
X

X

Day-Ahead Transactions
Import(Firm or
ImportNon Firm) (Spot in)
Export
Wheel
X
X1
X1
X2
X
X
X
X

X

X

X

X

X

X

X

X
X
X
X
X
X
X
X
X
X
X
X

X

X
X
X
X
X
X
X
X
X
X
X
X

X
X
X
X
X

X

X
X

X

Up to
Congestion

X
X
X
X
X
X
X
X
X

X
X
X
X
X
X
X

2021 Quarterly State of the Market Report for PJM: January through June 425

2021 Quarterly State of the Market Report for PJM: January through June

Aggregate Imports and Exports
Table 9-2 shows the real-time and day-ahead scheduled interchange totals forthe first six months of 2020 and 2021. In the first six months of 2021, grossimports in the day-ahead energy market were 121.2 percent of gross imports
in the real-time energy market (616.2 percent in the first six months of 2020).
The large decrease in day-ahead gross imports in the first six months of 2021
was the result of decreases in up to congestion transactions associated with
the new requirement for these transactions to pay uplift charges. In the firstsix months of 2021, gross exports in the day-ahead energy market were 76.3
percent of gross exports in the real-time energy market (120.3 percent in thefirst six months of 2020).

Transactions in the day-ahead energy market create financial obligations todeliver in the real-time energy market and to pay operating reserve charges
based on differences between the transaction MWh in the day-ahead andreal-time energy markets times the applicable operating reserve rates. Up tocongestion transactions also create financial obligations to deliver in realtime, but did not pay operating reserve charges until November 1, 2020. In
2020, the total day-ahead gross imports and exports were higher than the realtime gross imports and exports, the day-ahead imports net of up to congestiontransactions were less than the real-time imports, and the day-ahead exports
net of up to congestion transactions were less than real-time exports.
Figure 9-1 Scheduled imports and exports: January through June, 2021

Table 9-2 Real-time and day-ahead scheduled interchange volumes (GWh):
January through June, 2020 and 2021
Jan-Jun 2020
3,564.7
22,220.0(18,655.2)
21,966.7
26,726.9(4,760.2)
3,703.3
594.1
4,454.5
3,661.1

Jan-Jun 2021
3,721.5
21,722.8(18,001.2)
4,510.3
16,574.1(12,063.7)
3,620.5
620.3
2,762.3
751.7

Percent Change
4.4%(2.2%)(3.5%)(79.5%)(38.0%)
153.4%(2.2%)
4.4%(38.0%)(79.5%)

Export Volume
Import Volume
Net Interchange Volume

Volume (GWh)

Category
Real-Time Gross Imports
Real-Time Gross Exports
Real-Time Net Interchange
Day-Ahead Gross Imports
Day-Ahead Gross Exports
Day-Ahead Net InterchangeMonthly Average Real-Time Gross Exports
Monthly Average Real-Time Gross Imports
Monthly Average Day-Ahead Gross Exports
Monthly Average Day-Ahead Gross Imports

Real-Time

10,0005,000

0-5,000

Jan

Feb

Mar

Apr

Day-Ahead

10,000May

Jun

Export Volume
Import Volume

Figure 9-1 shows real-time and day-ahead import, export and net interchange
volumes. The day-ahead totals include fixed, dispatchable and up to congestiontransaction totals. The net interchange of up to congestion transactions are
represented by the orange line.

Volume (GWh)

Net Interchange Volume

In the first six months of 2021, PJM was a monthly net exporter of energy
in the real-time energy market in all months. In the first six months of 2021,
PJM was a monthly net exporter of energy in the day-ahead energy market in
all months (Figure 9-1).7

Up to Congestion Net

5,000

0

-5,000

Jan

Feb

Mar

Apr

May

Jun

7 Calculated values shown in Section 9, “Interchange Transactions,” are based on unrounded, underlying data and may differ from
calculations based on the rounded values in the tables.

426

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactionsof up to congestion transactions decreased. In February 2021, winter storms
caused significant generation outages in Texas and resulted in power outages
across the Electric Reliability Council of Texas (ERCOT) region. These outages
occurred between February 10, 2021, and February 27, 2021. During this time,
ERCOT imported generation from neighboring regions. While PJM did nothave any scheduled exports directly to the ERCOT region, PJM exports during
this time increased from an average hourly export of 4,772 MW per hour
between February 1 and February 10, 2021, to 7,003 MW per hour between
February 10 and February 27, 2021.

2015

2016

2017

2018

2019

2020

2021

2016

2017

2018

2019

2020

2021

2016

2017

2018

2019

2020

2021

2014

2015
2015

2013

2014
2014

2012

2013

2011

2010

2009

2007

2013

20,00015,00010,0005,000
0-5,000

2006

2005

2003

2002

2001

2000

1999

2004

Day-Ahead: Fixed and Dispatchable

Gross Exports

20,00015,00010,0005,000
0-5,0002008

Real-Time

Gross Exports
Gross Imports
Net Interchange

Gross Imports

2012

2011

2010

2009

2008

2007

2006

2005

2012

2011

2010

2009

2008

2007

Day-Ahead: Up to Congestion

2006

2004

2003

2002

2001

2000

Gross Exports - UTC
Gross Imports - UTC
Net Interchange - UTC

2005

2004

2003

2002

2001

2000

1999

Net Interchange

1999

20,00015,00010,0005,000
0-5,000Volume (GWh)

Volume (GWh)

Figure 9-2 Scheduled import and export transaction volume history:
January 1, 1999 through June 30, 2021

Volume (GWh)

Figure 9-2 shows the real-time and day-ahead import and export volume for
PJM from January 1999 through June 2021. PJM shifted from a consistent net
importer of energy to relatively consistent net exporter of energy in 2004 in both
the real-time and day-ahead energy markets, coincident with the expansionof the PJM footprint that included the integrations of Commonwealth Edison,
American Electric Power and Dayton Power and Light into PJM. The net
direction of power flows is generally a function of price differences net oftransactions costs. Since the modification of the up to congestion product in
September 2010, up to congestion transactions have played a significant rolein power flows between PJM and external balancing authorities in the dayahead energy market. On November 1, 2012, PJM eliminated the requirementthat every up to congestion transaction include an interface pricing point as
either the source or sink. As a result, the volume of import and export up tocongestion transactions decreased, and the volume of internal up to congestiontransactions increased. While the gross import and export volumes in the dayahead energy market decreased, PJM has remained primarily a net exporter inthe day-ahead energy market. The requirement for external capacity resources
to be pseudo tied into PJM has affected the real-time and day-ahead import
volumes. Prior to June 1, 2016, these units were dynamically scheduled into
PJM or were block scheduled into PJM and were part of scheduled interchange
as imports. Pseudo tied units are treated as internal generation and therefore
do not affect interchange volume. The reduction of the import volume basedon the switch to pseudo tie status contributed to PJM remaining a net exporterin the real-time and day-ahead energy markets. On February 20, 2018, FERC
issued an order limiting the eligible bidding points for up to congestiontransactions to hubs, residual metered load and interfaces.8 As a result,the volume of import and export up to congestion transactions increased,
contributing to PJM becoming a net importer in the day-ahead energy market
starting in March 2018. On July 16, 2020, FERC issued an order directing
PJM to revise uplift allocation rules to allocate uplift to up to congestiontransactions.9 The Order requires PJM to treat an up to congestion transaction,
for uplift allocation purposes, as if the up to congestion transaction wereequivalent to a DEC at its sink point. On November 1, 2020, PJM began
allocating uplift to up to congestion transactions. As a result, the volume
8 162 FERC ¶ 61,139.
9 172 FERC ¶ 61,046.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 427

2021 Quarterly State of the Market Report for PJM: January through June

Real-Time Interface Imports and Exports
In the real-time energy market, scheduled imports and exports are defined by
the scheduled path, which is the transmission path a market participant selectsfrom the original source to the final sink. These scheduled flows are measured
at each of PJM’s interfaces with neighboring balancing authorities. Table 9-19
includes a list of active interfaces in the first six months of 2021. Figure 9-3
shows the approximate geographic location of the interfaces. In the first six
months of 2021, PJM had 19 interfaces with neighboring balancing authorities.
While the Linden (LIND) Interface, the Hudson (HUDS) Interface and the
Neptune (NEPT) Interface are separate from the NYIS Interface, all four areinterfaces between PJM and the NYISO. There are 10 separate interfaces thatmake up the MISO Interface between PJM and MISO. Table 9-3 through Table
9-5 show the real-time energy market scheduled interchange totals at theindividual NYISO interfaces, as well as with the NYISO as a whole. Similarly,
the scheduled interchange totals at the individual interfaces between PJM andMISO are shown, as well as with MISO as a whole. Net scheduled interchange
in the real-time energy market is shown by interface for the first six monthsof 2021 in Table 9-3, while gross scheduled imports and exports are shown in
Table 9-4 and Table 9-5.
In the real-time energy market, in the first six months of 2021, there were netscheduled exports at 15 of PJM’s 19 interfaces. The top three net exportinginterfaces in the real-time energy market accounted for 52.2 percent of thetotal net scheduled exports: PJM/Cinergy (CIN) with 25.2 percent, PJM/
MidAmerican Energy Company (MEC) with 15.2 percent and PJM/NYIS with
11.8 percent of the net scheduled export volume. The four separate interfacesthat connect PJM to the NYISO (PJM/NYIS, PJM/NEPT, PJM/HUDS andPJM/Linden (LIND)) together represented 30.6 percent of the total net PJM
scheduled exports in the real-time energy market. There were net scheduledexports in the real-time energy market at nine of the 10 separate interfacesthat connect PJM to MISO. Those nine exporting interfaces represented 67.4
percent of the total net PJM scheduled exports in the real-time energy market.
In the real-time energy market, in the first six months of 2021, there were netscheduled imports at three of PJM’s 19 interfaces. The top importing interface
428

Section 9 Interchange Transactionsin the real-time energy market was the PJM/Duke Energy Corp. (DUK) interface,which accounted for 88.3 percent of the total net scheduled import volume.10
The four separate interfaces that connect PJM to the NYISO (PJM/NYIS, PJM/
NEPT, PJM/HUDS and PJM/Linden (LIND)) had net scheduled exports in thereal-time energy market. There were net scheduled imports in the real-timeenergy market at none of the 10 separate interfaces that connect PJM to MISO.
Table 9-3 Real-time scheduled net interchange volume by interface (GWh):
January through June, 2021
CPLE
CPLW
DUK
LGEE
MISO
ALTE
ALTW
AMIL
CIN
CWLP
IPL
MEC
MECS
NIPS
WEC
NYISO
HUDS
LIND
NEPT
NYIS
TVA
Total

Jan
(71.6)
0.3
180.3(70.3)(1,366.6)(45.6)(18.8)(28.4)(419.0)0.0(22.3)(462.2)17.7(334.6)(53.5)(1,043.4)(212.7)(226.3)(5.3)(599.2)89.0(2,282.4)

Feb
7.3
0.0
126.0
(2.9)
(2,572.4)(493.6)(40.5)(86.5)(1,123.5)
0.0(166.0)(445.3)(126.8)(4.8)(85.4)(1,602.5)(354.6)(211.2)(243.3)(793.4)(102.1)(4,146.5)

Mar
11.8
0.8
39.5
(75.6)(2,031.4)(222.7)(22.9)(43.2)(842.1)0.0(101.3)(367.0)(396.3)0.0(35.9)(763.5)(150.3)(191.8)(275.1)(146.3)6.9(2,811.5)

Apr(41.0)
1.0
164.9(55.9)(2,136.6)(243.6)(45.7)(24.6)(848.8)0.0(98.8)(440.8)(399.3)0.0(35.0)(454.4)(57.7)(108.5)(269.5)(18.7)
72.5(2,449.7)

May
125.1
0.0
(21.4)(30.9)(1,758.3)(84.9)(14.4)(28.7)(378.3)0.0(86.5)(456.4)(335.7)(340.2)(33.2)(566.1)(55.2)(163.9)(237.3)(109.7)(21.1)(2,272.7)

Jun
33.1
0.0
13.7
(63.9)(2,651.7)(335.5)(37.6)(36.5)(1,068.0)
0.0(130.6)(648.2)(340.6)
0.0(54.6)(1,260.0)(264.1)(202.3)(269.7)(523.8)(109.7)(4,038.4)

Total
64.7
2.0
502.9
(299.6)(12,517.0)(1,425.9)(180.0)(248.0)(4,679.6)
0.0(605.5)(2,819.9)(1,580.9)(679.5)(297.6)(5,689.9)(1,094.6)(1,104.0)(1,300.2)(2,191.1)(64.4)(18,001.2)

10 In the real-time energy market, one PJM interface had a net interchange of zero (PJM/City Water Light & Power (CWLP)). CWLP is abalancing authority on the western side of MISO.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-4 Real-time scheduled gross import volume by interface (GWh):
January through June, 2021
CPLE
CPLW
DUK
LGEE
MISO
ALTE
ALTW
AMIL
CIN
CWLP
IPL
MEC
MECS
NIPS
WEC
NYISO
HUDS
LIND
NEPT
NYIS
TVA
Total

Jan
9.3
0.3
237.0
7.6
354.2
135.5
0.0
2.2
63.7
0.0
9.3
19.5
123.9
0.0
0.1
123.7
0.0
0.1
0.0
123.6
138.7
870.8

Feb
112.1
0.0
221.9
84.9
304.5
70.4
3.8
13.8
44.1
0.0
19.2
0.0
153.2
0.1
0.0
142.3
0.0
0.0
0.1
142.2
55.4
921.1

Mar
101.8
0.8
98.3
0.9
142.4
44.2
0.0
0.0
31.7
0.0
0.5
18.9
47.2
0.0
0.0
138.7
0.0
0.5
0.0
138.3
33.5
516.4

Apr
41.7
1.0
188.0
13.8
94.1
33.2
0.0
4.4
32.7
0.0
1.8
17.6
1.8
0.0
2.6
117.9
0.0
2.8
0.0
115.1
115.2
571.6

May
174.2
0.0
51.1
13.9
127.3
32.2
0.1
7.4
40.1
0.0
6.9
24.2
9.9
0.0
6.6
116.8
0.0
0.4
0.0
116.4
18.9
502.3

Jun
85.8
0.0
59.3
6.4
51.3
22.0
0.0
3.4
2.7
0.0
0.6
12.4
8.4
0.0
1.9
100.8
0.7
0.5
0.1
99.6
35.7
339.3

Total
524.9
2.0
855.6
127.5
1,073.8
337.4
3.8
31.2
214.9
0.0
38.3
92.7
344.4
0.1
11.2
740.3
0.8
4.2
0.2
735.2
397.4
3,721.5

Table 9-5 Real-time scheduled gross export volume by interface (GWh):
January through June, 2021
CPLE
CPLW
DUK
LGEE
MISO
ALTE
ALTW
AMIL
CIN
CWLP
IPL
MEC
MECS
NIPS
WEC
NYISO
HUDS
LIND
NEPT
NYIS
TVA
Total

Jan
80.9
0.0
56.7
77.9
1,720.8
181.1
18.8
30.6
482.6
0.0
31.7
481.7
106.2
334.6
53.6
1,167.2
212.7
226.4
5.3
722.8
49.7
3,153.2

Feb
104.8
0.0
95.8
87.8
2,876.9
564.0
44.2
100.3
1,167.6
0.0
185.2
445.3
280.0
4.8
85.4
1,744.8
354.6
211.2
243.4
935.6
157.4
5,067.6

Mar
90.1
0.0
58.8
76.5
2,173.8
266.9
22.9
43.2
873.7
0.0
101.8
385.9
443.4
0.0
35.9
902.2
150.3
192.3
275.1
284.5
26.6
3,327.9

Apr
82.7
0.0
23.1
69.7
2,230.7
276.8
45.7
29.0
881.5
0.0
100.6
458.4
401.1
0.0
37.6
572.3
57.8
111.3
269.5
133.8
42.7
3,021.3

May
49.1
0.0
72.6
44.8
1,885.6
117.1
14.4
36.1
418.4
0.0
93.4
480.7
345.6
340.2
39.8
683.0
55.2
164.3
237.3
226.1
40.0
2,775.0

Jun
52.7
0.0
45.6
70.3
2,702.9
357.5
37.6
39.9
1,070.7
0.0
131.1
660.6
349.0
0.0
56.5
1,360.8
264.8
202.8
269.7
623.4
145.4
4,377.7

Total
460.2
0.0
352.7
427.1
13,590.8
1,763.3
183.8
279.1
4,894.5
0.0
643.8
2,912.6
1,925.3
679.6
308.8
6,430.2
1,095.4
1,108.2
1,300.4
2,926.3
461.8
21,722.8

Real-Time Interface Pricing Point Imports and Exports
Interfaces differ from interface pricing points. An interface is a point ofinterconnection between PJM and a neighboring balancing authority whichmarket participants may designate as a path on which scheduled imports
or exports will flow.11 An interface pricing point defines the price at whichtransactions are priced, and is based on the path of the actual, physicaltransfer of energy. While a market participant designates a scheduled pathfrom a generation control area (GCA) to a load control area (LCA), this pathreflects the scheduled path as defined by the transmission reservations only,
and may not reflect how the energy actually flows from the GCA to LCA.
For example, the import transmission path from LG&E Energy, L.L.C. (LGEE),
through MISO and into PJM would show the transfer of power into PJM at the
11 There are multiple paths between any generation and load balancing authority. Market participants select the path based on transmission
service availability and the transmission costs for moving energy from generation to load and interface prices.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 429

2021 Quarterly State of the Market Report for PJM: January through June

PJM/MISO Interface based on the scheduled path of the transaction. However,the physical flow of energy does not enter the PJM footprint at the PJM/MISO
Interface, but enters PJM at the southern boundary. For this reason, PJM
prices an import with the GCA of LGEE at the SOUTH interface pricing point
rather than the MISO pricing point.
Interfaces differ from interface pricing points. The challenge is to create
interface prices, composed of external pricing points, which accurately
represent the locational price impact of flows between PJM and externalsources of energy and that reflect the underlying economic fundamentals
across balancing authority borders.12
Transactions can be scheduled to an interface based on a contract transmission
path, but pricing points are developed and applied based on the estimatedelectrical impact of the external power source on PJM tie lines, regardlessof the contract transmission path.13 PJM establishes prices for transactions
with external balancing authorities by assigning interface pricing points toindividual balancing authorities based on the generation control area andload control area as specified on the NERC Tag. Dynamic interface pricing
calculations use actual system conditions to determine a set of weights foreach external pricing point in an interface price definition. The weights aredesigned so that the interface price reflects actual system conditions. However,
the weights are an approximation given the complexity of the transmission
network outside PJM and the dynamic nature of power flows. Table 9-20
presents the interface pricing points used in the first six months of 2021. On
October 21, 2020, PJM updated the mappings of external balancing authorities
to individual pricing points. Figure 9-4 shows a map of the default interface
pricing point assignments for all external balancing authorities. Figure 9-4
shows that the balancing authorities in the Western Interconnection are
mapped to either the MISO interface pricing point or the SOUTH interface
pricing point. This determination was made by PJM based on geographic
location rather than the electrical impact on the PJM system. When poweris scheduled across a DC tie line, its effects on the PJM system are as if agenerator is located at the point in the Eastern Interconnection where the DC
tie line connects. The electrical impact on PJM tie lines from sources in theWestern Interconnection differ based on the relevant DC tie line and could
vary from the MISO interface pricing point to the SOUTH interface pricing
point. The MMU recommends that transactions sourcing in the WesternInterconnection be priced at either the MISO interface pricing point or the
SOUTH interface pricing point based on the locational price impact of flows
between the DC tie line point of connection with the Eastern Interconnection
and PJM rather than geographical location. The MMU recommends that PJM
review the mappings of external balancing authority pricing points at least
annually to reflect the fact that changes to the system topology can affect theelectrical impact of external power sources on PJM.
The MMU has made multiple recommendations to either retire or consolidate
interface pricing points used by PJM. The reasons for those recommendations
include: pricing points that could no longer be used to price actual
transactions; pricing points that were inappropriately used to support special
agreements; pricing points that were treated as multiple pricing points when
they were a single pricing point; and pricing points that were noncontiguous
to the PJM footprint that created opportunities for sham scheduling. Table
9-6 shows the interface pricing points, the recommendation and the date therecommendation was adopted.

12 See the 2007 State of the Market Report for PJM, Volume II, Appendix D, “Interchange Transactions,” for a more complete discussion of
the development of pricing points.
13 See “Interface Pricing Point Assignment Methodology,” (June 1, 2021) <http://www.pjm.com/‌~/media/etools/exschedule/interfacepricing-point-assignment-methodology.ashx>. PJM periodically updates these definitions on its website.

430

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-6 Interface pricing point recommendations and dates adopted14
Interface Pricing Point
Southeast (Real-Time Market)
IMO
SOUTHEXP
SOUTHIMPSoutheast
Southwest
NCMPAEXPNCMPAIMP
Northwest
CPLEEXPCPLEIMPDUKEXPDUKIMP
NIPSCOOVEC

Recommendation
Retire Pricing Point - Support Special Agreements
Retire Pricing Point - Noncontiguous
Consolidate Pricing Points
Consolidate Pricing Points
Retire Pricing Point - Support Special Agreements
Retire Pricing Point - Support Special Agreements
Retire Pricing Point - Preferential Treatment
Retire Pricing Point - Preferential Treatment
Retire Pricing Point - Noncontiguous
Retire Pricing Point - Preferential Treatment
Retire Pricing Point - Preferential Treatment
Retire Pricing Point - Preferential Treatment
Retire Pricing Point - Preferential Treatment
Retire Pricing Point - Obsolete (Integration into MISO)
Retire Pricing Point - Obsolete (Integration into PJM)

Date Adopted

6/1/2021
6/1/2021
4/15/2021
4/15/2021
11/3/2020
11/3/2020
10/1/2020
6/1/2020
6/1/2020
6/1/2020
6/1/2020
6/1/2020
12/1/2018

The interface pricing method implies that the weighting factors reflect theactual system flows in a dynamic manner. In fact, the weightings are static,
and are modified by PJM only occasionally.15 The MMU recommends that PJM
monitor, and adjust as necessary, the weights applied to the components of
the interfaces to ensure that the interface prices reflect ongoing changes insystem conditions.
The contract transmission path only reflects the path of energy into or out
of PJM to one neighboring balancing authority. The NERC Tag requires thecomplete path to be specified from the generation control area (GCA) to theload control area (LCA), but participants do not always do so. The NERC Tag
path is used by PJM to determine the interface pricing point that PJM assigns
to the transaction. This approach will correctly identify the interface pricing
point only if the market participant provides the complete path in the Tag.
In the real-time energy market, in the first six months of 2021, there were netscheduled exports at seven of PJM’s nine interface pricing points eligible forreal-time transactions.16 The top three net exporting interface pricing points
14 The Southeast interface pricing point was retired from the Day-Ahead Market only. This pricing point can still be assigned to transactions
under the VACAR reserve sharing agreement.
15 On June 1, 2015, PJM began using a dynamic weighting factor in the calculation for the Ontario interface pricing point.
16 On June 1, 2021, PJM consolidated the SouthIMP and SouthEXP interface pricing points to one new South interface pricing point. This
reduces the number of real-time and day-ahead interface pricing points to eight.

© 2021 Monitoring Analytics, LLC

in the real-time energy market accounted for 81.8 percent of the total net
scheduled exports: PJM/MISO with 62.6 percent, PJM/NYIS with 10.9 percent
and PJM/SouthEXP with 8.3 percent of the net scheduled export volume.
The four separate interface pricing points that connect PJM to the NYISO(PJM/NYIS, PJM/NEPTUNE, PJM/HUDSONTP and PJM/LINDENVFT) together
represented 28.3 percent of the total net PJM scheduled exports in the realtime energy market.
In the real-time energy market, in the first six months of 2021, there were netscheduled imports at two of PJM’s nine interface pricing points eligible forreal-time transactions. The top importing interface pricing point in the realtime energy market was the PJM/SouthIMP interface pricing point, which
accounted for 80.7 percent of the total net scheduled import volume. The four
separate interface pricing points that connect PJM to the NYISO (PJM/NYIS,PJM/NEPTUNE, PJM/HUDSONTP and PJM/LINDENVFT) had net scheduledexports in the real-time energy market.17
Table 9-7 Real-time scheduled net interchange volume by interface pricing
point (GWh): January through June, 2021
IMO
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total

Jan
152.7
(1,514.5)(1,043.6)(212.7)(226.3)(5.3)(599.4)
395.2
0.0
395.2
(272.1)0.0(272.1)

Feb
219.7(2,527.6)(1,619.0)(354.6)(211.2)(243.3)(809.9)
488.0
0.0
488.0
(707.5)0.0(707.5)

Mar
46.9(2,077.8)(763.5)(150.3)(191.8)(275.1)(146.3)
237.7
0.0
237.7
(254.8)0.0(254.8)Apr
1.4(2,144.9)(454.4)(57.7)(108.5)(269.5)(18.7)
370.3
0.0
370.3
(222.2)0.0(222.2)May
13.4(1,781.6)(566.1)(55.2)(163.9)(237.3)(109.7)
278.0
0.0
278.0
(216.3)0.0(216.3)(2,282.4)(4,146.5)(2,811.5)(2,449.7)(2,272.7)

Jun(11.6)(2,597.0)(1,259.7)(264.1)(202.3)(269.7)(523.6)
0.0
0.0
0.0
0.0
(170.1)(4,038.4)

Total
422.3
(12,643.3)(5,706.4)(1,094.6)(1,104.0)(1,300.2)(2,207.5)
1,769.2
0.0
1,769.2(1,673.0)
0.0(1,673.0)(170.1)(18,001.2)

17 In the real-time energy market, one PJM interface pricing points had a net interchange of zero (Southeast).

2021 Quarterly State of the Market Report for PJM: January through June 431

2021 Quarterly State of the Market Report for PJM: January through June

Table 9-8 Real-time scheduled gross import volume by interface pricing point(GWh): January through June, 2021
IMO
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total

Jan
152.7
199.4
123.5
0.0
0.1
0.0
123.4
395.2
0.0
395.2
0.0
0.0
0.0

Feb
219.7
87.6
125.8
0.0
0.0
0.1
125.7
488.0
0.0
488.0
0.0
0.0
0.0

Mar
47.0
93.0
138.7
0.0
0.5
0.0
138.3
237.7
0.0
237.7
0.0
0.0
0.0

Apr
1.4
82.0
117.9
0.0
2.8
0.0
115.1
370.3
0.0
370.3
0.0
0.0
0.0

May
13.4
94.1
116.8
0.0
0.4
0.0
116.4
278.0
0.0
278.0
0.0
0.0
0.0

870.8

921.1

516.4

571.6

502.3

Jun
11.0
34.8
100.3
0.7
0.5
0.1
99.1
0.0
0.0
0.0
0.0
193.2
339.3

Total
445.0
590.9
723.1
0.8
4.2
0.2
718.0
1,769.2
0.0
1,769.2
0.0
0.0
0.0
193.2
3,721.5

Table 9-9 Real-time scheduled gross export volume by interface pricing point(GWh): January through June, 2021
IMO
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total

Jan
0.0
1,713.9
1,167.2
212.7
226.4
5.3
722.8
0.0
0.0
0.0
272.1
0.0
272.1

Feb
0.0
2,615.2
1,744.8
354.6
211.2
243.4
935.6
0.0
0.0
0.0
707.5
0.0
707.5

Mar
0.1
2,170.8
902.2
150.3
192.3
275.1
284.5
0.0
0.0
0.0
254.8
0.0
254.8

Apr
0.0
2,226.8
572.3
57.8
111.3
269.5
133.8
0.0
0.0
0.0
222.2
0.0
222.2

May
0.0
1,875.7
683.0
55.2
164.3
237.3
226.1
0.0
0.0
0.0
216.3
0.0
216.3

3,153.2

5,067.6

3,327.9

3,021.3

2,775.0

Jun
22.6
2,631.7
1,360.0
264.8
202.8
269.7
622.7
0.0
0.0
0.0
0.0
363.3
4,377.7

Total
22.7
13,234.3
6,429.5
1,095.4
1,108.2
1,300.4
2,925.5
0.0
0.0
0.0
1,673.0
0.0
1,673.0
363.3
21,722.8

Day-Ahead Interface Imports and Exports
In the day-ahead energy market, as in the real-time energy market, scheduled
imports and exports are determined by the scheduled path, which is thetransmission path a market participant selects from the original source to432

Section 9 Interchange Transactions

the final sink. Entering external energy transactions in the day-ahead energy
market requires fewer steps than in the real-time energy market. Market
participants need to acquire a valid, willing to pay congestion (WPC) OASIS
reservation to prove that their day-ahead schedule could be supported in thereal-time energy market.18 Day-ahead energy market schedules need to becleared through the day-ahead energy market process in order to become an
approved schedule. The day-ahead energy market transactions are financiallybinding, but will not physically flow unless they are also submitted in the realtime energy market. In the day-ahead energy market, a market participant is
not required to acquire a ramp reservation, a NERC Tag, or to go through aneighboring balancing authority checkout process.
There are three types of day-ahead external energy transactions: fixed; up tocongestion; and dispatchable.19
In the day-ahead energy market, transaction sources and sinks are determinedsolely by market participants. In Table 9-10, Table 9-11, and Table 9-12, thescheduled interface designation is determined by the transmission reservationthat was acquired and associated with the day-ahead market transaction, anddoes not bear any necessary relationship to the pricing point designation
selected at the time the transaction is submitted to PJM in real time. For
example, if market participants want to import energy from the Southwest
Power Pool (SPP) to PJM, they are likely to choose a scheduled path withthe fewest transmission providers along the path and therefore the lowest
transmission costs for the transaction, regardless of whether the resultant path
is related to the physical flow of power. The lowest cost transmission path runs
from SPP, through MISO, and into PJM, requiring only three transmission
reservations, two of which are available at no cost (MISO transmission would
be free based on the regional through and out rates, and the PJM transmission
would be free, if using spot import transmission). Any other transmission pathentering PJM, where the generating control area is to the south, would require
the market participant to acquire transmission through nonmarket balancing
authorities, and thus incur additional transmission costs. PJM’s interface
pricing method recognizes that transactions sourcing in SPP and sinking in
18 Effective September 17, 2010, up to congestion transactions no longer required a willing to pay congestion transmission reservation.
19 See the 2010 State of the Market Report for PJM, Volume II, Section 4, “Interchange Transactions,” for details.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

PJM will create flows across the southern border and prices those transactions
at the SOUTH interface price. As a result, a market participant who plans tosubmit a transaction from SPP to PJM may have a transmission reservation
with a point of receipt of MISO and a point of delivery of PJM but may
select SOUTH as the import pricing point when submitting the transaction in
the day-ahead energy market. In the scheduled interface tables, the importtransaction would appear as scheduled through the MISO Interface, and in thescheduled interface pricing point tables, the import transaction would appear
as scheduled through the SOUTH interface pricing point, which reflects the
expected power flow.
Table 9-10 through Table 9-12 show the day-ahead scheduled interchange
totals at the individual interfaces. Net scheduled interchange in the day-aheadenergy market is shown by interface for the first six months of 2021 in Table
9-10, while gross scheduled imports and exports are shown in Table 9-11 andTable 9-12.
In the day-ahead energy market, in the first six months of 2021, there were
net scheduled exports at 13 of PJM’s 19 interfaces. The top three net exportinginterfaces in the day-ahead energy market accounted for 59.3 percent of thetotal net scheduled exports: PJM/ MidAmerican Energy Company (MEC) with
22.4 percent, PJM/NYIS with 20.3 percent and PJM/Cinergy (CIN) with 16.6
percent of the net scheduled export volume. The four separate interfacesthat connect PJM to the NYISO (PJM/NYIS, PJM/NEPT, PJM/HUDS andPJM/Linden (LIND)) together represented 35.9 percent of the total net PJM
scheduled exports in the day-ahead energy market. In the first six monthsof 2021, there were net exports in the day-ahead energy market at seven of
the 10 separate interfaces that connect PJM to MISO. Those seven interfaces
represented 58.3 percent of the total net PJM exports in the day-ahead energy
market.
In the day-ahead energy market, in the first six months of 2021, there were
net scheduled imports at two of PJM’s 19 interfaces. The top importinginterface in the day-ahead energy market was the PJM/Duke Energy Corp.
(DUK) interface, which accounted for 99.5 percent of the net scheduled import© 2021 Monitoring Analytics, LLC

volume. The four separate interfaces that connect PJM to the NYISO (PJM/
NYIS, PJM/NEPT, PJM/HUDS and PJM/Linden (LIND)) had net scheduledexports in the day-ahead energy market. In the first six months of 2021, there
were no net imports in the day-ahead energy market at any of the 10 separate
interfaces that connect PJM to MISO.20
Table 9-10 Day-ahead scheduled net interchange volume by interface (GWh):
January through June, 2021
CPLE
CPLW
DUK
LGEE
MISO
ALTE
ALTW
AMIL
CIN
CWLP
IPL
MEC
MECS
NIPS
WEC
NYISO
HUDS
LIND
NEPT
NYIS
TVA
Total without Up To Congestion
Up To Congestion
Total

Jan
(61.9)
0.0
47.6(74.7)(1,016.7)(69.6)(17.4)
0.0(103.1)0.0
0.0(481.6)39.2(334.4)(49.9)(754.4)(79.7)
0.0(10.7)(663.9)(10.9)(1,871.0)(421.3)(2,292.3)

Feb(86.3)
0.0
28.7(91.9)(1,386.7)(363.9)(25.7)
0.0(475.7)0.0
0.0(438.3)(21.4)(4.8)(56.9)(1,326.6)(210.9)0.0(249.4)(866.4)(52.6)(2,915.4)(332.8)(3,248.1)

Mar(51.5)
0.8
21.3(79.8)(1,022.2)(151.9)(10.6)
0.0(463.4)0.0
0.0(383.8)16.1
0.0(28.5)(563.5)(80.5)
0.0(285.2)(197.8)(4.9)(1,699.9)(27.7)(1,727.6)

Apr(74.5)
0.0
53.5(67.4)(1,105.8)(126.2)(42.1)
0.0(437.6)0.0
0.0(458.2)(11.5)
0.0(30.3)(369.4)0.0
0.0(285.6)(83.8)
8.2(1,555.4)
387.7(1,167.7)

May
80.0
0.0
(9.0)
(46.3)(1,130.0)(59.2)(10.2)
0.0(36.9)
0.0
0.0(480.8)(170.0)(340.2)(32.7)(413.3)(7.3)
0.0(237.9)(168.0)(8.4)(1,526.9)
260.9(1,266.0)

Jun
13.2
0.0
(0.5)
(65.6)(1,396.9)(286.7)(40.0)
0.0(492.7)0.0
0.0(473.3)(50.4)
0.0(53.8)(915.9)(158.7)0.0(276.5)(480.8)(32.8)(2,398.6)
36.6(2,362.0)

Total(181.0)0.8
141.6(425.8)(7,058.3)(1,057.4)(146.0)0.0(2,009.4)
0.0
0.0(2,716.0)(198.0)(679.4)(252.2)(4,343.0)(537.0)0.0(1,345.4)(2,460.6)(101.5)(11,967.2)(96.6)(12,063.7)

20 In the day-ahead energy market, four PJM interfaces had a net interchange of zero (PJM/Ameren Illinois (AMIL), PJM/City Water Light &Power (CWLP), PJM/Indianapolis Power & Light (IPL) and PJM/Linden (LIND)).

2021 Quarterly State of the Market Report for PJM: January through June 433

2021 Quarterly State of the Market Report for PJM: January through June

Table 9-11 Day-ahead scheduled gross import volume by interface (GWh):
January through June, 2021
CPLE
CPLW
DUK
LGEE
MISO
ALTE
ALTW
AMIL
CIN
CWLP
IPL
MEC
MECS
NIPS
WEC
NYISO
HUDS
LIND
NEPT
NYIS
TVA
Total without Up To Congestion
Up To Congestion
Total

Jan
2.4
0.0
55.8
0.0
187.8
102.1
0.0
0.0
40.4
0.0
0.0
0.0
45.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
6.0
251.9
590.6
842.5

Feb
4.6
0.0
43.8
0.0
107.6
46.0
2.6
0.0
26.0
0.0
0.0
0.0
33.0
0.0
0.0
0.4
0.0
0.0
0.0
0.4
7.0
163.3
809.5
972.7

Mar
18.4
0.8
32.7
0.0
95.5
52.2
0.0
0.0
8.6
0.0
0.0
0.0
34.7
0.0
0.0
5.4
0.0
0.0
0.0
5.4
0.0
152.7
654.2
806.9

Apr
3.2
0.0
54.8
0.0
62.2
55.8
0.0
0.0
6.0
0.0
0.0
0.0
0.4
0.0
0.0
0.7
0.0
0.0
0.0
0.7
25.6
146.5
637.6
784.2

May
121.9
0.0
5.6
0.0
19.7
14.4
0.0
0.0
4.6
0.0
0.0
0.0
0.8
0.0
0.0
3.1
0.0
0.0
0.0
3.1
0.6
150.9
488.6
639.6

Jun
59.6
0.0
10.2
0.0
23.4
21.2
0.0
0.0
1.2
0.0
0.0
0.0
1.0
0.0
0.0
0.4
0.0
0.0
0.0
0.4
1.1
94.7
369.8
464.5

Total
210.1
0.8
202.8
0.0
496.2
291.5
2.6
0.0
86.8
0.0
0.0
0.0
115.2
0.0
0.0
9.8
0.0
0.0
0.0
9.8
40.3
960.0
3,550.3
4,510.3

Table 9-12 Day-ahead scheduled gross export volume by interface (GWh):
January through June, 2021
CPLE
CPLW
DUK
LGEE
MISO
ALTE
ALTW
AMIL
CIN
CWLP
IPL
MEC
MECS
NIPS
WEC
NYISO
HUDS
LIND
NEPT
NYIS
TVA
Total without Up To Congestion
Up To Congestion
Total

Jan
64.3
0.0
8.1
74.7
1,204.5
171.6
17.4
0.0
143.4
0.0
0.0
481.6
6.2
334.4
49.9
754.4
79.7
0.0
10.7
663.9
16.9
2,123.0
1,011.9
3,134.9

Feb
90.8
0.0
15.1
91.9
1,494.2
409.8
28.3
0.0
501.7
0.0
0.0
438.3
54.4
4.8
56.9
1,326.9
210.9
0.0
249.4
866.7
59.6
3,078.6
1,142.2
4,220.9

Mar
69.9
0.0
11.4
79.8
1,117.7
204.1
10.6
0.0
472.0
0.0
0.0
383.8
18.6
0.0
28.5
568.8
80.5
0.0
285.2
203.1
4.9
1,852.6681.9
2,534.4

Apr
77.7
0.0
1.3
67.4
1,168.0
181.9
42.1
0.0
443.6
0.0
0.0
458.2
11.9
0.0
30.3
370.2
0.0
0.0
285.6
84.5
17.4
1,701.9250.0
1,951.9

May
41.9
0.0
14.6
46.3
1,149.7
73.5
10.2
0.0
41.5
0.0
0.0
480.8
170.7
340.2
32.7
416.3
7.3
0.0
237.9
171.1
9.0
1,677.8
227.7
1,905.5

Jun
46.4
0.0
10.7
65.6
1,420.3
307.9
40.0
0.0
493.9
0.0
0.0
473.3
51.4
0.0
53.8
916.3
158.7
0.0
276.5
481.1
33.9
2,493.3
333.2
2,826.5

Total
391.2
0.0
61.2
425.8
7,554.5
1,349.0148.6
0.0
2,096.2
0.0
0.0
2,716.0
313.2
679.4
252.2
4,352.8537.0
0.0
1,345.4
2,470.5
141.7
12,927.2
3,646.9
16,574.1

Day-Ahead Interface Pricing Point Imports andExports
Table 9-13 through Table 9-18 show the day-ahead scheduled interchange
totals at the interface pricing points. In the first six months of 2021, up tocongestion transactions accounted for 78.7 percent of all scheduled import
MW transactions and 22.0 percent of all scheduled export MW transactionsin the day-ahead energy market. The day-ahead net scheduled interchange
in the first six months of 2021, including up to congestion transactions, isshown by interface pricing point in Table 9-13. Scheduled up to congestiontransactions by interface pricing point in the first six months of 2021 areshown in Table 9-14. Day-ahead gross scheduled imports and exports,
including up to congestion transactions, are shown in Table 9-15 and Table

434

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

9-17, while gross scheduled import and export up to congestion transactions
are shown in Table 9-16 and Table 9-18.
PJM consolidated the Southeast and Southwest interface pricing points
to a single interface pricing point with separate import and export prices(SouthIMP and SouthEXP) on October 31, 2006. At that time, the real-time
Southeast and Southwest interface pricing points remained only to support
certain grandfathered agreements with specific generating units and to priceenergy under the reserve sharing agreement with VACAR. The reserve sharing
agreement allows for the transfer of energy during emergencies. Interchangetransactions created as part of the reserve sharing agreement are currently
settled at the Southeast interface price. PJM also kept the day-ahead Southeast
and Southwest interface pricing points to facilitate long-term day-ahead
positions that were entered prior to the consolidation.
Maintaining outdated definitions of interface pricing points is unnecessary,inconsistent with the tariff and creates artificial opportunities for gaming byvirtual transactions and FTRs. The MMU recommends that PJM end the practiceof maintaining outdated definitions of interface pricing points, eliminate theSoutheast and Southwest interface pricing points from the day-ahead andreal-time energy markets and, with VACAR, assign the transactions createdunder the reserve sharing agreement to the SOUTH interface pricing point.21
PJM should immediately eliminate interface pricing points when changes tothe market mean that the pricing points can no longer be used to price actual
transactions and do not reflect actual price formation.
In the day-ahead energy market, in the first six months of 2021, there were netscheduled exports at seven of PJM’s nine interface pricing points eligible forday-ahead transactions.22 The top three net exporting interface pricing points
in the day-ahead energy market accounted for 83.9 percent of the total net
scheduled exports: PJM/MISO with 52.2 percent, PJM/NYIS with 21.9 percent
21 The grandfathered agreements associated with the Southwest interface pricing point expired in 2012. The Southwest interface pricing
point is no longer an eligible pricing point in the day-ahead or real-time energy markets.
22 On April 15, 2021, PJM retired the Southeast interface pricing point from the Day-Ahead Market. The Southeast interface pricing
point can still be assigned to transactions under the VACAR reserve sharing agreement in the Real-Time Market. On June 1, 2021, PJM
consolidated the SouthIMP and SouthEXP interface pricing points to one new SOUTH interface pricing point. This reduces the number of
day-ahead interface pricing points to seven.

© 2021 Monitoring Analytics, LLC

and PJM/NEPTUNE with 9.8 percent of the net scheduled export volume.
The four separate interface pricing points that connect PJM to the NYISO(PJM/NYIS, PJM/NEPTUNE, PJM/HUDSONTP and PJM/LINDENVFT) together
represented 39.3 percent of the total net PJM scheduled exports in the dayahead energy market. However, the PJM/LINDENVFT interface pricing point
had net scheduled imports in the day-ahead energy market.
In the day-ahead energy market, in the first six months of 2021, there were
net scheduled imports at three of PJM’s nine interface pricing points eligiblefor day-ahead transactions. The top importing interface pricing point in the
day-ahead energy market was the PJM/SouthIMP interface pricing point,
which accounted for 89.1 percent of the total net scheduled import volume.
The four separate interface pricing points that connect PJM to the NYISO(PJM/NYIS, PJM/NEPTUNE, PJM/HUDSONTP and PJM/LINDENVFT) together
represented 3.2 percent of the total net PJM scheduled imports in the dayahead energy market. However, the PJM/NYIS, PJM/NEPTUNE and PJM/
HUDSONTP interface pricing points had net scheduled exports in the dayahead energy market.
In the day-ahead energy market, in the first six months of 2021, up tocongestion transactions had net scheduled exports at five of PJM’s nineinterface pricing points eligible for day-ahead transactions.23 The top three net
exporting interface pricing points eligible for up to congestion transactions
accounted for 98.2 percent of the total net up to congestion scheduled exports:
PJM/HUDSONTP with 41.1 percent, PJM/NYIS with 40.2 percent and PJM/
SouthEXP with 17.0 percent of the net up to congestion scheduled export
volume. The four separate interface pricing points that connect PJM to the
NYISO (PJM/NYIS, PJM/NEPTUNE, PJM/HUDSONTP and PJM/LINDENVFT)
together represented 81.7 percent of the total net scheduled up to congestion
exports in the day-ahead energy market. However, the PJM/LINDENVFT
interface pricing points had net up to congestion scheduled imports in the
day-ahead energy market.
23 On April 15, 2021, PJM retired the Southeast interface pricing point from the Day-Ahead Market. The Southeast interface pricing
point can still be assigned to transactions under the VACAR reserve sharing agreement in the Real-Time Market. On June 1, 2021, PJM
consolidated the SouthIMP and SouthEXP interface pricing points to one new SOUTH interface pricing point. This reduces the number of
day-ahead interface pricing points to seven.

2021 Quarterly State of the Market Report for PJM: January through June 435

2021 Quarterly State of the Market Report for PJM: January through June

In the day-ahead energy market, in the first six months of 2021, up tocongestion transactions had net scheduled imports at four of PJM’s nineinterface pricing points eligible for day-ahead transactions. The top importinginterface pricing point eligible for up to congestion transactions was the
PJM/SouthIMP interface pricing point, which accounted for 88.6 percent of
the total net up to congestion scheduled import up to congestion volume.
The four separate interface pricing points that connect PJM to the NYISO(PJM/NYIS, PJM/NEPTUNE, PJM/HUDSONTP and PJM/LINDENVFT) together
represented 4.3 percent of the total net scheduled up to congestion imports inthe day-ahead energy market. However, the PJM/HUDSONTP, PJM/NEPTUNE
and PJM/NYIS interface pricing points had net up to congestion scheduledexports in the day-ahead energy market.24
Table 9-13 Day-ahead scheduled net interchange volume by interface pricing
point (GWh): January through June, 2021
IMO
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total

Jan
55.3
(1,410.2)(990.5)(207.5)51.2(11.3)(822.9)
239.9
0.0
239.9
(186.9)0.0(186.9)Feb(17.0)(1,951.1)(1,597.1)(293.2)18.8(256.4)(1,066.4)
635.7
0.0
635.7
(318.6)(4.3)(314.3)Mar(20.3)(821.9)(812.8)(232.4)5.8(280.0)(306.2)
145.5
0.0
145.5
(218.1)(1.0)(217.1)Apr
25.0(755.7)(442.8)(64.1)(15.7)(280.0)(82.9)
225.8
0.0
225.8
(220.1)(3.8)(216.3)May
34.4(889.6)(497.4)(76.7)(12.7)(245.6)(162.4)
246.2
0.0
246.2
(159.5)0.0(159.5)(2,292.3)(3,248.1)(1,727.6)(1,167.7)(1,266.0)

Jun
52.4(1,342.9)(1,053.4)(217.1)
6.2(278.1)(564.4)(18.1)(2,362.0)

Total
129.8
(7,171.4)(5,394.0)(1,091.0)
53.6(1,351.4)(3,005.2)
1,493.1
0.0
1,493.1(1,103.2)(9.1)(1,094.1)(18.1)(12,063.7)

Table 9-14 Up to congestion scheduled net interchange volume by interface
pricing point (GWh): January through June, 2021
IMO
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total Interfaces
INTERNAL
Total

Jan
(1.3)
(336.7)(236.2)(127.8)51.2(0.6)(159.1)
175.8
0.0
175.8
(22.8)
0.0(22.8)

Feb(71.1)(521.5)(270.6)(84.7)
18.8(7.1)(197.6)
580.3
0.0
580.3
(50.0)
0.0(50.0)

Mar(54.8)
234.9(249.3)(152.0)5.8
5.3(108.4)
93.7
0.0
93.7
(52.1)
0.0(52.1)

Apr
25.0
350.1
(73.3)(64.1)(15.7)
5.6
0.8
142.2
0.0
142.2
(56.3)
0.0(56.3)

May
33.9
240.9
(84.2)(69.4)(12.7)
(7.6)
5.6
118.0
0.0
118.0
(47.8)
0.0(47.8)(421.3)
3,896.8
3,475.6(332.8)5,150.6
4,817.8(27.7)
5,248.0
5,220.3387.7
4,060.0
4,447.6

260.9
4,519.9
4,780.9

Jun
50.2
53.8
(135.1)(56.0)
6.2(1.7)(83.7)

67.7
36.6
4,488.2
4,524.8

Total(18.1)
21.4(1,048.7)(554.0)53.6(6.0)(542.3)
1,110.0
0.0
1,110.0(228.9)0.0(228.9)67.7(96.6)
27,363.4
27,266.9

Table 9-15 Day-ahead scheduled gross import volume by interface pricing
point (GWh): January through June, 2021
IMO
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total

Jan
74.2
416.1
112.3
15.8
61.1
0.0
35.4
239.9
0.0
239.9
0.0
0.0
0.0

Feb
76.0
208.0
53.0
8.5
30.1
6.2
8.1
635.7
0.0
635.7
0.0
0.0
0.0

Mar
56.2
521.5
83.7
6.0
44.2
14.5
19.0
145.5
0.0
145.5
0.0
0.0
0.0

Apr
35.8
470.7
51.8
7.6
4.5
20.0
19.6
225.8
0.0
225.8
0.0
0.0
0.0

May
43.6
293.6
56.1
11.6
10.1
9.5
24.9
246.2
0.0
246.2
0.0
0.0
0.0

842.5

972.7

806.9

784.2

639.6

Jun
65.3
198.8
58.9
6.5
24.7
16.6
11.1

141.4
464.5

Total
351.1
2,108.8
415.9
56.1
174.7
66.9
118.1
1,493.1
0.0
1,493.1
0.0
0.0
0.0
141.4
4,510.3

24 In the day-ahead energy market, one PJM interface pricing point had up to congestion net interchange of zero (Southeast).

436

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-16 Up to congestion scheduled gross import volume by interface
pricing point (GWh): January through June, 2021
IMO
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total Interfaces

Jan
17.5
285.0
112.3
15.8
61.1
0.0
35.4
175.8
0.0
175.8
0.0
0.0
0.0
0.0
590.6

Feb
20.1
156.4
52.7
8.5
30.1
6.2
7.8
580.3
0.0
580.3
0.0
0.0
0.0
0.0
809.5

Mar
21.7
460.5
78.3
6.0
44.2
14.5
13.6
93.7
0.0
93.7
0.0
0.0
0.0
0.0
654.2

Apr
35.8
408.5
51.1
7.6
4.5
20.0
18.9
142.2
0.0
142.2
0.0
0.0
0.0
0.0
637.6

May
43.1
274.4
53.1
11.6
10.1
9.5
21.8
118.0
0.0
118.0
0.0
0.0
0.0
0.0
488.6

Jun
63.1
177.6
58.6
6.5
24.7
16.6
10.8

70.5
369.8

Total
201.2
1,762.6
406.0
56.1
174.7
66.9
108.3
1,110.0
0.0
1,110.0
0.0
0.0
0.0
70.5
3,550.3

Table 9-17 Day-ahead scheduled gross export volume by interface pricing
point (GWh): January through June, 2021
IMO
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total

Jan
18.9
1,826.3
1,102.8
223.3
9.9
11.3
858.3
0.0
0.0
0.0
186.9
0.0
186.9

Feb
93.1
2,159.1
1,650.1
301.7
11.3
262.7
1,074.5
0.0
0.0
0.0
318.6
4.3
314.3

Mar
76.5
1,343.4
896.5
238.5
38.4
294.5
325.2
0.0
0.0
0.0
218.1
1.0
217.1

Apr
10.8
1,226.4
494.6
71.7
20.3
300.0
102.5
0.0
0.0
0.0
220.1
3.8
216.3

May
9.2
1,183.2
553.5
88.4
22.8
255.1
187.3
0.0
0.0
0.0
159.5
0.0
159.5

3,134.9

4,220.9

2,534.4

1,951.9

1,905.5

Jun
12.9
1,541.8
1,112.3
223.6
18.4
294.7
575.6
0.0
0.0
0.0
0.0
159.5
2,826.5

Total
221.3
9,280.2
5,809.9
1,147.1
121.1
1,418.3
3,123.4
0.0
0.0
0.0
1,103.2
9.1
1,094.1
159.5
16,574.1

Table 9-18 Up to congestion scheduled gross export volume by interface
pricing point (GWh): January through June, 2021
IMO
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total Interfaces

Jan
18.8
621.8
348.6
143.6
9.9
0.6
194.5
0.0
0.0
0.0
22.8
0.0
22.8

Feb
91.1
677.9
323.2
93.2
11.3
13.3
205.4
0.0
0.0
0.0
50.0
0.0
50.0

Mar
76.5
225.7
327.7
158.0
38.4
9.2
122.0
0.0
0.0
0.0
52.1
0.0
52.1

Apr
10.8
58.4
124.4
71.7
20.3
14.4
18.0
0.0
0.0
0.0
56.3
0.0
56.3

May
9.2
33.5
137.2
81.1
22.8
17.1
16.2
0.0
0.0
0.0
47.8
0.0
47.8

1,011.9

1,142.2

681.9

250.0

227.7

Jun
12.9
123.8
193.7
62.5
18.4
18.3
94.5

2.8
333.2

Total
219.3
1,741.2
1,454.8
610.1
121.1
73.0
650.6
0.0
0.0
0.0
228.9
0.0
228.9
2.8
3,646.9

Table 9-19 Active scheduling interfaces: January through June, 202125
ALTE
ALTW
AMIL
CIN
CPLE
CPLW
CWLP
DUK
HUDS
IPL
LGEE
LIND
MEC
MECS
NEPT
NIPS
NYIS
TVA
WEC

Jan
ActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveFeb
ActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveMar
ActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveApr
ActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveMay
ActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveJun
ActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActiveActive25 On July 2, 2012, Duke Energy Corp. (DUK) completed a merger with Progress Energy Inc. (CPLE and CPLW). As of June 30, 2021, DUK, CPLE
and CPLW continued to operate as separate balancing authorities, and are still defined as distinct interfaces in the PJM energy market.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 437

2021 Quarterly State of the Market Report for PJM: January through June

Figure 9-3 PJM’s footprint and its external scheduling interfaces

Figure 9-4 External balancing authority default interface pricing point
assignments

Table 9-20 Active scheduled interface pricing points: January throughJune, 2021
HUDSONTP
LINDENVFTMISONEPTUNE
NYIS
Ontario IESOSoutheast
SOUTHEXP
SOUTHIMP
SOUTH

438

Jan
ActiveActiveActiveActiveActiveActiveActiveActiveActiveFeb
ActiveActiveActiveActiveActiveActiveActiveActiveActiveSection 9 Interchange Transactions

Mar
ActiveActiveActiveActiveActiveActiveActiveActiveActiveApr
ActiveActiveActiveActiveActiveActiveActiveActiveActiveMay
ActiveActiveActiveActiveActiveActiveActiveActiveActiveJun
ActiveActiveActiveActiveActiveActiveActiveActiveLoop Flows
Actual energy flows are the real-time metered power flows at an interface fora defined period. The comparable scheduled flows are the real-time power
flows scheduled at an interface for a defined period. Inadvertent interchange
is the difference between the total actual flows for the PJM system (net actualinterchange) and the total scheduled flows for the PJM system (net scheduledinterchange) for a defined period. Loop flows are the difference between
actual and scheduled power flows at a specific interface. Loop flows can exist
at the same time that inadvertent interchange is zero. For example, actual
imports could exceed scheduled imports at one interface and actual exports
could exceed scheduled exports at another interface by the same amount. The© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

result is loop flow, despite the fact that system actual and scheduled power
flow net to a zero difference.26

flows across the southern interface that received the MISO interface pricing
point.

Loop flows result, in part, from a mismatch between incentives to use aparticular scheduled transmission path and the market-based price differentials
at interface pricing points that result from the actual physical flows on thetransmission system.

In the first six months of 2021, net scheduled interchange was -18,001 GWh
and net actual interchange was -18,008 GWh, a difference of 7 GWh. In
the first six months of 2020, net scheduled interchange was -18,655 GWh
and net actual interchange was -18,652 GWh, a difference of 3 GWh. Thisdifference is inadvertent interchange. PJM attempts to minimize the amountof accumulated inadvertent interchange by continually monitoring andcorrecting for inadvertent interchange. PJM can reduce the accumulation of
inadvertent interchange using unilateral or bilateral paybacks. Inadvertentinterchange accumulations that are paid back unilaterally are paid bycontrolling to a non-zero area control error (ACE). For example, Table 9-21
shows that PJM had 7 GW of inadvertent interchange in the first six monthsof 2021. To reduce this inadvertent interchange, PJM can control to an ACE
less than zero, which would result in under generating. By way of the power
balance equation, power would flow into PJM from its neighboring balancing
authority areas. This would create additional actual imports that were notscheduled, thus reducing the overall inadvertent. To maintain reliability,
unilateral paybacks are accounted for in the control performance standard
calculations. Bilateral paybacks are scheduled with other balancing authority
areas by scheduling a correction and incorporating that amount as a bias in
the energy management system.27

PJM’s approach to interface pricing attempts to match prices with physicalpower flows and their impacts on the transmission system. For example, if
market participants want to import energy from the Southwest Power Pool
(SPP) to PJM, they are likely to choose a scheduled path with the fewest
transmission providers along the path and therefore the lowest transmission
costs for the transaction, regardless of whether the resultant path is related tothe physical flow of power. The lowest cost transmission path runs from SPP,
through MISO, and into PJM, requiring only three transmission reservations,
two of which are available at no cost (MISO transmission would be free basedon the regional through and out rates, and the PJM transmission would be free,
if using spot import transmission). Any other transmission path entering PJM,
where the generating control area is to the south, would require the market
participant to acquire transmission through nonmarket balancing authorities,
and thus incur additional transmission costs. PJM’s interface pricing method
recognizes that transactions sourcing in SPP and sinking in PJM will create
flows across the southern border and prices those transactions at the SOUTH
interface price. As a result, the transaction is priced appropriately, but adifference between scheduled and actual flows is created at PJM’s borders. For
example, if a 100 MW transaction were submitted, there would be 100 MW
of scheduled flow at the PJM/MISO interface border, but there would be no
actual flows on the interface. Correspondingly, there would be no scheduledflows at the PJM/Southern interface border, but there would be 100 MW ofactual flows on the interface. In the first six months of 2021, there were netscheduled flows of -280 GWh through MISO that received an interface pricing
point associated with the southern interface but there were no net scheduled
26 See the 2012 State of the Market Report for PJM, Volume II, Section 8, “Interchange Transactions,” for a more detailed discussion.

© 2021 Monitoring Analytics, LLC

Table 9-21 shows that in the first six months of 2021, the Northern Indiana
Public Service (NIPS) Interface had the largest loop flows of any interface
with -680 GWh of net scheduled interchange and -5,910 GWh of net actualinterchange, a difference of 5,231 GWh.

27 See PJM. “Manual 12: Balancing Operations,” Rev. 42 (January 27, 2021).

2021 Quarterly State of the Market Report for PJM: January through June 439

2021 Quarterly State of the Market Report for PJM: January through June

Table 9-21 Net scheduled and actual PJM flows by interface (GWh): January
through June, 2021
CPLE
CPLW
DUK
LGEE
MISO
ALTE
ALTW
AMIL
CIN
CWLP
IPL
MEC
MECS
NIPS
WEC
NYISO
HUDS
LIND
NEPT
NYIS
TVA
Total

Actual
(546)
(212)
1,121
736
(15,855)(1,322)(1,227)(1,725)(3,122)(227)(1,196)(3,680)(742)(5,910)3,299(5,636)(1,095)(1,104)(1,300)(2,137)2,383(18,008)

Net Scheduled
65
2
503
(300)
(12,517)(1,426)(180)(248)(4,680)0(606)(2,820)(1,581)(680)(298)(5,690)(1,095)(1,104)(1,300)(2,191)(64)(18,001)

Difference (GWh)
(611)
(214)
618
1,036
(3,338)104(1,047)(1,477)
1,557
(227)
(591)
(861)
839
(5,231)
3,596
54
0
0
0
54
2,448
(7)

Every external balancing authority is mapped to an import and export
interface pricing point. The mapping is designed to reflect the physical flow ofenergy between PJM and each balancing authority. The net scheduled values
for interface pricing points are defined as the MWh of scheduled transactions
that will receive the interface pricing point based on the external balancing
authority mapping.28 For example, the MWh for a transaction whosetransmission path is SPP through MISO and into PJM would be reflected in
the SOUTH interface pricing point net schedule totals because SPP is mapped
to the SOUTH interface pricing point. The actual flow on an interface pricing
point is defined as the metered flow across the transmission lines that areincluded in the interface pricing point.

28 The terms balancing authority and control area are used interchangeably in this section. The NERC Tag applications maintained theterminology of generation control area (GCA) and load control area (LCA) after the implementation of the NERC functional model. The
NERC functional model classifies the balancing authority as a reliability service function, with, among other things, the responsibility forbalancing generation, demand and interchange balance.

440

Section 9 Interchange Transactions

The differences between the scheduled MWh mapped to a specific interface
pricing point and actual power flows at the interface pricing points provide a
better measure of loop flows than differences at the interfaces. The scheduledtransactions are mapped to interface pricing points based on the expected
flow from the generation balancing authority and load balancing authority,
whereas scheduled transactions are assigned to interfaces based solely on the
OASIS path that the market participants reflect the transmission path intoor out of PJM to one neighboring balancing authority. Power flows at theinterface pricing points provide a more accurate reflection of where scheduled
power flows actually enter or leave the PJM footprint based on the complete
transaction path. Table 9-22 shows the net scheduled and actual PJM flows
by interface pricing point.
On June 1, 2021, PJM consolidated the SouthIMP and SouthEXP interface
pricing points to the SOUTH interface pricing point. Because the SouthIMPand SouthEXP interface pricing points were the same physical point, if there
were net actual exports from the PJM footprint to the southern region, by
definition, there could not be net actual imports into the PJM footprint fromthe southern region and therefore there would not be actual flows at theSouthIMP interface pricing point. In the case of PJM’s southern border, loop
flows can be analyzed by comparing the net scheduled and net actual flows
as a sum of the pricing points, rather than the individual pricing points. To
accurately calculate the loop flows from the southern region, the net actual
flows from the southern region are compared to the net scheduled flows
from the southern region. The net actual flows from the southern region aredetermined by summing the total southern import actual flows (10,298 GWh),
the total southern export actual flows (-7,322 GWh) and the total SOUTH
actual flows (507 GWh) for 3,482 GWh of net imports. The net scheduledflows from the southern region are determined by summing the total southern
import scheduled flows (1,769 GWh), the total southern export scheduled flows(-1,673 GWh) and the total SOUTH scheduled flows (-170 GWh) for -74 GWhof net exports. In the first six months of 2021, the loop flows at the southern
region were the difference between the southern region net scheduled flows(-74 GW) and the southern region net actual flows (3,482 GWh) for a total of
3,556 GWh of loop flows.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

The IMO interface pricing point with the Ontario IESO was created to reflect
the fact that transactions that originate or sink in the Ontario Independent
Electricity System Operator (IMO) balancing authority create physical flowsthat are split between the MISO and NYISO interface pricing points dependingon transmission system conditions, so a mapping to a single interface pricing
point does not reflect the actual flows. PJM created the IMO interface pricing
point to reflect the actual power flows across both the MISO/PJM and NYISO/PJM interfaces. The IMO does not have physical ties with PJM because it is notcontiguous. Table 9-22 shows actual flows associated with the IMO interface
pricing point as zero because there is no PJM/IMO Interface. The actual flows
between IMO and PJM are included in the actual flows at the MISO and NYISO
interface pricing points.
Table 9-22 PJM flows by interface pricing point (GWh): January throughJune, 2021
IMO
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total

Actual0(15,855)(5,636)(1,095)(1,104)(1,300)(2,137)
10,2980
10,298(7,322)0(7,322)507(18,008)

Net Scheduled422(12,643)(5,706)(1,095)(1,104)(1,300)(2,208)
1,769
0
1,769
(1,673)0(1,673)(170)(18,001)

Difference (GWh)(422)(3,211)
71
0
0
0
71
8,529
0
8,529
(5,649)0(5,649)677(7)

Table 9-23 shows the net scheduled and actual PJM flows by interface pricing
point, with adjustments made to the MISO and NYISO scheduled interface
pricing points based on the quantities of scheduled interchange wheretransactions from the IMO entered the PJM energy market. For example,
Table 9-25 shows that 406 of the 422 GWh (96.2 percent) of gross scheduledtransactions that were mapped to the IMO interface pricing point werescheduled as imports through MISO.

© 2021 Monitoring Analytics, LLC

Table 9-23 shows that in the first six months of 2021, the SouthIMP interface
pricing point had the largest loop flows of any interface pricing point with
1,769 GWh of net scheduled interchange and 10,298 GWh of net actualinterchange, a difference of 8,529 GWh.
Table 9-23 PJM flows by interface pricing point (GWh) (Adjusted for IMO
Scheduled Interfaces): January through June, 2021
MISO
NYISO
HUDSONTP
LINDENVFTNEPTUNE
NYIS
Southern Imports
SOUTHEAST
SOUTHIMPSouthern Exports
SOUTHEAST
SOUTHEXP
SOUTH
Total

Actual(15,855)(5,636)(1,095)(1,104)(1,300)(2,137)
10,2980
10,298(7,322)0(7,322)507(18,008)

Net Scheduled(12,237)(5,690)(1,095)(1,104)(1,300)(2,191)
1,769
0
1,769
(1,673)0(1,673)(170)(18,001)

Difference (GWh)(3,617)
54
0
0
0
54
8,529
0
8,529
(5,649)0(5,649)677(7)The NERC Tag requires the complete path to be specified from the generation
control area (GCA) to the load control area (LCA), but participants do notalways do so. The NERC Tag path is used by PJM to determine the interface
pricing point that PJM assigns to the transaction. This approach will correctly
identify the interface pricing point only if the market participant provides
the complete path in the Tag. This approach will not correctly identify theinterface pricing point if the market participant breaks the transaction into
portions, each with a separate Tag. The breaking of transactions into portions
can be a way to manipulate markets and the result of such behavior can beincorrect and noncompetitive pricing of transactions.
PJM attempts to ensure that external energy transactions are priced
appropriately through the assignment of interface prices based on the
expected actual flow from the generation balancing authority (source) andload balancing authority (sink) as specified on the NERC Tag. Assigning prices
in this manner is a reasonable approach to ensuring that transactions receive

2021 Quarterly State of the Market Report for PJM: January through June 441

2021 Quarterly State of the Market Report for PJM: January through Juneor pay the PJM market value of the transaction based on expected flows, but
this method does not address loop flow issues.
Loop flows remain a significant concern for the efficiency of the PJM market.
Loop flows can have negative impacts on the efficiency of markets with
explicit locational pricing, including impacts on locational prices, on FTR
revenue adequacy and on system operations, and can be evidence of attempts
to game the markets.
The MMU recommends that PJM implement a validation method for submitted
transactions that would prohibit market participants from breaking transactions
into smaller segments to defeat the interface pricing rule and receive higher
prices (for imports) or lower prices (for exports) from PJM resulting from theinability to identify the true source or sink of the transaction. If all of theNortheast ISOs and RTOs implemented validation to prohibit the breaking oftransactions into smaller segments, the level of Lake Erie loop flow would be
reduced.

Table 9-24 shows the net scheduled and actual PJM flows by interface andinterface pricing point. This table shows the interface pricing points that wereassigned to energy transactions that had paths at each of PJM’s interfaces. For
example, Table 9-24 shows that in the first six months of 2021, the majorityof imports to the PJM energy market for which a market participant specified
Ameren-Illinois (AMIL) as the interface with PJM based on the scheduledtransmission path, had a generation control area mapped to the SOUTHIMPInterface, and thus actual flows were assigned the SOUTHIMP interface pricing
point (26 GWh). The majority of exports from the PJM energy market for
which a market participant specified AMIL as the interface with PJM based on
the scheduled transmission path had a load control area for which the actual
flows would leave the PJM energy market at the MISO Interface, and wereassigned the MISO interface pricing point (-243 GWh).

The MMU also recommends that PJM implement a validation method forsubmitted transactions that would require market participants to submit
transactions on paths that reflect the expected actual power flow in order toreduce unscheduled loop flows.

442

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-24 Net scheduled and actual flows by interface and interface pricing point (GWh): January through June, 2021
Interface
ALTE

Interface
Pricing Point
IMO
MISO
SOUTHEXP

ALTW
IMO
MISO
AMIL
MISO
SOUTHEXP
SOUTHIMP
SOUTH
CIN
IMO
MISO
SOUTHEXP
SOUTHIMP
SOUTH
CPLE
SOUTHEXP
SOUTHIMP
SOUTH
CPLW
SOUTHEXP
SOUTHIMP
SOUTH
CWLP
MISO
DUK
SOUTHEXP
SOUTHIMPSOUTH
HUDS
HUDSONTP
IPL
IMO
MISO
SOUTHEXP
SOUTHIMP
SOUTH© 2021 Monitoring Analytics, LLC

Actual
(1,322)0(1,322)0(1,227)0(1,227)(1,725)(1,725)000(3,122)0(3,122)000(546)(1,613)
1,126
(58)
(212)
(232)
61
(41)
(227)
(227)
1,121
(438)
1,370
189
(1,095)(1,095)(1,196)0(1,196)000Net
Scheduled(1,426)40(1,462)
(3)
(180)
4
(184)
(248)
(243)
(35)
26
3
(4,680)17(4,525)
(135)
11
(47)
65
(408)
439
33
2
0
2
0
0
0
503
(307)
796
14
(1,095)(1,095)
(606)
26
(562)
(68)
0
(1)

Difference
(GWh)
104
(40)
140
3
(1,047)(4)(1,044)(1,477)(1,482)
35
(26)
(3)
1,557
(17)
1,403
135
(11)
47
(611)
(1,206)
687
(91)
(214)
(232)
59
(41)
(227)
(227)
618
(131)
573
175
0
0
(591)
(26)
(634)
68
(0)
1

Interface
LGEE

Interface
Pricing Point
SOUTHEXP
SOUTHIMP
SOUTH

LIND
LINDENVFT
MEC
IMO
MISO
SOUTHEXP
SOUTHIMP
SOUTH
MECS
IMO
MISO
SOUTHEXP
SOUTHIMP
SOUTH
NEPT
NEPTUNE
NIPS
IMO
MISO
NYIS
IMO
NYIS
TVA
MISO
SOUTHEXP
SOUTHIMP
SOUTH
WEC
MISO
SOUTHEXP
SOUTHIMP
SOUTH
Grand Total

Actual736(3,467)
4,149
54(1,104)(1,104)(3,680)0(3,680)
0
0
0
(742)
0
(742)
0
0
0
(1,300)(1,300)(5,910)0(5,910)(2,137)
0(2,137)2,383
0(1,572)
3,592
363
3,299
3,299
0
0
0
(18,008)

Net
Scheduled
(300)
(357)
121
(64)
(1,104)(1,104)(2,820)0(2,812)(9)
2(1)(1,581)319(1,889)(13)
1
1(1,300)(1,300)
(680)
0
(680)
(2,191)16(2,208)
(64)
(0)
(316)
362
(110)
(298)
(286)
(22)
9
2
(18,001)

Difference
(GWh)
1,036
(3,111)
4,028
118
0
0
(861)
(0)
(868)
9
(2)
1
839
(319)
1,147
13
(1)
(1)
0
0
(5,231)(0)(5,231)
54
(16)
71
2,448
0
(1,256)
3,231
473
3,596
3,585
22
(9)
(2)
(7)

2021 Quarterly State of the Market Report for PJM: January through June 443

2021 Quarterly State of the Market Report for PJM: January through June

Table 9-25 shows the net scheduled and actual PJM flows by interface pricing point and interface. The grouping is reversed from Table 9-24. Table 9-25 shows
the interfaces where transactions were scheduled which received the individual interface pricing points. For example, Table 9-25 shows that in the first six
months of 2021, the majority of imports to the PJM energy market for which a market participant specified a generation control area for which it was assigned
the IMO interface pricing point, had a path that entered the PJM energy market at the MECS Interface (319 GWh).
Table 9-25 Net scheduled and actual flows by interface pricing point and interface (GWh): January through June, 2021
Interface
Pricing PointHUDSONTPInterface
HUDS

IMO
ALTE
ALTW
CIN
IPL
MEC
MECS
NIPS
NYIS
LINDENVFT
LIND
MISO
ALTE
ALTW
AMIL
CIN
CWLP
IPL
MEC
MECS
NIPS
TVA
WEC
NEPTUNE
NEPT
NYIS
NYIS

Actual
(1,095)(1,095)
0
0
0
0
0
0
0
0
0
(1,104)(1,104)(15,855)(1,322)(1,227)(1,725)(3,122)(227)(1,196)(3,680)(742)(5,910)0
3,299(1,300)(1,300)(2,137)(2,137)

Net
Scheduled(1,095)(1,095)
422
40
4
17
26
0
319
0
16
(1,104)(1,104)(12,643)(1,462)(184)(243)(4,525)0(562)(2,812)(1,889)
(680)
(0)
(286)
(1,300)(1,300)(2,208)(2,208)Difference
(GWh)
0
0
(422)
(40)
(4)
(17)
(26)
(0)
(319)
(0)
(16)
0
0
(3,211)140(1,044)(1,482)
1,403
(227)
(634)
(868)
1,147
(5,231)
0
3,585
0
0
71
71

Interface
Pricing Point
SOUTH

AMIL
CIN
CPLE
CPLW
DUK
IPL
LGEE
MEC
MECS
TVA
WEC
SOUTHEXP
ALTE
AMIL
CIN
CPLE
CPLW
DUK
IPL
LGEE
MEC
MECS
TVA
WEC
SOUTHIMP
AMIL
CIN
CPLE
CPLW
DUK
IPL
LGEE
MEC
MECS
TVA
WEC
Grand Total

444

Section 9 Interchange Transactions

Interface

Actual
507
0
0
(58)
(41)
189
0
54
0
0
363
0
(7,322)000(1,613)
(232)
(438)
0
(3,467)00(1,572)
0
10,298
0
0
1,126
61
1,370
0
4,149
0
0
3,592
0
(18,008)

Net
Scheduled
(170)
3
(47)
33
0
14
(1)
(64)
(1)
1
(110)
2
(1,673)
(3)
(35)
(135)
(408)
0
(307)
(68)
(357)
(9)
(13)
(316)
(22)
1,769
26
11
439
2
796
0
121
2
1
362
9
(18,001)

Difference
(GWh)
677
(3)
47
(91)
(41)
175
1
118
1
(1)
473
(2)
(5,649)335
135(1,206)
(232)
(131)
68
(3,111)9
13(1,256)
22
8,529
(26)
(11)
687
59
573
(0)
4,028
(2)
(1)
3,231
(9)
(7)

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Data Required for Full Loop Flow Analysis
Loop flows are defined as the difference between actual and scheduled power
flows at one or more specific interfaces. The differences between actual andscheduled power flows can be the result of a number of underlying causes. To
adequately investigate the causes of loop flows, complete data are required.
Loop flows exist because electricity flows on the path of least resistanceregardless of the path specified by contractual agreement or regulatoryprescription. Loop flows can arise from transactions scheduled into, out of or
around a balancing authority on contract paths that do not correspond to theactual physical paths on which energy flows. Outside of LMP-based energy
markets, energy is scheduled and paid for based on contract path, without
regard to the path of the actual energy flows. Loop flows can also result fromactions within balancing authorities.
Loop flows are a significant concern. Loop flows can have negative impacts
on the efficiency of markets with explicit locational pricing, including impacts
on locational prices, on FTR revenue adequacy and on system operations, andcan be evidence of attempts to game such markets. Loop flows also have poorly
understood impacts on nonmarket areas. In general, the detailed sources of
the identified differences between scheduled and actual flows remain unclear
as a result of incomplete or inadequate access to the required data.
A complete analysis of loop flow could provide additional insight that
could lead to enhanced overall market efficiency and clarify the interactions
among market and nonmarket areas. A complete analysis of loop flow would
improve the overall transparency of electricity transactions. There are areas
with transparent markets, and there are areas with less transparent markets(nonmarket areas), but these areas together comprise a market, and overallmarket efficiency would benefit from the increased transparency that would
derive from a better understanding of loop flows.
For a complete loop flow analysis, several types of data are required from allbalancing authorities in the Eastern Interconnection. The Commission required
access to NERC Tag data. In addition to the Tag data, actual tie line data,© 2021 Monitoring Analytics, LLC

dynamic schedule and pseudo-tie data are required in order to analyze thedifferences between actual and scheduled transactions. ACE data, market flow
impact data and generation and load data are required in order to understandthe sources, within each balancing authority, of loop flows that do not result
from differences between actual and scheduled transactions.29

NERC Tag Data
An analysis of loop flow requires knowledge of the scheduled path ofenergy transactions. NERC Tag data include the scheduled path and energy
profile of the transactions, including the Generation Control Area (GCA),
the intermediate Control Areas, the Load Control Area (LCA) and the energy
profile of all transactions. Complete tag data include the identity of thespecific market participants. FERC Order No. 771 required access to NERC Tag
data for the Commission, regional transmission organizations, independent
system operators and market monitoring units.30

Actual Tie Line Flow Data
An analysis of loop flow requires knowledge of the actual path of energy
transactions. Currently, a very limited set of tie line data is made available
via the NERC IDC and the Central Repository for Curtailments (CRC) website.
The available tie line data, and the data within the IDC, are presented as
information on a screen, which does not permit analysis of the underlying
data.

Dynamic Schedule and Pseudo Tie Data
Dynamic schedule and pseudo ties represent another type of interchangetransaction between balancing authorities. While dynamic schedules are
required to be tagged, the tagged profile is only an estimate of what energy is
expected to flow. Dynamic schedules are implemented within each balancing
authority’s Energy Management System (EMS), with the current values
shared over Inter-Control Center Protocol (ICCP) links. By definition, thedynamic schedule scheduled and actual values will always be identical froma balancing authority standpoint, and the tagged profile should be removed
29 It is requested that all data be made available in downloadable format in order to make analysis possible. A data viewing tool alone is notadequate.
30 141 FERC ¶ 61,235 (2012).

2021 Quarterly State of the Market Report for PJM: January through June 445

2021 Quarterly State of the Market Report for PJM: January through Junefrom the calculation of loop flows to eliminate double counting of the energy
profile. Dynamic schedule data from all balancing authorities are required inorder to account for all scheduled and actual flows.
Pseudo-ties are similar to dynamic schedules in that they represent atransaction between balancing authorities and are handled within the EMS
systems and data are shared over the ICCP. Pseudo ties differ from dynamicschedules in how the generating resource is modeled within the balancing
authorities’ ACE equations. Dynamic schedules are modeled as resources
located in one area serving load in another, while pseudo ties are modeled
as resources in one area moved to another area. Unlike dynamic schedules,
pseudo tie transactions are not required to be tagged. Pseudo tie data from allbalancing authorities are required in order to account for all scheduled andactual flows.

Area Control Error (ACE) Data
Area control error (ACE) data provides information about how well eachbalancing authority is matching their generation with their load. This
information, combined with the scheduled and actual interchange values willshow whether an individual balancing authority is pushing on or leaning on
the interconnection, contributing to loop flows.
NERC makes real-time ACE graphs available on their Reliability Coordinator
Information System (RCIS) website. This information is presented only ingraphical form, and the underlying data is not available for analysis.

Market Flow Impact Data
In addition to interchange transactions, internal dispatch can also affect flows
on balancing authorities’ tie lines. The impact of internal dispatch on tie lines
is called market flow. Market flow data are imported in the IDC, but there is
only limited historical data, as only market flow data related to TLR levels 3
or higher are required to be made available via a Congestion Management
Report (CMR). The remaining data are deleted.

446

Section 9 Interchange Transactions

There is currently a project in development through the NERC Operating
Reliability Subcommittee (ORS) called the Market Flow Impact Tool. The
purpose of this tool is to make visible the impacts of dispatch on loop flows.
The MMU supports the development of this tool, but, equally important,requests that FERC and NERC ensure that the underlying data are provided tomarket monitors and other approved entities.

Generation and Load Data
Generation data (both real-time scheduled generation and actual output) andload data would permit analysis of the extent to which balancing authorities
are meeting their commitments to serve load. If a balancing authority is
not meeting its load commitment with adequate generation, the result isunscheduled flows across the interconnections to establish power balance.
Market areas are transparent in providing real-time load while nonmarket
areas are not. For example, PJM posts real-time load via its eDATA application.
Most nonmarket balancing authorities provide only the expected peak load on
their individual websites. Data on generation are not made publicly available,
as this is considered market sensitive information.
The MMU recommends, that in order to permit a complete analysis of loop
flow, FERC and NERC ensure that the identified data are made available tomarket monitors as well as other industry entities determined appropriate byFERC.

PJM and MISO Interface Prices
Both the PJM/MISO and MISO/PJM interface pricing points represent thevalue of power at the relevant border, as determined in each market. In bothcases, the interface price is the price at which transactions are settled. For
example, a transaction into PJM from MISO would receive the PJM/MISO
interface price upon entering PJM, while a transaction into MISO from PJM
would receive the MISO/PJM interface price. PJM and MISO use networkmodels to determine these prices and to attempt to ensure that the prices are
consistent with the underlying electrical flows.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Prior to June 1, 2014, the PJM interface definition for MISO consisted ofnine buses located near the middle of the MISO system and not at the border
between the RTOs. The interface definitions led to questions about the level ofcongestion included in interchange pricing.31
PJM modified the definition of the PJM/MISO interface price effective June 1,
2014. PJM’s new MISO interface pricing point includes 10 equally weighted
buses that are close to the PJM/MISO border. The 10 buses were selectedbased on PJM’s analysis that showed that over 80 percent of the hourly tie
line flows between PJM and MISO occurred on 10 ties composed of MISO andPJM monitored facilities. On June 1, 2017, MISO modified their MISO/PJM
interface definition to match PJM’s PJM/MISO interface definition.

positive and negative, the standard deviation of individual prices and of pricedifferences and the absolute value of the price differences (Table 9-30).
Table 9-26 PJM and MISO flow based hours and price differences: January
through June, 2021
LMP Difference
MISO/PJM LMP > PJM/MISO LMP

PJM/MISO LMP > MISO/PJM LMP

Number of
Hours
2,678
2,678
0
0
1,665
0
1,665
0

Average Hourly
Price Difference
$7.64
$7.64
$0.00
$0.00
$8.22
$0.00
$8.22
$0.00

Real-Time

$150
$100
$50
$0
-$50
-$100
-$150

Real-Time and Day-Ahead PJM/MISO Interface Prices

Jan

Feb

Mar

Apr

May

Jun

Apr

May

Jun

Day-Ahead$150
Price difference ($/MWh)In the first six months of 2021, the direction of flow was consistent with pricedifferentials in 61.7 percent of the hours. Table 9-26 shows the number ofhours and average hourly price differences between the PJM/MISO Interface
and the MISO/PJM Interface based on LMP differences and flow direction.
Figure 9-5 shows the underlying variability in prices calculated on a daily
hourly average basis. There are a number of relevant measures of variability,
including the number of times the price differential fluctuates between

Flow Direction
Total Hours
Consistent Flow (PJM to MISO)
Inconsistent Flow (MISO to PJM)No Flow
Total Hours
Consistent Flow (MISO to PJM)
Inconsistent Flow (PJM to MISO)No Flow

Figure 9-5 Price differences (MISO/PJM Interface minus PJM/MISO Interface):
January through June, 2021

Price difference ($/MWh)

Under the PJM/MISO Joint Operating Agreement, the two RTOs mutually
determine a set of transmission facilities on which both RTOs have an impact,
and therefore jointly operate to those constraints. These jointly controlled
facilities are M2M (Market to Market) flowgates. When a M2M constraint
binds, PJM’s LMP calculations at the buses that make up PJM’s MISO interface
pricing point are based on the PJM model’s distribution factors of the selectedbuses to the binding M2M constraint and PJM’s shadow price of the binding
M2M constraint. MISO’s LMP calculations at the buses that make up MISO’s
PJM interface pricing point are based on the MISO model’s distribution factorsof the selected buses to the binding M2M constraint and MISO’s shadow priceof the binding M2M constraint.

$100
$50
$0
-$50
-$100
-$150

Jan

Feb

Mar

31 See “LMP Aggregate Definitions,” (June 1, 2021) <http://www.pjm.com/~/media/markets-ops/energy/‌lmp-model-info/lmp-aggregatedefinitions.ashx>. PJM periodically updates these definitions on its website. See <http://www.pjm.com>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 447

2021 Quarterly State of the Market Report for PJM: January through June

Distribution and Prices of Hourly Flows at the PJM/MISO
InterfaceIn the first six months of 2021, the direction of hourly energy flows wasconsistent with PJM and MISO interface price differentials in 2,678 hours(61.7 percent of all hours), and was inconsistent with price differentials in
1,665 hours (38.3 percent of all hours). Table 9-27 shows the distribution ofhourly energy flows between PJM and MISO based on the price differences
between the PJM/MISO and MISO/PJM prices. Of the 1,665 hours where flows
were in a direction inconsistent with price differences, 1,269 of those hours(76.2 percent) had a price difference greater than or equal to $1.00 and 561
of those hours (33.7 percent) had a price difference greater than or equal to$5.00. The largest price difference with such flows was $469.04. Of the 2,678
hours where flows were consistent with price differences, 2,193 of those hours(81.9 percent) had a price difference greater than or equal to $1.00 and 717
of all such hours (26.8 percent) had a price difference greater than or equal to$5.00. The largest price difference with such flows was $566.78.
Table 9-27 Distribution of hourly flows that are consistent and inconsistent
with price differences between PJM and MISO: January through June, 2021
Price Difference Range(Greater Than or Equal To)
$0.00
$1.00
$5.00
$10.00$15.00$20.00$25.00$50.00$75.00$100.00$200.00$300.00$400.00$500.00

Inconsistent
Hours
1,665
1,269
561
304
205
152
119
40
17
13
4
3
2
0

Percent ofInconsistent
Percent of
Hours Consistent Hours Consistent Hours
100.0%
2,678
100.0%
76.2%
2,193
81.9%
33.7%
717
26.8%
18.3%
342
12.8%
12.3%
224
8.4%
9.1%
169
6.3%
7.1%
136
5.1%
2.4%
61
2.3%
1.0%
41
1.5%
0.8%
28
1.0%
0.2%
8
0.3%
0.2%
4
0.1%
0.1%
2
0.1%
0.0%
1
0.0%

PJM and NYISO Interface Prices
If interface prices were defined in a comparable manner by PJM and the NYISO,
if identical rules governed external transactions in PJM and the NYISO, if timelags were not built into the rules governing such transactions and if no risks
were associated with such transactions, then prices at the interfaces would
be expected to be very close and the level of transactions would be expected
to be related to any price differentials. The fact that none of these conditions
exists is important in explaining the observed relationship between interface
prices and inter-RTO/ISO power flows, and those price differentials.32
PJM and NYISO each calculate an interface LMP using network models
including distribution factor impacts. Prior to May 1, 2017, PJM used two
buses within NYISO to calculate the PJM/NYIS interface pricing point LMP.
The NYISO uses proxy buses to calculate interface prices with neighboringbalancing authorities. A proxy bus is a single bus, located outside the NYISO
footprint, which represents generation and load in a neighboring balancing
authority area. The NYISO models imports from PJM as generation at the
Keystone proxy bus, delivered to the NYISO reference bus with the assumptionthat 32 percent of the flow will enter the NYISO across the free flowing A/Cties, 32 percent will enter the NYISO across the Ramapo PARs, 21 percent willenter the NYISO across the ABC PARs and 15 percent will enter the NYISO
across the J/K PARs. The NYISO models exports to PJM as being delivered
to load at the Keystone proxy bus, sourced from the NYISO reference bus
with the assumption that 32 percent of the flow will enter PJM across thefree flowing A/C ties, 32 percent will enter PJM across the Ramapo PARs, 21
percent will enter PJM across the ABC PARs and 15 percent will enter PJM
across the J/K PARs.
The PJM/NYIS interface definition using two buses was created to include theimpact of the ConEd wheeling agreement. The ConEd wheeling agreement
ended on May 1, 2017. The end of the wheeling agreement meant that the
expected actual power flows would change and therefore the definition of
the interface price needed to change. Effective May 1, 2017, PJM replaced
the old PJM/NYIS interface price definition. The new PJM/NYIS interface
32 See the 2012 State of the Market Report for PJM, Volume II, Section 8, “Interchange Transactions,” for a more detailed discussion.

448

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

In the first six months of 2021, the relationship between prices at the PJM/
NYIS Interface and at the NYISO/PJM proxy bus and the relationship between
interface price differentials and power flows continued to be affected bydifferences in institutional and operating practices between PJM and the
NYISO. The direction of flow was consistent with price differentials in 55.3
percent of the hours in the first six months of 2021. Table 9-28 shows thenumber of hours and average hourly price differences between the PJM/NYISInterface and the NYIS/PJM proxy bus based on LMP differences and flow
direction. Figure 9-6 shows the underlying variability in prices calculated
on a daily hourly average basis. There are a number of relevant measuresof variability, including the number of times the price differential fluctuates
between positive and negative, the standard deviation of individual prices
and of price differences and the absolute value of the price differences (Table
9-30).
Table 9-28 PJM and NYISO flow based hours and price differences: January
through June, 202133
LMP Difference
NYIS/PJM proxy bus LBMP > PJM/NYIS LMP

PJM/NYIS LMP > NYIS/PJM proxy bus LBMPFlow Direction
Total Hours
Consistent Flow (PJM to NYIS)
Inconsistent Flow (NYIS to PJM)No Flow
Total Hours
Consistent Flow (NYIS to PJM)
Inconsistent Flow (PJM to NYIS)No Flow

Number of
Hours
2,099
1,819
280
0
2,244
581
1,663
0

33 The NYISO Locational Based Marginal Price (LBMP) is the equivalent term to PJM’s Locational Marginal Price (LMP).

© 2021 Monitoring Analytics, LLC

Average Hourly
Price Difference
$9.04
$9.37
$6.91
$0.00
$13.12$8.25$14.82$0.00

Price difference ($/MWh)

Real-Time and Day-Ahead PJM/NYISO Interface Prices

Figure 9-6 Price differences (NY/PJM proxy - PJM/NYIS Interface): January
through June, 2021
Real-Time

$150
$100
$50
$0
-$50
-$100
-$150

Price difference ($/MWh)price is based on four buses within NYISO. The four buses were chosen basedon a power flow analysis of transfers between PJM and the NYISO and theresultant distribution of flows across the free flowing A/C ties.

Jan

Feb

Mar

Apr

May

Jun

May

Jun

Day-Ahead

$150
$100
$50
$0
-$50
-$100
-$150

Jan

Feb

Mar

Apr

Distribution and Prices of Hourly Flows at the PJM/NYISO
InterfaceIn the first six months of 2021, the direction of hourly energy flows wasconsistent with PJM/NYISO and NYISO/PJM price differences in 2,400 hours(55.3 percent of all hours), and was inconsistent with price differences in
1,943 hours (44.7 percent of all hours). Table 9-29 shows the distribution ofhourly energy flows between PJM and NYISO based on the price differences
between the PJM/NYISO and NYISO/PJM prices. Of the 1,943 hours whereflows were in a direction inconsistent with price differences, 1,696 of those
hours (87.3 percent) had a price difference greater than or equal to $1.00 and
961 of all those hours (49.5 percent) had a price difference greater than orequal to $5.00. The largest price difference with such flows was $379.02. Of
the 2,400 hours where flows were consistent with price differences, 2,144 of
2021 Quarterly State of the Market Report for PJM: January through June 449

2021 Quarterly State of the Market Report for PJM: January through June

those hours (89.3 percent) had a price difference greater than or equal to $1.00
and 1,191 of all such hours (49.6 percent) had a price difference greater thanor equal to $5.00. The largest price difference with such flows was $521.78.
Table 9-29 Distribution of hourly flows that are consistent and inconsistent
with price differences between PJM and NYISO: January through June, 2021
Price Difference Range(Greater Than or Equal To)
$0.00
$1.00
$5.00
$10.00$15.00$20.00$25.00$50.00$75.00$100.00$200.00$300.00$400.00$500.00

Inconsistent
Hours
1,943
1,696
961
486
333
265
216
110
68
47
18
4
0
0

Percent ofInconsistent
Percent of
Hours Consistent Hours Consistent Hours
100.0%
2,400
100.0%
87.3%
2,144
89.3%
49.5%
1,191
49.6%
25.0%
562
23.4%
17.1%
298
12.4%
13.6%
191
8.0%
11.1%
145
6.0%
5.7%
50
2.1%
3.5%
27
1.1%
2.4%
16
0.7%
0.9%
2
0.1%
0.2%
1
0.0%
0.0%
1
0.0%
0.0%
1
0.0%

Summary of Interface Prices between PJM andOrganized Markets
Some measures of the real-time and day-ahead PJM interface pricing withMISO and with the NYISO are summarized and compared in Table 9-30,
including average prices and measures of variability.
Table 9-30 PJM, NYISO and MISO border price averages: January throughJune, 202134
Description
PJM Price at ISO Border
ISO Price at PJM Border
Average Interval Price Difference at Border (PJM-ISO)
Average Absolute Value of Interval Difference at Border
Sign Changes per Day
PJM Price at ISO BorderStandard Deviation
ISO Price at PJM Border
Difference at Border (PJM-ISO)

Real-Time
NYISO
MISO
$29.89 $27.41$27.45 $28.97$2.44 ($1.56)$51.89 $52.03
39.1
45.7
$52.01 $38.42$27.81 $45.45$53.48 $52.89

Day-Ahead
NYISO
MISO
$28.28 $28.30$27.61 $30.46$0.66 ($2.16)$4.99 $11.28
2.6
3.3$14.61 $17.23$15.88 $25.91$6.62 $11.89

Neptune Underwater Transmission Line to Long
Island, New YorkThe Neptune Line is a 65 mile direct current (DC) merchant 230 kV transmissionline, with a capacity of 660 MW, providing a direct connection between
PJM (Sayreville, New Jersey), and NYISO (Nassau County on Long Island).
Schedule 14 of the PJM Open Access Transmission Tariff provides that power
flows will only be from PJM to New York. The flows were consistent withprice differentials in 67.5 percent of the hours in the first six months of 2021.
Table 9-31 shows the number of hours and average hourly price differences
between the PJM/NEPT Interface and the NYIS/Neptune bus based on LMP
differences and flow direction.

34 Effective April 1, 2018, PJM implemented 5 minute LMP settlements in the real-time energy market. The sign changes per day
represented in this table reflect the number of intervals where the sign changed per day. For the real-time energy market, there are 288
five minute intervals. For the day-ahead market there are 24 hourly intervals.

450

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-31 PJM and NYISO flow based hours and price differences (Neptune): January through June, 2021
LMP Difference
NYIS/Neptune Bus LBMP > PJM/NEPT LMP

PJM/NEPT LMP > NYIS/Neptune Bus LBMPFlow Direction
Total Hours
Consistent Flow (PJM to NYIS)
Inconsistent Flow (NYIS to PJM)No Flow
Total Hours
Consistent Flow (NYIS to PJM)
Inconsistent Flow (PJM to NYIS)No Flow

Number of
Hours
3,661
2,932
0
729
682
0
649
33

Average Hourly
Price Difference$24.38$22.29$0.00$32.81
$9.12
$0.00
$9.38
$4.12

To move power from PJM to NYISO using the Neptune Line, two PJM transmission service reservations are required. A transmission service reservation isrequired from the PJM Transmission System to the Neptune HVDC Line (“Out Service”) and another transmission service reservation is required on the Neptune
HVDC Line (“Neptune Service”).35 The PJM Out Service is covered by normal PJM OASIS business operations.36 The Neptune Service falls under the provisions
for controllable merchant facilities, Schedule 14 of the PJM Tariff. The Neptune Service is also acquired on the PJM OASIS.
Neptune Service is owned by a primary rights holder, and any nonfirm service that is not used (as defined by a schedule on a NERC Tag) may be released either
voluntarily by the primary rights holder or by default by PJM. The primary rights holder may elect to voluntarily release monthly, weekly, daily or hourly firmor nonfirm service. Voluntarily releasing the service allows for the primary rights holder to specify a rate to be charged for the released service. If the primaryrights holder does not elect to voluntarily release nonfirm service, and does not use the service, the available transmission will be released by default at 12:00,
one business day before the start of service. On June 30, 2021, the rate for the nonfirm service released by default was $10.00 per MWh. The primary rights
holder remains obligated to pay for the released service unless a second transmission customer acquires the released service.
Table 9-32 shows the percent of scheduled interchange across the Neptune Line by the primary rights holder since commercial operations began in July 2007.
Table 9-32 shows that in the first six months of 2021, the primary rights holder was responsible for 100 percent of the scheduled interchange across the Neptune
Line in all months. Figure 9-7 shows the hourly average flow across the Neptune Line for the first six months of 2021.
Table 9-32 Percent of scheduled interchange across the Neptune Line by primary rights holder: July 2007 through June 2021
January
February
March
April
May
June
July
AugustSeptember
OctoberNovember
December

2007
NA
NA
NA
NA
NA
NA
100.00%100.00%100.00%100.00%100.00%100.00%2008
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2009
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2010
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2011
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2012
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2013
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2014
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2015
100.00%100.00%100.00%99.99%
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2016
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2017
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2018
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2019
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2020
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2021
100.00%100.00%100.00%100.00%100.00%100.00%35 See OASIS “PJM Business Practices for Neptune Transmission Service,” (August 21, 2015) <http://www.pjm.com/~/‌media/etools/oasis/merch-trans-facilities/neptune-oasis-Business-practices-doc-clean.ashx>.
36 See OASIS “Regional Transmission and Energy Scheduling Practices,” Rev. 9 (August 5, 2021) <http://www.pjm.com/~/media/etools/oasis/regional-practices-clean-pdf.ashx>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 451

2021 Quarterly State of the Market Report for PJM: January through June

Figure 9-7 Neptune hourly average flow: January through June, 2021
800

LMP Difference

600

NYIS/Linden Bus LBMP > PJM/LIND LMP

400

Volume (MWh)200

PJM/LIND LMP > NYIS/Linden Bus LBMP

Total Capacity

0

-200
-400
-600
-800

Table 9-33 PJM and NYISO flow based hours and price differences (Linden):January through June, 2021

Total Capacity
1

2

3

4

5

6

7

8

9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour ending (EPT)

Linden Variable Frequency Transformer (VFT) facility
The Linden VFT facility is a controllable AC merchant transmission facility,with a capacity of 315 MW, providing a direct connection between PJM(Linden, New Jersey) and NYISO (Staten Island, New York). The flows wereconsistent with price differentials in 75.3 percent of the hours in the first six
months of 2021. Table 9-33 shows the number of hours and average hourly
price differences between the PJM/LIND Interface and the NYIS/Linden Bus
based on LMP differences and flow direction.

Flow Direction
Total Hours
Consistent Flow (PJM to NYIS)
Inconsistent Flow (NYIS to PJM)No Flow
Total Hours
Consistent Flow (NYIS to PJM)
Inconsistent Flow (PJM to NYIS)No Flow

Number of
Hours
3,349
3,272
0
77
994
0
953
41

Average Hourly
Price Difference$14.57$14.81$0.00$4.39$12.14$0.00$12.50$3.88

To move power from PJM to NYISO on the Linden VFT Line, two PJM transmission
service reservations are required. A transmission service reservation is required
from the PJM Transmission System to the Linden VFT (“Out Service”) andanother transmission service reservation is required on the Linden VFT (“Linden
VFT Service”).37 The PJM Out Service is covered by normal PJM OASIS business
operations.38 The Linden VFT Service falls under the provisions for controllable
merchant facilities, Schedule 16 and Schedule 16-A of the PJM Tariff. The
Linden VFT Service is also acquired on the PJM OASIS.
Linden VFT Service is owned by a primary rights holder, and any nonfirm
service that is not used (as defined by a schedule on a NERC Tag) may bereleased either voluntarily by the primary rights holder or by default by PJM.
The primary rights holder may elect to voluntarily release monthly, weekly,
daily or hourly firm or nonfirm service. Voluntarily releasing the service
allows for the primary rights holder to specify a rate to be charged for the
released service. If the primary rights holder elects to not voluntarily releasenonfirm service, and does not use the service, the available transmission will
be released by default at 12:00, one business day before the start of service.
On June 30, 2021, the rate for the nonfirm service released by default was$6.00 per MWh. The primary rights holder remains obligated to pay for the
released service unless a second transmission customer acquires the released
service.
37 See OASIS “PJM Business Practices for Linden VFT Transmission Service,” (June 1, 2011) <http://www.pjm.com/~/media/etools/oasis/merch-trans-facilities/linden-vft-oasis-Business-practices-doc-clean.ashx>.
38 See OASIS “Regional Transmission and Energy Scheduling Practices,” Rev. 9 (August 5, 2021) <http://www.pjm.com/~/media/etools/oasis/regional-practices-clean-doc.ashx>.

452

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-34 shows the percent of scheduled interchange across the Linden VFT Line by the primary rights holder since commercial operations began in November,2009. Table 9-34 shows that in the first six months of 2021, the primary rights holder was responsible for 100 percent of the scheduled interchange across the
Linden VFT Line in all months. Figure 9-8 shows the hourly average flow across the Linden VFT Line for the first six months of 2021.
Table 9-34 Percent of scheduled interchange across the Linden VFT Line by primary rights holder: November 2009 through June 2021
2009
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
100.00%100.00%January
February
March
April
May
June
July
AugustSeptember
OctoberNovember
December

2010
100.00%100.00%100.00%99.97%
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2011
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2012
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%98.22%

2013
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%99.86%
100.00%2014
100.00%100.00%100.00%99.98%
100.00%27.27%
29.56%
82.46%
81.68%
100.00%100.00%100.00%2015
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%35.05%
61.45%
84.57%

2016
70.53%
94.95%
96.46%
49.32%
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2017
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2018
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2019
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2020
100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%100.00%2021
100.00%100.00%100.00%100.00%100.00%100.00%Figure 9-8 Linden hourly average flow: January through June, 202139
800
600
400

Total Capacity

Volume (MWh)

200
0

-200
Total Capacity

-400
-600
-800

1

2

3

4

5

6

7

8

9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour ending (EPT)

39 The Linden VFT Line is a bidirectional facility. The “Total Capacity” lines represent the maximum amount of interchange possible in either direction. These lines were included to maintain a consistent scale, for comparison purposes, with the Neptune DC Tie Line.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 453

2021 Quarterly State of the Market Report for PJM: January through June

Hudson Direct Current (DC) Merchant Transmission
Line
The Hudson direct current (DC) Line is a bidirectional merchant 230 kV
transmission line, with a capacity of 673 MW, providing a direct connection
between PJM (Public Service Electric and Gas Company’s (PSE&G) Bergen
230 kV Switching Station located in Ridgefield, New Jersey) and NYISO(Consolidated Edison’s (Con Ed) W. 49th Street 345 kV Substation in New York
City). The connection is a submarine cable system. While the Hudson DC Lineis a bidirectional line, power flows are only from PJM to New York because
the Hudson Transmission Partners, LLC had only requested withdrawal rights(320 MW of firm withdrawal rights, and 353 MW of nonfirm withdrawal
rights). The flows were consistent with price differentials in 67.5 percent of
the hours in the first six months of 2021. Table 9-35 shows the number ofhours and average hourly price differences between the PJM/HUDS Interface
and the NYIS/Hudson bus based on LMP differences and flow direction.
Table 9-35 PJM and NYISO flow based hours and price differences (Hudson):January through June, 2021
LMP Difference
NYIS/Hudson Bus LBMP > PJM/HUDS LMP

PJM/HUDS LMP > NYIS/Hudson Bus LBMPFlow Direction
Total Hours
Consistent Flow (PJM to NYIS)
Inconsistent Flow (NYIS to PJM)No Flow
Total Hours
Consistent Flow (NYIS to PJM)
Inconsistent Flow (PJM to NYIS)No Flow

Number of
Hours
3,064
2,931
0
133
1,279
0
1,237
42

Average Hourly
Price Difference$12.00$12.23$0.00$6.73$19.37$0.00$19.90$3.79

business operations.41 The Hudson Service falls under the provisions forcontrollable merchant facilities, Schedule 17 of the PJM Tariff. The Hudson
Service is also acquired on the PJM OASIS.
Hudson Service is owned by a primary rights holder, and any nonfirm service
that is not used (as defined by scheduled on a NERC Tag) may be released
either voluntarily by the primary rights holder or by default by PJM. The
primary rights holder may elect to voluntarily release monthly, weekly, daily
or hourly firm or nonfirm service. Voluntarily releasing the service allows
for the primary rights holder to specify a rate to be charged for the released
service. If the primary rights holder elects to not voluntarily release nonfirm
service, and does not use the service, the available transmission will be
released by default at 12:00, one business day before the start of service. On
June 30, 2021, the rate for the nonfirm service released by default was $10.00
per MWh. The primary rights holder remains obligated to pay for the released
service unless a second transmission customer acquires the released service.
Table 9-36 shows the percent of scheduled interchange across the Hudson
Line by the primary rights holder since commercial operations began in May,
2013. Table 9-36 shows that in the first six months of 2021, the primary rights
holder was responsible for less than 100 percent of the scheduled interchange
across the Hudson Line in all months. Figure 9-9 shows the hourly average
flow across the Hudson Line for the first six months of 2021.

To move power from PJM to NYISO on the Hudson Line, two PJM transmission
service reservations are required. A transmission service reservation is required
from the PJM Transmission System to the Hudson Line (“Out Service”) andanother transmission service reservation is required on the Hudson Line(“Hudson Service”).40 The PJM Out Service is covered by normal PJM OASIS
40 See OASIS “PJM Business Practices for Hudson Transmission Service,”<http://www.pjm.com/‌~/media/etools/oasis/merch-trans-facilities/
htp-Business-practices.ashx>.

454

Section 9 Interchange Transactions

41 See OASIS “Regional Transmission and Energy Scheduling Practices,” Rev. 9 (August 5, 2021) <http://www.pjm.com/~/media/etools/oasis/regional-practices-clean-doc.ashx>.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-36 Percent of scheduled interchange across the Hudson Line by
primary rights holder: May 2013 through June 202142
2013
NA
NA
NA
NA
100.00%100.00%100.00%100.00%100.00%100.00%85.57%
28.32%

January
February
March
April
May
June
July
AugustSeptember
OctoberNovember
December

2014
51.22%
49.00%
40.40%
100.00%26.87%
5.89%
18.51%
75.17%
75.31%
99.71%
99.60%
1.68%

2015
16.27%
14.67%
71.88%
100.00%100.00%59.72%
84.34%
65.48%
78.73%
18.65%
24.67%
100.00%2016
100.00%NA
NA
NA
100.00%100.00%NA
NA
NA
100.00%100.00%
NA

2017
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
80.12%
21.93%

201824.44%
23.25%
9.55%
15.13%
92.18%
44.89%
16.26%
19.24%
22.90%
22.67%
50.44%
29.38%

201952.21%
77.12%
72.42%
100.00%100.00%44.98%
36.43%
43.10%
43.42%
33.60%
44.36%
41.78%

Figure 9-9 Hudson hourly average flow: January through June, 2021
800
600

200
Volume (MWh)2021
37.64%
47.37%
53.27%
70.90%
65.15%
73.81%The PJM metered system peak load during the first six monthsof 2021 was 143,559 MW in the HE 1700 on June 29, 2021.
PJM was a net scheduled exporter of energy in all hours on
June 29, 2021, with average hourly scheduled exports of
4,498 MW. During HE 1700 on June 29, 2021, PJM had net
scheduled exports of 3,366 MW and net metered actual exportsof 3,389 MW. Net transaction exports during this time wereinconsistent with the price differences between PJM and MISO.
Net transaction exports were consistent with price differences
between PJM and the NYISO interfaces (NYIS, Neptune, Lindenand Hudson). During June 2021, PJM was a net scheduled exporter of energy
in all hours. During June 2021, the average hourly scheduled interchange was-5,609 MW (representing 5.9 percent of the average hourly load of 94,138
MW in June 2021).

Operating Agreements with Bordering Areas

400

Total Capacity
0
-200
-400
-600
-800

2020
29.70%
23.61%
87.24%
10.02%
20.53%
38.26%
27.56%
35.64%
30.75%
52.58%
38.60%
38.82%

Interchange Activity During High Load
Hours

Total Capacity

1

2

3

4

5

6

7

8

To improve reliability and reduce potential seams issues, PJM and its neighbors
have developed operating agreements, including: operating agreements withMISO and the NYISO; a reliability agreement with TVA; an operating agreementwith Duke Energy Progress, Inc.; a reliability coordination agreement with
VACAR South; a balancing authority operations agreement with the Wisconsin
Electric Power Company (WEC); and a Northeastern planning coordination
protocol with NYISO and ISO New England.
Table 9-37 shows a summary of the elements included in each of the operating
agreements PJM has with its bordering areas.

9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour ending (EPT)42 The designation of “NA” means there was no flow on the Hudson Line during those months.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 455

2021 Quarterly State of the Market Report for PJM: January through June

Table 9-37 Summary of elements included in operating agreements withbordering areas
VACAR Reserve
Agreement:
PJM-MISOPJM-NYISOPJM-TVAPJM-DEP PJM-VACAR
Sharing Agreement
Data Exhange
Real-Time Data
YES
YES
YES
YES
YES
NO
Projected Data
YES
YES
YES
YES
NO
SCADA Data
YES
YES
YES
YES
NO
EMS Models
YES
YES
YES
YES
NO
Operations Planning Data
YES
YES
YES
YES
NO
Available Flowgate Capability Data
YES
YES
YES
YES
NO
Near-Term System Coordination
Operating Limit Violation Assistance
YES
YES
YES
YES
YES
Over/Under Voltage Assistance
YES
YES
YES
YES
YES
Emergency Energy Assistance
YES
YES
NO
YES
YES
Outage Coordination
YES
YES
YES
YES
YES
Long-Term System Coordination
YES
YES
YES
YES
NO
Congestion Management Process
ATC Coordination
YES
YES
YES
YES
NO
Market Flow Calculations
YES
YES
YES
NO
NO
Firm Flow Entitlements
YES
YES
YES
NO
NO
Market to Market Redispatch
YES - Redispatch YES - RedispatchNO
NO
NO
Joint Checkout Procedures
YES
YES
YES
YES
NO
PJM-MISO = MISO/PJM Joint Operating Agreement
PJM-NYISO = New York ISO/PJM Joint Operating Agreement
PJM-TVA = Joint Reliablity Coordination Agreement Between PJM - Tennessee Valley Authority (TVA)
PJM-DEP = Duke Energy Progress (DEP) - PJM Joint Operating Agreement
PJM-VACAR = PJM-VACAR South Reliability Coordination Agreement
PJM-WEP = Balancing Authority Operations Coordination Agreement Between Wisconsin Electric Power Company and PJM Interconnection, LLC
Northeastern Protocol = Northeastern ISO-Regional Transmission Organization Planning Coordination Protocol

PJM and MISO Joint Operating Agreement43
The Joint Operating Agreement between MISO and PJM Interconnection,
L.L.C. was executed on December 31, 2003. The PJM/MISO JOA includes
provisions for market based congestion management that, for designatedflowgates within MISO and PJM, allow for redispatch of units within the PJM
and MISO regions to jointly manage congestion on these flowgates and toassign the costs of congestion management appropriately. In 2012, MISO andPJM initiated a joint stakeholder process to address issues associated with theoperation of the markets at the seam.44
43 See “Joint Operating Agreement Between the Midwest Independent Transmission System Operator, Inc. and PJM Interconnection, L.L.C.”(December 11, 2008) <http://www.pjm.com/directory/merged-tariffs/miso-joa.pdf>.
44 See “PJM/MISO Joint and Common Market Initiative,” <http://www.pjm.com/committees-and-groups/stakeholder-meetings/pjm-misojoint-common.aspx>.

456

Section 9 Interchange Transactions

PJM-WEP

Northeastern
Protocol

YES
NO
NO
NO
NO
NO

NO
NO
NO
YES
YES
YES

NO
NO
NO
NO
NO

NO
NO
NO
NO
YES

NO
NO
NO
NO
YES

NO
NO
NO
NO
NO

Under the market to market rules,
the organizations coordinate pricing
at their borders. PJM and MISO
each calculate an interface LMP
using network models including
distribution factor impacts. PJM
uses 10 buses along the PJM/MISO
border to calculate the PJM/MISO
interface pricing point LMP. Prior toJune 1, 2017, MISO used all of the
PJM generator buses in its model ofthe PJM system in its calculationof the MISO/PJM interface pricing
point.45 On June 1, 2017, MISO
modified their MISO/PJM interface
definition to match PJM’s PJM/MISO interface definition.46

An operating entity is an entity that
operates and controls a portion of
the bulk transmission system withthe goal of ensuring reliable energy
interchange between generators,
loads and other operating entities.47 Coordinated flowgates are identified todetermine which flowgates an operating entity affects significantly. This setof flowgates may then be used in the congestion management process. An
operating entity will conduct sensitivity studies to determine which flowgatesare significantly affected by the flows of the operating entity’s control zones(historic control areas that existed in the IDC). An operating entity identifies
these flowgates by performing five studies to determine which flowgatesthe operating entity will monitor and help control. These studies include
generation to load distribution factor studies, transfer distribution factor
45 See the 2012 State of the Market Report for PJM, Volume II, Section 8, “Interchange Transactions,” for a more detailed discussion.
46 See “Joint and Common Market: MISO-PJM Interface Pricing Update,” (November 15, 2016) <http://www.pjm.com/~/media/committeesgroups/stakeholder-meetings/pjm-miso-joint-common/20161115/20161115-item-03a-interface-pricing-post-implementation.ashx>.
47 See “Joint Operating Agreement Between the Midwest Independent Transmission System Operator, Inc. and PJM Interconnection, L.L.C.,”(December 11, 2008) <http://www.pjm.com/directory/merged-tariffs/miso-joa.pdf>.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

48 See “Joint Operating Agreement Between the Midwest Independent Transmission System Operator, Inc. and PJM Interconnection, L.L.C.,”(December 11, 2008) <http://www.pjm.com/directory/merged-tariffs/miso-joa.pdf>.

© 2021 Monitoring Analytics, LLC

PJM Credit$10,000,000

MISO Credit$8,000,000$6,000,000$4,000,000

Jun-21

Apr-21

May-21

Mar-21

Feb-21

Jan-21

Dec-20Nov-20

Oct-20

Sep-20Jul-20Aug-20Jun-20May-20$0

Apr-20$2,000,000

Mar-20April 1, 2004, known as the freeze date, is used to determine the firm rights
on flowgates based on historic premarket firm flows as of that date. In the past
16 years, topology and market changes have occurred, making the 2004 flows
irrelevant in 2021. The RTOs and stakeholders recognize that a modification to

Figure 9-10 PJM/MISO credits for coordinated congestion management:
January 2020 through June 202150

Feb-20The firm flow entitlement (FFE) represents the amount of historic 2004
flow that each RTO had created on each RCF used in the market to market
settlement process. The FFE establishes the amount of market flow that each
RTO is permitted to create on the RCF before incurring redispatch costs during
the market to market process. If the nonmonitoring RTO’s real-time market
flow is greater than their FFE plus the approved MW adjustment from dayahead coordination, then the nonmonitoring RTO will pay the monitoring
RTO based on the difference between their market flow and their FFE. If thenonmonitoring RTO’s real-time market flow is less than their FFE plus theapproved MW adjustment from day-ahead coordination, then the monitoring
RTO will pay the nonmonitoring RTO for congestion relief provided by thenonmonitoring RTO based on the difference between the nonmonitoring
RTO’s market flow and their FFE.

In the first six months of 2021, market to market operations resulted in MISO
and PJM redispatching units to control congestion on M2M flowgates andthe exchange of payments for this redispatch. Figure 9-10 shows credits for
coordinated congestion management between PJM and MISO.

Jan-20

As of January 1, 2021, PJM had 143 flowgates eligible for M2M (Market
to Market) coordination. In the first six months of 2021, PJM added 35
flowgates and deleted 12 flowgates, resulting in 166 flowgates eligible forM2M coordination as of June 30, 2021. As of January 1, 2021, MISO had
147 flowgates eligible for M2M coordination. In the first six months of 2021,
MISO added 39 flowgates and deleted 32 flowgates, resulting in 154 flowgates
eligible for M2M coordination as of June 30, 2021.

the freeze date is necessary.49 PJM and MISO stakeholders have spent several
years on the freeze date issues. Discussions regarding the Firm Flow Limit (FFL)
solutions between market and nonmarket areas are also ongoing. No resolution tothese issues appears imminent. The final resolution to the freeze date alternative
should account for the investments made by each RTO in the transmission
system. The MMU recommends modifications to the FFE calculation to ensurethat FFE calculations reflect the current capability of the transmission system as
it evolves. The MMU recommends that the Commission set a deadline for PJM
and MISO to resolve the FFE freeze date and related issues.

Creditanalysis and an external asynchronous resource study. An operating entity
may also specify additional flowgates that have not passed any of the fivestudies to be coordinated flowgates where the operating entity expects to use
the TLR process to manage congestion.48 A reciprocal coordinated flowgate(RCF) is a CF that is monitored and controlled by PJM or MISO, on which
both have significant impacts. Only RCFs are subject to the market to market
congestion management process.

49 See “Freeze Date Alternatives,” (May 21, 2019) <https://www.pjm.com/-/media/committees-groups/‌stakeholder-meetings/pjm-misojoint-common/20190521/20190521-item-01-freeze-date-update.ashx>.
50 The totals represented in this figure represent the settlements as of the time of this report and may not include adjustments orresettlements.

2021 Quarterly State of the Market Report for PJM: January through June 457

2021 Quarterly State of the Market Report for PJM: January through June

Figure 9-11 PJM/NYISO credits for coordinated congestion management(flowgates): January 2020 through June 202153

The Joint Operating Agreement between NYISO and PJM Interconnection,
L.L.C. became effective on January 15, 2013. Under the market to market
rules, the organizations coordinate pricing at their borders.

$8,000,000$6,000,000$4,000,000

Jun-21

May-21

Apr-21

Mar-21

Feb-21

Jan-21

Dec-20Nov-20

Oct-20

Sep-20Aug-20Jul-20Jun-20

Apr-20May-20$0Mar-20$2,000,000

Jan-20In the first six months of 2021, market to market operations did not result in
NYISO and PJM redispatching units to control congestion on M2M flowgates.
Therefore, there was no exchange of payments for redispatch in the firstsix months of 2021. Figure 9-11 shows credits for coordinated congestion
management between PJM and NYISO.

NYISO Credit

CreditOn June 28, 2019, NYISO and PJM submitted revisions to the NYISO-PJM
Joint Operating Agreement (JOA). The revisions would address RTO concerns
identified in their joint request for limited waiver of the JOA to authorize
redispatch of generation in PJM. The intent of the redispatch would be to
mitigate post-contingency overloads of transmission equipment on the
New York side of the East Towanda-Hillside 230 kV Transmission Line. The
agreement allows for the RTOs to control for this contingency without theexchange of payments for redispatch.52

PJM Credit$10,000,000

Feb-20PJM and New York Independent System Operator
Joint Operating Agreement (JOA)51

The M2M coordination process focuses on real-time market coordination
to manage transmission limitations that occur on M2M flowgates in a costeffective manner. Coordination between NYISO and PJM includes not only
joint redispatch, but also incorporates coordinated operation of the PARs thatare located at the PJM/NYIS border. This real-time coordination results inan efficient economic dispatch solution across both markets to manage thereal-time transmission constraints that impact both markets, focusing on theactual flows in real time to manage constraints.54 For each M2M flowgate, aPAR settlement will occur for each interval during coordinated operations.
The PAR settlements are determined based on whether the measured real-timeflow on each of the PARs is greater than or less than the calculated target
value. If the actual flow is greater than the target flow, NYISO will make
51 See “New York Independent System Operator, Inc., Joint Operating Agreement with PJM Interconnection, L.L.C.,” (September 16, 2019)<http://www.pjm.com/~/media/documents/‌agreements/nyiso-joa.ashx>.
52 See NYISO Filing, FERC Docket No. ER19-2282-000 (June 28, 2019).

458

Section 9 Interchange Transactions

53 The totals represented in this figure represent the settlements as of the time of this report and may not include adjustments orresettlements.
54 See “New York Independent System Operator, Inc., Joint Operating Agreement with PJM Interconnection, L.L.C.,” (September 16, 2019)<http://www.pjm.com/~/media/documents/‌agreements/nyiso-joa.ashx>.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

a payment to PJM. This payment is calculated as the product of the M2M
flowgate shadow price, the PAR shift factor and the difference between theactual and target PAR flow. If the actual flow is less than the target flow, PJM
will make a payment to NYISO. This payment is calculated as the product of theM2M flowgate shadow price, the PAR shift factor and the difference between
the target and actual PAR flow. Effective May 1, 2017, coincident with thetermination of the ConEd wheel, PJM and NYISO began M2M coordination
at all of the PARs along the PJM/NYISO seam. Prior to May 1, 2017, only theRamapo PARs were included in the M2M process. In the first six months of2021, market to market operations resulted in NYISO and PJM adjusting PARs
to control congestion and the exchange of payments for this coordination.
Figure 9-12 shows the PAR credits for coordinated congestion management
between PJM and NYISO.
Figure 9-12 PJM/NYISO credits for coordinated congestion management(PARs): January 2020 through June 202155$10,000,000

PJM Credit

The joint reliability coordination agreement (JRCA) executed on April 22,
2005, provides for the exchange of information and the implementation ofreliability and efficiency protocols between TVA and PJM. The agreement also
provides for the management of congestion and arrangements for both nearterm and long-term system coordination. Under the JRCA, PJM and TVA honor
constraints on the other’s flowgates in their Available Transmission Capability(ATC) calculations. Market flows are calculated on reciprocal flowgates. Whena constraint occurs on a reciprocal flowgate within TVA, PJM has the option
to redispatch generation to reduce market flow, and therefore alleviate theconstraint. Unlike the M2M procedure between MISO and PJM, this redispatch
does not result in M2M payments. However, electing to redispatch generation
within PJM can avoid potential market disruption by curtailing transactions
under the Transmission Line Loading Relief (TLR) procedure to achieve thesame relief. The agreement remained in effect in the first six months of 2021.

PJM and Duke Energy Progress, Inc. Joint Operating
Agreement57

NYISO Credit$8,000,000

On September 9, 2005, FERC approved a JOA between PJM and Progress Energy
Carolinas, Inc. (PEC), with an effective date of July 30, 2005. As part of thisagreement, both parties agreed to develop a formal congestion management
protocol (CMP). On February 2, 2010, PJM and PEC filed a revision to include
a CMP under Article 14 of the JOA.58 On January 20, 2011, the Commission
conditionally accepted the compliance filing. On July 2, 2012, Duke Energy
and Progress Energy Inc. completed a merger. At that time, Progress Energy
Carolinas Inc., now a subsidiary of Duke Energy, changed its name to Duke
Energy Progress (DEP).

Credit$6,000,000$4,000,000

55 The totals represented in this figure represent the settlements as of the time of this report and may not include adjustments orresettlements.

© 2021 Monitoring Analytics, LLC

Jun-21

May-21

Apr-21

Mar-21

Jan-21

Feb-21

Dec-20

Oct-20Nov-20

Sep-20Aug-20Jul-20Jun-20

Apr-20May-20Mar-20Jan-20Feb-20$2,000,000$0

PJM and TVA Joint Reliability Coordination
Agreement (JRCA)56

56 See “Joint Reliability Coordination Agreement Among and Between PJM Interconnection, L.L.C., and Tennessee Valley Authority,” (October
15, 2014) <http://www.pjm.com/~/media/documents/‌agreements/joint-reliability-coordination-agreement-miso-pjm-tva.ashx>.
57 See “Amended and Restated Joint Operating Agreement Among and Between PJM Interconnection, L.L.C., and Duke Energy Progress Inc.,”(July 22, 2019) <http://www.pjm.com/directory/merged-tariffs/progress-joa.pdf>.
58 See PJM Interconnection, L.L.C and Progress Energy Carolinas, Inc. Docket No. ER10-713-000 (February 2, 2010).

2021 Quarterly State of the Market Report for PJM: January through June 459

2021 Quarterly State of the Market Report for PJM: January through June

On May 20, 2019, PJM and DEP submitted revisions to the JOA to delete
Article 14.59 PJM and DEP requested an effective date of July 22, 2019, for the
filed revisions. On July 2, 2019, the Commission issued a letter order accepted
the revisions to the JOA to delete the congestion management agreement
effective July 22, 2019.60

There are issues with the VRSA. The details of the VRSA, including any
responsibilities assigned to PJM, are not public. Under PJM’s Operating
Reserve Demand Curve (ORDC) method of procuring reserves, expected to be
implemented on May 1, 2022, it will not be possible for Dominion to meetboth the VRSA and the PJM reserve rules.65

PJM and VACAR South Reliability Coordination
Agreement61

Balancing Authority Operations Coordination
Agreement between Wisconsin Electric Power
Company (WEC) and PJM Interconnection, LLC66

On May 23, 2007, PJM and VACAR South (comprised of Duke Energy
Carolinas, LLC (DUK), DEP, South Carolina Public Service Authority (SCPSA),Southeast Power Administration (SEPA), South Carolina Energy and Gas
Company (SCE&G) and Yadkin Inc. (a part of Alcoa)) entered into a reliability
coordination agreement which provides for system and outage coordination,
emergency procedures and the exchange of data. The parties meet on a yearlybasis. The agreement remained in effect in the first six months of 2021.

VACAR Reserve Sharing Agreement
The VACAR Reserve Sharing Agreement (VRSA) is a combination of agreements
among the entities in the VACAR Subregion including Dominion.62 VACAR isa subregion of the SERC Reliability Corporation (SERC) region. The agreement
remained in effect in the first six months of 2021. The agreement requires thateach entity maintain primary reserves to meet the VACAR contingency reserve
commitment (VACAR reserves) and deploy such reserves in the case of an
emergency (e.g. loss of a unit in VACAR).63 Dominion is the only party to the
VRSA that is also a transmission owner and a generation owner in PJM. The
VRSA is not a public agreement. PJM is not a party to the VRSA. However,as the reliability coordinator for Dominion Virginia Power, PJM is responsible
for scheduling Dominion’s required reserves in the SERC region as describedin the PJM manuals.64
59 See PJM Interconnection, L.L.C, Docket No. ER19-1905-000 (May 20, 2019).
60 FERC Docket No. ER19-1905-000 (July 2, 2019).
61 See “PJM-VACAR South RC Agreement,” (November 7, 2014) <http://www.pjm.com/~/media/‌documents/agreements/executed-pjmvacar-rc-agreement.ashx>.
62 VRSA entities: Dominion, Duke Energy Progress, Duke Energy Carolinas, South Carolina Electric & Gas Company, South Carolina PublicService Authority and Cube Hydro Carolinas.
63 See SERC Regional Criteria, Contingency Reserve Policy, NERC Reliability Standard BAL-002 at 10-11.
64 See PJM. “Manual 13: Emergency Operations,” Rev. 78 (January 27, 2021).

460

Section 9 Interchange Transactions

The Balancing Authority Operations Coordination Agreement executed on
July 20, 2013, provides for the exchange of information between WEC and
PJM. The purpose of the data exchange is to allow for the coordination ofbalancing authority actions to ensure the reliable operation of the systems.
The agreement remained in effect in the first six months of 2021.

Northeastern ISO-Regional Transmission Organization
Planning Coordination Protocol67
The Northeastern ISO-RTO Planning Coordination Protocol executed on
December 8, 2004, provides for the exchange of information among PJM,
NYISO and ISO New England. The purpose of the data exchange is to allow for
the long-term planning coordination among and between the ISOs and RTOs
in the Northeast. The agreement remained in effect in the first six months of2021.

Interchange Transaction Issues
PJM Transmission Loading Relief Procedures (TLRs)
TLRs are called to control flows on electrical facilities when economic
redispatch cannot solve overloads on those facilities. TLRs are called to control
65 See the 2021 Quarterly State of the Market Report for PJM: January through June, Section 10: Ancillary Services, “VACAR Reserve
Sharing Agreement” for more information on issues identified with the VACAR Reserve Sharing Agreement.
66 See “Balancing Authority Operations Coordination Agreement between Wisconsin Electric Power Company and PJM Interconnection,
L.L.C.,” (July 20, 2013) <https://www.pjm.com/directory/merged-tariffs/rs43.pdf>.
67 See “Northeastern ISO/RTO Planning Coordination Protocol,” (December 8, 2004) <http://www.pjm.com/~/media/documents/agreements/
northeastern-iso-rto-planning-coordination-protocol.ashx>.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

flows related to external balancing authorities, as redispatch within an LMP
market can generally resolve overloads on internal transmission facilities.
The number of PJM issued TLRs of level 3a or higher was zero in the firstsix months of 2020 and two in the first six months of 2021.68 The number ofdifferent flowgates for which PJM declared a TLR 3a or higher was zero in thefirst six months of 2020, and one in the first six months of 2021. The total
MWh of transactions curtailed was zero in the first six months of 2020 andzero in the first six months of 2021.
The number of MISO issued TLRs of level 3a or higher increased from 46 in
the first six months of 2020 to 48 in the first six months of 2021. The numberof different flowgates for which MISO declared a TLR 3a increased from 11 in
the first six months of 2020 to 14 in the first six months of 2021. The total
MWh of transaction curtailments increased by 26.4 percent from 45,864 MWhin the first six months of 2020 to 57,978 MWh in the first six months of 2021.
The number of NYISO issued TLRs of level 3a or higher decreased from two in
the first six months of 2020 to one in the first six months of 2021. The numberof different flowgates for which NYISO declared a TLR 3a or higher was one in
the first six months of 2020, and one in the first six months of 2021. The total
MWh of transaction curtailments decreased by 62.1 percent from 1,030 MWhin the first six months of 2020, to 390 MWh in the first six months of 2021.

Table 9-38 PJM, MISO, and NYISO TLR procedures: January through June,
202169Month
Jan-21
Feb-21
Mar-21
Apr-21
May-21
Jun-21
Total

Number of TLRs
Level 3 and Higher
PJM
MISO
NYISO
0
7
0
2
17
0
0
6
1
0
9
0
0
2
0
0
7
0
2
48
1

Number of Unique FlowgatesThat Experienced TLRs
PJM
MISO
NYISO
0
3
0
1
10
0
0
3
1
0
3
0
0
1
0
0
3
0
1
14
1

Curtailment Volume (MWh)
PJM
MISO
NYISO
0
1,642
0
0
38,912
0
0
4,776
390
0
7,259
0
0
1,964
0
0
3,425
0
0
57,978390

Table 9-39 Number of TLRs by TLR level by reliability coordinator: January
through June, 202170
Year
2021

Total

Reliability
Coordinator
MISO
NYIS
ONT
PJM
SOCO
SWPP
TVA
VACS

3a
20
1
0
0
0
3
5
1
30

3b
16
0
0
2
0
4
7
3
32

4
0
0
0
0
0
2
0
0
2

5a
7
0
0
0
0
17
11
0
35

5b
5
0
0
0
0
10
9
0
24

6
0
0
0
0
0
0
0
0
0

Total
48
1
0
2
0
36
32
4
123

Up To Congestion Transactions
The original purpose, in 2000, of up to congestion transactions (UTC) was toallow market participants to submit a maximum congestion charge, up to $25
per MWh, they were willing to pay on an import, export or wheel throughtransaction in the day-ahead energy market. This product was offered as atool for market participants to limit their congestion exposure on scheduledtransactions in the real-time energy market.71

68 TLR Level 3a is the first level of TLR that results in the curtailment of transactions. See the 2020 State of the Market Report for PJM,
Volume II, Appendix E, “Interchange Transactions,” for a more complete discussion of TLR levels.

© 2021 Monitoring Analytics, LLC

69 The total row in the columns of the number of unique flowgates that experience TLRs are not a sum of the individual months. The total
row represents the number of unique flowgates that have experienced TLRs for the year to date.
70 Southern Company Services, Inc. (SOCO) is the reliability coordinator covering a portion of Mississippi, Alabama, Florida and Georgia.
Southwest Power Pool (SWPP) is the reliability coordinator for SPP. VACAR-South (VACS) is the reliability coordinator covering a portionof North Carolina and South Carolina.
71 See the 2012 State of the Market Report for PJM, Volume II, Section 8, “Interchange Transactions,” for a more detailed discussion.

2021 Quarterly State of the Market Report for PJM: January through June 461

2021 Quarterly State of the Market Report for PJM: January through June

Up to congestion transaction volumes decreased following the allocation of
uplift charges to UTCs effective November 1, 2020. The average number ofup to congestion bids submitted in the day-ahead energy market decreasedby 82.5 percent, from 52,781 bids per day in the first six months of 2020
to 26,781 bids per day in the first six months of 2021. The average clearedvolume of up to congestion bids submitted in the day-ahead energy market
decreased by 59.8 percent, from 469,113 MWh per day in the first six monthsof 2020, to 188,479 MWh per day in the first six months of 2021.

Figure 9-13 Monthly up to congestion cleared bids in MWh: January 2005
through June 2021
60,000,000

50,000,000

Up to Congestion Cleared MWh

Up to congestion transactions affect the day-ahead dispatch and unit
commitment. Despite that, up to congestion transactions were not required
to pay uplift charges from their introduction in 2010 through October 31,
2020. On July 16, 2020, FERC issued an Order directing PJM to revise uplift
allocation rules to allocate uplift to one side of up to congestion transactions.72
The Order requires PJM to treat an up to congestion transaction, for uplift
allocation purposes, as if the up to congestion transaction were equivalent toa DEC at its sink point. On November 1, 2020, PJM began allocating uplift to
up to congestion transactions. Up to congestion transactions also negatively
affect FTR funding.73

40,000,000

30,000,000

20,000,000

10,000,000

072 172 FERC ¶ 61,046 (2020).
73 See the 2021 Quarterly State of the Market Report for PJM: January through June, Section 13: FTRs and ARRs, “FTR Forfeitures” for more
information on up to congestion transaction impacts on FTRs.

462

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-40 Monthly volume of cleared and submitted up to congestion bids: January 2020 through June 2021
Month
Jan-20Feb-20Mar-20
Apr-20May-20Jun-20Jul-20Aug-20
Sep-20
Oct-20Nov-20Dec-20Jan-21
Feb-21
Mar-21
Apr-21
May-21
Jun-21TOTAL

Import
5,709,294
5,676,276
6,665,180
6,091,885
6,271,609
6,831,949
7,876,157
7,758,436
7,498,635
3,329,528
1,930,357
1,719,227
2,282,816
2,560,448
2,517,187
2,221,212
1,702,148
1,138,201
79,780,544

Export2,231,205
2,666,146
2,978,585
2,682,191
1,965,274
2,804,284
2,322,606
2,285,138
3,279,523
3,582,220
707,420
1,017,140
1,938,192
1,732,756
947,439551,805
715,117
520,848
34,927,889

Bid MW
Wheel
Internal
Total
1,944,774 18,039,136 27,924,410
2,199,490 17,493,382 28,035,292
2,003,110 18,814,938 30,461,812
1,468,174
16,612,116 26,854,366
1,075,904 21,565,323
30,878,110
1,743,982 31,474,224 42,854,440
1,988,024 35,708,931 47,895,717
2,157,739 34,944,219 47,145,532
2,074,365 34,571,326 47,423,850
1,038,616 33,641,971 41,592,335
554,083 12,050,981 15,242,840
131,755 10,500,435 13,368,557
276,618 10,688,893 15,186,519
251,312 11,403,148 15,947,664
117,398 14,674,083 18,256,107
181,710 12,376,262 15,330,989
134,953 12,828,933 15,381,151
73,906 11,088,523 12,821,478
19,415,913 358,476,824 492,601,170

Import275,752
242,264
251,993
254,545
331,575
334,466
288,710
246,363236,272
116,339
57,03659,54278,521
79,571
78,177
67,57574,896
65,6493,139,246

Export162,609
146,844
161,948
137,594
137,922
159,856
109,436
101,479
113,749
118,061
33,28757,003
88,947
91,05250,61832,831
38,71845,8601,787,814

Bid Volume
Wheel
75,18365,051
66,56952,77560,794
63,796
65,63560,50368,01336,445
13,7298,237
15,555
12,982
9,589
6,639
7,785
4,682
693,962Internal
1,039,001
1,030,601
983,109893,782
1,273,857
1,404,345
1,425,030
1,307,254
1,249,116
1,185,280
654,986
576,292
607,025
641,265
669,293636,750
744,269
699,115
17,020,370

Total
1,552,545
1,484,760
1,463,619
1,338,696
1,804,148
1,962,463
1,888,811
1,715,599
1,667,150
1,456,125759,038
701,074
790,048824,870
807,677
743,795
865,668
815,306
22,641,392

MonthJan-20Feb-20Mar-20
Apr-20May-20Jun-20Jul-20Aug-20
Sep-20
Oct-20Nov-20Dec-20Jan-21
Feb-21
Mar-21
Apr-21
May-21
Jun-21TOTAL

Import2,898,979
2,612,370
2,858,559
2,865,235
2,683,033
2,446,275
2,327,354
2,885,456
2,759,958
1,170,266
473,510414,395
505,184
665,309591,031564,781442,299335,834
29,499,827

Export1,255,867
1,482,095
1,898,911
1,604,592
1,003,073
1,274,509
929,229965,737
1,311,305
1,614,110
372,486
595,040
926,449
998,094
618,699
177,129
181,378
299,253
17,507,957

Cleared MW
Wheel
Internal
Total
934,870
9,125,163 14,214,879
854,591
8,563,657 13,512,713
836,553
8,904,119 14,498,142
753,404
7,928,948 13,152,179
483,381
9,243,633 13,413,120
679,616 12,187,056 16,587,456
654,258 11,723,592 15,634,434
602,209 12,270,529 16,723,930
545,808
11,870,827 16,487,899
333,422 11,454,599 14,572,397
207,826
5,194,734
6,248,556
74,6614,240,307
5,324,402
85,441
3,896,822
5,413,896
144,146
5,150,556
6,958,106
63,162
5,247,981
6,520,873
72,851
4,059,957
4,874,718
46,3194,519,932
5,189,928
33,954
4,488,181
5,157,223
7,406,472 140,070,593 194,484,849

Import137,826
110,759
104,922
119,135
145,382
153,982
122,042
114,008
112,007
58,86925,97827,21532,02638,38430,02625,34330,27627,4901,415,670

Cleared Volume
ExportWheel
96,03540,54287,19032,242
101,540
33,17385,20928,416
69,53529,462
93,233
28,63067,44030,59456,585
26,662
54,772
24,40958,982
17,031
20,3006,857
36,578
4,791
41,6104,835
56,952
6,752
36,6996,398
20,672
3,991
21,686
4,028
31,522
3,063
1,036,540
331,876

Internal
564,363535,392
495,693454,794590,351
734,369
692,881665,354626,387559,349
363,785
322,872
327,824
362,064
333,759
306,151
379,282
385,387
8,700,057

Total
838,766
765,583
735,328
687,554834,730
1,010,214
912,957
862,609817,575
694,231416,920
391,456
406,295
464,152
406,882
356,157
435,272
447,462
11,484,143© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 463

2021 Quarterly State of the Market Report for PJM: January through June

In the first six months of 2021, the cleared MW volume of up to congestiontransactions was comprised of 9.1 percent imports, 9.4 percent exports, 1.3
percent wheeling transactions and 80.2 percent internal transactions. Less
than 0.1 percent of the up to congestion transactions had matching real-timeenergy market transactions.

Sham Scheduling
Sham scheduling refers to a scheduling method under which a market
participant breaks a single transaction, from generation balancing authority(source) to load balancing authority (sink), into multiple segments. Shamscheduling hides the actual source of generation from the load balancing
authority. When unable to identify the source of the energy, the load balancing
authority cannot see how the power will flow to the load, which can create
loop flows and result in inaccurate pricing for transactions.
For example, if the generation balancing authority (source) is NYISO, and theload balancing authority (sink) is PJM, the transaction would be priced, in the
PJM energy market, at the PJM/NYIS Interface regardless of the submitted
path. However, if a market participant were to break the transaction into
multiple segments, one on the NYIS-ONT path, and a second segment on the
ONT-MISO-PJM path, the market participant would conceal the true source(NYISO) from PJM, and PJM would price the transaction as if its source wereOntario (the ONT interface price).
Sham scheduling can also be achieved by submitting a transaction that is in
the opposite direction of a portion of a larger transaction schedule.
For example, market participants can submit one transaction with multiple
segments among balancing authorities and another transaction which offsets
all or part of a segment of the first transaction. If a market participant submits
two separate transactions, one on the ONT-MISO-PJM path, and a second on
the PJM-MISO path, the result of these transactions would be a net scheduledtransaction from ONT to MISO, as the MISO-PJM segment of the firsttransaction is offset by the PJM-MISO transaction. In this example, PJM is not
required to raise or lower generation as a result of these transactions, as they

464

Section 9 Interchange Transactions

would for an import or an export, and there are no associated power flows
across PJM. Nonetheless, the market participant is paid the price difference
between the PJM/ONT interface pricing point and the PJM/MISO interface
pricing point. The market participant would be paid the PJM/ONT interface
pricing point for the first transaction (ONT to PJM import) and the market
participant would pay the PJM/MISO interface pricing point for the second
transaction (PJM to MISO export). If the PJM/ONT interface price were higher
than the PJM/MISO interface price, the market participant would be paid a
net profit from the PJM market even though there was no impact on PJM
operations.
At the April 10, 2013, PJM Market Implementation Committee (MIC), the MMU
presented a problem statement and issue charge to address sham schedulingactivities.74 The expected deliverables from the stakeholder meetings wererevisions to the Tariff and PJM business manuals. The topic was discussed
at several MIC meetings. While there was stakeholder agreement that shamscheduling activity was inappropriate, consensus on revised tariff and manual
language was not achieved. The topic was closed. The MMU clarified that it
would continue to monitor transactions for sham scheduling activities andthat the MMU could refer market participants for sham scheduling activities.
The MMU monitors for sham scheduling activities on a daily basis. Following
the stakeholder discussions in 2013, the net profits obtained from shamscheduling activities fell by 101.0 percent, from net profits of $15.5 million
in 2014, to a net loss of $149,893 in 2020. The total number of hours ofsham scheduling segments where the MW profile matched exactly across all
segments of the path combinations in the same hour fell by 96.6 percent, from1,898 hours in 2014 to 64 hours in 2020.
The MMU recommends that PJM implement rules to prevent sham scheduling.
The MMU recommends that PJM apply after the fact market settlement
adjustments to identified sham scheduling segments to ensure that market
participants cannot benefit from sham scheduling.
74 See Market Path/Interface Pricing Point alignment Problem Statement, at: <http://www.monitoringanalytics.com/reports/
Presentations/2013/IMM_MIC_Market_Path_Interface_Pricing_Point_Alignment_Problem_Statement_201304010.pdf>.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Elimination of Ontario Interface Pricing Point
The PJM/IMO interface pricing point (Ontario) was created to reflect the factthat transactions that originate or sink in the IESO balancing authority create
actual energy flows that are split between the MISO and NYISO interface
pricing points. PJM created the PJM/IMO interface pricing point to reflect theactual power flows across both the MISO/PJM and NYISO/PJM interfaces. The
IMO does not have physical ties with PJM because it is not contiguous.
Prior to June 1, 2015, the PJM/IMO interface pricing point was defined as the
LMP at the IESO Bruce bus. The LMP at the Bruce bus includes a congestion
and loss component across the MISO and NYISO balancing authorities.
The noncontiguous nature of the PJM/IMO interface pricing point creates
opportunities for market participants to engage in sham scheduling activities.75
For example, a market participant can use two separate transactions to create
a flow from Ontario to MISO. In this example, the market participant uses thePJM energy market as a temporary generation and load point by first submitting
a wheeling transaction from Ontario, through MISO and into PJM, then bysubmitting a second transaction from PJM to MISO. These two transactions,combined, create an actual flow along the Ontario/MISO Interface. Throughsham scheduling, the market participant receives settlements from PJM whenno changes in generation occur. This activity is similar to that observed when
PJM had a Southwest and Southeast interface pricing point. During that time,
market participants would use the PJM spot market as a temporary load andgeneration point to wheel transactions through the PJM energy market. Thiswas done to take advantage of the price differences between the interfaces
without providing the market benefits of congestion relief.
A new PJM/IMO interface price method was implemented on June 1, 2015.
The new method uses a dynamic weighting of the PJM/MISO interface priceand the PJM/NYIS interface price, based on the performance of the MichiganOntario PARs. When the absolute value of the actual flows on the PARs are
greater than or equal to the absolute value of the scheduled flows on thePARs, and the scheduled and actual flows are in the same direction, the PJM/
75 See “Sham Scheduling,” Presented at the PJM Market Monitoring Unit Advisory Committee (MMUAC) meeting held on December 6, 2013<http://www.monitoringanalytics.com/‌reports/Presentations/2013/IMM_Sham_Scheduling_20131206.pdf>.

© 2021 Monitoring Analytics, LLC

IMO interface price will be equal to the PJM/MISO interface price (i.e. 100
percent weighting on the PJM/MISO Interface). When actual flows on thePARs are in the opposite direction of the scheduled flows on the PARs, thePJM/IMO interface price will be equal to the PJM/NYIS interface price (i.e.
100 percent weighting on the PJM/NYIS Interface). When the absolute valueof the actual flows on the PARs are less than or equal to the absolute value ofthe scheduled flows on the PARs, and the scheduled and actual flows are in
the same direction, the PJM/IMO interface price will be a combination to the
PJM/MISO interface price and the PJM/NYIS interface price. In this case theweightings of the PJM/MISO and PJM/NYIS interface prices are determinedbased on the scheduled and actual flows. For example, in a given interval, thescheduled flow on the Michigan-Ontario PARs is 1,000 MW, and the actual
flow is 800 MW. If in that same interval, the PJM/MISO interface price is$45.00 and the PJM/NYIS interface price $30.00, the PJM/IMO interface pricewould be calculated with a weighting of 80 percent of the PJM/MISO interface
price ($45.00 * 0.8, or $36.00) and 20 percent of the PJM/NYIS interface price($30.00 * 0.2, or $6.00), for a PJM/IMO interface price of $42.00.
The MMU believes that the new PJM/IMO interface price method is a step inthe right direction towards pricing energy that sources or sinks in Ontario
based on the path of the actual, physical transfer of energy. The MMU remains
concerned about the assumption of PAR operations, and will continue toevaluate the impact of PARs on the scheduled and actual flows and theimpacts on the PJM/IMO interface price. The MMU remains concerned about
the potential for market participants to continue to engage in sham schedulingactivities after the new method is implemented.
The MMU recommends that if the PJM/IMO interface price remains and with
PJM’s new method in place, that PJM implement additional business rules toremove the incentive to engage in sham scheduling activities using the PJM/
IMO interface price. Such rules would prohibit the same market participantfrom scheduling an export transaction from PJM to any balancing authority
while at the same time an import transaction is scheduled to PJM that receives
the PJM/IMO interface price. PJM should also prohibit the same market
participant from scheduling an import transaction to PJM from any balancing

2021 Quarterly State of the Market Report for PJM: January through June 465

2021 Quarterly State of the Market Report for PJM: January through June

authority while at the same time an export transaction is scheduled from PJM
that receives the PJM/IMO interface price.
In the first six months of 2021, of the 422 GWh of gross scheduled transactions
between PJM and IESO, 406 GWh (96.2 percent) wheeled through MISO (Table
9-25). The MMU recommends that PJM eliminate the PJM/IMO interface
pricing point, and assign the transactions that originate or sink in the IESO
balancing authority to the PJM/MISO interface pricing point.76

PJM and NYISO Coordinated Interchange Transactions
Coordinated transaction scheduling (CTS) provides the option for market
participants to submit intra-hour transactions between the NYISO and PJM
that include an interface spread bid on which transactions are evaluated.77
The evaluation is based on the forward-looking prices as determined by PJM’s
intermediate term security constrained economic dispatch tool (IT SCED) andthe NYISO’s real-time commitment (RTC) tool. PJM shares its PJM/NYISO
interface price IT SCED results with the NYISO. The NYISO compares the PJM/
NYISO interface price with its RTC calculated NYISO/PJM interface price. If the
PJM and NYISO interface price spread is greater than the market participant’s
CTS bid, the transaction is approved. If the PJM and NYISO interface pricespread is less than the CTS bid, the transaction is denied.

10.5 percent of all intervals, the absolute value of the average price difference
between the IT SCED forecasted LMP and the actual real-time interface LMP
was greater than $20.00. The average price differences were $65.81 when
the price difference was greater than $20.00, and $137.27 when the pricedifference was greater than -$20.00.
Table 9-41 Differences between forecast and actual PJM/NYIS interface
prices: January through June, 2021
Range of Price Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Percent of All Intervals
6.7%
6.1%
8.7%
37.2%
31.4%
4.0%
2.1%
3.8%

Average Price Difference$65.81$14.12
$7.09
$1.64
$1.41
$6.93
$14.28$137.27

Table 9-42 shows how the accuracy of the IT SCED forecasted LMPs changes
as the cases approach real-time. In the final IT SCED results prior to realtime, in 71.6 percent of all intervals, the average price difference between the
IT SCED forecasted LMP and the actual real-time interface LMP fell within+/- $5.00 of the actual PJM/NYIS interface real-time LMP, compared to 61.2
percent in the 135 minute ahead IT SCED results.

The IT SCED application runs every five minutes and each run produces
forecast LMPs for the intervals approximately 30 minutes, 45 minutes, 90
minutes and 135 minutes ahead. Therefore, for each 15 minute interval, thevarious IT SCED solutions will produce 12 forecasted PJM/NYIS interface
prices. To evaluate the accuracy of IT SCED forecasts, the forecasted PJM/
NYIS interface price for each 15 minute interval from IT SCED was comparedto the actual real-time interface LMP for the first six months of 2021. Table
9-41 shows that over all 12 forecast ranges, IT SCED predicted the real-time
PJM/NYIS interface LMP within the range of $0.00 to $5.00 in 37.2 percentof the intervals. In those intervals, the average price difference between the IT
SCED forecasted LMP and the actual real-time LMP was $1.64 per MWh. In
76 On October 1, 2013, a sub-group of PJM’s Market Implementation Committee started stakeholder discussions to address thisinconsistency in market pricing.
77 PJM and the NYISO implemented CTS on November 4, 2014. 146 FERC ¶ 61,096 (2014).

466

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-42 Differences between forecast and actual PJM/NYIS interface prices: January through June, 2021
Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20~ 135 Minutes Prior to
Real-Time
Percent of Average Price
Intervals
Difference
10.6%$64.948.8%$14.39
10.3%
$7.19
34.5%
$1.84
26.7%
$1.54
3.5%
$6.94
2.1%
$14.37
3.6%$142.09~ 90 Minutes Prior to
Real-Time
Percent of Average Price
Intervals
Difference
10.7%$62.808.5%$14.26
10.3%
$7.20
34.8%
$1.82
26.6%
$1.54
3.5%
$6.90
1.9%
$14.343.6%$140.85~ 45 Minutes Prior to
Real-Time
Percent of Average Price
Intervals
Difference
4.2%$62.164.9%$14.08
7.8%
$7.11
33.6%
$1.59
37.6%
$1.51
5.4%
$6.90
2.3%
$14.034.1%$132.25~ 30 Minutes Prior to
Real-Time
Percent of Average Price
Intervals
Difference
4.2%$61.66
4.9%$13.99
7.6%
$7.08
33.8%
$1.60
37.8%
$1.49
5.3%
$6.89
2.5%
$14.044.0%$135.91

In 8.2 percent of the intervals in the 30 minute ahead forecast, the absolute value of the average price difference between the IT SCED forecasted LMP and theactual real-time interface LMP was greater than $20.00. The average price difference was $61.66 when the price difference was greater than $20.00, and $135.91
when the price difference was greater than -$20.00.
Table 9-43 and Table 9-44 show the monthly differences between forecasted and actual PJM/NYIS interface prices. Analysis of the data on a monthly basis
shows that there is a decline in the accuracy of the IT SCED forecast during periods of cold and hot weather.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 467

2021 Quarterly State of the Market Report for PJM: January through June

Table 9-43 Monthly Differences between forecast and actual PJM/NYIS
interface prices (percent of intervals): January through June, 2021
Interval~ 30 Minutes
Prior to Real-TimeInterval~ 45 Minutes
Prior to Real-TimeInterval~ 90 Minutes
Prior to Real-TimeInterval~ 135 Minutes
Prior to Real-Time

468

Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20

Table 9-44 Monthly differences between forecast and actual PJM/NYIS
interface prices (average price difference): January through June, 2021

Jan
6.4%
4.5%
5.6%
28.0%
42.1%
4.0%
2.5%
7.0%

Feb
11.8%
10.1%
9.5%
27.1%
24.2%
5.6%
4.5%
7.3%

Mar
0.9%
2.6%
4.9%
34.1%
46.3%
5.9%
2.0%
3.3%

Apr
1.6%
4.3%
11.2%
40.5%
35.2%
4.3%
1.8%
1.1%

May
1.0%
2.2%
6.9%
35.0%
43.1%
7.2%
2.2%
2.4%

Jun
4.1%
6.1%
7.8%
38.1%
34.3%
4.5%
2.0%
3.0%

YTD Avg
4.2%
4.9%
7.6%
33.8%
37.8%
5.3%
2.5%
4.0%

Jan
6.8%
3.7%
5.7%
27.9%
42.4%
3.8%
2.6%
7.1%

Feb
11.8%
9.8%
10.3%
26.4%
23.5%
6.1%
4.3%
7.8%

Mar
0.9%
2.8%
5.3%
34.0%
46.1%
6.1%
1.8%
3.1%

Apr
1.4%
4.9%
11.2%
40.7%
34.2%
4.3%
1.8%
1.4%

May
1.0%
2.4%
7.1%
34.1%
43.5%
7.5%
1.8%
2.4%

Jun
4.1%
6.1%
7.5%
38.3%
34.3%
4.7%
1.9%
3.1%

YTD Avg
4.2%
4.9%
7.8%
33.6%
37.6%
5.4%
2.3%
4.1%

Jan
14.1%
8.3%
7.3%
25.6%
32.5%
3.6%
2.1%
6.6%

Feb
15.2%
10.2%
10.5%
24.0%
22.2%
5.5%
5.1%
7.4%

Mar
8.6%
8.0%
10.7%
39.5%
27.2%
2.6%
1.0%
2.4%

Apr
9.5%
10.9%
14.9%
39.4%
20.8%
2.6%
1.1%
0.8%

May
5.4%
7.1%
10.4%
40.0%
29.9%
3.9%
1.3%
2.0%

Jun
11.7%
7.1%
8.2%
39.3%
26.4%
3.3%
1.3%
2.8%

YTD Avg
10.7%
8.5%
10.3%
34.8%
26.6%
3.5%
1.9%
3.6%

Jan
13.8%
8.4%
7.4%
25.0%
33.1%
3.3%
2.5%
6.5%

Feb
15.5%
10.8%
10.0%
23.6%
21.9%
5.4%
5.4%
7.4%

Mar
8.2%
8.1%
10.7%
39.5%
27.6%
2.6%
0.9%
2.5%

Apr
9.2%
11.7%
14.5%
39.4%
20.8%
2.6%
1.0%
0.8%

May
5.7%
6.7%
10.6%
39.6%
30.2%
4.0%
1.3%
2.0%

Jun
11.4%
7.4%
8.8%
39.0%
26.1%
3.1%
1.5%
2.7%

YTD Avg
10.6%
8.8%
10.3%
34.5%
26.7%
3.5%
2.1%
3.6%

Section 9 Interchange Transactions

Interval~ 30 Minutes
Prior to Real-TimeInterval~ 45 Minutes
Prior to Real-TimeInterval~ 90 Minutes
Prior to Real-TimeInterval~ 135 Minutes
Prior to Real-Time

Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Jan$44.95$14.69
$7.01
$1.33
$1.41
$6.83
$13.92$145.03Feb$73.81$14.35
$7.26
$1.80
$1.51
$7.19
$13.85$157.03Mar$39.78$14.07
$6.78
$1.33
$1.40
$6.85
$13.66$161.81Apr$31.47$13.09
$7.00
$1.81
$1.44
$6.78
$14.90$45.06

May$51.34$13.33
$6.99
$1.71
$1.65
$6.78
$13.45$104.99Jun$75.21$13.76
$7.36
$1.59
$1.55
$6.93
$14.82$95.98YTD Avg$61.66$13.99
$7.08
$1.60
$1.49
$6.89
$14.04$135.91Jan$45.33$14.78
$7.10
$1.39
$1.43
$6.86
$14.04$144.06

Feb$74.95$14.21
$7.33
$1.73
$1.46
$7.20
$13.61$149.23Mar$43.12$14.13
$6.92
$1.36
$1.43
$6.80
$14.19$166.30Apr$32.04$13.88
$7.02
$1.80
$1.46
$6.76
$14.21$41.75May$48.27$13.65
$6.84
$1.68
$1.66
$6.85
$13.74$102.57Jun$74.92$13.79
$7.38
$1.58
$1.59
$6.94
$14.89$93.93YTD Avg$62.16$14.08
$7.11
$1.59
$1.51
$6.90
$14.03$132.25Jan$47.82$14.46
$7.17
$1.73
$1.53
$6.88
$14.62$147.42Feb$71.96$14.46
$7.45
$1.79
$1.56
$7.15
$14.25$153.79Mar$49.65$13.99
$7.04
$1.68
$1.41
$6.62
$14.92$200.12Apr$28.90$14.42
$7.22
$1.94
$1.45
$6.93
$13.14$43.55May$76.52$13.93
$7.27
$1.87
$1.62
$6.86
$14.12$103.17Jun$101.55$14.14
$7.01
$1.87
$1.63
$6.80
$15.00$95.05YTD Avg$62.80$14.26
$7.20
$1.82
$1.54
$6.90
$14.34$140.85Jan$48.55$14.52
$7.40
$1.71
$1.54
$6.85
$14.68$150.33

Feb$73.92$14.49
$7.27
$1.73
$1.54
$7.34
$14.30$153.71Mar$50.91$14.21
$7.05
$1.69
$1.41
$6.76
$14.44$194.79Apr$29.52$14.34
$7.16
$1.96
$1.49
$6.85
$13.31$43.92

May$76.18$14.36
$7.33
$1.88
$1.59
$6.77
$14.20$105.27

Jun$107.48$14.40
$6.99
$1.97
$1.68
$6.83
$14.90$98.11YTD Avg$64.94$14.39
$7.19
$1.84
$1.54
$6.94
$14.37$142.09© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

16,00014,000Consistent With Price Difference
Inconsistent With Price Difference

12,00010,000
8,000
6,000
4,000

May-21

Nov-20May-20Nov-19

May-19

Nov-18May-18

Nov-17May-17

Nov-16May-160

Nov-152,000

May-15

CTS transactions were evaluated for each 15 minute interval. From November
4, 2014, through June 30, 2021, 444,516 15 minute CTS schedules wereapproved through the CTS process based on the forecast LMPs. When theforecast LMPs for the approved intervals were compared to the hourly
integrated real-time LMPs, the direction of the flow in 142,701 (32.1 percent)of the intervals was inconsistent with the differences in real-time PJM/NYISO
and NYISO/PJM prices. For example, if a market participant submits a CTS
transaction from NYISO to PJM with a spread bid of $5.00, and NYISO’s
forecasted PJM interface price was at least $5.00 lower than PJM’s forecasted
NYISO interface price, the transaction would be approved. For 32.1 percentof the approved transactions, the actual, real-time price differentials werein the opposite direction of the forecast differential. The actual, real-time

Figure 9-14 Monthly cleared PJM/NYIS CTS bid volume: November 4, 2014
through June 30, 2021

Nov-14

CTS transactions are evaluated based on the spread bid, which limits theamount of price convergence that can occur. As long as balancing operating
reserve charges are applied and CTS transactions are optional, the CTS proposal
represents a small incremental step toward better interface pricing. The NYISO
has a 75 minute bid submission deadline. While market participants have theoption to specify bid data on 15 minute intervals, market participants must
submit their bids 75 minutes prior to the requested transaction start time.
The 75 minute bid submission deadline associated with scheduling energy
transactions in the NYISO should be shortened. Reducing this deadline could
significantly improve pricing efficiency at the PJM/NYISO border for nonCTS transactions and for CTS transactions as market participants would be
able to adjust their bids in response to real-time price signals.

price differentials meant that the transactions would have been economic
in the opposite direction. For 67.9 percent of the intervals, the forecast pricedifferentials were consistent with real-time PJM/NYISO and NYISO/PJM pricedifferences. Figure 9-14 shows the monthly volume of cleared PJM/NYIS CTS
bids. Figure 9-14 also shows the percent of cleared bids that resulted in flows
consistent and inconsistent with price differences.

CTS Bid Volume

The NYISO uses PJM’s IT SCED forecasted LMPs to compare against the NYISO
Real-Time Commitment (RTC) results in its evaluation of CTS transactions.
The NYISO approves CTS (spread bid) transactions when the offered spreadis less than or equal to the spread between the IT SCED forecast PJM/NYIS
interface LMP and the NYISO RTC forecast NYIS/PJM interface LMP. The
large differences between forecast and actual LMPs in the intervals closest to
real-time could cause CTS transactions to be approved that would contributeto transactions being scheduled counter to real-time economic signals, andcontribute to inefficient scheduling across the PJM/NYIS border.

Month

The data reviewed show that IT SCED is not a highly accurate predictor of thereal-time PJM/NYIS interface prices. This limits the effectiveness of CTS in
improving interface pricing between PJM and NYISO.

2021 Quarterly State of the Market Report for PJM: January through June 469

2021 Quarterly State of the Market Report for PJM: January through June

Reserving Ramp on the PJM/NYISO Interface
Prior to the implementation of CTS, PJM held ramp space for all transactions
submitted between PJM and the NYISO as soon as the NERC Tag was approved.
At that time, once transactions were evaluated by the NYISO through theirreal-time market clearing process, any adjustments made to the submitted
transactions would be reflected on the NERC Tags and the PJM ramp was
adjusted accordingly.
As part of this process, PJM was often required to make adjustments totransactions on its other interfaces in order to bring total system ramp back towithin its limit. The default ramp limit in PJM is +/- 1,000 MW. For example,
the ramp in a given interval is currently -1,000 MW, consisting of 2,000 MW
of imports from the NYISO to PJM and 3,000 MW of exports from PJM on its
other interfaces. If, through the NYISO real-time market clearing process, the
NYISO only approves 1,000 MW of the imports, the other 1,000 MW of importtransactions from the NYISO would be curtailed. The ramp in this interval
would then be -2,000 MW, consisting of the 1,000 MW of cleared imports
from the NYISO to PJM and 3,000 MW of exports from PJM on its otherinterfaces. PJM would then be required to curtail an additional 1,000 MW
of exports at its other interface to bring the limit back to within +/- 1,000.
These curtailments were made on a last in first out basis as determined by thetimestamp on the NERC Tag.
With the implementation of the CTS product with the NYISO, PJM modified
how ramp is handled at the PJM/NYISO Interface. Effective November 4, 2014,
PJM no longer holds ramp room for any transactions submitted between PJM
and the NYISO at the time of submission. Only after the NYISO completes its
real-time market clearing process, and communicates the results to PJM, does
PJM perform a ramp evaluation on transactions scheduled with the NYISO.
If, in the event the NYISO market clearing process would violate ramp, PJM
would make additional adjustments based on a last-in first-out basis as
determined by the timestamp on the NERC Tag. This process prevents thetransactions scheduled at the PJM/NYISO Interface from holding (or creating)ramp until NYISO has completed its economic evaluation and the transactions
are approved through the NYISO market clearing process.
470

Section 9 Interchange Transactions

PJM and MISO Coordinated Interchange Transaction
Proposal
PJM and MISO proposed the implementation of coordinated interchangetransactions, similar to the PJM/NYISO approach, through the Joint andCommon Market Initiative. The PJM/MISO coordinated transaction scheduling(CTS) process provides the option for market participants to submit intra-hourtransactions between the MISO and PJM that include an interface spread bid
on which transactions are evaluated. Similar to the PJM/NYISO approach,the evaluation is based, in part, on the forward-looking prices as determined
by PJM’s intermediate term security constrained economic dispatch tool (ITSCED). Unlike the PJM/NYISO CTS process in which the NYISO performs theevaluation, the PJM/MISO CTS process uses a joint clearing process in which
both RTOs share forward looking prices. On October 3, 2017, PJM and MISO
implemented the CTS process.
The IT SCED application runs every five minutes and each run produces
forecast LMPs for the intervals approximately 30 minutes, 45 minutes, 90
minutes and 135 minutes ahead. Therefore, for each 15 minute interval, thevarious IT SCED solutions will produce 12 forecasted PJM/MISO interface
prices. To evaluate the accuracy of IT SCED forecasts, the forecasted PJM/MISO interface price for each 15 minute interval from IT SCED was comparedto the actual real-time interface LMP for the first six months of 2021. Table
9-45 shows that over all 12 forecast ranges, IT SCED predicted the real-time
PJM/MISO interface LMP within the range of $0.00 to $5.00 in 36.6 percent
of all intervals. In those intervals, the average price difference between the IT
SCED forecasted LMP and the actual real-time LMP was $1.69. In 9.9 percent
of all intervals, the absolute value of the average price difference between
the IT SCED forecasted LMP and the actual real-time interface LMP was
greater than $20.00. The average price differences were $55.89 when the pricedifference was greater than $20.00, and $77.46 when the price difference wasgreater than -$20.00.

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Table 9-45 Differences between forecast and actual PJM/MISO interface prices: January through June, 2021
Range of Price Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Percent of All Intervals
6.4%
7.1%
8.6%
36.6%
32.0%
3.7%
2.1%
3.5%

Average Price Difference$55.89$14.07
$7.17
$1.69
$1.48
$6.88
$14.01$77.46

Table 9-46 shows how the accuracy of the IT SCED forecasted LMPs change as the cases approach real-time. In the final IT SCED results prior to real-time, in
70.6 percent of all intervals, the average price difference between the IT SCED forecasted LMP and the actual real-time interface LMP fell within +/- $5.00 of
the actual PJM/MISO interface real-time LMP, compared to 65.7 percent in the 135 minute ahead IT SCED results.
Table 9-46 Differences between forecast and actual PJM/MISO interface prices: January through June, 2021
Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20~ 135 Minutes Prior to
Real-Time
Percent of Average Price
Intervals
Difference
7.8%$45.24
7.6%$14.39
8.0%
$7.08
33.2%
$1.78
32.5%
$1.65
4.6%
$6.92
2.5%
$14.053.8%$76.83~ 90 Minutes Prior to
Real-Time
Percent of Average Price
Intervals
Difference
7.7%$44.487.4%$14.39
7.8%
$7.10
33.7%
$1.78
32.6%
$1.64
4.4%
$6.89
2.6%
$13.85
3.8%$76.42~ 45 Minutes Prior to
Real-Time
Percent of Average Price
Intervals
Difference
4.0%$52.606.9%$13.81
8.1%
$7.17
34.5%
$1.70
36.1%
$1.57
4.3%
$6.84
2.3%
$14.083.8%$75.44~ 30 Minutes Prior to
Real-Time
Percent of Average Price
Intervals
Difference
4.0%$52.82
6.5%$13.74
8.4%
$7.20
35.0%
$1.67
35.6%
$1.55
4.3%
$6.87
2.3%
$13.983.8%$74.86

In 7.8 percent of the intervals in the 30 minute ahead forecast, the absolute value of the average price difference between the IT SCED forecasted LMP and theactual real-time interface LMP was greater than $20.00, the average price differences were $52.82 when the price difference was greater than $20.00, and $74.86
when the price difference was greater than -$20.00.
Table 9-47 and Table 9-48 show the monthly differences between forecasted and actual PJM/MISO interface prices. Analysis of the data on a monthly basis
shows that there is a decline in the accuracy of the IT SCED forecast during periods of cold and hot weather.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 471

2021 Quarterly State of the Market Report for PJM: January through June

Table 9-47 Monthly differences between forecast and actual PJM/MISO
interface prices (percent of intervals): January through June, 2021
Interval~ 30 Minutes
Prior to Real-TimeInterval~ 45 Minutes
Prior to Real-TimeInterval~ 90 Minutes
Prior to Real-TimeInterval~ 135 Minutes
Prior to Real-Time

472

Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20

Table 9-48 Monthly differences between forecast and actual PJM/MISO
interface prices (average price difference): January through June, 2021

Jan
0.9%
2.4%
3.8%
36.9%
48.4%
3.6%
2.0%
2.1%

Feb
9.9%
4.7%
6.5%
32.9%
31.5%
5.3%
2.7%
6.6%

Mar
1.7%
3.5%
7.5%
37.7%
40.1%
4.3%
1.8%
3.5%

Apr
5.1%
12.1%
14.0%
33.1%
26.3%
4.3%
2.0%
3.0%

May
0.9%
6.9%
9.8%
34.1%
37.4%
4.6%
2.9%
3.4%

Jun
6.4%
9.4%
9.0%
35.3%
29.1%
3.6%
2.5%
4.8%

YTD Avg
4.0%
6.5%
8.4%
35.0%
35.6%
4.3%
2.3%
3.8%

Jan
1.0%
2.6%
3.6%
36.4%
49.0%
3.4%
2.0%
2.1%

Feb
9.6%
5.4%
6.6%
32.2%
31.7%
5.0%
3.0%
6.6%

Mar
1.7%
3.9%
7.1%
37.4%
40.5%
4.0%
2.0%
3.4%

Apr
5.5%
12.7%
12.5%
32.2%
27.9%
4.3%
2.2%
2.9%

May
1.0%
7.5%
9.5%
32.9%
38.1%
5.0%
2.6%
3.4%

Jun
6.0%
9.5%
9.2%
35.8%
28.5%
3.9%
2.4%
4.7%

YTD Avg
4.0%
6.9%
8.1%
34.5%
36.1%
4.3%
2.3%
3.8%

Jan
2.3%
3.0%
3.9%
37.5%
46.5%
3.0%
1.8%
2.0%

Feb
11.4%
4.7%
6.6%
31.6%
30.1%
5.0%
4.0%
6.6%

Mar
3.5%
5.9%
8.2%
37.2%
34.8%
4.3%
2.4%
3.6%

Apr
13.2%
12.6%
11.3%
29.7%
23.5%
4.8%
2.3%
2.6%

May
5.1%
10.2%
8.9%
32.4%
32.5%
5.3%
2.5%
3.1%

Jun
11.5%
8.2%
8.1%
33.4%
27.6%
3.8%
2.5%
4.9%

YTD Avg
7.7%
7.4%
7.8%
33.7%
32.6%
4.4%
2.6%
3.8%

Jan
2.2%
3.0%
4.0%
37.5%
46.4%
3.1%
1.7%
2.1%

Feb
11.8%
4.7%
6.2%
31.7%
30.0%
5.1%
3.9%
6.6%

Mar
3.5%
6.0%
8.3%
36.9%
35.1%
4.4%
2.2%
3.6%

Apr
13.3%
12.5%
12.3%
28.3%
23.0%
5.5%
2.3%
2.7%

May
5.0%
10.7%
9.0%
31.5%
32.6%
5.7%
2.4%
3.1%

Jun
11.5%
8.8%
8.2%
33.1%
27.2%
3.8%
2.7%
4.8%

YTD Avg
7.8%
7.6%
8.0%
33.2%
32.5%
4.6%
2.5%
3.8%

Section 9 Interchange Transactions

Interval~ 30 Minutes
Prior to Real-TimeInterval~ 45 Minutes
Prior to Real-TimeInterval~ 90 Minutes
Prior to Real-TimeInterval~ 135 Minutes
Prior to Real-Time

Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Range of Price
Differences> $20$10 to $20$5 to $10
$0 to $5
$0 to -$5-$5 to -$10-$10 to -$20
< -$20Jan$31.30$13.55
$6.84
$1.45
$1.36
$6.88
$14.15$61.67Feb$60.02$13.93
$7.06
$1.55
$1.48
$7.05
$13.83$58.63Mar$125.91$13.50
$7.02
$1.64
$1.62
$6.88
$14.19$113.80Apr$29.41$13.83
$7.26
$2.03
$1.74
$6.75
$13.51$49.22

May$25.20$13.96
$7.19
$1.71
$1.68
$6.84
$13.76$88.55Jun$48.24$13.53
$7.55
$1.69
$1.50
$6.83
$14.50$78.41YTD Avg$52.82$13.74
$7.20
$1.67
$1.55
$6.87
$13.98$74.86Jan$30.86$14.14
$6.86
$1.45
$1.38
$6.78
$14.11$60.66

Feb$60.30$14.39
$7.21
$1.51
$1.44
$6.72
$13.59$59.71

Mar$126.02$13.55
$6.99
$1.71
$1.66
$6.85
$13.73$114.46Apr$29.56$13.84
$7.18
$2.11
$1.72
$6.80
$13.98$50.07May$25.38$13.84
$7.10
$1.76
$1.69
$6.89
$14.15$88.43Jun$48.75$13.44
$7.49
$1.70
$1.56
$7.00
$14.90$79.26YTD Avg$52.60$13.81
$7.17
$1.70
$1.57
$6.84
$14.08$75.44Jan$27.95$14.55
$6.97
$1.60
$1.48
$6.84
$13.97$60.91

Feb$56.15$14.67
$7.13
$1.54
$1.53
$6.98
$13.59$61.47

Mar$75.15$13.96
$6.93
$1.86
$1.77
$6.78
$12.92$114.68Apr$32.10$14.49
$7.13
$2.08
$1.80
$7.00
$14.11$51.01May$27.20$14.20
$7.27
$1.77
$1.64
$6.91
$14.36$92.86Jun$49.52$14.61
$7.06
$1.86
$1.71
$6.78
$14.30$75.71YTD Avg$44.48$14.39
$7.10
$1.78
$1.64
$6.89
$13.85$76.42Jan$26.98$14.42
$6.93
$1.57
$1.51
$7.07
$13.81$61.55Feb$56.37$14.23
$7.18
$1.60
$1.54
$7.11
$14.02$61.65Mar$77.07$14.12
$7.05
$1.84
$1.81
$7.00
$13.25$115.73Apr$32.16$14.60
$7.12
$2.06
$1.78
$6.88
$14.16$50.20May$27.54$14.14
$7.20
$1.81
$1.63
$6.75
$14.09$92.93Jun$51.30$14.69
$6.94
$1.87
$1.74
$6.80
$14.77$77.63YTD Avg$45.24$14.39
$7.08
$1.78
$1.65
$6.92
$14.05$76.83© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

Figure 9-15 Monthly cleared PJM/MISO CTS bid volume: October 3, 2017
through June 30, 2021

18,00016,000Consistent With Price Difference
Inconsistent With Price Difference

14,000CTS Bid Volume

12,00010,000
8,000
6,000
4,000

Apr-21

Oct-20

Apr-20

Oct-19Apr-19Oct-180

Apr-182,000

Oct-17

CTS transactions were evaluated for each interval. From October 3, 2017,
through June 30, 2021, 203,878 CTS schedules were approved throughthe CTS process based on the forecast LMPs. When the forecast LMPs forthe approved intervals were compared to the hourly integrated real-time
LMPs, the direction of the flow in 37,636 (18.5 percent) of the intervals wasinconsistent with the differences in real-time PJM/MISO and MISO/PJM
prices. For example, if a market participant submits a CTS transaction fromMISO to PJM with a spread bid of $5.00, and MISO’s forecasted PJM interface
price was at least $5.00 lower than PJM’s forecasted MISO interface price, thetransaction would be approved. For 18.5 percent of the approved transactions,the actual, real-time price differentials were in the opposite direction of theforecast differential. The actual, real-time price differentials meant that thetransactions would have been economic in the opposite direction. For 81.5
percent of the intervals, the forecast price differentials were consistent withreal-time PJM/MISO and MISO/PJM price differences. Figure 9-15 shows themonthly volume of cleared PJM/MISO CTS bids. Figure 9-15 also shows thepercent of cleared bids that resulted in flows consistent and inconsistent withprice differences.

Month

The data reviewed show that IT SCED is not a highly accurate predictor of thereal-time PJM/MISO interface prices. This limits the effectiveness of CTS in
improving interface pricing between PJM and MISO.

Willing to Pay Congestion and Not Willing to Pay
Congestion
When reserving nonfirm transmission, market participants have the option tochoose whether or not they are willing to pay congestion. When the market
participant elects to pay congestion, PJM operators redispatch the system ifnecessary to allow the energy transaction to continue to flow. The system
redispatch often creates price separation across buses on the PJM system.
The difference in LMPs between two buses in PJM is the congestion cost (and© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 473

2021 Quarterly State of the Market Report for PJM: January through June

losses) that the market participant pays inorder for their transaction to continue toflow.
The MMU recommended that PJM modify
the not willing to pay congestion product toaddress the issues of uncollected congestion
charges. The MMU recommended charging
market participants for any congestion
incurred while the transaction is loaded,regardless of their election of transmission
service, and restricting the use of notwilling to pay congestion transactions (aswell as all other real-time external energy
transactions) to transactions at interfaces.

Table 9-49 Monthly uncollected congestion charges: January 2010 throughJune 2021
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

2010
$148,764$542,575$287,417$31,255$41,025$169,197$827,617$731,539$119,162$257,448$30,843$127,176$3,314,018

2011$3,102$1,567$0$4,767$0$1,354$1,115$37$0($31,443)($795)($659)($20,955)

2012
$0
($15)
$0
($68)
($27)
$78
$0
$0
$0
($6,870)($4,678)($209)($11,789)

On April 12, 2011, the PJM Market Implementation Committee (MIC) endorsed
the changes recommended by the MMU. The elimination of internal sources
and sinks on transmission reservations addressed most of the MMU concerns,
as there can no longer be uncollected congestion charges for imports to
PJM or exports from PJM. There is still potential exposure to uncollected
congestion charges in wheel through transactions, and the MMU will continue
to evaluate if additional mitigation measures would be appropriate to address
this exposure.
Table 9-49 shows that since the inception of the business rule change on
April 12, 2013, there was uncollected congestion in only two months (January
2016 and February 2019). In both months, there was negative uncollected
congestion. The negative congestion means that market participants who
used the not willing to pay congestion transmission option for their wheel
through transactions had transactions that flowed in the direction opposite tocongestion. When market participants use the not willing to pay congestion
product, it also means that they are not willing to receive congestion credits,which was the case in both January 2016 and February 2019.

474

Section 9 Interchange Transactions

2013
$5
$249
$0
($3,114)
$0
$0
$0
$0
$0
$0
$0
$0
($2,860)

2014
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0

2015
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0

2016
($44)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
($44)

2017
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0

2018
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0

2019
$0
($69,992)
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
($69,992)

2020
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0

2021
$0
$0
$0
$0
$0
$0

$0

Spot Imports
Figure 9-16 shows the spot import service use for the NYISO Interface, and forall other interfaces, from January 1, 2013 through June 30, 2021. The yellow
line shows the total monthly MWh of spot import service reserved and theorange line shows the total monthly MWh of tagged spot import service. The
gray shaded area between the yellow and orange lines represents the MWh ofretracted spot import service and may represent potential hoarding volumes.
This ATC was initially reserved, but not tagged (used). It is possible that in someinstances the reserved transmission consisted of the only available ATC which
could have been used by another market participant had it not been reserved
and not used. The blue shaded area between the orange line and green shaded
area represents the MWh of curtailed transactions using spot import service.
This area may also represent hoarding opportunities, particularly at the NYISO
Interface. In this instance, it is possible that while the market participant
reserved and scheduled the transmission, they may have submitted purposely
uneconomic bids in the NYISO market so that their transaction would becurtailed, yet their transmission would not be retracted. The NYISO allows formarket participants to modify their bids on an hourly basis, so these market
participants can hold their transmission service and evaluate their bids hourly,
while withholding the transmission from other market participants that may
wish to use it. The green shaded area represents the total settled MWh of spot

© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

import service. Figure 9-16 shows that while there are proportionally fewer
retracted MWh on the NYISO Interface than on all other interfaces, the NYISO
has proportionally more curtailed MWh. This is a result of the NYISO market
clearing process.78
Figure 9-16 Spot import service use: January 2013 through June 2021
3,000,000

NYISO Interface

Volume (MWh)Retracted
Curtailed2,000,000

Settled MW
Reserved
Tagged1,000,0000Interfaces other than NYISO
Volume (MWh)3,000,000

2,000,000

1,000,000

0The MMU continues to recommend that PJM permit unlimited spot market
imports (as well as all nonfirm point to point willing to pay congestion
imports and exports) at all PJM interfaces.

Interchange Optimization
When PJM prices are higher than prices in surrounding balancing authorities,
imports will flow into PJM until the prices are approximately equal. This is
an appropriate market response to price differentials. Given the nature of
78 See the 2018 State of the Market Report for PJM, Volume II, Section 9, “Interchange Transactions,” for a more complete discussion of thehistory of spot import transmission service.

© 2021 Monitoring Analytics, LLC

interface pricing and the treatment of interface transactions, it is not possible
for PJM system operators to reliably predict the quantity or sustainability ofsuch imports. The inability to predict interchange volumes creates additional
challenges for PJM dispatch in trying to meet loads, especially on high loaddays. If all external transactions were submitted as real-time dispatchable
transactions during emergency conditions, PJM would be able to include
interchange transactions in its supply stack, and dispatch only enoughinterchange to meet the demand.
The MMU recommends that the submission deadline for real-time dispatchable
transactions be modified from 1800 on the prior day to three hours prior to
the requested start time, and that the minimum duration be modified from one
hour to 15 minutes.79 These changes would give PJM a more flexible productthat could be used to meet load based on economic dispatch rather thanguessing the sensitivity of the transactions to price changes.
In addition to changing prices, transmission line loading relief procedures(TLRs), market participants’ curtailments for economic reasons, andexternal balancing authority curtailments affect the duration of interchangetransactions.
The MMU recommends that PJM explore an interchange optimization solution
with its neighboring balancing authorities that would remove the need formarket participants to schedule physical transactions across seams. Such asolution would include an optimized, but limited, joint dispatch approachthat uses supply curves and treats seams between balancing authorities asconstraints, similar to other constraints within an LMP market.

Interchange Cap During Emergency Conditions
An interchange cap is a limit on the level of interchange permitted
for nondispatchable energy using spot import or hourly point to pointtransmission. An interchange cap is a nonmarket intervention which should
be a temporary solution and should be replaced with a market based solution
79 The minimum duration for a real-time dispatchable transaction was modified to 15 minutes as per FERC Order No. 764.

2021 Quarterly State of the Market Report for PJM: January through June 475

2021 Quarterly State of the Market Report for PJM: January through June

as soon as possible. Since the approval of this process on October 30, 2014,
PJM has not yet needed to implement an interchange cap.
The purpose of the interchange cap is to help ensure that actual interchange
more closely meets operators’ expectations of interchange levels wheninternal PJM resources, e.g. CTs or demand response, are dispatched to meetthe peak load. Once these resources have been called on, PJM must honor theirminimum operating constraints regardless of whether additional interchangethen materializes. Therefore any interchange received in excess of what was
expected can have a suppressive effect on energy and reserve pricing andresult in increased uplift.
PJM will notify market participants of the possible use of the interchange cap
the day before. The interchange cap will be implemented for the forecasted
peak and surrounding hours during emergency conditions.
The interchange cap will limit the acceptance of spot import and hourly nonfirm
point to point interchange (imports and exports) not submitted as real timewith price transactions once net interchange has reached the interchange cap
value. Spot imports and hourly nonfirm point to point transactions submitted
prior to the implementation of the interchange cap will not be limited. In
addition, schedules with firm or network designated transmission service will
not be limited either, regardless of whether net interchange is at or above thecap.
The calculation of the interchange cap is based on the operator expectationof interchange at the time the cap is calculated plus an additional margin.
The margin is set at 700 MW, which is half of the largest contingency on thesystem. The additional margin also allows interchange to adjust to the loss ofa unit or deviation between actual load and forecasted load. The interchange
cap is based on the maximum sustainable interchange from PJM reliability
studies.

45 Minute Schedule Duration RulePJM limits the change in interchange volumes on 15 minute intervals. Thesechanges are referred to as ramp. The PJM ramp limit is designed to limit
the change in the amount of imports or exports in each 15 minute interval
to account for the physical characteristics of the generation to respond tochanges in the level of imports and exports. The purpose of imposing aramp limit is to help ensure the reliable operation of the PJM system. The
1,000 MW ramp limit per 15 minute interval was based on the availabilityof ramping capability by generators in the PJM system. The limit is basedon the assumption that the available generation in the PJM system can only
move 1,000 MW over any 15 minute period, although there is no supporting
analysis. As an example of how the ramp limit works, if at 0800 the sum of all
external transactions were -3,000 MW (negative sign indicates net exporting),
the limit for 0815 would be -2,000 MW to -4,000 MW. In other words, thestarting or ending of transactions would be limited so that the overall change
from the previous 15 minute period would not exceed 1,000 MW in either
direction.
In 2008, there was an increase in 15 minute external energy transactions thatcaused swings in imports and exports submitted in response to intrahour LMPchanges. This activity was due to market participants’ ability to observe pricedifferences between RTOs in the first third of the hour, and predict the directionof the price difference on an hourly integrated basis. Large quantities of MW
would then be scheduled between the RTOs for the last 15 minute interval tocapture those hourly integrated price differences with relatively little risk ofprices changing. This increase in interchange on 15 minute intervals created
operational control issues, and in some cases led to an increase in upliftcharges due to calling on resources with minimum run times greater than 15
minutes needed to support the interchange transactions. As a result, a new
business rule was proposed and approved that required all transactions to beat least 45 minutes in duration.
On June 22, 2012, FERC issued Order No. 764, which required transmission
providers to give transmission customers the option to schedule transmission
service at 15 minute intervals to reflect more accurate power production

476

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 9 Interchange Transactions

forecasts, load and system conditions.80 81 On April 17, 2014, FERC issued its
order which found that PJM’s 45 minute duration rule was inconsistent with
Order No. 764.82
PJM and the MMU issued a statement indicating ongoing concern aboutmarket participants’ scheduling behavior, and a commitment to address anyscheduling behavior that raises operational or market manipulation concerns.83

MISO Multi-Value Project Usage Rate (MUR)MISO defines a multi-value project (MVP) to be a project which, according
to MISO, enables the reliable and economic delivery of energy in support ofpublic policy needs, provides multiple types of regional economic value orprovides a combination of regional reliability and economic value.84 On July
15, 2010, MISO submitted revisions to the MISO Tariff to implement criteria
for identifying and allocating the costs of MVPs.85 On December 16, 2010, theCommission accepted the proposed MVP charge for export and wheel-throughtransactions, except for transactions that sink in PJM.86 The Commission statedthat MISO had not shown that their proposal did not constitute a resumptionof rate pancaking along the MISO-PJM seam. Following the December 16,
2010, Order, MISO began applying a multi-value usage rate (MUR) to monthly
net actual energy withdrawals, export schedules and through schedules withthe exception of transactions sinking in PJM. The MUR charge was applied to
the relevant transactions in addition to the applicable transmission, ancillary
service and network upgrade charges.
On June 7, 2014, the U.S. Court of Appeals for the Seventh Circuit granted
a petition for review regarding the Commission’s determination in the MVP
Order and MVP Rehearing Order.87 The Court ordered the Commission toconsider on remand whether, in light of current conditions, what if any
80 Order No. 764, 139 FERC ¶ 61,246, order on reh’g, Order No. 764-A, 141 FERC ¶ 61231 (2012).
81 Id. at P 51.
82 See Id. at P 12.
83 See joint statement of PJM and the MMU re Interchange Scheduling issued July 29, 2014 <http://www.monitoringanalytics.com/reports/
Market_Messages/Messages/PJM_IMM_Statement_on_Interchange_Scheduling_20140729.pdf>.
84 See MISO. MTEP “Multi Value Project Portfolio Analysis,” <https://cdn.misoenergy.org/‌2011%20MVP%20Portfolio%20Analysis%20Full%20
Report117059.pdf>.
85 See Midwest Independent Transmission Operator Inc. filing, Docket No. ER10-1791-000 (July 15, 2010).
86 133 FERC ¶ 61,221; order on reh’g, 137 FERC ¶ 61,074 (2011).
87 Illinois Commerce Commission, et al. v. FERC, 721 F.3d 764, 778–780 (7th Cir. 2013).

© 2021 Monitoring Analytics, LLC

limitations on export pricing to PJM by MISO are justified.88 The Seventh
Circuit highlighted the fact that at the time of the Commission’s decision toprohibit rate pancaking on transactions between MISO and PJM, all of MISO’stransmission projects were local and provided only local benefits.89
On July 13, 2016, FERC issued an order permitting MISO to collect charges
associated with MVPs for all transactions sinking in PJM, effective
immediately.90 The July 13th Order noted that in light of “the development oflarge scale wind generation capable of serving both MISO’s and its neighbors’
energy policy requirements in the western areas of MISO; the reported needof PJM entities to access those resources; and the reported need for MISO
to build new transmission facilities to deliver the output of those resources
within MISO for export… it is appropriate to allow MISO to assess the MVP
usage charge for transmission service used to export to PJM just as MISO
assesses the MVP usage charge for transmission service used to export energy
to other regions.”91
The policy rationale for permitting MISO to impose transmission costs on PJM
market participants without clear criteria is weak and results in pancaking ofrates. The impact is expected to increase.
Table 9-50 shows the projected usage rate to be collected for all wheels
through and exports from MISO, including those that sink in PJM, for 2021
through 2040.92 As shown in Table 9-4, there were 1,073.8 GWh of imports
from MISO in the first six months of 2021. At the 2021 MUR of $1.67 per
MWh, PJM market participants paid $1.8 million towards the costs of MISO’s
multi value projects. It is not clear whether the MUR charge has affectedinterchange volumes from MISO into PJM.

88 Id. at 780.
89 Id. at 779.
90 156 FERC ¶ 61,034 (2016).
91 Id. at P 55.
92 See MISO, “Schedule 26A Indicative Annual Charges,” (August 5, 2020) <https://cdn.‌misoenergy.org/Schedule%2026A%20Indicative%20
Annual%20Charges106365.xlsx>.

2021 Quarterly State of the Market Report for PJM: January through June 477

2021 Quarterly State of the Market Report for PJM: January through June

Table 9-50 MISO projected multi value project usage rate: 2021 through 2040
Year
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040

478

Total Indicative MVP Usage Rate ($/MWh)
$1.67
$1.65
$1.64
$1.77
$1.75
$1.73
$1.72
$1.70
$1.69
$1.67
$1.65
$1.64
$1.62
$1.61
$1.59
$1.58
$1.56
$1.55
$1.53
$1.52

Section 9 Interchange Transactions© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Ancillary Service Markets

Table 10-2 The day-ahead scheduling reserve market results were competitive

FERC defined six ancillary services in Order No. 888: scheduling, system
control and dispatch; reactive supply and voltage control from generation
service; regulation and frequency response service; energy imbalance service;
operating reserve—synchronized reserve service; and operating reserve—
supplemental reserve service.1 PJM provides scheduling, system control
and dispatch, and reactive on a cost basis. PJM provides regulation, energy
imbalance, synchronized reserve, and supplemental reserve services throughmarket mechanisms.2 Although not defined by FERC as an ancillary service,
black start service plays a comparable role. Black start service is provided on
the basis of formula rates.
The MMU analyzed measures of market structure, conduct and performancefor the PJM Synchronized Reserve Market, the PJM DASR Market, and the
PJM Regulation Market in the first six months of 2021.
Table 10-1 The tier 2 synchronized reserve market results were competitive
Market Element
Market Structure: Regional Markets
Participant Behavior
Market Performance

Evaluation
Not Competitive
Competitive
Competitive

Market Design

Mixed• The tier 2 synchronized reserve market structure was evaluated as notcompetitive because of high levels of supplier concentration.

• Participant behavior was evaluated as competitive because the market

Market Element
Market Structure
Participant Behavior
Market Performance

Evaluation
Not Competitive
Mixed
Competitive

percent of hours where the DASRMCP was greater than $0.01 in the firstsix months of 2021.

• Participant behavior was evaluated as mixed because while most offers
were equal to marginal costs, a significant proportion of offers reflectedeconomic withholding.

• Market performance was evaluated as competitive because there wereadequate offers in every hour to satisfy the requirement and the clearing
prices reflected those offers, although there is concern about offers above
the competitive level affecting prices. The day-ahead scheduling reserve
market clearing price was above $0 in 448 hours in the first six months of2021. In 98.1 percent of hours when the clearing price was above $0, theclearing price was the offer price of the marginal unit. In the remaining
1.9 percent of hours, the price included lost opportunity cost.

• Market design was evaluated as mixed because the DASR product does notinclude performance obligations. Offers should be based on opportunity
cost only, to ensure competitive outcomes and that market power cannot
be exercised.

Table 10-3 The regulation market results were not competitiveof participant behavior with the market design results in competitive
prices.

Market Element
Market Structure
Participant Behavior
Market Performance• Market design was evaluated as mixed. Market power mitigation

rules result in competitive outcomes despite high levels of supplierconcentration. However, tier 1 reserves are inappropriately compensatedwhen the nonsynchronized reserve market clears with a nonzero price.

Mixed• The DASR market would have failed a three pivotal supplier test in 45.8

rules require cost-based offers.

• Market performance was evaluated as competitive because the interaction

Market Design

Evaluation
Not Competitive
Competitive
Not Competitive

Market Design

Flawed• The regulation market structure was evaluated as not competitive because
the PJM Regulation Market failed the three pivotal supplier (TPS) test in
87.7 percent of the hours in the first six months of 2021.

1 75 FERC ¶ 61,080 (1996).
2 Energy imbalance service refers to the real-time energy market.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 479

2021 Quarterly State of the Market Report for PJM: January through June

• Participant behavior in the PJM Regulation Market was evaluatedas competitive in the first six months of 2021 because market power
mitigation requires competitive offers when the three pivotal supplier test
is failed, although the inclusion of a positive margin raises questions.

• Market performance was evaluated as not competitive, because all units
are not paid the same price on an equivalent MW basis.

• Market design was evaluated as flawed. The market design has failed

to correctly incorporate a consistent implementation of the marginal
benefit factor in optimization, pricing and settlement. The market results
continue to include the incorrect definition of opportunity cost. The
result is significantly flawed market signals to existing and prospective
suppliers of regulation.

Overview
Primary Reserve
PJM’s primary reserves are made up of resources, both synchronized andnonsynchronized, that can provide energy within 10 minutes. Primaryreserve is PJM’s implementation of the NERC 15-minute contingency reserve
requirement.3
PJM determines the primary reserve requirement based on the most severe
single contingency plus 190 MW in every approved RT SCED case. Every realtime market solution calculates the available tier 1 synchronized reserve. The
required synchronized reserve and nonsynchronized reserve are calculated
and dispatched in every real-time market solution, and there are associatedclearing prices (SRMCP and NSRMCP) assigned every five minutes. Scheduled
resources are credited based on a dispatched assignment and a five minuteclearing price.

Market Structure• Supply. Primary reserve is satisfied by both synchronized reserve(generation or demand response currently synchronized to the grid and3 See PJM. “Manual 10: Pre-Scheduling Operations,” § 3.1.1 Day-ahead Scheduling (Operating Reserve, Rev. 39 (Nov. 19, 2020).

480

Section 10 Ancillary Services

available within 10 minutes), and nonsynchronized reserve (generation
currently off line but available to start and provide energy within 10
minutes).

• Demand. The PJM primary reserve requirement is 150 percent of the most
severe single contingency plus 190 MW. In the first six months of 2021,
the average primary reserve requirement was 2,427.3 MW in the RTO
Zone and 2,427.2 in the MAD Subzone.

Tier 1 Synchronized Reserve
Synchronized reserve is provided by generators and demand response resources
synchronized to the grid and capable of increasing output or decreasing load
within 10 minutes in response to a PJM declared synchronized reserve event.
Synchronized reserve consists of tier 1 and tier 2 synchronized reserves.
Tier 1 synchronized reserve is the capability of online resources following
economic dispatch to ramp up in 10 minutes from their current output in
response to a synchronized reserve event. There is no formal market for tier 1
synchronized reserve.

• Supply. No offers are made for tier 1 synchronized reserves. The market

solution estimates tier 1 synchronized reserve as available 10 minuteramp from the energy dispatch. In the first six months of 2021, there wasan average hourly supply of 1,611.4 MW of tier 1 available in the RTO
Zone and an average hourly supply of 807.9 MW of tier 1 synchronizedreserve available within the MAD Subzone.

• Demand. The synchronized reserve requirement is calculated for eachreal-time dispatch solution as the most severe single contingency plus
190 MW within both the RTO Zone and the MAD Subzone.

• Tier 1 Synchronized Reserve Event Response. Tier 1 synchronized reserveis paid when a synchronized reserve event occurs and it responds. Whena synchronized reserve event is called, all tier 1 response is paid forincreasing its output (or reducing load for demand response) at the rateof $50 per MWh in addition to LMP.4 This is the Synchronized Energy
Premium Price.

4 See PJM. “Manual 11: Energy & Ancillary Services Market Operations,”§ 4.2.10 Settlements, Rev. 115 (June 1, 2021).

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services• Issues. The competitive offer for tier 1 synchronized reserves is zero, as

there is no incremental cost associated with the ability to ramp up fromthe current economic dispatch point and the appropriate payment for
responding to an event is the synchronized energy premium price of $50
per MWh. The tariff requires payment of the tier 2 synchronized reserve
market clearing price to tier 1 resources whenever the nonsynchronizedreserve market clearing price rises above zero. This requirement is
unnecessary and inconsistent with efficient markets. This change had asignificant impact on the cost of tier 1 synchronized reserves, resulting ina windfall payment of $89,719,045 to tier 1 resources in 2014, $34,397,441
in 2015, $4,948,084 in 2016, $2,197,514 in 2017, $4,732,025 in 2018, and$3,217,178 in 2019. The nonsynchronized reserve market clearing price
was above $0 in 2,015 intervals (1.9 percent of intervals) in 2020 resulting
in a payment to tier 1 resources of $3,319,263. In the first six months of2021, the nonsynchronized reserve market clearing price was above $0
in 29.6 percent of all intervals resulting in a net payment of $2,372,703.

Tier 2 Synchronized Reserve Market
Tier 2 synchronized reserve is part of primary reserve and is comprisedof resources that are synchronized to the grid, that may incur costs to besynchronized, and that have an obligation to respond to PJM declaredsynchronized reserve events. Tier 2 synchronized reserve is penalized for
failure to respond to a PJM declared synchronized reserve event. In PJM therequired amount of synchronized reserve is defined to be no less than thelargest single contingency, and 10 minute primary reserve as no less than
150 percent of the largest single contingency, plus 190 MW. This is stricter
than the NERC standard of the greater of 80 percent of the largest single
contingency or 900 MW.5
When the synchronized reserve requirement cannot be met with tier 1
synchronized reserve, PJM uses the tier 2 synchronized reserve market tosatisfy the balance of the requirement. The tier 2 synchronized reserve market
includes the PJM RTO Reserve Zone and a subzone, the Mid-Atlantic Dominion
Reserve Subzone (MAD).

Market Structure• Supply. In the first six months of 2021, the supply of daily offered andeligible tier 2 synchronized reserve was 36,322.9 MW in the RTO Zone ofwhich 4,649.6 MW was located in the MAD Subzone.

• Demand. The average hourly synchronized reserve requirement was 1,699.5
MW in the RTO Reserve Zone and 1,672.6 in the Mid-Atlantic Dominion
Reserve Subzone. The hourly average cleared tier 2 synchronized reserve
was 239.7 MW in the MAD Subzone and 612.6 MW in the RTO.

• Market Concentration. Both the Mid-Atlantic Dominion Subzone Tier 2

Synchronized Reserve Market and the RTO Synchronized Reserve Zone
Market were characterized by structural market power in the first six
months of 2021.
The average HHI for tier 2 synchronized reserve in the RTO Zone was5235 which is classified as highly concentrated.

Market Conduct• Offers. There is a must offer requirement for tier 2 synchronized reserve.

All nonemergency generation capacity resources are required to submit adaily offer for tier 2 synchronized reserve, unless the unit type is exempt.
Tier 2 synchronized reserve offers from generating units are subject toan offer cap of marginal cost plus $7.50 per MW, plus opportunity costwhich is calculated by PJM. PJM automatically enters an offer of $0 fortier 2 synchronized reserve when an offer is not entered by the owner.

Market Performance• Price. The weighted average price for tier 2 synchronized reserve forall cleared hours in the MAD subzone was $5.54 per MW in the firstsix months of 2021. The weighted average price for tier 2 synchronizedreserve for all cleared intervals in the RTO Synchronized Reserve Zone
was $5.48 per MW in the first six months of 2021.

5 NERC (June 2, 2020) <NERC Reliability Standard BAL 002-2 Glossary_of_Terms.pdf>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 481

2021 Quarterly State of the Market Report for PJM: January through June

Nonsynchronized Reserve Market
Nonsynchronized reserve is part of primary reserve and includes the RTO
Reserve Zone and the Mid-Atlantic Dominion Reserve Subzone (MAD).
Nonsynchronized reserve is comprised of nonemergency energy resources not
currently synchronized to the grid that can provide energy within 10 minutes.
Nonsynchronized reserve is available to fill the primary reserve requirement
above the synchronized reserve requirement. Generation owners do not
submit supply offers for nonsynchronized reserve. PJM defines the demand
curve for nonsynchronized reserve and PJM defines the supply curve based onnonemergency generation resources that are available to provide energy andcan start in 10 minutes or less (based on offer parameters), and on the resource
opportunity costs calculated by PJM.

Market Structure• Supply. In the first six months of 2021, the average supply of eligible andavailable nonsynchronized reserve was 1,537.3 MW in the RTO Zone.

• Demand. Demand for nonsynchronized reserve equals the primary reserve

requirement minus the tier 1 synchronized reserve estimate and minus thescheduled tier 2 synchronized reserve.6• Market Concentration. The MMU calculates that the three pivotal supplier

test would have been failed in 95.6 percent of intervals where the price
was above $0.01 in the first six months of 2021.

Market Conduct• Offers. Generation owners do not submit supply offers. Nonemergency

generation resources that are available to provide energy and can start in
10 minutes or less are considered available for nonsynchronized reservesby the market solution software. PJM calculates the associated offer
prices based on PJM calculations of resource specific opportunity costs.

6 See PJM. “Manual 11: Energy & Ancillary Services Market Operations,” § $b.2.2 Non-Synchronized Reserve Zones and Levels, Rev. 115(June 1, 2021). “Because Synchronized Reserve may be utilized to meet the Primary Reserve requirement, there is no explicit requirement
for non-synchronized reserves. “

482

Section 10 Ancillary Services

Market Performance• Price. The nonsynchronized reserve price is determined by the opportunity

cost of the marginal nonsynchronized reserve unit. The nonsynchronizedreserve weighted average price for all intervals in the RTO Reserve Zone
was $0.25 per MW in the first six months of 2021.

Secondary Reserve (DASR)
There is no NERC standard for secondary reserve. PJM defines secondary
reserve in the day-ahead market as reserves (online or offline available fordispatch) that can be converted to energy in 30 minutes. PJM defines asecondary reserve requirement but is not required to maintain this level ofsecondary reserve in real time.
PJM maintains a day-ahead, offer-based market for 30 minute day-ahead
secondary reserve. The PJM Day-Ahead Scheduling Reserve Market (DASR) has
no performance obligations except that a unit which clears the DASR market
may not be on an outage in real time.7 If DASR units are on an outage in realtime or cleared DASR MW are not available, the DASR payment is not made.

Market Structure• Supply. The DASR market is a must offer market. Any resources that do

not make an offer have their offer set to $0.00 per MW. DASR is calculatedby the day-ahead market solution as the lesser of the 30 minute energy
ramp rate or the economic maximum MW minus the day-ahead dispatch
point for all resources that can provide energy within 30 minutes of arequest from PJM Dispatch. In the first six months of 2021, the averageavailable hourly DASR was 17,368.1 MW.8

• Demand. The DASR requirement is the sum of the PJM requirement and theDominion requirement based on the VACAR reserve sharing agreement.
For November 2020 through October 2021, the DASR requirement is 4.72
percent of peak load forecast. The average hourly DASR MW purchased

7 See PJM, “Manual 11: Energy & Ancillary Services Market Operations,” § 11.2.7 Day-Ahead Scheduling Reserve Performance, Rev. 115(June 1, 2021).
8 The average hourly available DASR MW are modified from previously reported values due to a calculation error which has been fixed.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

in the first six months of 2021 was 4,563.4 MW, a reduction from the4,987.2 hourly MW in 2020.

• Concentration. The three pivotal supplier test would have failed in 216
hours in the first six months of 2021.

Market Conduct• Withholding. Economic withholding remains an issue in the DASR Market.

The direct marginal cost of providing DASR is zero. PJM calculates theopportunity cost for each resource. All offers by resource owners greaterthan zero constitute economic withholding. In the first six months of2021, 39.3 percent of daily unit offers were above $0.00 and 15.8 percent
of daily unit offers were above $5.

• DR. Demand resources are eligible to participate in the DASR Market. Somedemand resources have entered offers for DASR. No demand resources
cleared the DASR market in the first six months of 2021.

Market Performance• Price. In the first six months of 2021, the weighted average DASR price forall hours when the DASRMCP was above $0.00 was $0.95.

Regulation Market
The PJM Regulation Market is a real-time market. Regulation is provided
by generation resources and demand response resources that qualify tofollow one of two regulation signals, RegA or RegD. PJM jointly optimizes
regulation with synchronized reserve and energy to provide all three products
at least cost. The PJM regulation market design includes three clearing pricecomponents: capability; performance; and opportunity cost. The RegA signal
is designed for energy unlimited resources with physically constrained ramp
rates. The RegD signal is designed for energy limited resources with fast ramp
rates. In the regulation market RegD MW are converted to effective MW usinga marginal rate of technical substitution (MRTS), called a marginal benefit
factor (MBF). Correctly implemented, the MBF would be the marginal rateof technical substitution (MRTS) between RegA and RegD, holding the level© 2021 Monitoring Analytics, LLC

of regulation service constant. The current market design is critically flawed
as it has not properly implemented the MBF as an MRTS between RegA and
RegD resource MW and the MBF has not been consistently applied in the
optimization, clearing and settlement of the regulation market.

Market Structure• Supply. In the first six months of 2021, the average hourly offered supplyof regulation for nonramp hours was 758.5 performance adjusted MW(751.6 effective MW). This was an increase of 57.4 performance adjusted
MW (an increase of 45.7 effective MW) from the first six months of 2020.
In the first six months of 2021, the average hourly offered supply of
regulation for ramp hours was 1,072.8 performance adjusted MW (1,093.8
effective MW). This was an increase of 91.3 performance adjusted MW (anincrease of 65.1 effective MW) from the first six months of 2020, when
the average hourly offered supply of regulation was 981.5 performanceadjusted MW (1,028.7 effective MW).

• Demand. The hourly regulation demand is 525.0 effective MW for
nonramp hours and 800.0 effective MW for ramp hours.

• Supply and Demand. The nonramp regulation requirement of 525.0

effective MW was provided by a combination of RegA and RegD resources
equal to 491.3 hourly average performance adjusted actual MW in thefirst six months of 2021. This is an increase of 1.7 performance adjusted
actual MW from the first six months of 2020, when the average hourly
total regulation cleared performance adjusted actual MW for nonramp
hours were 489.6 performance adjusted actual MW. The ramp regulation
requirement of 800.0 effective MW was provided by a combination of
RegA and RegD resources equal to 707.3 hourly average performanceadjusted actual MW in the first six months of 2021. This is an increase of
3.2 performance adjusted actual MW from the first six months of 2020,
where the average hourly regulation cleared MW for ramp hours were704.1 performance adjusted actual MW.
The ratio of the average hourly offered supply of regulation to averagehourly regulation demand (performance adjusted cleared MW) for ramp

2021 Quarterly State of the Market Report for PJM: January through June 483

2021 Quarterly State of the Market Report for PJM: January through June

hours was 1.52 in the first six months of 2021 (1.39 in the first six monthsof 2020). The ratio of the average hourly offered supply of regulation toaverage hourly regulation demand (performance adjusted cleared MW)
for nonramp hours was 1.54 in the first six months of 2021 (1.43 in thefirst six months of 2020).

• Market Concentration. In the first six months of 2021, the three pivotal

supplier test was failed in 87.7 percent of hours. In the first six monthsof 2021, the actual MW weighted average HHI of RegA resources was
2288 which is highly concentrated and the weighted average HHI of RegD
resources was 1670 which is moderately concentrated. The weighted
average HHI of all resources was 1218, which is moderately concentrated.

Market Conduct• Offers. Daily regulation offer prices are submitted for each unit by theunit owner. Owners are required to submit a cost-based offer and may
submit a price-based offer. Offers include both a capability offer and aperformance offer. Owners must specify which signal type the unit will
be following, RegA or RegD.9 In the first six months of 2021, there were
219 resources following the RegA signal and 50 resources following the
RegD signal.

Market Performance• Price and Cost. The weighted average clearing price for regulation was$17.46 per MW of regulation in the first six months of 2021, an increaseof $5.73 per MW, or 48.9 percent, from the weighted average clearing
price of $11.73 per MW in the first six months of 2020. The weighted
average cost of regulation in the first six months of 2021 was $21.66 per
MW of regulation, an increase of 46.4 percent, from the weighted average
cost of $14.79 per MW in the first six months of 2020.

• Prices. RegD resources continue to be incorrectly compensated relative to

RegA resources due to an inconsistent application of the marginal benefit
factor in the optimization, assignment and settlement processes. If the

9 See the 2019 State of the Market Report for PJM, Vol. II, Appendix F “Ancillary Services Markets.”

484

Section 10 Ancillary Services

regulation market were functioning efficiently and competitively, RegD
and RegA resources would be paid the same price per effective MW.

• Marginal Benefit Factor. The marginal benefit factor (MBF) is intended

to measure the operational substitutability of RegD resources for RegA
resources. The marginal benefit factor is incorrectly defined and appliedin the PJM market clearing. The current incorrect and inconsistent
implementation of the MBF has resulted in the PJM Regulation Market
over procuring RegD relative to RegA in most hours and in an inefficient
market signal about the value of RegD in every hour.

Black Start Service
Black start service is required for the reliable restoration of the grid following a
blackout. Black start service is the ability of a generating unit to start without
an outside electrical supply, or is the demonstrated ability of a generating unit
to automatically remain operating at reduced levels when disconnected fromthe grid (automatic load rejection or ALR).10
In the first six months of 2021, total black start charges were $33.6 million,
including $33.3 million in revenue requirement charges and $0.2 million in
uplift charges. Black start revenue requirements consist of fixed black start
service costs, variable black start service costs, training costs, fuel storage
costs, and an incentive payment. Black start uplift charges are paid to units
scheduled in the day-ahead energy market or committed in real time to provide
black start service under the ALR option or for black start testing. Black start
zonal charges in the first six months of 2021 ranged from $0.02 per MW-day
in the BGE Zone (total charges were $22,716) to $4.13 per MW-day in the PE
Zone (total charges were $2,176,976).
CRF values are a key determinant of total payments to black start units. The
CRF values in PJM tariff tables should have been changed for both black startand the capacity market when the tax laws changed in December 2017. As aresult, CRF values have overcompensated black start units since the changes
to the tax code.
10 OATT Schedule 1 § 1.3BB. There are no ALR units currently providing black start service.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Reactive
Reactive service, reactive supply and voltage control are provided bygeneration and other sources of reactive power (measured in MVAr). Reactive
power helps maintain appropriate voltage levels on the transmission system
and is essential to the flow of real power (measured in MW). The sameequipment provides both MVAr and MW. The current rules permit double
recovery of some fixed costs.
Reactive capability charges are based on FERC approved filings that permit
recovery based on an outdated cost of service approach.11 All capacity costsof generators should be incorporated in the capacity market. The nonmarket
cost of service approach to reactive capability payments should be eliminated.
Reactive service charges are paid to units that operate in real time outsideof their normal range at the direction of PJM for the purpose of providing
reactive service. Total reactive charges increased 4.81 percent from $174.8
million in the first six months of 2020 to $182.5 million in 2021. Reactive
capability charges increased 4.51 percent from $174.6 million in the first six
months of 2020 to $182.460 million in 2021. Total reactive service charges in
the first six months of 2021 ranged from $0 in the REC and OVEC Zones, to$25.0 million in the AEP Zone.

Frequency Response
On February 15, 2018, the Commission issued Order No. 842, which modified
the pro forma large and small generator interconnection agreements andprocedures to require newly interconnecting generating facilities, bothsynchronous and nonsynchronous, to include equipment for primary frequency
response capability as a condition to receive interconnection service.12 PJM
filed revisions in compliance with Order No. 842 that incorporated the pro
forma agreements into its market rules.13
The PJM Tariff requires that all new generator interconnection customers(Nuclear Regulatory Commission regulated facilities are exempt from thisprovision) have hardware and/or software that provides frequency responsive
11 OATT Schedule 2.
12 See 157 FERC ¶ 61,122 (2016).
13 See 164 FERC ¶ 61,224 (2018).

© 2021 Monitoring Analytics, LLC

real power control with the ability to sense changes in system frequency
and autonomously adjust real power output in a direction to correct forfrequency deviations. This includes a governor or equivalent controls capableof operating with a maximum five percent droop and a +/- 0.036 deadband.14
In addition to resource capability, resource owners must comply by setting
control systems to autonomously adjust real power output in a direction tocorrect for frequency deviations.
The response of generators within PJM to NERC identified frequency events
remains under evaluation. A frequency event is declared when the frequency
goes outside +/-40mHz for 60 continuous seconds. The NERC BAL-003-2
requirement for balancing authorities (PJM is a balancing authority) uses athreshold value (L10) equal to -261.1 MW/0.1 Hz and has selected four events
between June 1, 2020 and December 31, 2020 as well as two events in Januaryof 2021 to evaluate.

Ancillary Services Costs per MWh of Load
Table 10-4 shows PJM ancillary services costs for the first six months of 1999
through 2021, per MWh of load. The rates are calculated as the total charges
for the specified ancillary service divided by the total PJM real-time load in
MWh.15 The scheduling, system control, and dispatch category of costs iscomprised of PJM scheduling, PJM system control and PJM dispatch; ownerscheduling, owner system control and owner dispatch; other supporting
facilities; black start services; direct assignment facilities; and ReliabilityFirst
Corporation charges. The cost per MWh of load in Table 10-4 is a different
metric than the cost of each ancillary service per MW of that service. The cost
per MWh of load includes the effects both of price changes per MW of theancillary service and changes in total load.

14 OATT Attachment O § 4.7.2 (Primary Frequency Response).
15 The total prices in this table are a load-weighted, average system price per MWh by category, even if each category is not charged onthat basis. These totals are presented for informational purposes and should not be used to calculate the costs of any specific market
activity in PJM.

2021 Quarterly State of the Market Report for PJM: January through June 485

2021 Quarterly State of the Market Report for PJM: January through June

Table 10-4 History of ancillary services costs per MWh of load: January
through June, 1999 through 202116 17
Year (Jan-Jun)
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Regulation
$0.08
$0.26
$0.50
$0.31
$0.57
$0.53
$0.58
$0.48
$0.61
$0.73
$0.38
$0.34
$0.33
$0.20
$0.26
$0.46
$0.29
$0.11
$0.13
$0.24
$0.11
$0.09
$0.14

Scheduling, Dispatch
and System Control
$0.23
$0.32
$0.73
$0.81
$1.06
$1.07
$0.80
$0.74
$0.71
$0.52
$0.32
$0.36
$0.36
$0.43
$0.43
$0.43
$0.42
$0.43
$0.49
$0.47
$0.46
$0.49
$0.51

Reactive
$0.27
$0.33
$0.22
$0.19
$0.24
$0.26
$0.27
$0.29
$0.27
$0.34
$0.36
$0.37
$0.40
$0.47
$0.65
$0.42
$0.37
$0.39
$0.43
$0.42
$0.44
$0.49
$0.50

Synchronized
Reserve
$0.00
$0.00
$0.00
$0.00
$0.16
$0.16
$0.11
$0.08
$0.09
$0.08
$0.04
$0.06
$0.10
$0.03
$0.03
$0.20
$0.14
$0.05
$0.06
$0.08
$0.04
$0.02
$0.05

Total
$0.58
$0.91
$1.45
$1.31
$2.03
$2.02
$1.76
$1.59
$1.68
$1.67
$1.10
$1.13
$1.19
$1.13
$1.37
$1.51
$1.22
$0.98
$1.11
$1.21
$1.05
$1.09
$1.20

Market Procurement of Real-Time Ancillary Services
PJM uses market mechanisms to varying degrees in the procurement ofancillary services, including primary reserves and regulation. Ideally, allancillary services would be procured taking full account of the interactions
with the energy market. When a resource is used for an ancillary service
instead of providing energy in real time, the cost of removing the resource,
either fully or partially, from the energy market should be weighed against
the benefit the ancillary service provides. The degree to which PJM markets
account for these interactions depends on the timing of the product clearing
and software limitations and the accuracy of unit parameters and offers.
16 Note: The totals in Table 10-4 account for after the fact billing adjustments made by PJM and may not match totals presented in pastreports.
17 Reactive totals include FERC approved rates for reactive capability.

486

Section 10 Ancillary Services

The synchronized reserve market clearing is more integrated with the energy
market clearing than the other ancillary services. Resources categorized as
flexible tier 2 reserve, those that can provide reserves by backing down
according to their ramp rate, are jointly cleared along with energy in every
real-time market solution. Given the joint clearing of energy and flexible
tier 2, the synchronized reserve market clearing price should always cover
the opportunity cost of providing flexible tier 2. PJM should never need to
pay uplift to flexible tier 2. The uplift paid to flexible tier 2 results fromissues with the dispatch and pricing software timing. Inflexible tier 2 reserves,
provided by resources that require longer notice to take actions to prepare forreserve deployment, are not cleared along with energy in the real-time market
solution. Inflexible tier 2 reserves are cleared hourly by the Ancillary Service
Optimizer (ASO). The ASO uses forward looking information about the energy
market, flexible tier 2, tier 1, and regulation to estimate the costs and benefitsof using a resource for inflexible tier 2 synchronized reserves.
Nonsynchronized reserves are cleared with every real-time energy market
solution, but their costs are not fully known by the real-time energy market
software (RT SCED) because the resources are offline. PJM uses an estimateof the cost of using a resource for nonsynchronized reserve instead of energy
from a previously solved IT SCED solution. IT SCED runs every 15 minutes
looking ahead at target dispatch times up to two hours in the future. Theenergy commitment decisions for the offline resources have already been
made when the RT SCED clears the nonsynchronized reserve market. RT SCED
compares the IT SCED estimated cost of nonsynchronized reserve clearing to
the RT SCED determined cost of synchronized reserve clearing in satisfying
the primary reserve requirement. Nonsynchronized reserve clearing indirectlyinteracts with energy clearing through both products’ substitutability withsynchronized reserves.
Prices for the regulation and reserve markets are set by the pricing calculator(LPC), which is based on the RT SCED solution. The software determining theprices (RT SCED) is partially, but not fully clearing the reserve market. The
software determining the prices is not clearing the regulation market.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Recommendations• The MMU recommends that all data necessary to perform the regulation

market three pivotal supplier test be saved by PJM so that the test can be
replicated. (Priority: Medium. First reported 2016. Status: Not adopted.)• The MMU recommends that the total regulation (TReg) signal sent on a

fleet wide basis be eliminated and replaced with individual regulation
signals for each unit. (Priority: Low. First reported 2019. Status: Not
adopted.)assigned regulation resources within the hour. (Priority: Medium. First
reported 2016. Status: Not adopted. FERC rejected.22)• The MMU recommends enhanced documentation of the implementationof the regulation market design. (Priority: Medium. First reported 2010.
Status: Not adopted. FERC rejected.23)• The MMU recommends that PJM be required to save data elements
necessary for verifying the performance of the regulation market.
(Priority: Medium. First reported 2010. Status: Not adopted.)• The MMU recommends that the ability to make dual offers (to make offers• The MMU recommends that the $12.00 margin adder be eliminated from• The MMU recommends that the regulation market be modified to• The MMU recommends that PJM replace the static MidAtlantic/Dominion

as both a RegA and a RegD resource in the same market hour) be removed
from the regulation market. (Priority: High. First reported 2019. Status:
Not adopted.)
incorporate a consistent application of the marginal benefit factor (MBF)
throughout the optimization, assignment and settlement process. The
MBF should be defined as the Marginal Rate of Technical Substitution(MRTS) between RegA and RegD. (Priority: High. First reported 2012.
Status: Not adopted. FERC rejected.18)• The MMU recommends that the lost opportunity cost in the ancillary
services markets be calculated using the schedule on which the unit wasscheduled to run in the energy market. (Priority: High. First reported 2010.
Status: Not adopted.19 FERC rejected.20)• The MMU recommends that the lost opportunity cost calculation usedin the regulation market be based on the resource’s dispatched energy
offer schedule, not the lower of its price or cost offer schedule. (Priority:
Medium. First reported 2010. Status: Not adopted. FERC rejected.21)• The MMU recommends that, to prevent gaming, there be a penalty

enforced in the regulation market as a reduction in performance score
and/or a forfeiture of revenues when resource owners elect to deassign

18 162 FERC ¶ 61,295 (2018), reh’g denied, 170 FERC ¶ 61,259 (2020).
19 This recommendation was adopted by PJM for the energy market. Lost opportunity costs in the energy market are calculated using theschedule on which the unit was scheduled to run. In the regulation market, this recommendation has not been adopted, as the LOC
continues to be calculated based on the lower of price or cost in the energy market offer.
20 162 FERC ¶ 61,295 (2018), reh’g denied, 170 FERC ¶ 61,259 (2020).
21 Id.

© 2021 Monitoring Analytics, LLC

the definition of the cost based regulation offer because it is a markup
and not a cost. (Priority: Medium. First reported Q1, 2021. Status: Not
adopted.)Reserve Subzone with a reserve zone structure consistent with the actual
deliverability of reserves based on current transmission constraints.
(Priority: High. First reported 2019. Status: Not adopted.)• The MMU recommends that the $7.50 margin be eliminated from thedefinition of the cost of tier 2 synchronized reserve because it is amarkup and not a cost. (Priority: Medium. First reported 2018. Status:
Not adopted.)• The MMU recommends that the variable operating and maintenance costbe eliminated from the definition of the cost of tier 2 synchronized reserveand that the calculation of synchronized reserve variable operations andmaintenance costs be removed from Manual 15. (Priority: Medium. First
reported 2019. Status: Not adopted.)• The MMU recommends that the components of the cost-based offers forproviding regulation and synchronous condensing be defined in Schedule
2 of the Operating Agreement. (Priority: Low. First reported 2019. Status:
Not adopted.)• The MMU recommends that the rule requiring that tier 1 synchronizedreserve resources be paid the tier 2 price when the nonsynchronized

22 Id.
23 Id.

2021 Quarterly State of the Market Report for PJM: January through June 487

2021 Quarterly State of the Market Report for PJM: January through June

reserve price is above zero be eliminated immediately and that, under
the current rule, tier 1 synchronized reserve resources not be paid the tier2 price when they do not respond. (Priority: High. First reported 2013.
Status: Not adopted.)• The MMU recommends that the tier 2 synchronized reserve must

offer requirement be enforced on a daily and hourly basis. The MMU
recommends that PJM define a set of acceptable reasons why a unit canbe made unavailable daily or hourly and require unit owners to select areason in Markets Gateway whenever making a unit unavailable either
daily or hourly or setting the offer MW to 0 MW. (Priority: Medium. First
reported 2013. Status: Partially adopted.)

similar to agreements between PJM and other bordering areas. (Priority:
Medium. First reported 2020. Status: Not adopted.)• The MMU recommends that a reason code be attached to every hourin which PJM market operations adds additional DASR MW. (Priority:
Medium. First reported 2015. Status: Not adopted.)• The MMU recommends that PJM modify the DASR market to ensure that
all resources cleared incur a real-time performance obligation. (Priority:
Low. First reported 2013. Status: Not adopted.)• The MMU recommends that, in order to mitigate market power, offers in

the DASR market be based on opportunity cost only. (Priority: Low. First
reported 2009. Modified, 2018. Status: Not adopted.)• The MMU recommends that, for calculating the penalty for a tier 2• The MMU recommends that all resources, new and existing, have a• The MMU recommends that aggregation not be permitted to offset unit

• The MMU recommends that new CRF rates for black start units,

resource failing to meet its scheduled obligation during a spinning event,the penalty should be based on the actual time since the last spinning
event of 10 minutes or longer during which the resource performed
because performance is only measured for events 10 minutes or longer.
(Priority: Medium. First reported 2018. Status: Not adopted.)
specific penalties for failure to respond to a synchronized reserve event.
(Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that PJM eliminate the use of Degree of Generator
Performance (DGP) in the synchronized reserve market solution andimprove the actual tier 1 estimate. If PJM continues to use DGP, DGP
should be documented in PJM’s manuals. (Priority: Medium. First reported
2018. Status: Not adopted.)• The MMU recommends that the details of VACAR Reserve Sharing
Agreement (VRSA) be made public, including any responsibilities assigned
to PJM and including the amount of reserves that Dominion commits tomeet its obligations under the VRSA. (Priority: Medium. First reported
2020. Status: Not adopted.)• The MMU recommends that the VRSA be terminated and, if necessary,

replaced by a reserve sharing agreement between PJM and VACAR South,

488

Section 10 Ancillary Services

requirement to include and maintain equipment for primary frequency
response capability as a condition of interconnection service. The PJM
capacity and energy markets already compensate resources for frequency
response capability and any marginal costs. (Priority: Medium. First
reported 2018. Status: Not adopted.)
incorporating current tax code changes, be implemented immediately.
The new CRF rates should apply to all black start units. The black start
units should be required to commit to providing black start service for thelife of the unit. (Priority: High. First reported 2020. Status: Not adopted.)• The MMU recommends for oil tanks shared with other resources that

only a proportionate share of the minimum tank suction level (MTSL) be
allocated to black start service. The MMU further recommends that the
PJM tariff be updated to clearly state how the MTSL will be calculated forblack start units sharing oil tanks. (Priority: Medium. First reported 2017.
Status: Not adopted.)• The MMU recommends that separate cost of service payments for reactive
capability be eliminated and the cost of reactive capability be recoveredin the capacity market. (Priority: Medium. First reported 2016. Status: Not
adopted.)© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services• The MMU recommends that payments for reactive capability, if continued,
be based on the 0.90 power factor that PJM has determined is necessary.
(Priority: Medium. First reported 2018. Status: Not adopted.)• The MMU recommends that, if payments for reactive are continued,

fleet wide cost of service rates used to compensate resources for reactive
capability be eliminated and replaced with compensation based on unit
specific costs. (Priority: Low. First reported 2019.24 Status: Partiallyadopted.)• The MMU recommends that Schedule 2 to OATT be revised to state

explicitly that only generators that provide reactive capability to thetransmission system that PJM operates and has responsibility for are
eligible for reactive capability compensation. Specifically, such eligibility
should be determined based on whether a generation facility’s point ofinterconnection is on a transmission line that is a Monitored Transmission
Facility as defined by PJM and is on a Reportable Transmission Facility
as defined by PJM.25 (Priority: Medium. First reported 2020. Status: Not
adopted.)Conclusion
The design of the PJM Regulation Market is significantly flawed.26 The
market design does not correctly incorporate the marginal rate of technicalsubstitution (MRTS) in market clearing and settlement. The market designuses the marginal benefit factor (MBF) to incorrectly represent the MRTS anduses a mileage ratio instead of the MBF in settlement. This failure to correctly
and consistently incorporate the MRTS into the regulation market design has
resulted in both underpayment and overpayment of RegD resources and in theover procurement of RegD resources in all hours. The market results continue
to include the incorrect definition of opportunity cost. These issues are thebasis for the MMU’s conclusion that the regulation market design is flawed.

24 The MMU has discussed this recommendation in state of the market reports since 2016 but Q3, 2019 was the first time it was reported asa formal MMU recommendation.
25 See PJM Transmission Facilities (note that this requires you first log into a PJM Tools account. If you do not, then the link sends you to an
Access Request page, <https://pjm.com/markets-and-operations/ops-analysis/transmission-facilities>.
26 The current PJM regulation market design that incorporates two signals using two resource types was a result of FERC Order No. 755 andsubsequent orders. Order No. 755, 137 FERC ¶ 61,064 at PP 197–200 (2011).

© 2021 Monitoring Analytics, LLC

To address these flaws, the MMU and PJM developed a joint proposal which
was approved by the PJM Members Committee on July 27, 2017, and filed with
FERC on October 17, 2017.27 The PJM/MMU joint proposal addresses issues
with the inconsistent application of the marginal benefit factor throughout
the optimization and settlement process in the PJM Regulation Market. FERC
rejected the joint proposal on March 30, 2018, as being noncompliant with
Order No. 755.28 The MMU and PJM separately filed requests for rehearing,which were denied by order issued March 26, 2020.29
The structure of the tier 2 synchronized reserve market has been evaluated andthe MMU has concluded that these markets are not structurally competitive as
they are characterized by high levels of supplier concentration and inelastic
demand. As a result, these markets are operated with market clearing prices
and with offers based on the marginal cost of producing the product plus a
margin. As a result of these requirements, the conduct of market participants
within these market structures has been consistent with competition, andthe market performance results have been competitive. However, the $7.50
margin is not a cost. The margin is effectively a rule-based form of economic
withholding and is therefore not consistent with a competitive outcome. The$7.50 margin should be eliminated. The variable operating and maintenancecomponent of the synchronized reserve offer should also be eliminated. Allvariable operating and maintenance costs are incurred to provide energy andto make units available to provide energy. There are no variable operating andmaintenance costs associated with providing synchronized reserve.
Participant performance has not been adequate for tier 2 synchronized reserve.
Compliance with calls to respond to actual synchronized reserve events
remains significantly less than 100 percent. Actual participant performancemeans that the penalty structure is not an adequate incentive for performance.
The rule that requires payment of the tier 2 synchronized reserve price to tier
1 synchronized reserve resources when the nonsynchronized reserve price isgreater than zero, is inefficient and results in a substantial windfall payment
27 18 CFR § 385,211 (2017)28 162 FERC ¶ 61,295.
29 170 FERC ¶ 61,259.

2021 Quarterly State of the Market Report for PJM: January through June 489

2021 Quarterly State of the Market Report for PJM: January through Juneto the holders of tier 1 synchronized reserve resources. Tier 1 resources haveno obligation to perform and pay no penalties if they do not perform, and tier1 resources do not incur any costs when they are part of the tier 1 estimate
in the market solution. Tier 1 resources are already paid for their response if
they do respond to a synchronized reserve event. Tier 1 resources require no
additional payment. If tier 1 resources wish to be paid as tier 2 resources, therules provide the opportunity to make competitive offers in the tier 2 market
and take on the associated obligations. Overpayment of tier 1 resources basedon this rule has added more than $100 million to the cost of primary reserve
since 2014.
The benefits of markets are realized under these approaches to ancillary
service markets. Even in the presence of structurally noncompetitive markets,
there can be transparent, market clearing prices based on competitive offersthat account explicitly and accurately for opportunity cost. This is consistent
with the market design goal of ensuring competitive outcomes that provide
appropriate incentives without reliance on the exercise of market power andwith explicit mechanisms to prevent the exercise of market power.
The MMU concludes that the regulation market results were not competitive,
and the market design is significantly flawed. The MMU concludes that thesynchronized reserve market results were competitive, although the $7.50
margin should be removed. The MMU concludes that the DASR market results
were competitive, although offers above the competitive level continue toaffect prices.

Primary Reserve
NERC Performance Standard BAL-002-3, Disturbance Control Standard –Contingency Reserve for Recovery from a Balancing Contingency Event,requires PJM to carry sufficient contingency reserve to recover from a suddenbalancing contingency (usually a loss of generation). The Contingency Event
Recovery Period is the time required to return the ACE to zero if it was zeroor positive before the event or to its pre-event level if it was negative at
the start of the event. NERC standards set the Contingency Event Recovery

490

Section 10 Ancillary Services

Period as 15 minutes and Contingency Reserve Restoration Period as 90
minutes.30 The NERC requirement is 100 percent compliance and status must
be reported quarterly. PJM implements this contingency reserve requirement
using primary reserves.31 PJM maintains 10 minute reserves (primary reserve)
to ensure reliability in the event of disturbances. PJM’s primary reserves are
made up of resources, both synchronized and nonsynchronized, that can
provide energy within 10 minutes. PJM does not have a Contingency Reserve
Restoration Period standard.

Market Structure
DemandPJM requires that 150 percent of the largest single contingency on the system
be maintained as primary reserve plus 190 MW. PJM can make temporary
adjustments to the primary reserve requirement when grid maintenance oroutages change the largest contingency or in cases of hot weather alerts orcold weather alerts.
The primary reserve market requirement is set equal to 150 percent of thelargest single contingency for each market solution, ASO, IT SCED, and RT
SCED. This is usually the output of the largest generating unit to which PJM
adds 190 MW. In cases where temporary switching conditions create the riskthat a single fault could remove several generators, PJM will define the largest
single contingency as the sum of the output of those generators.32
PJM can also increase the primary and synchronized reserve requirementin cases of hot weather or cold weather alerts or escalating emergency
procedures.33 Such additional reserves are committed as part of the hourly(ASO) and five minute (RT SCED) processes. In the first six months of 2021, theaverage primary reserve requirement for the RTO Zone was 2,427.3 MW. The
average primary reserve requirement in the MAD Subzone was also 2,427.2
MW. These averages include the hours when PJM raised the requirements.
30 See PJM “Manual 12: Balancing Operations,” Rev. 42 (January 27, 2021) Attachment D, “the Disturbance Recovery Period is 15 minutes
after the start of a Reportable Disturbance. Subsequently, PJM must fully restore the Synchronized Reserve within 90 minutes.”
31 See PJM “Manual 10: Pre-Scheduling Operations,” § 3.1.1 Day-ahead Scheduling (Operating) Reserve, Rev. 39 (Nov. 19, 2020).
32 PJM Manual 11: Energy & Ancillary Services Market Operations, Rev. 115 (June 1, 2021)
33 PJM Manual 11: Energy & Ancillary Services Market Operations, Rev. 115 (June 1, 2021), p. 84© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

The MMU identified instances when PJM increased the primary andsynchronized reserve requirements (Table 10-5).

Figure 10-1 PJM RTO Zone and MAD Subzone map of constraints andgeneration sources

Table 10-5 Temporary adjustments to primary and synchronized reserve:
January through June, 2021
From
6-Mar-21
15-Mar-21
14-Jun-21

To
8-Mar-21
29-Mar-21
17-Jun-21

Number of
Hours
34
230
64

Amount of Adjustment
Primary Reserve (255 MW), Synchronized Reserve (170 MW)
Primary Reserve (230 MW), Synchronized Reserve (160 MW)
Primary Reserve (0 MW), Synchronized Reserve (0 MW)

Transmission constraints can limit the deliverability of reserves within the
RTO, requiring the definition of a subzone. PJM defines a single subzone,
the Mid-Atlantic Dominion (MAD) Subzone (Figure 10-1).34 Figure 10-1
is a map of constraints and major generation sources. The constraints
separating the RTO Zone and MAD Subzone are defined by underlying grid
topology. The RTO Zone into MAD Subzone constraints reflect limits on thetransmission line capacity that separate the RTO Zone and MAD Subzone.
If, in the case of a spinning event, the current economic dispatch plus thecurrent synchronized market dispatch would overload the constraint, then all
additional synchronized reserve MW must be cleared from the unconstrainedside of the constraints. When this occurs, the synchronized reserve prices
between the RTO Zone and the MAD Subzone will diverge. PJM operators areauthorized to define additional separate subzones under certain conditions.35
In practice, PJM has always maintained only the MAD Subzone but for any
market solution several distinct constraining paths are analyzed and the mostlimiting one becomes the definition for that solution.

34 Additional subzones may be defined by PJM to meet system reliability needs. PJM will notify stakeholders in such an event. See “PJM
Manual 11: Energy & Ancillary Services Market Operations,” § 4.2.2 Synchronized Reserve Requirement Determination, Rev. 115 (June 19,2021).
35 PJM Manual 11: Energy & Ancillary Services Market Operations, Rev. 115 (June 1, 2021), p. 86.

© 2021 Monitoring Analytics, LLC

The most limiting transmission constraint for power flow from the RTO Zone
into the MAD Subzone since August 2017, has been the AP South Interface.
The most frequent constraint is Brighton-Conastone, then Bedington-Black
Oak, and Dooms-Cunningham.
The NERC standard requires a control area to carry primary reserve MW
equal to or greater than the most severe single contingency (MSSC) plus 190
MW.36 PJM requires primary reserves in the amount of 150 percent of thelargest single contingency with at least 100 percent of the requirement madeup of synchronized reserves.37 In the first six months of 2021, the averagesynchronized reserve requirement was 1,682.2 MW in the MAD Subzone
and 1,682.3 MW in the RTO Zone. The synchronized reserve requirement iscalculated for every real-time market dispatch solution.

36 NERC BAL-002-3. “Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event,” September
25, 2018. <https://www.nerc.com/pa/Stand/‌Reliability%20Standards/BAL-002-3.pdf>.
37 “PJM Manual 13: Emergency Operations,” Rev 78 (Jan. 27, 2021), p. 18.

2021 Quarterly State of the Market Report for PJM: January through June 491

2021 Quarterly State of the Market Report for PJM: January through June

SupplyThe demand for primary reserve is satisfied by tier 1 synchronized reserves,tier 2 synchronized reserves and nonsynchronized reserves, subject to therequirement that synchronized reserves equal 100 percent of the largest
contingency. After the synchronized reserve requirement is satisfied, theremainder of primary reserves is from the least expensive combination ofsynchronized and nonsynchronized reserves.
Estimated tier 1 is credited against PJM’s primary reserve requirement as well
as PJM’s synchronized reserve requirement. In the MAD Subzone, an averageof 807.9 MW of tier 1 was identified by the dispatch solutions as available in
the first six months of 2021 (Table 10-6).38 Tier 1 synchronized reserve fully
satisfied the MAD Subzone synchronized reserve requirement or reduced theneed for tier 2 synchronized reserve to self scheduled reserves in 4.1 percent
of dispatch solutions in the first six months of 2021. In the RTO Zone, anaverage of 1,611.4 MW of tier 1 was available (Table 10-7) fully satisfying
the synchronized reserve requirement in 39.9 percent of real-time dispatch
solutions.
Regardless of online/offline state, all nonemergency generation capacity
resources must submit a daily offer for tier 2 synchronized reserve in Markets
Gateway prior to the offer submission deadline (14:15 the day prior to theoperating day). Resources listed as available for tier 2 synchronized reserve
without a synchronized reserve offer will have their offer price automatically
set to $0.00. Offer MW and other non-cost offer parameters can be changed
during the operating day. Owners who opt in for intraday updates may change
their offer price up to 65 minutes before the hour. Certain unit types including
nuclear, wind, solar, and energy storage resources, are expected to have zeroMW tier 2 synchronized reserve offer quantities.39
After tier 1 is estimated, the remainder of the synchronized reserve requirement
is met by tier 2.

In the first six months of 2021, in the MAD Subzone, there was an average of
1,244.8 MW of eligible nonsynchronized reserve supply available to meet the
average demand for primary reserve. (Table 10-7) In the RTO Zone, an averageof 1,744.4 MW of supply was available to meet the average demand of 1,537.3
MW (Table 10-7).
Table 10-6 provides the average dispatch solution reserves, by type of reserve,
used by the RT SCED market solution to satisfy the primary reserve requirementin the MAD Subzone from January 2020 through June 2021.
Table 10-6 Average reserves used to satisfy the primary reserve requirement,
MAD Subzone: January 2020 through June 2021
Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Average

Tier 1 Total MW
1,276.6
1,026.9980.7
1,150.5
911.1
1,276.2
995.4
881.4
1,016.9
724.1
566.4
689.0
957.9

Tier 2 Synchronized
Reserve MW
325.9
193.6
259.0
199.9
200.5
142.5
210.5
148.3
88.5
290.2
257.2
252.2
214.0

Nonsynchronized
Reserve MW
1,249.0
1,219.6
1,231.8
1,067.7
1,177.5
976.6
1,216.0
1,200.6
1,123.2
1,247.8
1,188.8
1,319.6
1,184.8

Total Primary
Reserve MW
2,851.5
2,440.1
2,471.4
2,418.1
2,289.0
2,395.4
2,421.9
2,230.3
2,228.6
2,262.2
2,012.5
2,260.8
2,356.8

2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun
Average

835.6
974.9
881.9
689.7
651.4
834.6
811.4

251.1
215.1
213.2
315.5
247.5
198.8
240.2

1,330.6
1,242.7
1,162.6
1,274.8
1,141.4
1,263.7
1,236.0

2,417.3
2,432.7
2,257.7
2,280.0
2,040.2
2,297.1
2,369.2

Table 10-7 shows the average dispatch solution reserves, by type of reserve,
satisfying the primary reserve requirement in the RTO Zone in January 2020
through June 2021.

38 ASO, Ancillary Services Optimizer. This is the hour-ahead market software that optimizes ancillary services with energy. ASO schedules
hourly the Tier 2 Synchronized Reserve, Regulation, and Nonsynchronized Reserves.
39 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 4.2 PJM Synchronized Reserve Market Business Rules, Rev. 115(June 1, 2021).

492

Section 10 Ancillary Services© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Table 10-7 Average monthly reserves used to satisfy the primary reserve
requirement, RTO Zone: January 2020 through June 2021
Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Average

Tier 1 Total MW
2,416.4
2,284.2
2,155.1
2,228.6
2,128.3
2,728.9
2,109.4
1,972.1
2,053.8
1,381.3
1,499.7
1,512.4
2,039.2

Tier 2 Synchronized
Reserve MW
486.8
283.3
458.7
342.1
297.4
283.7
402.2
398.8
299.4
778.2
683.9
697.0
450.9

Nonsynchronized
Reserve MW
1,364.8
1,279.6
1,365.6
1,174.0
1,250.6
1,082.7
1,363.5
1,387.0
1,271.0
1,612.3
1,509.5
1,648.3
1,359.1

Total Primary
Reserve MW
4,268.0
3,847.1
3,979.4
3,744.7
3,676.3
4,095.3
3,875.1
3,757.9
3,624.1
3,771.7
3,693.1
3,857.7
3,849.2

2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun
Average

1,761.2
1,848.8
1,705.5
1,313.5
1,371.4
1,708.1
1,618.1

506.7
600.3
593.1
748.3
790.1
610.3
641.5

1,512.5
1,515.2
1,454.1
1,589.6
1,569.2
1,573.6
1,535.7

3,780.4
3,964.3
3,752.7
3,651.2
3,731.2
3,892.0
3,832.5

synchronized reserve, the RT SCED may decommit previously committed
flexible synchronized reserve.
The ASO satisfied the primary reserve requirement for the RTO Zone andthe MAD Subzone in all hours of the first six months of 2021. RT SCED for
the MAD Subzone satisfied the primary reserve requirement in all but nine
dispatch solutions. Three of the dispatch solutions, occurred during temporary
increases in the required synchronized reserve and nonsynchronized reserveon March 17 and March 22.
The market solution first estimates how much tier 1 synchronized reserve isavailable. If there is enough tier 1 MW available to satisfy the synchronizedreserve requirement, then RT SCED economically assigns available
synchronized reserve and nonsynchronized reserve to meet the remaining
primary reserve requirement. If there is not enough tier 1 synchronizedreserve then the remaining synchronized reserve requirement is filled with tier
2 synchronized reserve. After synchronized reserve is assigned, the primaryreserve requirement is filled by economically assigning synchronized reserveand nonsynchronized reserve.

Supply and Demand
The market solution software relevant to reserves consists of: the Ancillary
Services Optimizer (ASO) solving hourly; the intermediate term security
constrained economic dispatch market solution (IT SCED); and the real-time(short term) security constrained economic dispatch market solution (RTSCED).
All dispatch solutions determine the actual primary reserves required as 150
percent of the largest contingency plus 190 MW. Of this, synchronized reserves
must be 100 percent of the largest contingency plus 190 MW.
If the tier 1 synchronized reserve plus ASO committed inflexible tier 2
synchronized reserve does not meet the requirement, RT SCED will commit
available flexible tier 2 synchronized reserve. If there is an excess of© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 493

2021 Quarterly State of the Market Report for PJM: January through June

Figure 10-2 shows how the market solutions satisfy the primary reserve
requirement for the RTO Zone.
Figure 10-2 RTO reserve zone primary reserve MW by source (Daily Averages):
January through June, 2021
6,000
Nonsychronized Reserve MW
Tier 2 Synchronized Reserve MW
Tier 1 Synchronized Reserve MW

5,000

Synchronized Reserve Required MW
Primary Reserve Required MW

MW

4,000

3,000

factor for primary reserve levels ranging from 0 MW to a MW amount equal
to 150 percent of the MSSC and a constraint with a $300 penalty factor for
primary reserves ranging from 150 percent of MSSC to 150 percent of MSSC
plus 190 MW.
The supply of primary reserves is made up of available tier 1 and tier
2 synchronized reserves and nonsynchronized reserves. Offer prices forsynchronized reserve are capped at $7.50 plus costs plus opportunity costs.
Figure 10-3 shows daily weighted average synchronized and nonsynchronizedmarket clearing prices in the first six months of 2021. The MAD SRMCP and
RTO SRMCP price diverged in 25 five minute intervals in the first six monthsof 2021.
Figure 10-3 Daily average market clearing prices ($/MW) for synchronizedreserve and nonsynchronized reserve: January through June, 2021
$18

2,000

Nonsynchronized Reserve Market Clearing Price RTO$16

0

Nonsynchronized Reserve Market Clearing Price MAD
Synchronized Reserve Market Clearing Price RTO

1,000

$14

Synchronized Reserve Market Clearing Price MAD

$12
Jan

Feb

Mar

Apr

May

Jun

In the first six months of 2021, tier 1 and tier 2 were both essential to satisfying
the synchronized reserve requirement. Tier 1 synchronized reserve remains
the major contributor to satisfying the synchronized reserve requirement inboth the RTO Zone and the MAD Subzone.

Price and Cost
The price of primary reserves results from the demand curve for primaryreserves and the supply of primary reserves. The demand curve is modeledin each of the primary reserve clearing engines (ASO, IT SCED, RT SCED).
The demand curve for primary reserves has two steps, with an $850 penalty

494

Section 10 Ancillary Services

$/MWh

$10
$8
$6
$4
$2
$0

Jan

Feb

Mar

Apr

May

Jun

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

PJM’s primary reserves are made up of three components, tier 1 synchronizedreserve, tier 2 synchronized reserve, and nonsynchronized reserve, each with
its own price and cost determinants and interdependent scheduling algorithms.
The overall price and cost to customers, including uplift credits, for meeting
the BAL-002-3 primary reserve requirement is calculated by combining thethree components. Each of these three components is shown in Table 10-8. The
Cost per MW column is the total credits divided by the total MW of reserves.
The ratio of price to cost for all primary reserve during first six months of 2021
was 64.5 percent. While tier 1 has zero actual incremental cost, estimated tier
1 is paid the tier 2 clearing price in any hour where nonsynchronized reserves
clears at a nonzero price.
Table 10-8 Primary reserve requirement components, RTO Reserve Zone:
January through June 2021
Primary Reserve ProductTier 1 Synchronized Reserve Response
Tier 1 Synchronized Reserve in Market Solution
Tier 2 Synchronized Reserve Scheduled
Non Synchronized Reserve Scheduled
Primary Reserve (total of above)

MW Share of
Credited Primary
Reserve Requirement
NA
2.3%
28.4%
69.2%
100.0%

While PJM relies on tier 1 resources to respond to a synchronized reserve
event, tier 1 resources are not obligated to respond during an event. Tier 1
resources are credited if they do respond but are not penalized if they do not.

Market Structure
SupplyAll generating resources operating on the PJM system with the exceptionof those assigned to tier 2 synchronized reserve are available for tier 1
synchronized reserve and any response to a spinning event will becredited at the Synchronized Energy Premium Price.

Price Per
Cost Per
MWh Credits Paid MW Reserve MW Reserve
1,615$101,063
NA$62.57
154,363 $2,372,703$26.63$26.63
1,900,050 $15,863,821
$5.44
$8.35
4,625,059 $5,904,407
$0.25
$1.28
6,681,087 $24,241,994
$2.34
$3.63

Tier 1 Synchronized Reserve
Tier 1 synchronized reserve is a component of primary reserve comprisedof online resources following economic dispatch and able to ramp up fromtheir current output in response to a synchronized reserve event. The tier
1 synchronized reserve for a unit is estimated as the lesser of the available
10 minute ramp or the difference between the economic dispatch point andthe synchronized reserve maximum output. By default the synchronizedreserve maximum for a resource is equal to its economic maximum. Resource
owners may request a lower synchronized reserve maximum if a physicallimitation exists.40 Tier 1 resources are identified by the market solution. Tier
1 synchronized reserve has an incremental cost of zero. Tier 1 synchronized
40 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 4.2.1 Synchronized Reserve Market Eligibility, Rev. 115 (June 1,2021).

© 2021 Monitoring Analytics, LLC

reserve is paid under two circumstances. Tier 1 reserves are paid when
they respond to a synchronized reserve event. Tier 1 reserves are paid thesynchronized reserve market clearing price when the nonsynchronized reserve
market clearing price is above $0.

Beginning in 2014, DGP (Degree of Generator Performance) was
introduced as a metric to improve the accuracy of the tier 1 MW
estimate used by the market solution. The available tier 1 MW
estimated by the market solution for each resource is based uponits economic dispatch, and submitted synchronized reserve ramp
rate, adjusted by its DGP. PJM communicates to generation operators whosetier 1 MW is part of the market solution the latest estimate of units’ tier 1
MW and units’ current DGP.41 DGP should be documented in PJM’s market
rules.42 DGP violates the basic PJM principle that generation owners are solely
responsible for their own offers. In addition, DGP is a crude estimate of ramp
rates and does not account for the actual discontinuities along unit offer
curves.
The supply of tier 1 synchronized reserve available to the market solution
is adjusted by eliminating tier 1 MW from unit types that cannot reliably
provide synchronized reserve. These unit types are nuclear, wind, solar,
41 PJM. Ancillary Services, “Communication of Synchronized Reserve Quantities to Resource Owners,” (May 6, 2015). <http://www.pjm.
com/~/media/markets-ops/ancillary/‌communication-of-synchronized-reserve-quantities-to-resource-owners.ashx>
42 See PJM, Generation Performance Monitor and Degree of Generator Performance Whitepaper. <http://www.pjm.com/-/media/etools/
oasis/system-information/generation-performance-monitor-and-degree-of-generator-performance-white-paper.ashx>.

2021 Quarterly State of the Market Report for PJM: January through June 495

2021 Quarterly State of the Market Report for PJM: January through Junelandfill gas, energy storage, and hydro units.43 These unit types are credited
the synchronized energy premium price, like any other responding unit, if
they respond to a spinning event. These units will not, however, be paid astier 1 resources when the nonsynchronized reserve market clearing price goes
above $0. There is a review process for resources excluded by default fromthe tier 1 estimate that request to be included.44 PJM also excludes units,
regardless of type, that it deems unreliable as tier 1, though it allows thoseresources to provide tier 2 synchronized reserve.
Table 10-9 provides tier 1 synchronized reserve supplied by unit and fuel typein the first six months of 2021, including all tier 1 credited for responding tosynchronized reserve events and paid when the nonsychronized reserve priceexceeded $0 per MW.
Table 10-9 Supply of tier 1 synchronized reserve by unit and fuel type:
January through June, 2021
Unit / Fuel Type
Steam - Coal
Combined Cycle
Hydro - Run of RiverCT - Natural Gas
Wind
Solar
Steam - Natural Gas
RICE - Natural Gas
Hydro - Pumped Storage
Steam - Other
NuclearDSR
RICE - Other
CT - OilCT - Other
Battery
RICE-Oil

Percent by MW
43.1%
35.8%
6.3%
5.6%
3.2%
3.0%
1.1%
0.8%
0.6%
0.4%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

Percent by Credits
49.0%
29.8%
7.3%
5.3%
3.0%
2.7%
1.1%
0.7%
0.5%
0.4%
0.1%
0.1%
0.0%
0.0%
0.0%
0.0%
0.0%

ramp available in a spinning event. For the seven spinning events in January
through June 2021, PJM Settlements paid a total of 1,620.0 MW intervals
from an average of 343 distinct units for an average 1,853.2 MW of real-time
MW increase. Settlements include units like wind, solar, nuclear, and demand
response which are not a part of the estimated tier 1 in the SCED market
solutions.
By observing spin event response recorded in PJM’s SCADA data, the MMU
estimates actual response as the sum of the products contributing to total ACE
increase from the time the event is initiated to 10 minutes after the event isinitiated. Total increase in ACE is a summation not only of tier 1 response,
but also of tier 2 response, regulation A and regulation D actual response(RegD response is sometimes a MW increase and sometimes a MW decrease),and changes to net imports/exports across PJM’s boundaries (sometimes anincrease and sometimes a decrease in MW).
In the RTO Reserve Zone, the average estimated tier 1 synchronized reserve
was 1,744.4 MW (Table 10-7). In 39.9 percent of dispatch solutions, theestimated tier 1 synchronized reserve was greater than the synchronizedreserve requirement, meaning that the synchronized reserve requirement wasmet entirely by tier 1 synchronized reserve plus self scheduled tier 2.
In the first six months of 2021, the average estimated tier 1 synchronizedreserve within the MAD Subzone was 807.9 MW (Table 10-6). In 4.1 percent of
dispatch solutions the estimated tier 1 synchronized reserve available within
the MAD Subzone plus self scheduled tier 2 in MAD was greater than thesynchronized reserve requirement and no tier 2 market needed to be cleared.

DemandIn the first six months of 2021, the SCED market solutions estimated that tier
1 MW from an average of 59 units could have an average of 1,734.1 MW of

There is no required amount of tier 1 synchronized reserve. The estimatedtier 1 MW are used to satisfy the total required amounts of synchronized andprimary reserve.

43 See PJM. “Manual 11: Energy & Ancillary Services Market Operations,” § 4.2.1 Synchronized Reserve Market Eligibility, Rev. 115 (June 1,2021).
44 See PJM. “Manual 11: Energy & Ancillary Services Market Operations,” § 4.2.1 Synchronized Reserve Market Eligibility, Rev. 115 (June 1,2021).

The ancillary services market solution treats the cost of estimated tier 1
synchronized reserve as $0, even when the nonsynchronized reserve market

496

Section 10 Ancillary Services© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

clearing price is above $0. As a result, the optimization cannot and does notminimize the total cost of primary reserves. The MMU recommends that tier 1
synchronized reserve not be paid when the nonsynchronized reserve market
clearing price is above $0.

Supply and Demand
The price of synchronized reserves results from the demand curve forsynchronized reserves and the supply of synchronized reserves. The demand
curve is modeled in each of the synchronized reserve clearing engines (ASO, IT
SCED, RT SCED). The demand curve for synchronized reserves has two steps,
with an $850 penalty factor for synchronized reserve levels ranging from 0
MW to a MW amount equal to 100 percent of the MSSC and a constraint witha $300 penalty factor for synchronized reserves ranging from 100 percent of
MSSC to 100 percent of MSSC plus 190 MW.
When solving for the synchronized reserve requirement the market solution
first estimates the amount of tier 1 available from the energy dispatch. If therequirement is not filled by tier 1, it then commits tier 2 beginning with all
self scheduled synchronized reserve.
In the MAD Subzone, the market solution takes all tier 1 MW estimated to beavailable within the MAD Subzone as well as the synchronized reserve MW
estimated to be available within the MAD Subzone from the RTO Zone (green
area of Figure 10-2). If the total tier 1 synchronized reserve is less than thesynchronized reserve requirement, the remainder of the synchronized reserve
requirement is filled with tier 2 synchronized reserve.

Tier 1 Synchronized Reserve Payments
Tier 1 synchronized reserve is awarded credits under two distinct circumstances.
In response to a spinning event, all resources (except scheduled tier 2 resources)
are paid for increasing output (or reducing load for demand response) at therate of $50 per MWh in addition to LMP.45 This is the Synchronized Energy
Premium Price. Spinning event response is calculated as the highest output
between 9 minutes and 11 minutes after the event is declared minus the
45 See PJM. “Manual 11: Energy & Ancillary Services Market Operations,”§ 4.2.10 Settlements, Rev. 115 (June 1, 2021).

© 2021 Monitoring Analytics, LLC

lowest output between one minute before and one minute after the event
is declared. Generator outputs are measured and reported to PJM every four
seconds via SCADA. Total response credited to a resource is capped at 110
percent of estimated capability. These rules apply to all resources that are notscheduled tier 2 resources. As a result, spinning event response involves more
MW response than the original estimate of tier 1. Many resources that are notincluded in PJM’s estimate of tier 1 nevertheless respond to spinning eventsand in accordance with the PJM Tariff are paid the Synchronized Energy
Premium Price. This can include incidental response from nuclear units or
steam turbines running at maximum output. Such response is expected when
the response is measured as the highest output for the two minute periodaround the end of an event minus lowest output from the two minute periodaround the start of an event. Tier 1 synchronized reserve that is part of theestimate (at market solution time) when there is no spinning event is also
credited for its full estimated MW whenever the nonsynchronized reserve
market clearing price is above $0.
In the event that the nonsynchronized reserve market clearing price is above$0 and there is a spinning event, estimated tier 1 is credited with the lesser
of its actual response or its estimated capability times the SRMCP. Tier 1
synchronized reserve not part of the estimate is credited the SRMCP times its
actual response.46 In the first six months of 2021, the nonsynchronized reserve
market clearing price was above $0 in 5.6 percent of intervals.
In the first six months of 2021, tier 1 synchronized reserve spinning event
response credits of $101,063 were paid for seven spinning events averaging
8.7 minutes. Table 10-10 shows the number of spinning events each month,
the credits paid for tier 1 response, the number of MWh credited, and theactual response in MW.

46 See PJM “Manual 28: Operating Agreement Accounting,” Rev. 84 (Dec. 17, 2020) p. 54.

2021 Quarterly State of the Market Report for PJM: January through June 497

2021 Quarterly State of the Market Report for PJM: January through June

Table 10-10 Tier 1 synchronized reserve event response costs: January 2020
through June 2021
Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun
Total

Number of
Spinning Events
2
4
1
1
1
0
3
0
1
2
1
1
17

Total Tier 1
Spinning Event
Credits$22,200$56,595$3,514$5,873$11,302NA$34,249
NA$11,390$23,038$7,964$10,050$186,176

1
0
1
2
1
2
7

$6,796NA$15,729$40,442$21,822$16,275$101,063

Total Tier 1 Spinning
Total Tier 1 Spinning
Response from Event
Event Credited (MWh) Start to Event End (MW)453.2
5,438.8
1,148.2
13,778.8
70.3
843.5
118.2
1,418.5
226.0
2,712.6NANA
699.8
8,397.2
NANA
236.2
2,843.1
460.8
5,713.0
159.3
2,019.3
201.0
2,426.1
3,773.0
45,590.9
97.1
NA
291.7
732.2
331.7
162.6
1,615.3

1,165.0NA1,715.8
4,677.7
2,618.6
3,183.0
13,360.1

Paying Tier 1 the Tier 2 Price
Tier 1 synchronized reserve has zero marginal cost and the corresponding
competitive price for tier 1 synchronized reserves is also zero. However,the PJM rules artificially create a marginal cost of tier 1 when the price of
nonsynchronized reserve is greater than zero and tier 1 is paid the tier 2 price.
The PJM market solutions do not include that marginal cost and therefore do
not solve for the efficient level of tier 1, tier 2 and nonsynchronized reserve inthose cases. When called to respond to a spinning event, tier 1 is compensatedat the Synchronized Energy Premium Price (Table 10-12). However, theshortage pricing tariff changes (October 1, 2012) modified the pricing of tier
1 so that tier 1 synchronized reserve is paid the tier 2 synchronized reserve
market clearing price whenever the nonsynchronized reserve market clearing
price rises above zero. The rationale for this change was and is unclear, but it

498

Section 10 Ancillary Services

has had a significant impact on the cost of tier 1 synchronized reserves (Table
10-11). In the first six months of 2021, the nonsynchronized reserve market
clearing price was above $0.00 in 29.6 percent of all intervals. For thoseintervals, tier 1 synchronized reserve was paid $2,372,703 for an average of
620.2 MW per interval.
Table 10-11 Price of tier 1 synchronized reserve attributable to anonsynchronized reserve price above zero: January 2020 through June 2021
Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun
Total

Number ofIntervals When
NSRMCP>$0
0
0
0
27
24
116
166
309
50
944
255
124
2015
31
160
60
196
644
183
1274

Weighted Average
Average Tier
SRMCP When
Total Tier 1 MWh Total Tier 1 Credits 1 MWh When
NSRMCP>$0 When NSRMCP>$0 When NSRMCP>$0 NSRMCP>$0
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
$6.12
3,654.9$22,372456.9$6.20
3,105.4$19,262
310.5$7.58
17,163.0$130,140
490.4$11.1822,696.6$253,682
687.8$12.5242,499.8$531,928
708.3
$3.94
7,277.5$28,658519.8$11.86
148,481.8$1,760,874
1,124.9$13.5532,994.0$447,060
673.4
$8.20
15,282.5$125,286
527.0
$9.02
293,155.5$3,319,263
611.0$20.78$16.36$93.20$8.14$10.65$10.63$26.633,625.7
19,953.0
7,768.9
24,971.2
74,895.9
23,148.4
154,363.1$75,337$326,372$724,083$203,196$797,736$245,979$2,372,703

604.3
739.0
517.3
531.3
720.2
609.2
620.2

The additional payments to tier 1 synchronized reserves under the shortage
pricing rule are a windfall. The additional payment does not create an incentive
to provide more tier 1 synchronized reserves. The additional payment is nota payment for performance; all estimated tier 1 receives the higher payment
regardless of whether they provide any response during any spinning event.
Tier 1 resources are not obligated to respond to synchronized reserve events.
In the first six months of 2021, there were three spinning events of 10 minutes© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

or longer. In those events, an average of 53.1 percent of the estimated tier 1
responded and 76.3 percent of tier 2 responded.
The MMU recommends that the rule requiring the payment of tier 1
synchronized reserve resources when the nonsynchronized reserve price isabove zero be eliminated immediately.47 Tier 1 should be compensated only
for a response to synchronized reserve events, as it was before the shortage
pricing changes. This compensation requires that when a synchronized reserve
event is called, all tier 1 response is paid the synchronized energy premium
price.
PJM’s current tier 1 compensation rules are presented in Table 10-12.
Table 10-12 Tier 1 compensation as currently implemented by PJM
Tier 1 Compensation by Type of Interval as Currently Implemented by PJM
Interval
Parameters

No Synchronized Reserve Event

NSRMCP=$0

T1 credits = $0

NSRMCP>$0

T1 credits = T2 SRMCP * estimated tier 1 MW

Synchronized Reserve Event
T1 credits = Synchronized Energy Premium Price *actual response MWi
T1 credits = T2 SRMCP * min(estimated tier 1 MW,
actual response MWi)

The MMU’s recommended compensation rules for tier 1 MW are in Table 10-13.
Table 10-13 Tier 1 compensation as recommended by MMU
Tier 1 Compensation by Type of Hour as Recommended by MMU
Interval
Parameters

No Synchronized Reserve Event

NSRMCP=$0

T1 credits = $0

NSRMCP>$0

T1 credits = $0

Synchronized Reserve Event
T1 credits = Synchronized Energy Premium Price *actual response MWi
T1 credits = Synchronized Energy Premium Price *actual response MWi

47 This recommendation was presented as a proposal, “Tier 1 Compensation,” to the Markets and Reliability Committee Meeting, October 22,
2015. The MMU proposal and a PJM counterproposal were both rejected.

© 2021 Monitoring Analytics, LLC

Tier 2 Synchronized Reserve Market
Synchronized reserve is provided by generators or demand response resources
synchronized to the grid and capable of increasing output or decreasingload within 10 minutes. Synchronized reserve consists of tier 1 and tier 2
synchronized reserves. When the synchronized reserve requirement cannot
be met by tier 1 synchronized reserve, PJM clears a market to satisfy therequirement with tier 2 synchronized reserve. Tier 2 synchronized reserve isprovided by online resources, either synchronized to the grid but not producing
energy, or dispatched to provide synchronized reserve at an operating point
below their economic dispatch point. Tier 2 synchronized reserve is also
provided by demand resources that have offered to reduce load in the eventof a synchronized reserve event. Tier 2 synchronized reserves are committed
to be available in the event of a synchronized reserve event. Tier 2 resources
have a must offer requirement. Some tier 2 resources are scheduled by the
ASO 60 minutes before the operating hour and are committed to provide
synchronized reserve for the entire hour. Tier 2 resources are paid the higherof the SRMCP or their offer price plus lost opportunity cost (LOC). Demand
response resources are paid the clearing price (SRMCP).
Synchronized reserve resources can be flexible or inflexible. Inflexible
resources are defined as those resources that require an hourly commitment
due to minimum run times or staffing constraints. Examples of inflexible
reserves are synchronous condensers operating in condensing mode, resources
with an economic minimum (EcoMin) equal to economic maximum (EcoMax),offline CTs and hydro that can operate in the condense mode, and demand
resources. Inflexible tier 2 synchronized reserve resources are committed for a
full hour by the hour ahead ASO market solution. Inflexible resources requirea 30 minute notification time and cannot be released for energy during theoperating hour. The inflexible commitments made by the hour ahead ASO
solution may satisfy only part of the tier 2 requirement. The actual requirement
is determined by the RT SCED solution and the requirement not satisfied byinflexible units is satisfied by flexible units. Flexible resources are alreadyonline for energy, require no notification time, and can be automaticallydispatched.

2021 Quarterly State of the Market Report for PJM: January through June 499

2021 Quarterly State of the Market Report for PJM: January through June

During the operating hour, RT SCED can dispatch additional tier 2 resources. RT
SCED can redispatch online tier 1 generating resources as tier 2 synchronizedreserve to meet the synchronized and primary reserve requirements within theoperational hour. Resources that are redispatched as tier 2 within the hour are
expected to maintain their available ramp and are paid the SRMCP plus any
lost opportunity costs that exceed the SRMCP.

Market Structure
SupplyPJM has a must offer tier 2 synchronized reserve requirement. All nonemergency
generating resources are required to submit tier 2 synchronized reserve offers.
All online, nonemergency generating resources are deemed available toprovide both tier 1 and tier 2 synchronized reserve although certain unit
types are exempt. If PJM issues a primary reserve warning, voltage reduction
warning, or manual load dump warning, all offline emergency generation
capacity resources available to provide energy must submit an offer for tier 2
synchronized reserve.48
In the first six months of 2021, the Mid Atlantic Dominion (MAD) Reserve
Subzone averaged 4,649.6 MW of tier 2 synchronized reserve offers, and the
RTO Reserve Zone averaged 36,322.9 MW of tier 2 synchronized reserve offers(Figure 10-6).

This means that in some hours demand resources make up considerably morethan 33 percent of the cleared tier 2 MW. Demand resources often offer at a
price of $0, do not incur an LOC, and clear even when the price is $0. As aresult, their share of credits in the synchronized reserve market is much lessthan their share of cleared MW.
Table 10-14 Supply of Generation Tier 2 Synchronized Reserve by Unit Typeand Fuel Type: January through June, 2021
Unit / Fuel TypeCT - Natural Gas
DSR
CT - Oil
Combined Cycle
Hydro - Run of River
Steam - Coal
RICE - Natural Gas
Hydro - Pumped Storage
Steam - Natural Gas
Battery
CT - Other
Fuel Cell
Nuclear
RICE - Other
Solar
Solar + Storage
Solar + Wind
Steam - Oil
Steam - Other
Wind
Wind + Storage

Percent by MW
34.9%
30.7%
11.2%
9.7%
8.2%
4.2%
0.5%
0.5%
0.1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

Percent by Credits
44.4%
13.9%
8.7%
22.7%
3.8%
5.1%
0.7%
0.4%
0.1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

The supply of tier 2 synchronized reserve offered in the first six months of2021 was sufficient to cover the ASO hourly requirement net of tier 1 in both
the RTO Reserve Zone and the MAD Reserve Subzone.

DemandThe largest portion of cleared tier 2 synchronized reserve in the first six monthsof 2021 was from CTs running on natural gas or oil (Table 10-14). Althoughdemand resources are limited to providing no more than 33 percent of the total
synchronized reserve requirement, the amount of tier 2 synchronized reserve
required in any hour is often much less than the full synchronized reserve
requirement because so much of it is met with tier 1 synchronized reserve.

On July 12, 2017, PJM adopted a dynamic synchronized reserve requirement set
equal to 100 percent of the most severe single contingency (MSSC) as the firststep, and extended by a 190 MW second step.49 There are two circumstances inwhich PJM may alter the base portion of the synchronized reserve requirementfrom its 100 percent of the largest contingency value. Reserve requirements
may be increased during a temporary switching condition when transmission
outages or configuration problems cause several generation resources to

48 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 4.2.1 Synchronized Reserve Market Eligibility, Rev. 115 June 1,2021).

500

Section 10 Ancillary Services

49 See the 2021 Quarterly State of the Market Report: January through June, Section 3: Energy Market, at “Operating Reserve Demand
Curves”.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

The RTO Reserve Zone scheduled and identified an average of 613.0 MW oftier 2 synchronized reserves in the first six months of 2021. Of this, an averageof 531.3 MW was scheduled hourly.
Figure 10-4 and Figure 10-5 show the average monthly synchronized reserve
required and the average monthly tier 2 synchronized reserve MW scheduled(PJM scheduled plus self scheduled) from January 2019 through March 2021,
for MAD Reserve Subzone and the RTO Reserve Zone. There were 33 intervalsof shortage in 2019. There were 13 spinning events in 2019 but only two lasted
longer than 10 minutes. There were seven intervals of shortage in 2020 and 16
spinning events with three longer than 10 minutes. In the first six months of2021 there were four intervals of shortage and seven spinning events.

2,500

$20
Average Synchronized Reserve Required
Average Tier 2 Synchronized Reserve Scheduled

2,000

Average Tier 2 Synchronized Reserve Market Clearing Price

$18
$16
$14

1,500

$12
$10

1,000

$8
$6

500

Synchronized Reserve Market Clearing PriceIn the first six months of 2021, the average synchronized reserve requirement
was 1,699.5 MW in the RTO Zone and 1,672.6 the MAD Subzone. Theseaverages include temporary increases to the synchronized reserve requirement.

Figure 10-4 MAD hourly average tier 2 synchronized reserve scheduled MW:
January 2018 through June 2021

MWbe subject to a single contingency. When PJM operators anticipate periodsof high load, they may bring on additional units to account for increased
operational uncertainty in meeting load. When a Hot Weather Alert, Cold
Weather Alert or an emergency procedure (as defined in Manual 11 § 4.2.2
Synchronized Reserve Requirement Determination) has been issued for theoperating day, operators may increase the synchronized reserve requirement
up to the full amount of the additional MW brought on line.50

$4
$2

0

$0

50 PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 4.2.2 Synchronized Reserve Requirement Determination, Rev. 115(June 1, 2021).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 501

2021 Quarterly State of the Market Report for PJM: January through June

Figure 10-5 RTO hourly average tier 2 synchronized reserve scheduled MW:
January 2019 through June 2021
2,500

$20
Average Tier 2 Synchronized Reserve Scheduled

2,000

Average Tier 2 Synchronized Reserve Market Clearing Price

$18

$16
$14

1,500

$12

MW

$10
1,000

$8

$6
500

Synchronized Reserve Market Clearing Price

Average Synchronized Reserve Required

$4
$2

0

$0

Market Concentration
The average HHI for tier 2 synchronized reserve cleared intervals in the MidAtlantic Dominion Subzone Tier 2 Synchronized Reserve Market in the firstsix months of 2021 was 5235, which is defined as highly concentrated. In 85.0
percent of all cleared pricing intervals the maximum market share was greaterthan or equal to 40 percent.
The average HHI for tier 2 synchronized reserve for cleared pricing intervalsof the RTO Zone Tier 2 Synchronized Reserve Market in the first six monthsof 2021 was 3919, which is defined as highly concentrated. In 55.5 percent
of cleared intervals there was a maximum market share greater than or equal
to 40 percent.

In the MAD Subzone, flexible synchronized reserve was 9.7 percent of alltier 2 synchronized reserve in the first six months of 2021. In the RTO Zone,
flexible synchronized reserve was 13.0 percent of all tier 2 synchronizedreserve in the first six months of 2021.
The market structure results indicate that the RTO Zone and Mid-Atlantic
Dominion Subzone Tier 2 Synchronized Reserve Markets are not structurallycompetitive.

Market Behavior
OffersDaily cost-based offers are submitted for each unit by the unit owner. For
generators the offer must include, when relevant, a tier 1 synchronizedreserve ramp rate, a tier 1 synchronized reserve maximum, self scheduled
status, synchronized reserve availability, synchronized reserve offer quantity(MW), tier 2 synchronized reserve offer price, energy use for tier 2 condensing
resources (MW), condense to gen cost, shutdown costs, condense startup cost,condense hourly cost, condense notification time, and spin as a condenser
status. The synchronized reserve offer price made by the unit owner is subject
to an offer cap of marginal cost plus a markup of $7.50 per MW. The tier 1
synchronized reserve ramp rate must be greater than or equal to the real-time
economic ramp rate. If the synchronized reserve ramp rate is greater thanthe economic ramp rate it must be justified by the submission of actual datafrom previous synchronized reserve events.51 All suppliers are paid the higherof the market clearing price or their offer plus their unit specific opportunity
cost. The offer quantity is limited to the economic maximum. PJM monitors
this offer by checking to ensure that all offers are greater than or equal to 90
percent of the resource’s ramp rate times 10 minutes. A resource that is unable
to participate in the synchronized reserve market during a given hour may set
its hourly offer to zero MW. Certain defined resource types are not required tooffer tier 2 because they cannot reliably provide synchronized reserve. These
include: nuclear, wind, solar, landfill gas and energy storage resources.52
51 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 4.2.1 Synchronized Reserve Market Eligibility Rev. 115 (June 1,2021).
52 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 4.2.1 Synchronized Reserve Market Eligibility Rev. 115 (June 1,2021).

502

Section 10 Ancillary Services© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

PJM has a tier 2 synchronized reserve must offer requirement for all generationthat is online, nonemergency, and physically able to operate with an output
less than dictated by economic dispatch. Tier 2 synchronized reserve offers
are made on a daily basis with hourly updates permitted. Daily offers can bechanged as a result of maintenance status or physical limitations only and are
required regardless of online/offline state.53 The tier 2 synchronized reserve
market is not cleared based on daily offers but based on hourly updates tothe daily offers. As a result of hourly updates the actual amount of eligible
tier 2 MW can change significantly every hour (Figure 10-6). Changes tothe hourly offer status are only permitted when resources are physicallyunable to provide tier 2. Changes to hourly eligibility levels are the resultof online status, minimum/maximum runtimes, minimum notification times,
maintenance status and grid conditions including constraints. However,resource operators can make their units unavailable for an hour or block ofhours without having to provide a reason.

Figure 10-6 Tier 2 synchronized reserve hourly offer and eligible volume(MW): January through June, 2021
50,000
RTO Daily Average Tier 2 Synchronized Reserve Offer and Eligible

45,000MAD Daily Average Tier 2 Synchronized Reserve Offer and Eligible

40,00035,00030,000MW

Figure 10-6 shows the daily average of hourly offered tier 2 synchronizedreserve MW for both the RTO Synchronized Reserve Zone and the MidAtlantic Dominion Synchronized Reserve Subzone.

25,00020,00015,00010,000
5,000
0

Jan

Feb

Mar

Apr

May

Jun

Although tier 2 synchronized reserve has a must offer requirement, there area large number of hours when many units make themselves unavailable fortier 2 synchronized reserve.
The MMU recommends that the tier 2 synchronized reserve must offer
requirement be enforced. The MMU recommends that PJM define a set of
acceptable reasons why a unit can be made unavailable daily or hourly andrequire unit owners to select a reason in Markets Gateway whenever making
a unit unavailable either daily or hourly or setting the offer to 0 MW.54

53 See id. (“Regardless of online/offline state, all non-emergency generation capacity resources must submit a daily offer for Tier 2
Synchronized Reserve in eMKT…”).

© 2021 Monitoring Analytics, LLC

54 PJM adopted a new business rule in the third quarter of 2017 to enforce compliance with the tier 2 must-offer requirement. PJM enters azero dollar offer price for all units with a must offer obligation for tier 2 synchronized reserves.

2021 Quarterly State of the Market Report for PJM: January through June 503

2021 Quarterly State of the Market Report for PJM: January through June

Market Performance

Supply, demand, and performance are reflected in the price of synchronizedreserve (Table 10-16).

Price
The price of tier 2 synchronized reserve is calculated in real time every fiveminutes by the RTSCED market solution for the RTO Reserve Zone and the
MAD Subzone. The tier 2 synchronized reserve market price is determined not
only by the offer price of each cleared MW of tier 2, but additionally by thenet cost of jointly optimizing the dispatch of energy and synchronized reserve.
For each MW assigned, the clearing engines determine a product substitution
price, i.e. the marginal cost of replacing the reserve MW with energy fromother resources. The product substitution cost is a function of the LMPs of
the MW of reserve, the marginal cost of energy for the resources providing
reserves, and the minimized cost of substituted MW providing energy. At themargin, the price is the sum of the offer price plus the product substitution
cost of the marginal unit(s).55 The number of marginal units by schedule typeis shown in Table 10-15.
Table 10-15 Schedule used for LOC of marginal units in RTSCED Tier 2
Synchronized Reserve Market LOC calculation: January through June, 2021
Number of Marginal Units
80,850Percent of Marginal Units with LOC
Based on Cost Schedule
7.9%

Percent of Marginal Units with LOC
Based on Price Schedule
92.1%

In the first six months of 2021, the RTSCED cleared the RTO tier 2 synchronizedreserve market in 60.4 percent of all dispatch solutions. In all other intervals
there was enough tier 1 synchronized reserve to cover the synchronizedreserve requirement. For intervals when the synchronized reserve requirement
could not be met with tier 1, the market cleared an average of 612.6 MW ofsynchronized reserve (including 140.3 MW of demand response) at a MW
weighted average price of $5.04 per hour.
The market clearing price for the MAD Subzone diverged from the RTO Zone
in 25 intervals during the first six months of 2021.
55 PJM Manual 11: Energy & Ancillary Services Market Operations, Rev. 115 (June 1, 2021), p. 92.

504

Section 10 Ancillary Services

Table 10-16 RTO Zone, average SRMCP and average scheduled, tier 1
estimated and demand response MW in RT SCED market solutions: January
2020 through June 2021

Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Average

2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun
Average

Average Interval
Weighted Average
Tier 2 Generation
Synchronized Reserve Synchronized Reserve
Market Clearing Price
Purchased (MW)
$0.41
322.4
$0.42
183.7
$0.93
293.8
$1.77
255.0
$0.85
202.5
$1.05
221.9
$1.05
335.4
$1.90
314.7
$1.47
209.6
$3.96
575.1
$3.03
502.6
$2.61
507.7
$1.62
327.0
$5.74
$4.84
$6.84
$3.74
$6.18
$5.55
$5.48

243.7
325.0
309.3
380.7
407.9
322.4
331.5

Average Interval
Tier 1 Synchronized
Average Interval
Reserve Estimated Demand Response(MW)
Cleared (MW)2,410.7
67.2
2,285.5
42.6
2,142.0
92.8
2,223.8
66.5
2,130.4
52.6
2,723.9
58.6
2,102.5
65.3
1,961.6
86.5
2,054.2
79.2
1,380.2
165.3
1,500.4
141.4
1,506.8
145.0
2,035.2
88.6
1,760.6
1,845.7
1,704.9
1,313.3
1,372.3
1,699.5
1,616.1

88.1
136.5
122.6
164.5
186.3
142.6
140.1

Settlement Cost
As a result of changing grid conditions, load forecasts, and unexpected
generator performance, prices do not always cover the full cost to customers,
including the final LOC for each resource. Because price formation occurs
within the hour (on a five minute basis) but inflexible synchronized reserve
commitment occurs prior to the hour, the realized, within hour price can be
zero even when some tier 2 synchronized reserve is cleared. All resources
cleared in the market are guaranteed to be made whole and are paid if the
SRMCP does not compensate them for their offer plus LOC.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

The full cost of tier 2 synchronized reserve including payments for theclearing price and out of market costs is calculated and compared to the price.
The closer the price to cost ratio is to 100 percent, the more the market pricereflects the full cost of tier 2 synchronized reserve. The price to cost ratioshows much tier 2 compensation results from price rather than uplift. A lower
price to cost ratio indicates higher uplift.
In the first six months of 2021, the price to cost (including self scheduled) ratioof the RTO zone tier 2 synchronized reserve market averaged 65.1 percent,which was higher than the 50.6 percent price to cost ratio for 2020 (Table
10-17). Prices were significantly higher in the first six months of 2021 ($5.81)
than they were in 2020 ($2.57) because of increases in the synchronizedreserve requirement. The market clearing solution includes a constraintthat forces all remaining synchronized reserve to be cleared from the MAD
Subzone (ref. Figure 10-1) when one of the constraints defining MAD binds.
RTO/MAD prices diverged in only 25 intervals in the first six months of 2021.
The average tier 2 synchronized reserve price in the RTO differed from theaverage Tier 2 synchronized reserve price in MAD by less than $0.01.

Table 10-17 RTO Zone tier 2 synchronized reserve MW, credits, price, andcost: January 2020 through June 2021

Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec

2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun

Tier 2Tier 2Credited
SRMCP
MW
Credits
177,649$244,383
76,770$127,375
180,688$440,691
161,868$909,181
113,879$320,911
152,400$468,431
250,123$881,318
234,393 $1,076,888
149,778$581,505
415,190 $3,364,375
353,269 $1,884,507
380,153 $1,854,411
2,646,160 $12,153,976

Weighted
Synchronized
Tier 2
Reserve Market Synchronized
LOC Credits Clearing Price Reserve Cost
$575,741
$1.38
$4.62
$147,292
$1.66
$3.58
$329,176
$2.44
$4.26
$307,374
$5.62
$7.52
$340,727
$2.82
$5.81
$526,993
$3.07
$6.53
$2,530,837$3.53$13.64$1,412,986$4.59$10.62$523,833
$3.88
$7.38
$1,210,422$8.13$11.02$738,252
$5.35
$7.42
$819,880
$4.94
$7.03
$9,463,512
$3.95
$7.45

235,289 $1,350,486
304,466 $1,355,042
315,327 $2,326,081
385,229 $1,351,927
437,210 $2,831,105
222,529 $1,098,124
1,900,050 $10,312,766$277,227$1,053,117$1,447,580$655,823$1,275,730$841,578$5,551,055

$5.74
$4.45
$7.44
$3.52
$6.54
$4.95
$5.44

$6.92
$7.91
$11.97
$5.21
$9.39
$8.72
$8.35

Price/Cost
Ratio
29.8%
46.4%
57.2%
74.7%
48.5%
47.0%
25.9%
43.3%
52.6%
73.8%
72.0%
70.2%
53.0%
83.0%
56.3%
62.1%
67.5%
69.7%
56.8%
65.1%

Performance
Tier 1 resource owners are paid for the actual amount of synchronizedreserve they provide in response to a synchronized reserve event.56 Tier 2
resource owners are paid for being available but are not paid based on theactual response to a synchronized reserve event. The MMU has identified andquantified the actual performance of scheduled tier 2 synchronized reserve
resources when called on to deliver during synchronized reserve events since2011.57 When synchronized reserve resources self schedule or clear the Tier 2
Synchronized Reserve Market they are obligated to provide their full scheduledtier 2 MW during a synchronized reserve event. Actual synchronized reserve
event response is determined by final output minus initial output where final
output is the largest output between 9 and 11 minutes after start of the event,56 See id. at 98.
57 See 2011 State of the Market Report for PJM, Vol. II, Section 9, “Ancillary Services,” at 250.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 505

2021 Quarterly State of the Market Report for PJM: January through Juneand initial output is the lowest output between one minute before the eventand one minute after the event.58 Tier 2 resources are obligated to sustain their
final output for the shorter of the length of the event or 30 minutes. Penalties
are assessed for failure of a scheduled tier 2 resource to perform during any
synchronized reserve event lasting 10 minutes or longer.
Tier 2 performance has not been adequate. Compliance with calls to respondto actual synchronized reserve events remains significantly less than 100
percent. For the spinning events 10 minutes or longer in 2016, the averagetier 2 synchronized reserve response was 85.5 percent of all scheduled MW.
In 2017, the response rate was 87.6 percent. In 2018, the response rate was74.2 percent. In 2019, the response rate was 86.8 percent. In 2020, there
were five spinning events 10 minutes or longer with an average response
rate of 59.5 percent of scheduled tier 2 MW. There were three spinning eventsin the first six months of 2021 that were 10 minutes or longer. They had atier 2 synchronized reserve response rate of 76.3 percent. Actual participant
performance means that the penalty structure is not adequate to incent
performance.
The penalty structure when a tier 2 resource fails to respond fully to a spinning
event includes two components. The resource forfeits all SRMCP credits and
LOC credits in the amount of the MW shortage for the day on which the event
occurred. The resource also receives a penalty for all hours in the Immediate
Past Interval (IPI) in the amount of MW it falls short of its scheduled MW.
The penalty is applied only to the SRMCP credits, not to the LOC credits.
The penalty period is calculated as the lesser of the average number of days
between spinning events over the past two years (ISI) or the number of days
since the resource last failed to respond fully. There are several problems
with this penalty structure. Resource owners are permitted to aggregate theresponse of multiple units to offset an underresponse from one unit withan overresponse from a different unit to reduce an underresponse penalty.59
The IPI uses the last spinning event when the resource did comply. But for
all spin events less than 10 minutes, compliance is automatically counted as
100 percent. This incorrectly truncates the IPI. The penalty applies only to
58 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 4.2.10 Settlements Rev. 115 (June 1, 2021).
59 See PJM “Manual 28: Operating Agreement Accounting,”§ 6.3 Charges for Synchronized Reserve, Rev. 84 (Dec. 17, 2020.)

506

Section 10 Ancillary Services

the SRMCP credits not the LOC credits. But most credits awarded are for LOC(Table 10-18).
Under the current penalty structure it is possible for a resource to not respondto any spin events and yet be paid for providing tier 2. The current penalty
structure for tier 2 synchronized reserve nonperformance is not adequate toprovide appropriate performance incentives.
The IPI is defined as the number of days between spinning events, regardlessof duration. This definition artificially shortens the period since the lastrequirement to perform. The MMU continues to recommend that the IPI
be defined as the number of days between spinning events 10 minutes or
longer. In the first two quarters of 2021, PJM had seven spin events. Threeof those events were 10 minutes or longer, March 9, April 30, and May 26.
The previous 10 minute event was on December 16, 2020. If only events 10
minutes or longer were considered, the IPI would increase to 71 days fromits current level of 29 days. Use of the currently defined average IPI is not
appropriate. The penalty should be based on the actual time since the last
spinning event of 10 minutes or longer during which the resource performed
because performance is only measured for events 10 minutes or longer. Even
using the proposed IPI the penalties may be insufficient to ensure response. A
tier 2 shortfall penalty should include LOC payments as well as SRMCP and
MW of shortfall.
Table 10-18 Comparison of tier 2 shortfall penalties under current IPI vs.
MMU recommended IPI: January through June, 2021
Actual SRMCP Credits
Using Current IPI$1,190,407

Actual Retroactive
Penalty Charges Using
Current IPI$121,752

Retroactive Penalty
Using MMU
Recommended IPI$236,960

Retroactive Penalty Using MMU
Recommended IPI and LOC
Forfeiture$395,716

Including aggregate responses from all online resources weakens the
incentive to perform and creates an incentive to withhold reserves from otherresources. Synchronized reserve commitment is unit specific, so the obligation
to respond should also be unit specific. Any potentially offsetting response
from an affiliated tier 1 resource should have been included as part of the© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

reserves in the tier 1 estimate. Any potentially offsetting response from a tier2 resource should have been included in that tier 2 offer.
The MMU recommends that aggregation not be permitted
to offset unit specific penalties for failure to respond to asynchronized reserve event.
Spinning event response data as reported by PJM in its
Operating Committee meetings is shown in Table 1019. The tier 1 estimate is from the most recent RT SCED
market solution. The tier 1 estimate includes estimatedramp only from the units that are eligible and excludes
resources that have ramp available but are not part of theestimate.
Tier 1 synchronized reserve that responds to a spinning
event receives a bonus payment of $50 per MWh, basedon a calculation using SCADA data, regardless of whether
PJM included those reserves in the estimate.

Spin Event (Day, EPTTime)
Sep 23, 2019 12:07
Oct 1, 2019 14:56
2019 Average

Duration(Minutes)11
11
11

Tier 1 Estimate(Market Solution
MW Adj by DGP)
1,485.1
265.4
924.7

Feb 18, 2020 20:15
Jul 6, 2020 21:22
Jul 25, 2020 16:39
Sep 10, 2020 00:29
Dec 16, 2020 16:49
2020 Average

10
10
11
10
10
10

2,216.1
1,464.0
868.4
1,275.4
268.4
1,218.5

1,434.8
526.1
421.6
453.6
196.9
606.6

Mar 9, 2021 07:50
Apr 30, 2021 16:30
May 26, 2021 10:17
2021 Average

10
12
10
11

1,354.9
1,487.6
1,138.4
1,327.0

635.4
610.2
811.0
685.5

Table 10-19 shows synchronized reserve event response compliance for tier
1 and tier 2 reserves as reported by PJM, using only response from tier 1
estimated and tier 2 cleared reserves. Actual synchronized reserve responseis the total increase in MW from all resources from the moment the spinning
event is called to ten minutes after. To determine the actual tier 1 response,the calculation would subtract tier 2 response, changes in assigned regulation
output (net compliance level to both RegA and RegD), and changes to net
power flow across PJM’s interface boundary. The overall response to spinning
events is adequate or more than adequate to meet NERC requirements. PJM
not only corrects the ACE disturbance that led to the event but over corrects.
In eight of the 10 spinning events the ACE recovers not just to the NERC
required level (which is the lesser of 0 or the value before the disturbancewhich caused the event) but overshoots.

© 2021 Monitoring Analytics, LLC

Table 10-19 Synchronized reserve events 10 minutes or longer, tier 1 and tier2 response compliance as reported by PJM, RTO Reserve Zone: January 2019
through June 2021
Response fromTier 2Tier 1 DGP Scheduled
Estimated (MW)(MW)
1,212.1
723.2
143.7
1,177.4
664.1
723.2

Tier 2
Response(MW)
632.1
1,016.4
632.1

Tier 2
Penalty
(MW)
91.1
161.0
91.1

DGP EstimatedTier 1 Response
Percent
81.6%
54.1%
71.8%

Tier 2
Response
Percent
87.4%
86.3%
87.4%

40.0
479.7
302.3
782.6
527.6
426.4

1.7
415.1
264.8
782.6
413.2
375.5

38.3
64.6
37.5
0.0
114.4
51.0

64.7%
35.9%
48.5%
35.6%
73.4%
49.7%

4.3%
86.5%
87.6%
100.0%
78.3%
59.5%

884.0
508.3
685.2
692.5

540.8
407.2
600.2
516.1

343.2
101.1
85.0
176.4

46.9%
41.0%
71.2%
53.1%

61.2%
80.1%
87.6%
76.3%

Until April 2019, PJM’s ASO market solution software allowed operators tobias the inflexible tier 2 synchronized reserve solution by forcing the software
to assume a different tier 1 MW value than the actual estimate. PJM, in
response to the MMU recommendation, no longer uses tier 1 biasing in anyof its market solutions. Biasing means manually modifying (decreasing or
increasing) the tier 1 synchronized reserve estimate of the market solution.
Tier 1 biasing was never referenced in PJM manuals or any public document.
PJM could resume tier 1 biasing at its discretion. Although tier 1 biasing has
been discontinued, PJM can and does still deselect tier 1 resources based on
PJM judgment. The impact of tier 1 deselection can be very significant (Table
10-20 and Table 10-21).

2021 Quarterly State of the Market Report for PJM: January through June 507

2021 Quarterly State of the Market Report for PJM: January through June

History of Synchronized Reserve Events

Table 10-20 Units deselected for tier 1 by market solutions but awarded
credits for actual response: 2021

Spinning Event
1/24/2021 3:22
3/9/2021 12:50
4/13/2021 20:05
4/30/2021 20:30
5/26/2021 14:17
6/21/2021 5:54
6/23/2021 3:33

Number ofUnits Awarded
T1 Credits
1513
1515
1497
1496
1492
1494
1492

Number Units
Deselected by
RTSCED Awarded
T1 Credits
280
938
374
705
864
545
354

Total T1
Credits
Awarded$6,592$14,658$18,496$20,868$21,233$10,301$5,735Percent of
T1 Credits
Awarded to Units
Deselected for T1
46.0%
46.4%
38.3%
44.5%
49.0%
28.9%
50.5%

Total T1 Percent of T1 MW
CreditedAwarded CreditsMW
But Deselected
1,582.2
46.0%
1,918.985.0%
4,439.0
38.3%
2,921.5
76.3%
5,095.8
49.0%
2,119.0
33.7%
1,376.5
50.5%

Table 10-21 Comparison of market solution tier 1 estimate, tier 1 responsewith PJM Settlements tier 1 MW credited: January 2020 through June 2021
Start TimeJan 20, 2020 14:06
Jan 23, 2020 16:17
Feb 7, 2020 12:06
Feb 8, 2020 03:44
Feb 10, 2020 20:15
Feb 18 2020 11:16
Mar 8, 2020 05:17
Apr 13, 2020 19:53
May 3, 2020 12:23
Jul 6, 2020 21:22
Jul 24, 2020 01:03
Jul 25, 2020 16:39
Sep 10, 2020 00:19
Oct 10, 2020 18:52
Oct 12, 2020 04:29
Nov 13, 2020 11:36
Dec 16, 2020 16:38
Jan 25, 2021 03:32
Mar 9, 2021 12:50
Apr 13, 2021 20:05
Apr 30, 2021 20:30
May 26, 2021 14:17
Jun 21, 2021 05:54
Jun 23, 2021 03:33

Duration(Minutes)
7.8
8.7
6.4
8.4
9.6
10.0
5.6
7.9
6.6
10.4
9.9
11.7
9.5
7.7
9.3
5.9
10.0
6.5
10.8
8.8
11.6
10.0
6.9
4.7

PJM Market Solution
DGP Estimated Tier 1
Estimate MW
1,903.6
2,084.6
1,233.0
1,961.4
1,333.3
2,216.1
1,541.4
433.0
4,154.4
1,464.0
1,562.7
868.4
1,275.4
2,134.3
1,625.8
1,687.9
268.4
2,134.5
1,354.9
2,093.4
1,487.6
1,138.4
2,340.8
2,277.0

PJM Market Solution
DGP Estimated Tier 1 PJM Settlements Tier 1
Response MW Credited Response MW
765.9
1,306.3
1,073.0
1,860.4730.2
2,883.9
826.1
1,517.6
824.3
1,573.8
1,434.8
2,528.6
660.1
843.5
207.2
886.5
1,369.6
2,260.5
526.1
1,554.5852.8
1,762.7
421.6
961.5
453.6
1,417.0
1,234.3
2,187.8
670.5
1,229.2
882.4
1,682.8196.9
1,213.0
577.9
1,582.2
635.4
1,918.9975.6
4,439.0
610.2
2,921.5
811.0
5,095.8
1,764.1
2,119.0
1,367.8
1,376.5

Synchronized reserve is designed to provide relief for disturbances.60 61 A
disturbance is defined as loss of the lesser of 900 MW or 80 percent of
the most severe single contingency within 60 seconds. In the absenceof a disturbance, PJM operators have used synchronized reserve as asource of energy to provide relief from low ACE.

The risk of using synchronized reserves for energy or any othernondisturbance reason is that it reduces the amount of synchronizedreserve available for a disturbance. Disturbances are unpredictable.
Synchronized reserve has a requirement to sustain its output for only
up to 30 minutes. When the need is for reserve extending past 30 minutes,
secondary reserve is the appropriate source of the response. The use ofsynchronized reserve is an expensive solution during an hour when the hourahead market solution and reserve dispatch indicate no shortage of primaryreserve. PJM’s primary reserve levels have been sufficient to recover fromdisturbances and should remain available in the absence of disturbances.
From January 2010 through June 2021, PJM experienced 265 synchronizedreserve events (Table 10-22), approximately two events per month. During thisperiod, synchronized reserve events had an average duration of 11.1 minutes.

60 2013 State of the Market Report for PJM, Appendix F – PJM’s DCS Performance, at 451–452.
61 See PJM “Manual 12: Balancing Operations,” Rev. 42 (Jan. 27, 2021) § 4.1.2 Loading Reserves.

508

Section 10 Ancillary Services© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Table 10-22 Synchronized reserve events: January 2017 through June 202162
Effective Time
JAN-08-2017 03:21
JAN-09-2017 19:24
JAN-10-2017 13:05
JAN-15-2017 20:13
JAN-23-2017 09:08
FEB-13-2017 18:30
FEB-14-2017 00:11
FEB-15-2017 06:37
MAR-23-2017 06:48
APR-08-2017 11:53
MAY-08-2017 04:18
JUN-08-2017 03:39
JUN-20-2017 05:38
SEP-04-2017 20:18
SEP-07-2017 09:16
SEP-21-2017 14:15

Duration(Minutes) Effective Time
7 JAN-01-2018 02:41
9 JAN-03-2018 03:00
9 JAN-07-2018 14:15
8 APR-12-2018 13:28
7 JUN-04-2018 10:22
7 JUN-29-2018 15:21
6 JUN-30-2018 09:46
6 JUL-04-2018 10:56
24 JUL-10-2018 15:45
10 JUL-23-2018 09:02
10 JUL-23-2018 15:43
10 JUL-24-2018 16:17
9 AUG-12-2018 11:06
15 SEP-13-2018 09:47
9 SEP-14-2018 13:24
16 SEP-26-2018 19:08
SEP-30-2018 11:29
OCT-30-2018 10:40

Region
RTO
RTO
MAD
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
MAD
RTO
RTO

Region
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO

Duration(Minutes) Effective Time
7 JAN-22-2019 22:30
13 JAN-31-2019 01:26
9 JAN-31-2019 09:26
10 FEB-25-2019 00:25
6 MAR-03-2019 12:31
9 MAR-06-2019 22:06
11 JUL-27-2019 23:31
7 AUG-11-2019 12:14
13 SEP-03-2019 13:39
8 SEP-23-2019 16:06
6 OCT-01-2019 18:56
7 DEC-11-2019 21:08
11 DEC-18-2019 15:07
7
7
8
11
11

Region
RTO
RTO
RTO
RTO
RTO
RTO
RTO
RTO
MAD
RTO
RTO
RTO
RTO

Duration(Minutes) Effective Time
8 JAN-20-2020 14:06
5 JAN-23-2020 16:17
9 FEB-07-2020 12:06
9 FEB-08-2020 03:44
9 FEB-10-2020 20:15
9 FEB-18-2020 11:16
7 MAR-08-2020 05:17
8 APR-13-2020 20:01
9 MAY-03-2020 12:29
11 JUL-06-2020 21:22
11 JUL-24-2020 01:03
8 JUL-25-2020 16:39
9 SEP-10-2020 00:19
OCT-10-2020 18:52
OCT-12-2020 04:29
NOV-13-2020 07:46
DEC-16-2020 16:38

Region
MAD
RTO
RTO
RTO
RTO
RTO
MAD
RTO
RTO
RTO
RTO
MAD
RTO
RTO
RTO
RTO
MAD

Duration(Minutes) Effective Time
8 JAN-24-2021 22:32
9 MAR-9-2021 07:51
6 APR-13-2021 20:05
8 APR-30-2021 20:30
9 MAY-26-2021 14:17
10 JUN-21-2021 05:54
5 JUN-23-2021 03:33
8
6
10
9
11
10
8
9
6
10

Region
RTO
RTO
RTO
RTO
RTO
RTO
RTO

Duration(Minutes)
6
11
9
12
10
7
5

Figure 10-7 shows spin event durations over the past eight years.
Figure 10-7 Synchronized reserve events duration distribution curve: January 2013 through June 2021
16
2013

14

2014
2015

12

2016

Number of Events

2017

2018

10

2019
2020

8

2021

6
4
2
0

5-9

10-14

15-19
20-24
25-29
Synchronized Reserve Event Duration (Minutes)

30+

62 For full history of spinning events, see the 2019 State of the Market Report for PJM, Appendix E - Ancillary Service Markets.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 509

2021 Quarterly State of the Market Report for PJM: January through June

Nonsynchronized Reserve Market
Nonsynchronized reserve consists of MW available within 10 minutes but notsynchronized to the grid. Startup time for nonsynchronized reserve resources
is not subject to testing and is based on parameters in offers submitted
by resource owners. There is no defined requirement for nonsynchronizedreserves. It is available to meet the primary reserve requirement. Generation
resources that have designated their entire output as emergency are noteligible to provide nonsynchronized reserves. Generation resources that are
not available to provide energy are not eligible to provide nonsynchronizedreserves.
The market mechanism for nonsynchronized reserve does not include any
direct participation by market participants. PJM defines the demand curvefor nonsynchronized reserve and PJM defines the supply curve based onnonemergency generation resources that are available to provide energy andcan start in 10 minutes or less and on the associated resource opportunity
costs calculated by PJM. Generation owners do not submit supply offers.
Since nonsynchronized reserve is a lower quality product, its clearing price isless than or equal to the synchronized reserve market clearing price. In mosthours, the nonsynchronized reserve clearing price is zero.

Market Structure
DemandDemand for primary reserve is established by PJM as one and a halftimes the largest contingency. Demand for primary reserve is calculated
dynamically in every synchronized and nonsynchronized reserve market
solution. After filling the synchronized reserve requirement the balanceof primary reserve can be made up by the most economic combination ofsynchronized and nonsynchronized reserve. In practice this means that the
primary reserve requirement minus the scheduled synchronized reserve is thenonsynchronized requirement for the interval. PJM may increase the primaryreserve requirement to cover times when a single contingency could cause an

outage of several generating units or in times of high load conditions causing
operational uncertainty.63
The average scheduled nonsynchronized reserve in the RTO Zone in the firstsix months of 2021 was 1,537.3 MW. The average scheduled nonsynchronizedreserve in the MAD Subzone for primary reserve was 1,235.7 MW.

SupplyFigure 10-2 shows that when tier 1 synchronized reserve does not fully meetthe synchronized reserve requirement, then most of the primary reserve
requirement (blue line) in excess of the synchronized reserve requirement(purple line) is satisfied by nonsynchronized reserve (green area).
There are no offers for nonsynchronized reserve. The market solution considers
the available supply of nonsynchronized reserve to be all generation resources
currently not synchronized to the grid but available and capable of providing
energy within 10 minutes. Generators that have set themselves as unavailable
or have set their output to be emergency only will not be considered. The
market solution considers the offered MW to be the lesser of the economic
maximum or the ramp rate times 10 minutes minus the startup and notification
time. The market supply curve is constructed from the nonsynchronized units’
opportunity cost of providing reserves. PJM and generation owners may agree
upon exceptions to the requirements.
Nonsynchronized reserve resources are scheduled economically basedon estimated LOC until the Primary Reserve requirement is filled. The
nonsynchronized reserve market clearing price is determined every fiveminutes based on the LOC of the marginal unit. When a unit clears thenonsynchronized reserve market and is scheduled, it is committed to remain
offline and available to provide 10 minute reserves.
Resources that generally qualify as nonsynchronized reserve include run ofriver hydro, pumped hydro, combustion turbines, combined cycles that can
63 See PJM “Manual 11: Energy and Ancillary Services Market Operations,” § 4.2.2 Synchronized Reserve Requirement Determination, Rev.
115 (June 1, 2021).

510

Section 10 Ancillary Services© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

start in 10 minutes or less, and diesels.64 In the first six months of 2021, an
average of 1,243.4 MW of nonsynchronized reserve was scheduled per fiveminute interval out of 1,320.1 eligible MW as part of the primary reserve
requirement in the RTO Zone. If only intervals when the price was greaterthan $0 are looked at, then an average of 635.4 MW of nonsynchronizedreserve is scheduled out of 983.5 MW available.
In the first six months of 2021, CTs provided 88.4 percent of scheduled
nonsynchronized reserve (Table 10-23). Natural gas was the primary fuel fornonsynchronized reserve.
Table 10-23 Supply of nonsynchronized reserve by fuel and unit type: January
through June, 2021
Unit / Fuel TypeCT - Natural Gas
CT - Oil
Hydro - Run of River
Hydro - Pumped Storage
CT - Other
Combined Cycle
Steam - Coal
RICE - Natural Gas
Steam - Natural Gas
Battery
RICE - Other
Fuel Cell
Nuclear
Solar
Solar + Storage
Solar + Wind
Steam - Oil
Steam - Other
Wind
Wind + Storage

Percent by MW
51.9%
36.5%
11.1%
0.2%
0.2%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

Percent by Credits
62.1%
27.7%
10.0%
0.1%
0.1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

Table 10-24 Nonsynchronized reserve market pivotal supplier test: January
through June, 2021
Year
2021
2021
2021
2021
2021
2021
2021

Month
Jan
Feb
Mar
Apr
May
Jun
Average

Number Intervals ofClearing Price > $0.01
30
130
56
163
615
186
197

Percent of Intervals
NSRMCP>$0.02 Pivotal
100.0%
89.8%
83.9%
100.0%
100.0%
100.0%
95.6%

Price
The settled price of nonsynchronized reserve is calculated in real time every
five minutes for the RTO Reserve Zone and the Mid-Atlantic Dominion
Reserve Subzone.
Figure 10-8 shows the daily average nonsynchronized reserve market clearing
price (NSRMCP) and average scheduled MW for the RTO Zone. In the firstsix months of 2021, the weighted average nonsynchronized market clearing
price was $0.25 per MW. The average nonsynchronized reserve scheduled was
1,065.7 MW.

Market Concentration
The supply of nonsynchronized reserves in the Mid-Atlantic Dominion
Subzone and the RTO Zone was highly concentrated in the first six monthsof 2021.
64 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 4b.2 Non-Synchronized Reserve Market Business Rules, Rev. 115(June 1, 2021)© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 511

2021 Quarterly State of the Market Report for PJM: January through June

Figure 10-8 Daily average RTO Zone nonsynchronized reserve market clearing
price and MW purchased: January through June, 2021
2,500

$7.00

Daily Average Nonsynchronized Reserve (MWh)Daily Average Weighted Nonsynchronized Reserve Market Clearing Price

$6.00

2,000
$5.00
1,500

$4.00

$3.00

1,000

$2.00
500

$1.00

0

Jan

Feb

Mar

Apr

May

Jun

Daily Average Weighted Nonsynchronized Reserve Market Clearing Price($)

Average Daily Nonsynchronized Reserve MWhprice (Table 10-25). The closer the price to cost ratio comes to one, the morecompensation is provided through market prices rather than uplift.
In the first six months of 2021, the average price of nonsynchronized reserve
was $0.25. The average cost per MW of nonsynchronized reserve was $1.28.
Resources that are not synchronized to the grid are generally off because
it is not economic for them to produce energy. A resource scheduled fornonsynchronized reserve is obligated to remain unsynchronized even if its
LMP changes and it becomes economic to start. In that case, the unit has apositive LOC.

$0.00

Price and Cost
As a result of changing grid conditions, load forecasts, incorrect LMP and lost
opportunity cost projections, and unexpected generator performance, prices
frequently do not cover the full LOC of each resource. All resources clearedin the market are guaranteed to be made whole and are paid uplift credits if
the NSRMCP does not fully compensate them. When real-time LMP is greaterthan the generator’s incremental energy offer at economic minimum, then an
LOC is paid, even if LMP revenue would not have covered the unit’s start andno load costs.65
The full cost to customers of nonsynchronized reserve, including payments
for the clearing price and uplift costs is calculated and compared to the
65 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 2.16 Minimum Capacity Emergency in Day-ahead Market, Rev. 115(June 1, 2021).

512

Section 10 Ancillary Services© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Market Structure

Table 10-25 RTO zone nonsynchronized reserve MW, charges, price, and cost:
January 2020 through June 2021
Market
RTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO Zone

Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

RTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO ZoneRTO Zone

2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun
Total

Total
Total
Weighted
Nonsynchronized NonsynchronizedNonsynchronized Nonsynchronized
Reserve MW Reserve Charges Reserve Market Price
Reserve Cost
775,929$377,336
$0.00
$0.49
758,614$138,939
$0.00
$0.18
806,059$170,156
$0.00
$0.21
665,747$644,306
$0.02
$0.97
774,183$425,791
$0.01
$0.55
619,391$649,601
$0.11
$1.05
767,222$648,118
$0.24
$0.84
799,233$1,106,678
$0.49
$1.38
761,617$750,028
$0.02
$0.98
773,420$1,588,183
$0.93
$2.05
725,048$809,177
$0.36
$1.12
851,859$921,357
$0.07
$1.08
9,078,323$8,229,669
$0.19
$0.91
878,568
706,486
760,807752,203725,702801,295
4,625,059$531,437$600,304$1,612,035$422,508$1,795,780$942,343$5,904,407

$0.05
$0.27
$0.34
$0.14
$0.53
$0.19
$0.25

$0.60
$0.85
$2.12
$0.56
$2.47
$1.18
$1.28

Secondary Reserve (DASR)
There is no NERC standard for secondary reserve. PJM defines secondary reserve
as reserves (online or offline available for dispatch) that can be converted
to energy in 30 minutes. PJM defines a secondary reserve requirement but
does not currently have a defined reserve product to maintain this reserve
requirement in real time.

SupplyPrice/Cost
Ratio
NA
NA
NA
2.1%
1.1%
10.4%
28.4%
35.4%
2.0%
45.2%
31.9%
6.4%
18.10%
8.3%
31.8%
16.0%
25.8%
21.3%
16.3%
19.9%

Both generation and demand resources are eligible to offer DASR.
DASR offers consist of price only. Available DASR MW are calculatedby the market clearing engine. DASR MW are the lesser of the energy
ramp rate per minute for online units times 30 minutes, or the economic
maximum MW minus the day-ahead dispatch point. For offline
resources capable of being online in 30 minutes, the DASR quantity is
the economic maximum. In the first six months of 2021, the averageavailable hourly DASR was 17,368.1 MW, a 3.7 percent decrease from2020. The DASR hourly MW purchased averaged 4,563.4 MW.67
PJM excludes resources that cannot reliably provide reserves in realtime from participating in the DASR market. Such resources include
nuclear, run of river hydro, self scheduled pumped hydro, wind,solar, and energy storage resources.68 The intent of this proposal is
to limit cleared DASR resources to those resources actually capableof providing reserves in the real-time market. Owners of excluded
resources may request an exemption from their default noneligibility.

Of the scheduled DASR MW cleared in the first six months of 2021, 84.1
percent was from CTs (Table 10-26).

PJM maintains a day-ahead, offer based market for 30 minute day-ahead
secondary reserve. The Day-Ahead Scheduling Reserve Market (DASR) has no
performance obligations except that a unit which clears the DASR market isrequired to be available for dispatch in real time.66
66 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 10.5 Aggregation for Economic and Emergency Demand
Resources, Rev. 115 (June 1, 2021).

© 2021 Monitoring Analytics, LLC

67 The average hourly available DASR MW are modified from previously reported values because of a calculation error which has been fixed.
68 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 11.2.2 Day-Ahead Scheduling Reserve Market Eligibility, Rev. 115(June 1, 2021).

2021 Quarterly State of the Market Report for PJM: January through June 513

2021 Quarterly State of the Market Report for PJM: January through June

Table 10-26 Scheduled DASR by fuel and unit type: January through June, 2021
Unit Types
CT - Natural Gas
CT - Oil
Hydro - Pumped Storage
Combined Cycle
Steam - Coal
Steam - Natural Gas
RICE - Oil
RICE - OtherRICE - Natural Gas
Steam - Other
NuclearCT - Other
Battery
Fuel Cell
Hydro - Run of River
Solar
Solar + Storage
Solar + Wind
Steam - Oil
Wind
Wind + Storage

Percentage of DASR MW
66.1%
18.0%
9.4%
3.9%
2.1%
0.2%
0.2%
0.1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

Percentage of DASR Credits
64.8%
17.5%
7.2%
5.1%
2.1%
2.0%
0.8%
0.3%
0.2%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

DemandSecondary reserve (30 minute reserve) requirements are determined by PJM foreach reliability region. In the ReliabilityFirst (RFC) region, secondary reserve
requirements are calculated based on historical under forecasted load rates
and generator forced outage rates.69 The DASR requirement is calculated daily
and is equal to the peak load forecast for the ReliabilityFirst region (RFC) and
EKPC times the sum of the forced outage rate and the load forecast error, plus
Dominion’s share of the VACAR contingency reserve commitment. Effective
November 1, 2020 through October 31, 2021, the day-ahead schedulingreserve requirement is 4.72 percent of the peak load forecast. This is basedon a 2.18 percent load forecast error component and a 2.60 percent forced
outage rate component. The DASR requirement is applicable for all hours of
the operating day.

69 See PJM “Manual 13: Emergency Operations,” § 2.2 Reserve Requirements, Rev. 78 (Jan. 27, 2021).

514

Section 10 Ancillary Services

The DASR requirement can be increased by PJM operators under conditionsof “hot weather or cold weather alert or max emergency generation alert orother escalating emergency.”70 The amount of additional DASR MW that may
be required is the Adjusted Fixed Demand (AFD) determined by a Seasonal
Conditional Demand (SCD) factor.71 The SCD factor is calculated separately for
the winter (November through March) and summer (April through October)seasons. The SCD factor is calculated every year based on the top 10 peakload days from the prior year. For November 2020 through October 2021, theSCD values are 2.12 percent for winter and 4.72 percent for summer. PJM
Dispatch may also schedule additional Day-Ahead Scheduling Reserves as
deemed necessary for conservative operations.72 PJM has defined the reasonsfor conservative operations to include, potential fuel delivery issues, forest/
brush fires, extreme weather events, environmental alerts, solar disturbances,
unknown grid operating state, physical or cyber attacks.73 The result is
substantial discretion for PJM to increase the demand for DASR under avariety of circumstances. PJM invoked adjusted fixed demand in 84 hours
during the first six months of 2021.
The MMU recommends that PJM modify the DASR market to ensure that all
resources cleared incur a real-time performance obligation. The MMU further
recommends that PJM attach a reason code to all hours when adjusted fixeddemand is dispatched.

70 PJM. “Energy and Reserve Pricing & Interchange Volatility Final Proposal Report,” <http://www.pjm.com/~/media/committees-groups/
committees/mrc/20141030/20141030-item-04-erpiv-final-proposal-report.ashx>.
71 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 11.2.1 Day-Ahead Scheduling Reserve Market Requirement. Rev.
115 (June 1, 2021)
72 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 11.2.1 Day-Ahead Scheduling Reserve Market Reserve
Requirement, Rev. 115 (June 1, 2021).
73 See PJM “Manual 13: Emergency Operations,” § 3.2 Conservative Operations, Rev. 78 (Jan. 27, 2021).

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Market Concentration
DASR market three pivotal supplier test results are provided in Table 10-27.
Table 10-27 DASR market three pivotal supplier test results and number ofhours with DASRMCP above $0.01: January 2020 through June 2021
Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Average

Number of Hours WhenDASRMCP > $0
1
1
1
17
70
73
89
73
59
86
47
35
46

Percent of Hours WhereDASRMCP>0 Pivotal
33.3%
50.0%
100.0%
70.8%
49.3%
22.7%
42.0%
22.7%
66.3%
50.6%
67.1%
50.7%
0.0%

2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun
Average

28
32
24
129
79
156
75

32.1%
46.9%
41.7%
47.3%
59.5%
47.4%
45.8%

Market Conduct
PJM rules allow any unit with reserve capability that can be converted into
energy within 30 minutes to offer into the DASR market.74 Units that do notoffer have their offers set to $0.00 per MW during the day-ahead market
clearing process.

offered DASR at a daily price above $0.00 per MW. In the first six months of2021 15.8 percent of daily offers were above $5.00 per MW.
The MMU recommends that market solutions for the DASR market be basedon opportunity cost only in order to eliminate economic withholding.

Market Performance
In the first six months of 2021, the DASR market cleared at a price above$0.00 per MW in 10.3 percent of all hours. The weighted average DASR pricefor all cleared hours was $0.10 per MW. The average cleared MW in all hours
was 4563.4 MW. The average cleared MW in all hours when the DASRMCP
was above $0.00 was 5,395.6 MW. The highest DASR price was $20.00 per
MW for a total of five hours in the first six months of 2021: two hours on June6, one hour on June 28, and two hours on June 29.
The introduction of Adjusted Fixed Demand (AFD) on March 1, 2015, createda bifurcated market. In 2015, PJM added AFD to the normal 5.93 percent
of forecast load in 367 hours. In 2016, PJM added AFD to the normal 5.7
percent of forecast load in 522 hours. In 2017, PJM added AFD to the normal
5.52 percent of forecast load in 336 hours. In 2018, PJM added AFD to thenormal 5.28 percent in 598 hours. In 2019, PJM added AFD to the normal 5.29
percent in 447 hours. In 2020, PJM added AFD to the normal 5.07 percent
in 430 hours. There were no AFD hours in the first four months of 2021.
There were 25 AFD hours in May and 115 AFD hours in June. The differencein market clearing price, MW cleared, obligation incurred, and charges to
PJM load are substantial. Table 10-28 shows the differences in price and MW
between AFD hours and non-AFD hours in 2021.

Economic withholding remains an issue in the DASR market. The marginal costof providing DASR is zero. All offers greater than zero constitute economic
withholding. In the first six months of 2021, 39.3 percent of generation units
74 See PJM “Manual 11: Energy & Ancillary Services Market Operations,” § 11.2.2 Day-Ahead Scheduling Reserve Market Eligibility, Rev. 115(June 1, 2021).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 515

2021 Quarterly State of the Market Report for PJM: January through June

Table 10-28 Impact of Adjusted Fixed Demand on DASR prices and demand: January through June, 2021
MetricAll hours
All hours when DASRMCP > $0
All hours when AFD used

Number of
Hours
4,344
448
139

Weighted Day-Ahead
Scheduling Reserve Market
Clearing Price (DASRMCP)
$0.10
$0.95
$2.24

Average Hourly Total DASR
MW4,563.4
5,395.6
8,397.9

While the new rules allow PJM operators’ substantial discretion to add to DASR demand for a variety of reasons, the rationale for each specific increase is notalways clear. The MMU recommends that PJM Market Operations attach a reason code to every hour in which PJM operators add additional DASR MW above
the default DASR hourly requirement. The addition of such a code would make the reason explicit, increase transparency and facilitate analysis of the use of
PJM’s ability to add DASR MW.
Comparing the Normal Hour column against the AFD Hour column for five metrics (Table 10-29) shows that the use of AFD for 84 hours in the first six monthsof 2021 significantly increased the cost of DASR. Table 10-29 shows that the cost increase was a result of a substantial increase in DASR MW cleared. The
average DASR clearing price in 2021 was $0.27 for hours when the clearing price was above $0.00 and $2.89 during hours when adjusted fixed demand was
invoked by PJM Dispatch.
Table 10-29 DASR market, regular hours vs. adjusted fixed demand hours: January 2020 through June 2021
Number of HoursDASRMCP > $0
Weighted DASRMCP
NormalAFD Normal
AFD
Hour
Hour
Hour
Hour
1
NA
$0.00
NA
1
NA
$0.00
NA
1
NA
$0.00
NA
17
NA
$0.00
NA
70
NA
$0.01
NA
73
48
$1.28
$1.87
89
358
$3.20
$2.41
73
24
$1.71
$5.74
59
NA
$0.39
NA
86
NA
$0.31
NA
47
NA
$0.21
NA
35
NA
$0.20
NA
552
430
$0.61
$2.55

Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec

2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun

516

Section 10 Ancillary Services

28
32
24
129
68
83
364

NA
NA
NA
NA
11
73
84

$0.08
$0.17
$0.17
$0.21
$0.58
$0.41
$0.27

NA
NA
NA
NA
$1.78
$4.00
$2.89

Average PJM Load
MW
Normal
AFD
Hour
Hour
89,919NA
88,655NA
78,508NA
70,687NA
71,826
NA
110,779
97,191
123,379 110,399
118,231
110,971
102,265NA
80,004NA
89,150NA
100,845NA
93,687 106,187
106,153
108,947
92,014
83,96299,007
115,654
100,956

NA
NA
NA
NA
105,454
118,725
112,090

Hourly Average
Cleared DASR MW
Normal
AFD
Hour
Hour
4939
NA
4863
NA
4449
NA
4045
NA
4106
NA
6512
10250
8269
9055
6051
10223
5064
NA
4195
NA
4484
NA
4820
NA
5,150
9,843
4,847
4,974
4,327
3,986
4,661
5,170
4,661

NA
NA
NA
NA
9,521
8,952
9,236

Average Hourly
DASR Credits
Normal
AFD
Hour
Hour
$2
NA
$2
NA
$1
NA
$0
NA
$57
NA
$8,78820,556$27,660
22,838$10,535
59,981$1,982NA$1,295
NA
$928
NA
$977
NA
$4,352 $34,458
$380
$815
$732
$846
$2,785$2,124$1,280NA
NA
NA
NA$18,160$42,697$30,428© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Table 10-30 shows total number of hours when a DASR market cleared at a
price above $0 along with average load, cleared MW, additional MW under
AFD, and total charges for the DASR market in January 2020 through June
2021.
Table 10-30 DASR market all hours of DASR market clearing price greaterthan $0: January 2020 through June 2021
Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

2021
2021
2021
2021
2021
2021
2021

Jan
Feb
Mar
Apr
May
Jun
Total

Number of HoursDASRMCP > $0
1
1
1
17
70
73
89
73
59
86
47
35
552
28
32
24
129
79
156
448

Weighted
DASR Market Average Hourly
Clearing Price
RT Load MW$0.08
111,016$0.16
109,218$0.17
92,457NANA$0.29
96,413$1.28
110,779$3.20
123,379$1.71
118,232$0.39
102,265$0.31
80,004$0.21
89,150$0.20
100,845$0.73
103,069
$0.08
$0.17
$0.17
$0.21
$0.75
$2.09
$0.58

106,153
108,947
92,014
83,96299,905
117,091
101,345

Total PJM Total PJM Cleared
Cleared DASR
Additional DASR
MW
MW
14,8170
15,961
0
4,532
0
NA
0
146,36501,015,850
491,982
2,753,429
3,241,749
1,349,321
245,362
531,7720851,6710385,6080438,634
07,507,960
3,979,093
135,710
159,163
103,839514,243
421,673
1,082,585
2,417,214

000053,470337,734
391,204

When the DASR requirement is increased by PJM dispatch, the reserve
requirement frequently cannot be met without redispatching online resources
which significantly affects the price by creating an LOC. Adjusted Fixed
Demand related increases in the DASR requirement (Table 10-30) in 2020
caused prices to increase. The lack of Adjusted Fixed Demand in January
through April of 2021 helped keep DASR price and cost lower than in 2020.

Regulation Market
Regulation matches generation with very short term changes in load by moving
the output of selected resources up and down via an automatic control signal.
Regulation is provided by generators with a short-term response capability(less than five minutes) or by demand response (DR). The PJM Regulation
Market is operated as a single real-time market.
Total Credits$1,462$1,524$861
NA$42,334$2,357,557$17,386,688$3,788,869$207,765$262,925$79,842$88,929$24,218,756$10,640$26,076$17,564$109,180$389,148$3,293,168$3,845,775

Market Design
PJM’s regulation market design is a result of Order No. 755.75 The
objective of PJM’s regulation market design is to minimize the cost
to provide regulation using two resource types in a single market.
The regulation market includes resources following two signals:
RegA and RegD. Resources responding to either signal help control
ACE (area control error). RegA is PJM’s slow-oscillation regulation
signal and is designed for resources with the ability to sustain energy
output for long periods of time, with slower ramp rates. RegD is
PJM’s fast-oscillation regulation signal and is designed for resources
with limited ability to sustain energy output and with faster ramp
rates. Resources must qualify to follow one or both of the RegA and
RegD signals, but will be assigned by the market clearing engine tofollow only one signal in a given market hour.

The PJM regulation market design includes three clearing pricecomponents: capability ($/MW, based on the MW being offered);
performance ($/mile, based on the total MW movement requested by thecontrol signal, known as mileage); and lost opportunity cost ($/MW oflost revenue from the energy market as a result of providing regulation).
The marginal benefit factor (MBF) and performance score translate a RegD
resource’s capability (actual) MW into marginal effective MW and offers into$/effective MW.
The regulation market solution is intended to meet the regulation requirementwith the least cost combination of RegA and RegD. When solving for the least
75 Order No. 755, 137 FERC ¶ 61,064 at P 2 (2011).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 517

2021 Quarterly State of the Market Report for PJM: January through June

cost combination of RegA and RegD MW to meet the regulation requirement,
the regulation market will substitute RegD MW for RegA MW when RegD ischeaper. Performance adjusted RegA MW are used as the common unit ofmeasure, called effective MW, of regulation service. All resource MW (RegA
and RegD) are converted into effective MW. RegA MW are converted into
effective MW by multiplying the RegA MW offered by their performance score.
RegD MW are converted into effective MW by multiplying the RegD offeredby their performance score and by the MBF. The regulation requirement isdefined as the total effective MW required to provide a defined amount of area
control error (ACE) control.
The regulation market converts performance adjusted RegD MW into effective
MW using the MBF in the PJM design. The MBF is used to convert incremental
additions of RegD MW into incremental effective MW. The total effective MW
for a given amount of RegD MW equal the area under the MBF curve (the sumof the incremental effective MW contributions). RegA and RegD resources
should be paid the same price per marginal effective MW.
The marginal rate of technical substitution (MRTS) is the marginal measureof substitutability of RegD resources for RegA resources in satisfying adefined regulation requirement at feasible combinations of RegA and RegD
MW. While resources following RegA and RegD can both provide regulation
service in PJM’s Regulation Market, PJM’s joint optimization is intended todetermine and assign the optimal mix of RegA and RegD MW to meet thehourly regulation requirement. The optimal mix is a function of the relative
effectiveness and cost of available RegA and RegD resources.

as offering 0.5 effective MW (0.5 MBF times 1.00 performance score times 1
MW). The total offer price would be $4 per effective MW ($2 per MW offer
divided by the 0.5 effective MW).
Regulation performance scores (0.0 to 1.0) measure the response of a regulating
resource to its assigned regulation signal (RegA or RegD) every 10 seconds bymeasuring: delay, the time delay of the regulation response to a change in theregulation signal; correlation, the correlation between the regulating resource
output and the regulation signal; and precision, the difference between theregulation response and the regulation requested.76 Performance scores arereported on an hourly basis for each resource.
Table 10-31 and Figure 10-9 show the average performance score byresource type and the signal followed in the first six months of 2021. Inthese figures, the MW used are actual MW and the performance score is thehourly performance score of the regulation resource.77 Each category (colorbar) is based on the percentage of the full performance score distribution foreach resource (or signal) type. As Figure 10-9 shows, 78.7 percent of RegD
resources had average performance scores within the 0.91-1.00 range, and27.2 percent of RegA resources had average performance scores within that
range in the first six months of 2021. In the first six months of 2020, 78.3
percent of RegD resources had average performance scores within the 0.911.00 range, and 36.8 percent of RegA resources had average performance
scores within that range.

At any valid combination of RegA and RegD, regulation offers are converted
to dollars per effective MW using the RegD offer and the MBF associated withthat combination of RegA and RegD. The marginal contribution of a RegD
MW to effective MW is equal to the MRTS associated with that RegA/RegD
combination.
For example, a 1.0 MW RegD resource with a total offer price of $2 per MWwith a MBF of 0.5 and a performance score of 100 percent would be calculated

518

Section 10 Ancillary Services

76 PJM “Manual 12: Balancing Operations,” § 4.5.6 Performance Score Calculation, Rev. 42 (Jan. 27, 2021).
77 Except where explicitly referred to as effective MW or effective regulation MW, MW means actual MW unadjusted for either MBF or
performance factor.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Table 10-31 Hourly average performance score by unit type: January throughJune, 2021
51-60
0.0%
0.0%
-

BatteryCT
Diesel
DSR
Hydro
Steam
BatteryCT
Diesel
DSR
Hydro
Steam

RegA

RegD

Performance Score Range
61-70
71-80
0.4%
3.3%
0.0%
29.3%
0.0%
2.3%
26.1%
2.4%
0.1%
0.0%
24.9%
0.0%
0.0%
10.5%
0.0%
-

81-90
41.0%
56.7%
35.2%
61.3%
16.4%
75.1%
100.0%
51.9%
40.5%
-

91-100
55.3%
91.2%
14.0%
64.8%
10.3%
80.7%
0.0%
37.6%
59.5%
-

Figure 10-9 Hourly average performance score by regulation signal type:
January through June, 2021
100%
90%

RegA
RegD

80%

Percent of Signal Type MW

70%

60%
50%
40%
30%

20%
10%
0%

0.51-0.60© 2021 Monitoring Analytics, LLC

0.61-0.70

0.71-0.80
Performance Score Range

0.81-0.90

0.91-1.00

Each cleared resource in a class (RegA or RegD) is allocated a portion of theclass signal (RegA or RegD). This portion of the class signal is based on thecleared regulation MW of the resource relative to the cleared MW for thatclass. This signal is called the Total Regulation Signal (TREG) for the resource.
A resource with 10 MW of capability will be provided a TREG signal asking
for a positive or negative regulation movement between negative and positive
10 MW around its regulation set point.
Resources are paid Regulation Market Clearing Price (RMCP) credits andlost opportunity cost credits, which are uplift payments. If a resource’s
lost opportunity costs for an hour are greater than its RMCP credits, that
resource receives lost opportunity cost credits equal to the difference. PJM
posts clearing prices for the regulation market (RMCCP, RMPCP and RMCP)
in dollars per effective MW. The regulation market clearing price (RMCP in $/effective MW) for the hour is the simple average of the 12 five minute RMCPs
within the hour. The RMCP is set in each five minute interval based on themarginal offer in each interval. The performance clearing price (RMPCP in $/effective MW) is based on the marginal performance offer (RMPCP) for thehour. The capability clearing price (RMCCP in $/effective MW) is equal to thedifference between the RMCP for the hour and the RMPCP for the hour. Thisis done so the total of RMPCP plus RMCCP equals the total clearing price(RMCP) but the RMPCP is maximized.
Market solution software relevant to regulation consists of the Ancillary
Services Optimizer (ASO) solving hourly; the intermediate term security
constrained economic dispatch market solution (IT SCED) solving every 15
minutes; and the real-time security constrained economic dispatch market
solution (RT SCED) solving approximately every five minutes. The market
clearing price is determined by pricing software (LPC) that looks at the units
cleared in the most recently approved RT SCED case, approximately 10 minutes
ahead of the target solution time. The marginal prices assigned by the LPC
to five minute intervals are averaged over the hour for an hourly regulation
market clearing price.

2021 Quarterly State of the Market Report for PJM: January through June 519

2021 Quarterly State of the Market Report for PJM: January through June

Market Design Issues
PJM’s current regulation market design is severely flawed and is not efficientor competitive. The market results do not represent the least cost solution forthe defined level of regulation service.
In a well functioning market, every resource should be paid the same clearing
price per unit produced. That is not true in the PJM Regulation Market. RegA
and RegD resources are not paid the same clearing price in dollars per effective
MW. RegD resources are being paid more than the market clearing price. This
flaw in the market design has caused operational issues, has caused overinvestment in RegD resources.
If all MW of regulation were treated the same in both the clearing of themarket and in settlements, many of the issues in the PJM Regulation Market
would be resolved. However, the current PJM rules result in the payment to
RegD resources being up to 1,000 times the correct price.
RegA and RegD have different physical capabilities. In order to permit RegA
and RegD to compete in the single PJM Regulation Market, RegD must betranslated into the same units as RegA. One MW of RegA is one effective
MW. The translation is done using the marginal benefit factor (MBF). As more
RegD is added to the market, the relative value of RegD declines, based on
its actual performance attributes. For example, if the MBF is 0.001, a MW of
RegD is worth 0.001 MW of RegA (or 1/1,000 of a MW of RegA). This is thesame thing as saying that 1.0 MW of RegD is equal to 0.001 effective MW
when the MBF is 0.001.
Almost all of the issues in PJM’s Regulation Market are caused by theinconsistent application of the MBF. Because the MBF is not included insettlements, when the MBF is less than 1.0, RegD resources are paid too much.
When the MBF is less than 1.0, each MW of RegD is worth less than 1.0 MW
of RegA. The market design buys the correct amount of RegD, but pays RegD
as if the MBF were 1.0. In an extreme case, when the MBF is 0.001, RegD
MW are paid 1,000 times too much. If the market clearing price is $1.00
per MW of RegA, RegD is paid $1,000 per effective MW. Resolution of this520

Section 10 Ancillary Services

problem requires that PJM pay RegD for the same effective MW it provides inregulation, 0.001 MW.
To address the identified market flaws, the MMU and PJM developed a joint
proposal which was approved by the PJM Members Committee on July27, 2017, and filed with FERC on October 17, 2017. The PJM/MMU joint
proposal addresses issues with the inconsistent application of the marginal
benefit factor throughout the optimization and settlement process in the PJMRegulation Market. FERC rejected the proposal finding it inconsistent with
Order No. 755.
The MBF related issues with the regulation market have been raised in the PJM
stakeholder process. In 2015, PJM stakeholders approved an interim, partial
solution to the RegD over procurement problem which was implemented
on December 14, 2015. The interim solution was designed to reduce therelative value of RegD MW in all hours and to cap purchases of RegD MW
during critical performance hours. But the interim solution did not address
the fundamental issues in the optimization or the lack of consistency in theapplication of the MBF.
Additional changes were implemented on January 9, 2017. These modifications
included changing the definition of off peak and on peak hours, adjusting
the currently independent RegA and RegD signals to be interdependent, andchanging the 15 minute neutrality requirement of the RegD signal to a 30
minute neutrality requirement.
The January 9, 2017, design changes appear to have been intended to make
RegD more valuable. That is not a reasonable design goal. The design goal
should be to determine the least cost way to provide needed regulation. The
RegA signal is now slower than it was previously, which may make RegA
following resources less useful as ACE control. RegA is now explicitly used
to support the conditional energy neutrality of RegD. The RegD signal is now
the difference between ACE and RegA. RegA is required to offset RegD when
RegD moves in the opposite direction of that required by ACE control inorder to permit RegD to recharge. These changes in the signal design will

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

allow PJM to accommodate more RegD in its market solutions. The new signal
design is not making the most efficient use of RegA and RegD resources. The
explicit reliance on RegA to offset issues with RegD is a significant conceptualchange to the design that is inconsistent with the long term design goal for
regulation. PJM increased the regulation requirement as part of these changes.
The January 9, 2017, design changes replaced off peak and on peak hours withnonramp and ramp hours with definitions that vary by season. The regulation
requirement for ramp hours was increased from 700 MW to 800 MW (Table
10-32). These market changes still do not address the fundamental issues in
the optimization or the lack of consistency in the application of the MBF.
Table 10-32 Seasonal regulation requirement definitions78
SeasonDates

Winter

Dec 1 - Feb 28(29)SpringMar 1 - May 31

SummerJun 1 - Aug 31

Fall

Sep 1 - Nov 30

Nonramp Hours
00:00 - 03:59
09:00 - 15:59
00:00 - 04:59
08:00 - 16:59
00:00 - 04:59
14:00 - 17:59
00:00 - 04:59
08:00 - 16:59

Ramp Hours
04:00 - 08:59
16:00 - 23:59
05:00 - 07:59
17:00 - 23:59
05:00 - 13:59
18:00 - 23:59
05:00 - 07:59
17:00 - 23:59

Performance Scores
Performance scores, by class and unit, are not an indicator of how wellresources contribute to ACE control. Performance scores are an indicator onlyof how well the resources follow their TREG signal. High performance scoreswith poor signal design are not a meaningful measure of performance. For
example, if ACE indicates the need for more regulation but RegD resources
have provided all their available energy, the RegD regulation signal will be in
the opposite direction of what is needed to control ACE. So, despite moving
in the wrong direction for ACE control, RegD resources would get a good
performance score for following the RegD signal and will be paid for moving
in the wrong direction.

The RegD signal prior to January 9, 2017, is an example of a signal that
resulted in high performance scores, but due to 15 minute energy neutrality
built into the signal, ran counter to ACE control at times. Energy neutrality
means that energy produced equals energy used within a defined timeframe.
With 15 minute energy neutrality, if a battery were following the regulation
signal to provide MWh for 7.5 minutes, it would have to consume the sameamount of MWh for the next 7.5 minutes. When neutrality correction of the
RegD signal is triggered, it overrides ACE control in favor of achieving zeronet energy over the 15 minute period. When this occurs, the RegD signal
runs counter to the control of ACE and hurts rather than helps ACE. In thatsituation, the control of ACE, which must also offset the negative impacts of
RegD, depends entirely on RegA resources following the RegA signal. Highperformance scores under the signal design prior to January 9, 2017, was not
an indication of good ACE control.
The January 9, 2017, design changes did not address the fundamental issues
with the definition of performance or the nature of payments for performancein the regulation market design. The regulation signal should not be designed
to favor a particular technology. The signal should be designed to result inthe lowest cost of regulation to the market. Only with a performance scorebased on full substitutability among resource types should payments be basedon following the signal. The MRTS must be redesigned to reflect the actual
capabilities of technologies to provide regulation. The PJM regulation market
design remains fundamentally flawed.
In addition, the absence of a performance penalty, imposed as a reduction in
performance score and/or as a forfeiture of revenues, for deselection initiatedby the resource owner within the hour, creates a possible gaming opportunity
for resources which may overstate their capability to follow the regulation
signal. The MMU recommends that there be a penalty enforced as a reductionin performance score and/or a forfeiture of revenues when resource owners
elect to deassign assigned regulation resources within the hour, to prevent
gaming.

78 See PJM. “Regulation Requirement Definition,” <http://www.pjm.com/~/media/markets-ops/ancillary/regulation-requirement-definition.
ashx>.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 521

2021 Quarterly State of the Market Report for PJM: January through June

Battery Settlement

Regulation Signal

The change from 15 to 30 minute signal neutrality, implemented in theJanuary 9, 2017, design changes, resulted in the reduction of performance
scores for short duration batteries. In April 2017 several participants filed acomplaint with FERC, stating that these changes discriminated against theirbattery units.79 The MMU objected to these complaints. On April 7, 2020,
FERC approved a settlement between PJM and the complainants.80 Starting
July 1, 2020, the affected battery units began receiving compensation basedon the greater of their current performance score, or their rolling average
actual hourly performance score for the last 100 hours the resource operated
prior to the January 9, 2017, implementation of the 30-minute conditional
neutrality. The FERC settlement also requires that the affected battery units
be cleared in the regulation market regardless of whether their offer would
have cleared under normal circumstances, as long as they are offered as either
self scheduled with a zero offer, or as a zero priced offer.81 In order to comply
with this condition, PJM clears additional MW beyond what is needed for the
regulation requirement in cases where the settlement battery units did not
clear but met the offer rules of the settlement. This results in excess charges
to customers for regulation service. Table 10-33 shows the impact of clearing
additional MW beyond what is needed for the regulation requirement, as aresult of the battery settlement. Through the first six months of 2021, thebattery settlement has resulted in customers paying $309,882 more thanneeded to compensate the settlement batteries.

As with any signal design for substitutable resources, the MBF function should
be determined by the ability of RegA and RegD resources to follow theirsignals, including conditions under which neutrality cannot be maintained
by RegD resources. The ability of energy limited RegD to provide ACE control
depends on the availability of excess RegA capability to support RegD under
the conditional neutrality design. When RegD resources are largely energy
limited resources, a correctly calculated MBF would exhibit a rapid decreasein the MBF value for every MW of RegD added. The result is that only a small
amount of energy limited RegD is economic. The current and proposed signals
and corresponding MBF functions do not reflect these principles or the actual
substitutability of resource types.

Table 10-33 Excess payments and MW cleared due to battery settlement:
January through June, 2021
Month
Jan
Feb
Mar
Apr
May
Jun
Total

Battery Settlement Impact
Regulation Credits
Additional Cleared Regulation MW$49,387
3,149.4$24,776
1,727.7$37,648
3,192.6$78,650
4,872.3$117,329
7,718.7$2,092147.4$309,882
20,808.0

79 See FERC Docket Nos. EL17-64-000 and EL17-65-000.
80 See 170 FERC ¶ 61,258.
81 See id. at P 17.

522

Section 10 Ancillary Services

Marginal Benefit Factor Issues
The MBF function, as implemented in the PJM Regulation Market, is not equal
to the MRTS between RegA and RegD. The MBF is not consistently applied
throughout the market design, from optimization to settlement, and market
clearing does not confirm that the resulting combinations of RegA and RegD
are realistic and can meet the defined regulation demand. The calculation of
total regulation cleared using the MBF is incorrect.82
The result has been that the PJM Regulation Market has over procured RegD
relative to RegA in most hours, has provided a consistently inefficient market
signal to participants regarding the value of RegD in every hour, and has
overpaid for RegD. This over procurement has degraded the ability of PJM
to control ACE in some hours while at the same time increasing the cost of
regulation. When the price paid for RegD is above the level defined by anaccurate MBF function, there is an artificial incentive for inefficient entry of
RegD resources.
PJM and the MMU filed a joint proposal with FERC on October 17, 2017, toaddress issues with the inconsistent application of the marginal benefit factor

82 The MBF, as used in this report, refers to PJM’s incorrectly calculated MBF and not the MBF equivalent to the MRTS.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

throughout the optimization and settlement process in the PJM Regulation
Market, but the proposal was rejected by FERC.83

Marginal Benefit Factor Not Correctly Defined
The MBF used in the PJM Regulation Market prior to the December 14,
2015, changes did not accurately reflect the MRTS between RegA and RegD
resources under the old market design, and it does not accurately reflect the
MRTS between RegA and RegD resources under the current design. The MBF
function is incorrectly defined and improperly implemented in the current
PJM Regulation Market.
The MBF should be the marginal rate of technical substitution between RegA
and RegD MW at different, feasible combinations of RegA and RegD that canbe used to provide a defined level of regulation service. The objective of themarket design is to find, given the relative costs of RegA and RegD MW, theleast cost feasible combination of RegA and RegD MW. If the MBF function
is incorrectly defined, or improperly implemented in the market clearing andsettlement, the resulting combinations of RegA and RegD will not represent
the least cost solution and may not be a feasible way to reach the target levelof regulation.
The MBF is not included in PJM’s settlement process. This is a design flaw that
results in incorrect payments for regulation. The issue results from two FERC
orders. From October 1, 2012, through October 31, 2013, PJM implemented a
FERC order that required the MBF to be fixed at 1.0 for settlement calculations
only. On October 2, 2013, FERC directed PJM to eliminate the use of the
MBF entirely from settlement calculations of the capability and performancecredits and replace it with the RegD to RegA mileage ratio in the performancecredit paid to RegD resources, effective retroactively to October 1, 2012.84 Thatrule continues in effect. The result of the current FERC order is that the MBF
is used in market clearing to determine the relative value of an additional MW
of RegD, but the MBF is not used in the settlement for RegD.

83 162 FERC ¶ 61,295 (2018), reh’g denied, 170 FERC ¶ 61,259 (2020).
84 145 FERC ¶ 61,011 (2013).

© 2021 Monitoring Analytics, LLC

If the MBF were consistently applied, every resource would receive the sameclearing price per marginal effective MW. But the MBF is not consistently
applied and resources do not receive the same clearing price per marginal
effective MW.
The change in design decreased RegA mileage (the change in MW output in
response to regulation signal per MW of capability), increased the proportionof cleared RegD resources’ capability that was called by the RegD signal(increased REG for a given MW) to better match offered capability, increased
the mileage required of RegD resources and changed the energy neutrality
component of the signal from a strict 15 minute neutrality to a conditional
30 minute neutrality. The changes in signal design increased the mileage ratio(the ratio of RegD mileage to RegA mileage). In addition, to adapt to the 30
minute neutrality requirement, some RegD resources decreased their offeredcapability to maintain their performance.
Figure 10-10 shows the daily average MBF and the mileage ratio. The weighted
average mileage ratio increased from 6.56 in the first six months of 2020, to
7.31 in the first six months of 2021 (an increase of 11.4 percent). The average
MBF decreased from 0.74 in the first six months of 2020, to 0.69 in the firstsix months of 2021 (a decrease of 7.5 percent). This decrease was primarily due
to the additional RegD MW clearing as a result of the FERC settlement ruling,which went into effect on July 1, 2020. The high mileage ratios are the resultof the mechanics of the mileage ratio calculation. Extreme mileage ratios
result when the RegA signal is fixed at a single value (pegged) to control ACE
and the RegD signal is not. If RegA is held at a constant MW output, mileageis zero for RegA. The result of a fixed RegA signal is that RegA mileage is verysmall and therefore the mileage ratio is very large.
These results are an example of why it is not appropriate to use the mileage
ratio, rather than the MBF, to measure the relative value of RegA and RegD
resources. In these events, RegA resources are providing ACE control byproviding a fixed level of MW output which means zero mileage, while RegD
resources alternate between helping and hurting ACE control, both of which
result in positive mileage.

2021 Quarterly State of the Market Report for PJM: January through June 523

2021 Quarterly State of the Market Report for PJM: January through June

Figure 10-10 Daily average MBF and mileage ratio: January 2020 throughJune 2021
140

MW than RegA resources (24.7 percent in the first six months of 2020) due tothe inclusion of the mileage ratio in RegD MW settlement.

1.6

Table 10-34 Average monthly price paid per performance adjusted actual MW
of RegD and RegA: January 2020 through June 2021

Mileage Ratio

1.4

Marginal Benefit Factor

120

1.2

100

Mileage Ratio

1
80
0.8
60
0.6
40

2020

0.4

20

Jun-21

May-21

Apr-21

Mar-21

Feb-21

Jan-21

Dec-20Nov-20

Oct-20

Sep-20Jul-20Aug-20Jun-20May-20

Apr-20Mar-20Feb-200.2

Jan-200Marginal Benefit Factor

Year

Yearly02021

Average

The increase in the average mileage ratio caused by the signal design changes
introduced on January 9, 2017, caused a large increase in payments to RegD
resources on a performance adjusted MW basis.
Table 10-34 shows RegD resource payments on a performance adjusted actual
MW basis and RegA resource payments on a performance adjusted MW
basis by month, from January 1, 2020, through June 30, 2021. The averageregulation market clearing price in the first six months of 2021 was $6.51
higher than in the first six months of 2020 (See Table 10-49). Coupled withthe lower average MBF, RegD continued to be overpaid compared to RegA
on a performance adjusted actual MW basis. In the first six months of 2021,
RegD resources earned 22.1 percent more per performance adjusted actual

524

Section 10 Ancillary Services

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun

RegD
($/Performance Adjusted
MW)$16.51$11.83$11.06$14.29$14.72$15.09$18.02$18.11$12.68$21.82$19.45$18.18$16.01$14.29$23.87$20.81$20.86$20.22$23.01$20.44

Settlement Payments
RegA($/Performance Adjusted
MW)$13.05$9.57$8.60$11.45$12.46$11.85$15.63$14.83$10.33$17.31$15.25$15.34$13.00$11.43$19.90$17.93$16.73$16.42$18.40$16.74

Percent RegD Overpayment($/Performance Adjusted
MW)
26.5%
23.6%
28.6%
24.8%
18.2%
27.3%
15.3%
22.2%
22.7%
26.0%
27.5%
18.6%
23.2%
25.1%
19.9%
16.0%
24.6%
23.2%
25.1%
22.1%

The current settlement process does not result in paying RegA and RegD
resources the same price per effective MW. RegA resources are paid on thebasis of dollars per effective MW of RegA. RegD resources are not paid interms of dollars per effective MW of RegA because the MBF is not used insettlements. Instead of being paid based on the MBF, (RMCCP + RMPCP)*MBF,
RegD resources are paid based on the mileage ratio (RMCCP + (RMPCP*mileage
ratio)). Because the RMCCP component makes up the majority of the overall
clearing price, when the MBF is above one, RegD resources can be underpaid
on a per effective MW basis by the current payment method, unless offset
by a high mileage ratio. When the MBF is less than one, RegD resources are© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

overpaid on a per effective MW basis, unless offset by a low mileage ratio. The
average MBF was less than 1.0 in the first six months of 2021 (0.69).
The effect of using the mileage ratio instead of the MBF for purposes ofsettlement is illustrated in Table 10-35. Table 10-35 shows how much RegD
resources are currently being paid, adjusted to a per effective MW basis, on
average, in every month in 2020 and the first six months of 2021 under thecurrent rules, compared to how much RegD resources should have been paid
if they were actually paid for effective MW. Using the MBF consistently
throughout the PJM regulation market would result in RegA and RegD
resources being paid exactly the same on a per effective MW basis. However,the PJM regulation market only uses the MBF in the market clearing andsetting of price on a dollar per effective MW basis, it does not use the MBF
to convert RegD MW into effective MW for purposes of settlement. Because
the MBF is not used to convert RegD MW into effective MW for purposes
settlement, RegD resources are paid the dollar per effective MW price, but
this is paid for performance adjusted MW, not for effective MW. This causes
the MW value of RegD resources to be inflated in settlement when the MBF isless than one. In the first six months of 2021, the MBF averaged 0.69, while
the average daily mileage ratio was 7.31, resulting in RegD resources being
paid $6.2 million more than they would have been paid on an effective MW
basis if the MBF were correctly implemented. In the first six months of 2020,
the MBF averaged 0.75, and the average mileage ratio was 6.56, resulting in
RegD resources being paid $3.5 million more than they would have been paid
if the MBF were correctly implemented.

Table 10-35 Average monthly price paid per effective MW of RegD and RegA
under mileage and MBF based settlement: January 2020 through June 202185

Year

2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec

Yearly2021

Average

Jan
Feb
Mar
Apr
May
Jun

RegD Settlement Payments
Marginal Rate ofPercent RegD
Mileage Based Technical Substitution
RegA Overpayment
Total RegD
RegD
Based RegD ($/Effective($/Effective Overpayment($/Effective MW)($/Effective MW)
MW)
MW)
($)
$19.61$13.05$13.0550.3%$318,560$25.79$9.57$9.57
169.5%$505,037$29.47$8.60$8.60
242.6%$665,219$38.85$11.45$11.45239.4%$745,528$37.37$12.46$12.46199.9%$746,137$25.00$11.85$11.85111.0%$548,730$34.99$15.63$15.63123.9%$657,628$31.78$14.83$14.83114.4%$753,199$28.51$10.33$10.33175.9%$661,906$69.18$17.31$17.31
299.6%$1,534,621$63.11$15.25$15.25313.8%$1,319,529$43.39$15.34$15.34182.9%$886,873$37.30$13.00$13.00186.9%$9,342,966$30.47$11.43$11.43166.6%$558,397$88.91$19.90$19.90346.7%$1,310,283$61.03$17.93$17.93240.4%$1,277,850$65.99$16.73$16.73294.3%$1,492,094$39.55$16.42$16.42140.9%$1,081,445$26.57$18.40$18.4044.4%$457,543$51.54$16.74$16.74207.8%$6,177,612

Figure 10-11 shows, the monthly maximum, minimum and average MBF, forJanuary 2020 through June 2021. The average daily MBF in the first six
months of 2021 was 0.69. The average daily MBF in the first six months of 2020
was 0.75. The bottom of the MBF range results from PJM’s administratively
defined MBF minimum threshold of 0.1.

85 There was an error in previously reported versions of this table. The total RegD overpayment column was overstated. The correct values
are included here.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 525

2021 Quarterly State of the Market Report for PJM: January through June

Figure 10-11 Maximum, minimum, and average PJM calculated MBF by
month: January 2020 through June 2021

Table 10-36 shows, by month, cleared RegD MW with an effective price of$0.00 (units with zero offers plus self scheduled units) for January 2020
through June 2021. In the first six months of 2021, an average of 99.7 percent
of all RegD MW clearing the market had an effective offer of $0.00. In the firstsix months of 2020, an average of 99.7 percent of all cleared RegD MW had
an effective cost of $0.00. In the first six months of 2021, an average of 74.9
percent of all RegD offers were self scheduled, compared to an average of 76.5
percent of all RegD offers in the first six months of 2020.

2.5

Average Marginal Benefit Factor

2.0

1.5

1.0

Jun-21

May-21

Apr-21

Mar-21

Feb-21

Jan-21

Dec-20Nov-20

Oct-20

Sep-20Aug-20Jul-20Jun-20May-20

Apr-20Mar-200.0

Feb-200.5

Jan-20Marginal Benefit Factor (Based on PJM's current assumptions)

Max-Min Marginal Benefit Factor

The MMU recommends that the regulation market be modified to incorporate
a consistent and correct application of the MBF throughout the optimization,
assignment and settlement process.86
The overpayment of RegD has resulted in offers from RegD resources thatare almost all at an effective cost of $0.00 ($0.00 offers plus self scheduledoffers). RegD MW providers are ensured that such offers will clear and will be
paid a price determined by the offers of RegA resources. This is evidence of
the impact of the flaws in the clearing engine and the overpayment of RegD
resources on the offer behavior of RegD resources.

The high percentage of self scheduled offers is a result of the incentives
created by the flaws in the regulation market. Because self scheduled offers
are price takers, they are cleared along with the zero cost offers in the market
clearing engine. However, unlike zero cost offers, self scheduled offers do
not risk having an LOC added to their offer during the market clearing
process, ensuring that self scheduled offers have a zero cost during market
clearing. Given the increasing saturation of the regulation market with RegD
MW, specifically demand response and battery units which do not receive
LOC, market participants eligible for LOC that offer at zero instead of selfscheduling, run the risk of an LOC added to their offer, and thus not clearing
the market.
The average monthly RegD cleared in the market increased 4.6 MW (2.4
percent), from 190.9 MW in the first six months of 2020 to 195.5 MW in thefirst six months of 2021. The average monthly RegD cleared with an effective
cost of zero increased 4.6 MW (2.4 percent), from 190.4 MW in the first six
months of 2020 to 195.0 MW in the first six months of 2021. Self scheduled
RegD cleared MW increased 0.5 MW (0.4 percent), from 145.9 MW in the firstsix months of 2020 to 146.5 MW in the first six months of 2021. Average
cleared RegD MW with a zero cost offer increased 4.1 MW (9.1 percent), from44.5 MW in the first six months of 2020 to 48.5 MW in the first six monthsof 2021. The increase in the average monthly RegD cleared resulted in the
reduction of the average monthly MBF seen in Figure 10-11.

86 See “Regulation Market Review,” Operating Committee (May 5, 2015) <http://www.pjm.com/~/media/committees-groups/committees/
oc/20150505/20150505-item-17-regulation-market-review.ashx>.

526

Section 10 Ancillary Services© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Table 10-36 Average cleared RegD MW and average cleared RegD with aneffective price of $0.00 by month: January 2020 through June 2021

Year

2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec

Yearly2021

Average

Jan
Feb
Mar
Apr
May
Jun

$0.00
Offer
32.1
48.8
48.0
47.1
43.2
47.7
47.9
48.2
40.7
46.2
50.3
47.2
45.6
49.6
52.4
47.2
48.6
47.5
45.8
48.5

Average Performance Adjusted Cleared RegD MW
Self
Effective$0.00 Offer
Scheduled
Total Cost of Zero
Percent of
Self Percentage
Effective Percentage
Total
Scheduledof Total Cost of Zeroof Total
18.8%
137.2
80.5%
169.2
99.4%
24.6%
149.6
75.4%
198.5
100.0%
24.4%
148.1
75.5%
196.1
100.0%
24.0%
149.3
75.9%
196.4
99.9%
22.6%
147.6
77.3%
190.8
99.9%
24.7%
143.8
74.5%
191.4
99.2%
24.0%
151.0
75.7%
199.0
99.8%
24.5%
147.5
74.9%
195.6
99.3%
21.3%
149.7
78.4%
190.4
99.7%
23.7%
148.7
76.1%
194.9
99.8%
25.3%
148.5
74.7%
198.8
100.0%
24.1%
147.9
75.7%
195.1
99.8%
23.6%
147.4
76.2%
193.0
99.7%
26.1%
139.9
73.7%
189.6
99.9%
25.6%
152.3
74.4%
204.7
100.0%
23.3%
155.4
76.7%
202.6
100.0%
24.0%
154.0
76.0%
202.7
100.0%
24.8%
143.8
75.0%
191.3
99.9%
25.2%
133.3
73.4%
179.2
98.6%
24.8%
146.4
74.9%
194.9
99.7%

Total
170.3
198.5
196.1
196.7
191.0
192.9
199.4
196.9
191.0
195.3
198.9
195.4
193.5
189.8
204.7
202.6
202.7
191.6
181.7
195.4

Incorrect MBF and total effective MW when clearing units with dual
product offers
Under PJM market rules, regulation units that have the capability to provide
both RegA and RegD MW are permitted to submit an offer for both signal
types in the same market hour. While the objective of the PJM market design
is to find the least cost combination of RegA and RegD resources to provide
the required level of regulation service, the method of clearing the regulation
market for an hour in which one or more units has a dual offer is incorrect
and leads to solutions that are not the most economic.
In order for the clearing engine to provide the correct economic solution when
the pool of available resources contains one or more units with dual offers,
the calculation would have to be performed iteratively to determine which of
the dual offers would provide the least cost solution. But this is not how PJM© 2021 Monitoring Analytics, LLC

clears the regulation market when there are dual offer units. PJM rank orders
the regulation supply curve by potential effective cost assuming the dual offer
resources are available as both RegA and RegD resources simultaneously, andassigns every RegD resource, including dual offer resources, a unit specificbenefit factor.
Each dual offer resource is assigned to run as either a RegD or RegA resource
based on which of the two offers has a lower effective cost. But PJM does
not redefine the supply curve using appropriately recalculated unit specificbenefit factors for the remaining RegD resources prior to clearing the market.
During the clearing phase, the MBF of RegD resources is a function of the
RegD MW that clear. The MBF for all RegD resources declines as more RegD
resources are cleared. Based on this relationship, in the case where a dual
offer unit is assigned to be a RegA resource rather than a RegD resource, theMBF of remaining RegD resources in the supply curve should increase. The
placeholder RegD MW from the dual offer should be removed, the cleared
MW from below the placeholder should be shifted up the supply/MBF curve,
and additional RegD MW offers that were pushed below an MBF of zero andinitially not included, should be considered. But PJM does not recalculate the
MBF values for the remaining RegD resources when determining the cleared
effective MW needed to satisfy the regulation requirement during the clearing
phase. The result is that the MBF in the clearing phase is incorrectly low, andthe actual amount of effective MW procured is higher.
After meeting the target effective MW to satisfy the regulation requirement
for that hour through the clearing process, the unit specific benefit factors of
those displaced units are recalculated in the real-time operating phase andincreased based on their actual contribution. The effective MW contributionsof those originally displaced units are correctly calculated in the operatingphase, but because the supply for that hour has already been set based on
their incorrect effective MW, the solution includes more effective MW thancalculated in the clearing phase. As a result, the market solution includes
more than the target level of effective MW in the actual operating hour.

2021 Quarterly State of the Market Report for PJM: January through June 527

2021 Quarterly State of the Market Report for PJM: January through June

The issue is illustrated in Figure 10-12. The example shows a clearing phaseand a real time operating phase. In this example, a 150 MW unit offers both
RegA and RegD. The 150 MW unit’s position in the RegD effective cost curve
and the potential effective MW are represented as the orange area under the
curve in the clearing phase. The effective MW of the cleared RegD resources
with higher effective costs are represented by the blue triangle in the clearing
phase. Not shown are additional RegD MW with higher effective costs thatwere assigned an MBF of 0 and not cleared. The 150 MW dual offer unit ischosen to operate as a RegA resource in the operational hour. As a result,the cleared supply for RegA in the clearing phase is the same RegA supply
realized in the real time operating phase. But that is not the case for the
RegD supply. Since the supply curve and unit specific benefit factors of RegD
MW are not recalculated in the clearing phase after the 150 MW RegD offer
is removed, the amount of effective MW realized in the real-time operatingphase is inconsistent with the clearing phase. Because the RegD portion of the
150 MW dual offer unit was not chosen to be RegD MW, the RegD resources
represented by the blue triangle in the clearing phase will contribute more
effective MW (the blue area in the real-time solution phase) in the real-time
solution phase than was assumed in the clearing phase because the MBF in theclearing phase was too low. Since the blue area under the curve in the realtime solution phase is greater than the blue area in the clearing phase and theamount of RegA remains the same between the clearing phase and real-time
operating phase, the market will have cleared too many effective MW relative
to the effective MW requirement. The MBF in the operating phase is higher
than if the clearing had been solved correctly.

528

Section 10 Ancillary Services

Figure 10-12 Clearing phase BF/effective MW reduction, real-time BF/
effective MW inflation, and exclusion of available RegD resources

In the first six months of 2021, all hours had at least one unit with a dual
offer. In the first six months of 2021, 92.8 percent of all hours had at least
one dual offer unit that was chosen to run as RegA, resulting in an average
MBF increase of 0.48 in the operating phase. If the market had been cleared
correctly, the correct average MBF would have been significantly lower
in real time (operating phase), because additional RegD offers with lower
benefit factors that were initially excluded, would have been included after
the removal of the dual offer placeholder, reducing the MBF. Figure 10-13
illustrates the PJM calculated average MBF in real time (operating phase), theaverage MBF displacement due to dual offers clearing as RegA, and what thecorrect average MBF would have been in each hour of the day for the first six
months of 2021 if the clearing solution were solved correctly.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Figure 10-13 Effect of PJM’s current dual offer clearing method on the
average MBF in each hour of the day: January through June, 2021of the adjusted LOC offer component, hour ahead projections of LMPs areused. Units are then cleared based on the sum of each of their hour ahead
adjusted offer components. The actual LOC is used to determine the final,
actual interval specific all in offer of RegD resources.

1.2
Average PJM calculated MBF
Average MBF Displacement

1

Average Correct MBF

MBF

0.8

0.6

0.4

0.2

0

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

Hour

Absent the ability to correctly clear dual offers, the MMU recommends thatthe ability of resources to submit dual offers be removed. Under this revision
to the rules, resources could offer as either RegA or RegD in a given hour, but
not both within the same market hour.

In some cases the estimated LOC is very low or zero but the actual withinhour LOC is a positive number. In instances where the MBF of the within hourmarginal unit is less than one (e.g. the marginal unit is a RegD unit), thisdiscrepancy in the estimated and realized LOC will cause a large discrepancy
between the expected offer price (as low as $0/MW) and the realized offer
price of the resource in the actual market result. This will cause a significant
price spike in the regulation market. In cases where the MBF of the marginal
resource is very low, such as 0.001, the price spikes can be very significant
for a small change between expected and actual LOC. In January 2019,
FERC approved PJM’s proposal to create a 0.1 floor for the MBF to reduce
the occurrence of these price spikes.87 This change reduced the amount andfrequency of the price spikes, but it was not designed to eliminate them andit did not eliminate them.
Figure 10-14 shows the LOC in each five minute interval in which the marginalunit had a unit specific benefit factor less than one (e.g. a RegD unit) and the
LOC was greater than zero in 2018, 2019, 2020, and in the first six monthsof 2021.

Price Spikes
Beginning in 2018, extreme price spikes were identified in the regulation
market. The price spikes were caused by a combination of the inconsistent
application of the MBF in the market design and the discrepancy between thehour ahead estimated LOC and the actual realized within hour LOC.
The regulation market is cleared on an hour ahead basis, using offers that are
adjusted by dividing each component of an offer (capability, performance,and lost opportunity cost) by the product of the unit specific benefit factor
and unit specific performance score. To calculate the hour ahead estimate© 2021 Monitoring Analytics, LLC

87 See 166 FERC ¶ 61,040 (2019).

2021 Quarterly State of the Market Report for PJM: January through June 529

2021 Quarterly State of the Market Report for PJM: January through June

Figure 10-14 LOC distribution in each five minute interval with a RegD
marginal unit and an LOC greater than zero: 2018 through June 2021

While an incorrect estimate of a potential LOC can result in an extremely highprice, the resulting regulation market prices are mathematically correct for the
price of each effective MW. The prices in every interval reflect the marginal
costs of regulation given the resources dispatched and accurately reflect themarginal offer of minimally effective resources which had unexpectedly high
LOC components of their within hour offers. But, due to the current market
design’s failure to use the MBF in settlement, RegD is not paid on a dollar per
effective MW basis. This disconnect between the process of setting price andthe process of paying resources is the primary source of the market failure
in PJM’s Regulation Market and the cause of the observed price spikes in theregulation market. In the example, the 0.001 MW from the RegD resource
should be paid $1,000 times 0.001 MW or $1.00. But the current rules would
pay the RegD resource $1,000 times 1.0 MW or $1,000. If the market clearing
and the settlements rules were consistent, the incentive for this behavior would
be eliminated. The current rules provide a strong incentive for this behavior.

250
2018
2019
2020

5-minute intervals

200

2021 Q2

150

100

50

0

10

110

210

310

410

510

610

710

810

910

>1000

LOC ($ per MW)

For a RegD resource to clear the regulation market with an MBF of 0.001,
the resource’s offer, in dollars per marginal effective MW, must be less thanor equal to competing offers from RegA MW. A RegD offer of 1 MW with an
MBF of 0.001 and a price of $1 per MW, would provide 0.001 effective MW
at a price of $1,000 per effective MW. So long as RegA MW are available forless than $1,000 per effective MW, this resource will not clear. The only way
for RegD MW to clear to the point where the MBF of the last MW is 0.001,
is if the offer price of the relevant resources that clear, including estimated
LOC, is $0.00. But, if the same resource(s) has a positive LOC within the hour,based on real-time changes in LMP, the zero priced offer is adjusted to reflect
the positive LOC, resulting in an extremely high offer and clearing price forregulation.

530

Section 10 Ancillary Services

The prices spikes observed in PJM’s Regulation Market are a symptom ofa market failure in PJM’s Regulation Market caused by an inconsistent
application of the MBF between market clearing and market settlement. Dueto the inconsistent application of the MBF, the current market results are
not consistent with a competitive market outcome. In any market, resources
should be paid the marginal clearing price for their marginal contribution.
In the regulation market, all resources should be paid the marginal clearing
price per effective MW and all resources in the regulation market should be
paid for each of their effective MW. PJM’s Regulation Market does not do this.
PJM’s market applies the MBF in determining the relative and total value of
RegD MW in the market solution for purposes of market clearing and price,
but does not apply the same logic in determining the payment of RegD for
purposes of settlement. As a result, market prices do not align with payment
for contributions to regulation service in market settlements.
The inconsistent application of the MBF in PJM’s regulation market design is
generating perverse incentives and perverse market results. The price spikes
are a symptom of the problem, not the problem itself.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Lost Opportunity Cost Calculation Issues

Market Structure

The final calculation of regulation LOC during settlements results in the
overpayment of uplift in some cases. In order to determine the amount ofregulation LOC, the difference between the MW output of the unit while it wasproviding regulation is compared to the desired MW output of the unit if it
had not provided regulation. The desired amount of MW output at LMP usedin the calculation of regulation LOC during settlements is determined based ona unit’s energy offer and the LMP during the interval being evaluated. But thisdesired MW does not account for the ability or inability of a unit to actually
produce the desired output because it does not take into account the physicallimitations of the unit’s ability to ramp. This can result in overpayment of
uplift by paying for MW that the unit would never have been able to achieve,
given their energy market output at the beginning of the interval and theirramp rate.

SupplyTable 10-37 shows the amount of uplift overpayment by fuel type for the firstsix months of 2021. The overpayments are calculated using a desired MW levelthat can be achieved based on the units’ ramp rates. In the first six monthsof 2021, overpayments totaled $3,409,442. Coal units receive the majority ofthe overpayment while only providing 9.4 percent of settled regulation MW.
Table 10-37 Amount of LOC overpayment: January through June, 2021
Month
Jan
Feb
Mar
Apr
May
Jun
Total

Coal
$193,493$192,078$264,985$193,678$467,981$565,172$1,877,387

Uplift overpayment
Natural Gas$158,574$317,746$429,131$214,241$178,919$233,445$1,532,055

Total$352,066$509,824$694,115$407,919$646,900$798,618$3,409,442

Table 10-38 shows average hourly offered MW (actual and effective), andaverage hourly cleared MW (actual and effective) for all hours in the first six
months of 2021.88 Actual MW are adjusted by the historic 100-hour moving
average performance score to get performance adjusted MW, and by the
resource specific benefit factor to get effective MW. A resource can choose tofollow either signal. For that reason, the sum of each signal type’s capability
can exceed the full regulation capability. Offered MW are calculated based on
the offers from units that are designated as available for the day. These are
daily offers that can be modified on an hourly basis up to 65 minutes before
the hour.89 Eligible MW are calculated from the hourly offers from units withdaily offers and units that are offered as unavailable for the day, but still offer
MW into some hours. Units with daily offers are permitted to offer above or
below their daily offer from hour to hour. As a result of these hourly MW
adjustments, the average hourly Eligible MW can be higher than the OfferedMW.
In the first six months of 2021, the average hourly offered supply of regulation
for nonramp hours was 758.5 actual MW (751.6 effective MW). This was anincrease of 57.4 actual MW (an increase of 45.7 effective MW) from the firstsix months of 2020, when the average hourly offered supply of regulation
was 701.1 actual MW (705.9 effective MW). In the first six months of 2021,
the average hourly offered supply of regulation for ramp hours was 1,072.8
actual MW (1,093.8 effective MW). This was an increase of 91.3 actual MW(an increase of 65.1 effective MW) from the first six months of 2020, when
the average hourly offered supply of regulation was 981.5 actual MW (1,028.7
effective MW).
The ratio of the average hourly offered supply of regulation to average hourly
regulation demand (actual cleared MW) for ramp hours was 1.52 in the firstsix months of 2021 (1.39 in the first six months of 2020). The ratio of the
88 Unless otherwise noted, analysis provided in this section uses PJM market data based on PJM’s internal calculations of effective MW
values, based on PJM’s currently incorrect MBF curve. The MMU is working with PJM to correct the MBF curve.
89 See “PJM Manual 11: Energy & Ancillary Services Market Operations,” § 3.2.2 Regulation Market Eligibility, Rev. 115 (June 1, 2021).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 531

2021 Quarterly State of the Market Report for PJM: January through Juneaverage hourly offered supply of regulation to average hourly regulation
demand (actual cleared MW) for nonramp hours was 1.54 in the first six
months of 2021 (1.43 in the first six months of 2020).

Figure 10-15 Average hourly RegA actual MW offered and cleared: January
through June, 2020 through 2021
1,000
2020 Q2 Offered

Table 10-38 Hourly average actual and effective MW offered and cleared:
January through June, 202190

Ramp
Nonramp
Ramp
Effective Offered MW
Nonramp
Ramp
Actual Cleared MW
Nonramp
Ramp
Effective Cleared MW
Nonramp
Actual Offered MWAll
Regulation
1,072.8
758.5
1,093.8
751.6
707.1
491.6
800.0
525.3

Generating
Resources
1,062.4
751.5
1,081.3
745.2
696.8
484.7
787.5
518.9

DemandResources
10.4
7.0
12.5
6.5
10.3
6.9
12.5
6.4

By Signal Type
RegA
RegD
Following
Following
Resources
Resources
810.5
262.4
554.8
203.7
698.7
395.1
474.6
277.1
487.6
219.4
289.0
202.6
423.5
376.5
248.6
276.6

2021 Q2 Offered2021 Q2 Cleared

800

700
RegA Actual MW

By Resource Type2020 Q2 Cleared

900

600
500

400
300

The average hourly offered and cleared actual MW from RegA resources areshown in Figure 10-15. The average hourly offered MW from RegA resources
during ramp hours for the first six months of 2021 was 810.5 actual MW, an
increase of 9.6 percent from the first six months of 2020 (739.7 actual MW.)The average hourly offered MW from RegA resources during nonramp hours
for the first six months of 2021 was 554.8 actual MW, an increase of 11.5
percent from the first six months of 2020 (497.6 actual MW). The averagehourly cleared MW from RegA resources during ramp hours for the first six
months of 2021 was 487.6 actual MW, a decrease of 0.5 percent from the firstsix months of 2020 (490.3 actual MW). The average hourly cleared MW fromRegA resources during nonramp hours for the first six months of 2021 was
289.0 actual MW, an increase of 0.2 percent from the first six months of 2020
(288.3 actual MW).

90 PJM operations treats some nonramp hours as ramp hours, with a regulation requirement of 800 MW rather than 525 MW. All ramp/
nonramp analysis performed is based on the requirement used in each hour rather than the definitions given in Table 10-2. A ramp hour
occurring during what is normally a nonramp period is treated as a ramp hour.

532

Section 10 Ancillary Services

200

0

1

2

3

4

5

6

7

8

9

10

11 12
Hour

13

14

15

16

17

18

19

20

21

22

23

The average hourly offered MW from RegD resources during ramp hours forthe first six months of 2021 was 262.4 actual MW, an increase of 8.5 percent
from the first six months of 2020 (241.8 actual MW). (Figure 10-16) The
average hourly offered MW from RegD resources during nonramp hours forthe first six months of 2021 was 203.7 actual MW, an increase of 0.1 percent
from the first six months of 2020 (203.5 actual MW) (Figure 10-16). The
average hourly cleared MW from RegD resources during ramp hours for the
first six months of 2021 was 219.4 actual MW, an increase of 2.6 percent fromthe first six months of 2020 (213.9 actual MW). The average hourly cleared
MW from RegD resources during nonramp hours for the first six monthsof 2021 was 202.6 actual MW, an increase of 0.6 percent from the first six
months of 2020 (201.4 actual MW). These increases in the amount of RegD
offered and cleared MW were the result of the battery settlement that went
into effect on July 1, 2020. If settlement battery units do not clear through the© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

normal clearing process, PJM clears those units anyway, procuring excess MW
beyond the regulation requirement and charging customers for the excess.
Figure 10-16 Average hourly RegD actual MW offered and cleared: January
through June, 2020 through 2021
320

decreasing from 38.9 percent in 2020, to 34.4 percent in the first six monthsof 2021. The total regulation credits in the first six months of 2021 were$49,803,839, an increase of 48.6 percent from $33,526,208 in the first six
months of 2020. The increase in regulation credits is due, in part, to a higher
LOC component of regulation prices as a result of higher energy prices in thefirst six months of 2021 compared to the first six months of 2020.

2020 Q2 Offered2020 Q2 Cleared

300

2021 Q2 Offered2021 Q2 Cleared

RegD Actual MW

280

260

240

220

200

180

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

Hour

Table 10-39 provides the settled regulation MW by source unit type, thetotal settled regulation MW provided by all resources, the percent of settled
regulation provided by unit type, and the clearing price, uplift, and total
regulation credits. In Table 10-39 the MW have been adjusted by theperformance score since this adjustment forms the basis of payment for units
providing regulation. Total regulation performance adjusted settled MW
increased 0.3 percent from 2,291,864.0 MW in the first six months of 2020
to 2,299,445.8 MW in the first six months of 2021. The average proportionof regulation provided by battery units had the largest increase (2.1 percent),
providing 33.7 percent of regulation in the first six months of 2020 and 35.8
percent of regulation in the first six months of 2021. Natural gas units had thelargest decrease in average proportion of regulation provided (4.5 percent),© 2021 Monitoring Analytics, LLC

When a resource offers into the regulation market, an estimated regulation
LOC is added by PJM to form a total offer (units self scheduled, or notproviding in the energy market, have a regulation LOC of zero). After a unit
clears and has provided regulation, their regulation LOC is calculated again
during settlements, using the actual LMP. If this actual regulation LOC causes
the unit’s total offer to be larger than the clearing price, the unit receives
uplift credits. The uplift credits received for each unit type are shown in Table
10-39. The total uplift credits received increased 42.2 percent from $4,117,883
in the first six months of 2020 to $5,854,455 in the first six months of 2021.
This increase, like the increase in total credits, is due in part to higher LOC
components of regulation prices and offers as a result of higher energy prices
in the first six months of 2021 compared to the first six months of 2020.
Natural gas units had the largest increase in uplift payments, increasing from$919,134 (22.3 percent of total) in the first six months of 2020, to $2,213,556(37.8 percent of total) in the first six months of 2021. Coal units had thelargest decrease in uplift payments, decreasing from $1,829,075 (44.4 percent
of total) in the first six months of 2020, to $1,788,061 (30.5 percent of total)in the first six months of 2021.

2021 Quarterly State of the Market Report for PJM: January through June 533

2021 Quarterly State of the Market Report for PJM: January through June

Table 10-39 PJM regulation by source: January through June, 2020 and 202191

SourceBattery
Coal
Hydro
Natural Gas
DR
Total

2020 (Jan-Jun)
Performance
Percent
Number of Adjusted Settled of Settled Clearing Price
Units Regulation (MW) Regulation
Credits
22
771,71933.7%$10,752,327
19
172,273
7.5%$2,287,764
26
413,31618.0%$5,066,814
146
891,54338.9%$10,658,211
21
43,0131.9%$643,210
234
2,291,864.0
100.0% $29,408,325

Uplift Total Regulation
Credits
Credits$0$10,752,327$1,829,075$4,116,839$1,369,675$6,436,489$919,134$11,577,344$0$643,210$4,117,883$33,526,2082021 (Jan-Jun)
Performance
Percent
Number of Adjusted Settled of Settled Clearing Price
Units Regulation (MW) Regulation
Credits
22
822,396
35.8% $17,138,298
19
216,2319.4%$3,786,446
27
436,673
19.0%$8,142,453
170
791,997
34.4% $14,177,799
18
32,1491.4%$704,387
256
2,299,445.8
100.0% $43,949,383

Significant flaws in the regulation market design have led to an overprocurement of RegD MW primarily in the form of storage capacity. The
incorrect market signals have contributed to more storage projects entering
PJM’s interconnection queue, despite clear evidence that the market design
is flawed and despite operational evidence that the RegD market is saturated(Table 10-40).
Table 10-40 Active battery storage projects by submitted year: 2014 throughJune 2021
Year
2014
2015
2016
2017
2018
2019
2020
2021
Total

Number of Storage Projects
1
5
0
1
19
62
158
151
397

Total Capacity (MW)
10.0
61.0
0.0
2.0
690.1
4,008.7
9,872.6
13,240.4
27,884.8

The supply of regulation can be affected by regulating units retiring fromservice. If all units that are requesting retirement through the first six monthsof 2021 retire, the supply of regulation in PJM will be reduced by less than
one percent.

91 Biomass data have been added to the natural gas category for confidentiality purposes.

534

Section 10 Ancillary Services

Uplift Total Regulation
Credits
Credits$0$17,138,298$1,788,061$5,574,507$1,852,838$9,995,291$2,213,556$16,391,355$0$704,387$5,854,455$49,803,839

DemandThe demand for regulation does not change with price. The regulation
requirement is set by PJM to meet NERC control standards, based on reliability
objectives, which means that a significant amount of judgment is exercised by
PJM in determining the actual demand. 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
several times. It had been scheduled to be reduced from 1.0 percent of peakload forecast to 0.9 percent on October 1, 2012, but instead it was changed
from 1.0 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,
2012 and reduced again to 0.70 percent of peak load forecast on December
18, 2012. On December 14, 2013, it was reduced to 700 effective MW during
peak hours and 525 effective MW during off peak hours. The regulation
requirement remained 700 effective MW during peak hours and 525 effective
MW during off peak hours until January 9, 2017. A change to the regulation
requirement was approved by the RMISTF in 2016, with an implementation
date of January 9, 2017. The regulation requirement was increased from 700
effective MW to 800 effective MW during ramp hours (Table 10-32).
Table 10-41 shows the average hourly required regulation by month andthe ratio of supply to demand for both actual and effective MW, for ramp
and nonramp hours. The average hourly required regulation by month isan average of the ramp and nonramp hours in the month. Changes in the© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

actual MW required to satisfy the regulation requirement are the result of theamount of RegD actual MW cleared. When more RegD MW are cleared, theMBF is lower, resulting in those actual MW being worth less effective MW,
requiring more actual MW to satisfy the requirement. When MBFs are higher,
the actual MW of RegD are worth more effective MW, reducing the amount of
actual MW needed to satisfy the requirement.
The nonramp regulation requirement of 525.0 effective MW was provided by
a combination of RegA and RegD resources equal to 491.3 hourly average
performance adjusted actual MW in the first six months of 2021. This is anincrease of 1.7 performance adjusted actual MW from the first six months of
2020, when the average hourly total regulation cleared performance adjusted
actual MW for nonramp hours were 489.6 performance adjusted actual MW.
The ramp regulation requirement of 800.0 effective MW was provided by
a combination of RegA and RegD resources equal to 707.3 hourly average
performance adjusted actual MW in the first six months of 2021. This is anincrease of 3.2 performance adjusted actual MW from the first six months of
2020, where the average hourly regulation cleared MW for ramp hours were704.1 performance adjusted actual MW.

Table 10-41 Required regulation and ratio of supply to requirement: January
2020 through June 2021

Hours

Month
Jan
Feb
Mar
Apr
May
Jun
Ramp
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Nonramp
Jul
Aug
Sep
Oct
Nov
Dec

Average Required
Regulation (MW)
2020
2021
712.9
713.2
694.3
709.7
692.5
713.8
707.5
702.8
711.8
705.5
705.5
698.8
702.8
705.1
694.8
696.0
700.9
705.5
479.5
495.1
495.9
500.4
493.1
495.9
492.7
490.9
486.6
487.1
490.0
478.6
498.1
489.8
484.8
491.3
501.8
500.8
-

Average Required
Regulation
Ratio of Supply MW(Effective MW)
to MW Requirement
2020
2021
2020
2021
800.1
800.0
1.36
1.59
800.0
800.0
1.31
1.53
800.1
800.0
1.33
1.54
800.1
800.0
1.41
1.48
800.1
800.0
1.42
1.45
800.0
799.9
1.52
1.50
800.1
1.57
800.0
1.47
799.8
1.46
800.1
1.46
800.1
1.43
800.1
1.56
525.1
525.2
1.43
1.52
525.1
525.1
1.45
1.59
525.1
525.2
1.36
1.59
525.2
525.1
1.46
1.51
525.3
525.5
1.45
1.54
525.1
525.4
1.45
1.50
525.4
1.46
525.0
1.43
525.2
1.46
525.2
1.50
525.5
1.50
525.1
1.63
-

Ratio of Supply
Effective MW to
Effective MW
Requirement
2020
2021
1.25
1.42
1.22
1.37
1.24
1.38
1.29
1.33
1.31
1.32
1.38
1.36
1.42
1.34
1.33
1.33
1.30
1.40
1.33
1.42
1.37
1.47
1.29
1.47
1.36
1.41
1.36
1.43
1.36
1.39
1.38
1.35
1.36
1.41
1.41
1.50
-

Market Concentration
In the first six months of 2021, the effective MW weighted average HHI of
RegA resources was 2288 which is highly concentrated and the weighted
average HHI of RegD resources was 1670 which is moderately concentrated.
The weighted average HHI of all resources was 1218, which is moderately
concentrated. The weighted average HHI reflects the fact that different owners
have large market shares in the RegA and RegD markets.
Table 10-42 includes a monthly summary of three pivotal supplier (TPS)
results. In the first six months of 2021, 87.7 percent of hours had three or© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 535

2021 Quarterly State of the Market Report for PJM: January through June

fewer pivotal suppliers. The MMU concludes that the PJM Regulation Market
in the first six months of 2021 was characterized by structural market power.
The results presented here are calculated by PJM. The MMU has been unable
to verify these results, as some of the underlying data necessary to replicate
these calculations is not saved. PJM has submitted a request to the vendor tosave all data necessary for verification.
Table 10-42 Regulation market monthly three pivotal supplier results: 2019
through June 2021
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Average

2019
77.8%
76.0%
93.3%
93.1%
94.0%
91.0%
92.7%
93.1%
93.3%
96.1%
90.7%
96.1%
90.6%

Percent of Hours Pivotal
2020
99.1%
97.4%
98.3%
96.5%
94.9%
89.8%
89.0%
94.6%
93.3%
94.0%
91.0%
83.6%
93.5%

2021
91.4%
88.7%
87.2%
88.5%
83.9%
86.4%

87.7%

Market Conduct
OffersResources seeking to regulate must qualify to follow a regulation signal bypassing a test for that signal with at least a 75 percent performance score. The
regulating resource must be able to supply at least 0.1 MW of regulation andnot allow the sum of its regulating ramp rate and energy ramp rate to exceed
its overall ramp rate.92 When offering into the regulation market, regulating
resources must submit a cost-based offer and may submit a price-based offer(capped at $100 per MW) by 14:15 the day before the operating day.93

92 See “PJM Manual 11: Energy & Ancillary Services Market Operations,” § 3.2.1 Regulation Market Eligibility, Rev. 115 (June 1, 2021).
93 Id. at 3.2.2, at p 62.

536

Section 10 Ancillary Services

Offers in the PJM Regulation Market consist of a capability component for
the MW of regulation capability provided and a performance component forthe miles (ΔMW of regulation movement) provided. The capability component
for cost-based offers is not to exceed the increased fuel costs resulting fromoperating the regulating unit at a lower output level than its economically
optimal output level, plus a $12.00 per MW margin. The $12.00 margin embeds
market power in the regulation offers, is not part of the cost of regulation, andshould be eliminated. The performance component for cost-based offers is not
to exceed the increased costs (increased short run marginal costs including
increased fuel costs) resulting from moving the unit up and down to provide
regulation. Batteries and flywheels have zero cost for lower efficiency fromproviding regulation instead of energy, as they are not net energy producers.
There is an energy storage loss component for batteries and flywheels as acost component of regulation performance offers to reflect the net energy
consumed to provide regulation service.94
Up until one hour before the operating hour, the regulating resource must
provide: status (available, unavailable, or self scheduled); capability (movement
up and down in MW); regulation maximum and regulation minimum (thehighest and lowest levels of energy output while regulating in MW); andthe regulation signal type (RegA or RegD). Resources may offer regulation
for both the RegA and RegD signals, but will be assigned to follow only one
signal for a given operating hour. Resources have the option to submit aminimum level of regulation they are willing to provide.95
All LSEs are required to provide regulation in proportion to their load share.
LSEs can purchase regulation in the regulation market, purchase regulationfrom other providers bilaterally, or self schedule regulation to satisfy their
obligation (Table 10-44).96 Figure 10-17 compares average hourly regulationand self scheduled regulation during ramp and nonramp hours on an effective
MW basis. The average hourly regulation is the amount of regulation that
actually cleared and is not the same as the regulation requirement because
PJM clears the market within a two percent band around the requirement.97
94 See “PJM Manual 15: Cost Development Guidelines,” § 7.8 Regulation Cost, Rev. 37 (Dec. 9, 2020).
95 See “PJM Manual 11: Energy & Ancillary Services Market Operations,” § 3.2.1 Regulation Market Eligibility, Rev. 115 (June 1, 2021).
96 See “PJM Manual 28: Operating Agreement Accounting,” § 4.1 Regulation Accounting Overview, Rev. 84 (Dec. 17, 2020).
97 See “PJM Manual 11: Energy & Ancillary Services Market Operations,” § 3.2.1 Regulation Market Eligibility, Rev. 115 (June 1, 2021).

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Self scheduled regulation comprised an average of 49.0 percent during ramp
hours and 63.4 percent during nonramp hours in the first six months of 2021.

led to the increased amount of RegD cleared (Table 10-36), and the decreasein the MBF (Figure 10-11).

Figure 10-17 Nonramp and ramp regulation levels: January 2020 throughJune 2021

Table 10-43 RegD self scheduled regulation by month: January 2020 throughJune 2021

900
800
700

Effective MW

600
500
400
300

200

Jun-21

May-21

Apr-21

Mar-21

Nonramp self scheduled

Feb-21

Nonramp regulation

Ramp self scheduled

Jan-21

Ramp regulation

Dec-20Nov-20

Oct-20

Sep-20Aug-20Jul-20Jun-20May-20

Apr-20Mar-20Feb-200

Jan-20100

Table 10-43 shows the role of RegD resources in the regulation market. RegD
resources are both a growing proportion of the market (10.9 percent of thetotal effective MW at the start of the performance based regulation market
design in October 2012 and 47.3 percent of the total effective MW in June2021) and a growing proportion of resources that self schedule (25.0 percent
of all self scheduled effective MW in October 2012 and 73.5 percent of all
self scheduled effective MW in June 2021). In the first six months of 2021,
the average RegD percentage of total self scheduled effective MW was 72.3
percent, an increase of 2.3 percentage points from the first six months of 2020,
when the average was 70.0 percent. This increase in RegD self scheduling has© 2021 Monitoring Analytics, LLC

Year
Month
2020
Jan
2020
Feb
2020
Mar
2020
Apr
2020
May
2020
Jun
2020
Jul
2020
Aug
2020
Sep
2020
Oct
2020
Nov
2020
Dec
2020 Average
2021
Jan
2021
Feb
2021
Mar
2021
Apr
2021
May
2021
Jun
2021 Average

RegD Percent
RegD Self
Total Selfof Total Self RegD Percent
Scheduled
RegD
Scheduled
Total
Scheduledof Total
Effective MW Effective MW Effective MW Effective MW Effective MW Effective MW
253.3
311.9
376.5
674.0
67.3%
46.3%
263.6
333.5
385.3
674.0
68.4%
49.5%
257.9
319.9
358.9
639.9
71.9%
50.0%
267.2
318.1
382.9
639.7
69.8%
49.7%
274.6
312.2
388.5
639.8
70.7%
48.8%
281.8
335.1
390.5
696.7
72.2%
48.1%
252.6
343.3
369.3
697.1
68.4%
49.2%
258.7
341.0
357.2
697.0
72.4%
48.9%
275.4
317.2
363.3
639.6
75.8%
49.6%
265.7
319.2
368.3
639.8
72.1%
49.9%
255.1
321.4
346.5
640.6
73.6%
50.2%
262.1
329.8
366.8
674.0
71.4%
48.9%
264.0
325.2
371.2
662.7
71.2%
49.1%
250.5
322.4
367.7
674.0
68.1%
47.8%
262.0
335.3
366.7
674.3
71.4%
49.7%
263.0
321.7
359.0
639.9
73.3%
50.3%
266.0
325.9
343.1
639.6
77.5%
51.0%
256.8
320.6
368.0
639.9
69.8%
50.1%
266.5
329.9
362.7
697.0
73.5%
47.3%
260.8
326.0
361.2
660.8
72.3%
49.4%

LSE’s can satisfy their obligation to provide regulation by purchasing in the
spot market, self scheduling, or through bilateral agreements. Increased selfscheduled regulation lowers the requirement for cleared regulation, resulting
in fewer MW cleared in the market and lower clearing prices. Of the LSEs’
obligation to provide regulation in the first six months of 2021, 48.5 percent
was purchased in the PJM market, 47.2 percent was self scheduled, and
4.3 percent was purchased bilaterally (Table 10-44). Table 10-45 shows thetotal regulation by source including spot market regulation, self scheduled
regulation, and bilateral regulation for January through June, 2012 through2021. Table 10-44 and Table 10-45 are based on settled (purchased) MW.

2021 Quarterly State of the Market Report for PJM: January through June 537

2021 Quarterly State of the Market Report for PJM: January through June

Table 10-44 Regulation sources: spot market, self scheduled, bilateralpurchases: January 2020 through June 2021

Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total
2021 Jan
2021 Feb
2021 Mar
2021 Apr
2021 May
2021 Jun
Total

Self
Spot Market
Scheduled
Self
Bilateral
Total
Regulation Spot Market Regulation Scheduled Regulation
Bilateral Regulation(Unadjusted
Percent of (Unadjusted Percent of (Unadjusted Percent of (Unadjusted
MW)
Total
MW)
Total
MW)
Total
MW)
179,061.4
46.2%
190,434.8
49.1%
18,166.0
4.7%
387,662.1
160,674.9
43.8%
185,702.6
50.6%
20,815.5
5.7%
367,193.0
175,560.8
46.5%
181,566.1
48.1%
20,266.0
5.4%
377,392.8
154,642.4
42.4%
187,819.3
51.5%
22,195.5
6.1%
364,657.2
167,682.0
44.2%
191,949.3
50.5%
20,125.5
5.3%
379,756.8
192,336.9
49.3%
178,239.7
45.7%
19,479.5
5.0%
390,056.1
189,151.3
46.4%
198,595.7
48.7%
19,997.5
4.9%
407,744.5
207,948.6
51.1%
181,392.4
44.6%
17,756.0
4.4%
407,097.0
181,955.4
49.6%
171,428.3
46.7%
13,358.0
3.6%
366,741.7
178,179.3
46.9%
186,687.3
49.1%
15,309.5
4.0%
380,176.1
180,188.6
48.9%
172,941.0
46.9%
15,668.5
4.2%
368,798.1
189,587.0
47.8%
188,798.6
47.6%
18,505.0
4.7%
396,890.6
2,156,968.5
47.0% 2,215,555.1
48.2%
221,642.5
4.8% 4,594,166.0
186,762.8
46.6%
192,708.2
48.1%
21,466.0
5.4%
400,937.0
172,967.1
47.4%
174,470.7
47.9%
17,095.5
4.7%
364,533.3
182,812.8
47.3%
189,176.1
48.9%
14,910.0
3.9%
386,898.9
190,444.5
51.0%
170,255.4
45.6%
12,763.0
3.4%
373,462.9
171,841.5
44.5%
198,026.9
51.3%
16,270.0
4.2%
386,138.5
211,800.7
54.2%
163,167.4
41.8%
15,526.0
4.0%
390,494.1
1,116,629.4
48.5% 1,087,804.8
47.2%
98,030.5
4.3% 2,302,464.7

Table 10-45 Regulation sources: January through June, 2012 through 2021

Year
(Jan-Jun)
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

538

Spot Market
Regulation Spot Market(Unadjusted
Percent of
MW)
Total
3,065,069.1
76.0%
1,740,438.6
64.9%
1,370,386.4
57.9%
1,282,300.1
55.7%
1,139,515.1
48.5%
1,176,249.8
52.2%
1,390,856.8
61.6%
1,085,870.9
49.8%
1,029,923.1
45.4%
1,116,629.4
48.5%

Self
Scheduled
Regulation(Unadjusted
MW)847,576.2
849,955.3
889,917.5
894,595.8
1,086,532.7
948,195.8
757,440.3
980,572.5
1,115,710.1
1,087,804.8

Section 10 Ancillary Services

Self
Bilateral
Scheduled Regulation
Percent of (Unadjusted
Total
MW)
21.0%
122,641.0
31.7%
92,120.0
37.6%
106,365.5
38.8%
126,408.6
46.3%
122,808.5
42.1%
128,534.5
33.5%
110,201.5
45.0%
114,334.0
49.2%
121,048.0
47.2%
98,030.5

Total
Bilateral Regulation
Percent of (Unadjusted
Total
MW)
3.0% 4,035,286.2
3.4% 2,682,513.9
4.5% 2,366,669.4
5.5% 2,303,304.4
5.2% 2,348,856.3
5.7% 2,252,980.1
4.9% 2,258,498.6
5.2% 2,180,777.4
5.3% 2,266,681.2
4.3% 2,302,464.7

In the first six months of 2021, DR provided an average of 10.3 MW of
regulation per hour during ramp hours (13.5 MW of regulation per hour
during ramp hours in the first six months of 2020), and an average of 6.9
MW of regulation per hour during nonramp hours (10.1 MW of regulation
per hour during nonramp hours in the first six months of 2020). Generating
units supplied an average of 696.8 MW of regulation per hour during ramp
hours in the first six months of 2021 (690.8 MW of regulation per hour duringramp hours in the first six months of 2020), and an average of 484.7 MW
per hour during nonramp hours in the first six months of 2021 (479.6 MW of
regulation per hour during nonramp hours in the first six months of 2020).

Market Performance
Price
Table 10-49 shows the regulation price and regulation cost per MW for
January through June, 2009 through 2021. The weighted average RMCP for
the first six months of 2021 was $17.46 per MW. This is an increase of $5.73
per MW, or 48.9 percent, from the weighted average RMCP of $11.73 per MW
in the first six months of 2020. This increase in the regulation clearing price
was the result of an increase in energy prices in the first three months of 2021
and the related decrease in the opportunity cost component of RMCP.
Figure 10-18 shows the capability price, performance price, and theopportunity cost component for the PJM Regulation Market on a performanceadjusted MW basis. The regulation clearing price is determined based on
the marginal unit’s total offer (RCP + RPP + PJM calculated LOC). Then the
maximum performance offer price (RPP) of any of the cleared units is used to
set the marginal performance clearing price for the purposes of settlements.
The difference between the marginal total clearing price and the highest
performance clearing price (RMPCP) is the marginal capability clearing price(RMCCP). The capability price presented here is equal to the clearing price,minus the maximum cleared performance offer price. This data is based on
actual five minute interval operational data.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Figure 10-18 illustrates the components of the regulation market clearing
price. Each section represents the contribution of the lost opportunity cost
(green area), capability price (blue area), and performance price (orange area),to the total price. From this figure, it is clear that the lost opportunity cost is
the predominant component of the total clearing price.
Figure 10-18 Regulation market clearing price components (Dollars per MW):January through June, 2021
$90.00

Table 10-46 Regulation market monthly component of price (Dollars perMW): January through June, 2021
Weighted Average Regulation
Market Capability Clearing Price
Month($/Perf. Adj. Actual MW)
Jan$11.26Feb$19.53Mar$18.30Apr$15.76May$15.59Jun$18.17
Average$16.38Weighted Average Regulation
Market Performance Clearing
Price ($/Perf. Adj. Actual MW)
$0.86
$1.07
$0.87
$1.59
$1.03
$1.05
$1.08

Weighted Average Regulation
Market Clearing Price ($/Perf.
Adj. Actual MW)$12.12$20.60$19.20$17.34$16.62$19.22$17.46Weighted Average Performance Price$80.00Weighted Average Capability Price
Weighted Average Lost Opportunity Cost

$70.00$60.00$50.00

Table 10-47 Total regulation charges: January 2020 through June 2021

$40.00$30.00$20.00

Dec

Nov

Oct

Sep

Aug

Jul

Jun

May

Apr

Mar

Feb

Jan

$10.00$0.00

Monthly and total annual scheduled regulation MW and regulation charges, aswell as monthly average regulation price and regulation cost are shown in Table
10-47. Total scheduled regulation is based on settled performance adjusted MW.
The total of all regulation charges in the first six months of 2021 was $49.9
million, compared to $33.5 million in the first six months of 2020.

Table 10-46 shows the capability and performance components of the monthly
average regulation prices. These components differ from the components of themarginal unit’s offers in Figure 10-18 because the performance component of
the settlement price for each hour is determined from the average of the highest
performance offers in each five minute interval, calculated independent of themarginal unit’s offers in those intervals.

© 2021 Monitoring Analytics, LLC

Year
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020

Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Yearly
2021
Jan
2021
Feb
2021
Mar
2021
Apr
2021
May
2021
Jun
Total

Weighted Average
Scheduled Total Regulation Regulation Market
Regulation (MW)Charges ($)
Price ($/MW)
387,662.1$6,495,664$13.70367,193.0$4,630,253$10.12
377,392.8$4,619,257$9.06
364,657.2$5,646,138$12.10379,756.8$6,078,957$12.97390,056.1$6,072,212$12.31
407,744.5$7,732,029$16.14
407,097.0$7,566,611$15.36
366,741.7$4,909,677$10.88380,176.1$8,168,776$17.64
368,798.1$7,381,789$15.95396,890.6$7,562,483$15.794,594,166.0$76,860,642$13.55400,937.0$6,038,564$12.12364,533.3$9,401,619$20.60386,898.9$8,793,373$19.20373,462.9$7,945,154$17.34
386,138.5$8,049,501$16.62
390,494.1$9,646,216$19.222,302,464.7$49,874,426$17.46

Cost of
Regulation Price as Percent($/MW)of Cost$16.76
81.7%$12.61
80.3%$12.2474.0%$15.4878.1%$16.01
81.0%$15.5779.1%$18.9685.1%$18.5982.6%$13.3981.2%$21.4982.1%$20.0279.7%$19.05
82.9%$16.7381.0%$15.0680.5%$25.7979.9%$22.7384.5%$21.27
81.5%$20.8579.8%$24.7077.8%$21.6680.6%2021 Quarterly State of the Market Report for PJM: January through June 539

2021 Quarterly State of the Market Report for PJM: January through June

The capability, performance, and opportunity cost components of the cost of regulation are shown in Table 10-48. Total scheduled regulation is based on settled
performance adjusted MW. In the first six months of 2021, the average total cost of regulation was $21.66 per MW, 46.4 percent higher than $14.79 in the firstsix months of 2020. In the first six months of 2021, the monthly average capability component cost of regulation was $16.82, 48.2 percent higher than $11.35
in the first six months of 2020. In the first six months of 2021, the monthly average performance component cost of regulation was $2.27, 39.8 percent higher
than $1.62 in the first six months of 2020. The increase of the average total cost in the first six months of 2021 versus the first six months of 2020, was primarilya result of higher LOC values due to higher prices in the energy market.
Table 10-48 Components of regulation cost: January 2020 through June 2021

Year

Month
Jan
Feb
Mar
Apr
May
Jun
2020
Jul
Aug
Sep
Oct
Nov
Dec
Yearly
Jan
Feb
Mar
2021
Apr
May
Jun
Total

540

Scheduled
Regulation (MW)387,662.1
367,193.0
377,392.8
364,657.2
379,756.8
390,056.1
407,744.5
407,097.0
366,741.7
380,176.1
368,798.1
396,890.6
4,594,166.0
400,937.0
364,533.3
386,898.9
373,462.9
386,138.5
390,494.1
2,302,464.7

Cost of
Regulation
Capability($/MW)$13.32$9.90$8.71$11.68$12.66$11.74$15.74$14.80$10.42$16.90$15.21$15.40$13.09$11.71$19.90$18.70$16.63$15.87$18.45$16.82

Section 10 Ancillary Services

Cost of
Regulation
Performance Opportunity Cost($/MW)($/MW)
$1.80
$1.64
$1.35
$1.36
$1.46
$2.07
$1.77
$2.03
$1.39
$1.95
$1.94
$1.88
$1.54
$1.68
$2.01
$1.78
$1.49
$1.47
$2.80
$1.78
$2.70
$2.11
$1.72
$1.94
$1.83
$1.81
$1.67
$1.68
$2.52
$3.37
$1.86
$2.16
$2.66
$1.98
$2.40
$2.58
$2.54
$3.71
$2.27
$2.57

Total Cost($/MW)$16.76$12.61$12.24$15.48$16.01$15.57$18.96$18.59$13.39$21.49$20.02$19.05$16.73$15.06$25.79$22.73$21.27$20.85$24.70$21.66© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Table 10-49 provides a comparison of the average price and cost for PJM regulation. The ratio of regulation market price to the cost of regulation in the firstsix months of 2021 was 80.6 percent, a 1.7 percent increase from 79.3 percent in the first six months of 2020.
Table 10-49 Comparison of average price and cost for regulation: January through March, June, September, and December, 2009 through 202198

Year
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Weighted
Regulation
Market Price$22.25$17.97$11.52$12.62$33.91$92.97$47.91$15.55$13.89$40.33$14.05$10.99$17.18

Jan-Mar
Weighted
Regulation
Regulation Price as Percent
Market Cost
Cost
$34.0665.3%$31.2457.5%$25.0346.0%$16.7575.3%$39.3686.2%$112.30
82.8%$58.23
82.3%$17.9286.8%$18.4775.2%$49.6081.3%$18.4976.0%$13.9179.0%$21.0181.8%

Weighted
Regulation
Market Price$25.23$18.33$15.31$13.89$32.04$62.71$40.94$15.90$15.08$32.97$13.85$11.73$17.46

Jan-JunWeighted
Regulation
Regulation Price as Percent
Market Cost
Cost
$33.82
74.6%$31.4358.3%$31.0049.4%$18.3475.7%$37.0486.5%$75.9782.5%$49.57
82.6%$18.3086.9%$20.6773.0%$40.7680.9%$18.1276.5%$14.7979.3%$21.6680.6%

Weighted
Regulation
Market Price$24.94$19.47$17.04$15.16$33.29$50.19$35.56$16.52$15.70$28.21$14.97$12.59Jan-Sep
Weighted
Regulation
Regulation Price as Percent
Market Cost
Cost
$32.2877.3%$34.5456.4%$32.7052.1%$21.0771.9%$38.4986.5%$60.9482.4%$43.0082.7%$18.9987.0%$21.7072.4%$35.0680.5%$19.15
78.1%$15.5980.8%

Weighted
Regulation
Market Price$23.00$18.00$16.49$19.02$30.85$44.49$31.92$15.73$16.79$25.32$16.27$13.55

Jan-Dec
Weighted
Regulation
Regulation Price as Percent
Market Cost
Cost
$30.6875.0%$32.8654.8%$29.72
55.5%$25.3275.1%$35.7986.2%$53.82
82.7%$38.3683.2%$18.1386.7%$23.0372.9%$31.9479.3%$20.3280.1%$16.73
81.0%

98 There was an error in previously reported values for 2009 through 2012 in this table. The correct values are included here.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 541

2021 Quarterly State of the Market Report for PJM: January through June

Performance Standards
PJM’s performance as measured by CPS1 and BAAL standards is shown in
Figure 10-19 for every month from January 2011 through June 2021 with thedashed vertical line marking the date (October 1, 2012) of the implementationof the Performance Based Regulation Market design.99 The horizontal dashedlines represent PJM internal goals for CPS1 and BAAL performance.
Figure 10-19 Monthly CPS1 and BAAL performance: January 2011 throughJune 2021
180%

100.0%

160%
140%

99.5%

100%
99.0%
80%

BAAL Score

CPS 1

120%

60%
98.5%

40%

CPS1 Score
PJM Internal Goal for CPS1

20%

BAAL Score

Jul-20Jan-21

Jan-20Jul-19Jul-18Jan-19Jul-17Jan-18

Jul-16

Jan-17

Jul-15Jan-16

Jul-14Jan-15

Jul-13Jan-14Jul-12

Jan-13

Jul-11

Jan-12

Jan-11PJM Internal Goal for BAAL

0%

98.0%

Black Start Service
Black start service is required for the reliable restoration of the grid following a
blackout. Black start service is the ability of a generating unit to start without
an outside electrical supply, or the demonstrated ability of a generating unit
to automatically remain operating at reduced levels when disconnected from99 See 2019 State of the Market Report for PJM, Appendix F: Ancillary Services.

542

Section 10 Ancillary Services

the grid (automatic load rejection or ALR).100 Although PJM has raised theissue, there are no firm fuel requirements for black start units.
PJM does not have a market to provide black start service, but compensatesblack start resource owners on the basis of cost of service rates defined in thetariff.101
PJM defines required black start capability zonally, while recognizing thatthe most effective way to provide black start service may be across zones.
Under the current rules PJM has substantial flexibility in procuring black start
resources and is responsible for black start resource selection.
On April 7, 2021, PJM issued an incremental RFP for additional black start
service in the BGE and PEPCO Zones. The RFP is a two stage process. Level
one submissions were due May 10, 2021. Level two submissions were due May
31, 2021. The expected award by date is November 1, 2021. The planned inservice date is April 1, 2023.102
Total black start charges are the sum of black start revenue requirement
charges and black start uplift (operating reserve) charges. Black start revenue
requirements for black start units consist of fixed black start service costs,
variable black start service costs, training costs, fuel storage costs, and an
incentive factor applicable when CRF rates are not used. The tariff specifies
how to calculate each component of the revenue requirement formula.103
Black start resources can choose to recover fixed costs under a formula rate
based on zonal Net CONE and unit ICAP rating, a cost recovery rate based onincremental black start NERC-CIP compliance capital costs, or a cost recovery
rate based on FERC-approved rate plus capital costs for new investment. In
addition, PJM applies a cost recovery rate based on incremental black startequipment capital costs.
Black start uplift (operating reserve) charges are paid to units committed
in real time to provide black start service or for black start testing.104 Total
100 OATT Schedule 1 § 1.3BB.
101 See OATT Schedule 6A para. 18.
102 RFPs issued can be found on the PJM website. See PJM. <http://www.pjm.com/markets-and-operations/ancillary-services.aspx>.
103 See OATT Schedule 6A para. 18.
104 There are no black start units currently using the ALR option.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

black start charges are allocated monthly to PJM customers proportionally to their zone and nonzone peak transmission use and point to point transmission
reservations.105 It is not clear why it is reasonable to have different charges for black start service across zones as the service is to ensure that PJM as a whole
can recover from a large scale outage.
In the first six months of 2021, total black start charges were $33.6 million, an increase of $0.1 million (0.2 percent) from 2020. Uplift charges for black start
service increased from $0.1 million in the first six months of 2020 to $0.2 million (12.0 percent) in the first six months of 2021. Table 10-50 shows total charges
in the first six months of each year from 2010 through 2021.106
Table 10-50 Black start revenue requirement charges: January through June, 2010 through 2021
Jan-Jun
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Revenue Requirement
Charges$5,481,206$5,968,676$7,873,702$10,584,683$10,874,608$23,348,866$33,778,388$35,617,856$33,363,286$32,100,135$33,343,875$33,390,578

Uplift Charges$0$0$0$48,075,584$14,339,174$5,036,053$168,645$146,223$126,698$138,612$141,918$158,989

Total$5,481,206$5,968,676$7,873,702$58,660,267$25,213,781$28,384,918$33,947,033$35,764,079$33,489,984$32,238,747$33,485,793$33,549,567

105 OATT Schedule 6A (paras. 25, 26 and 27 outline how charges are to be applied).
106 Starting December 1, 2012, PJM defined a separate black start uplift category. ALR units accounted for the high uplift charges in 2013 – 2015. All ALR units had been replaced by April 2015.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 543

2021 Quarterly State of the Market Report for PJM: January through June

Black start zonal charges in the first six months of 2021 ranged from $0.02 per MW-day in the BGE Zone (total charges were $22,716) to $4.13 per MW-day
in the PE Zone (total charges were $2,176,976). For each zone, Table 10-51 shows black start charges, the sum of monthly zonal peak loads multiplied by the
number of days of the month in which the peak load occurred, and black start rates (calculated as charges per MW-day). Customers paid an average of $1.16
per MW-day for black start service in the first six months of 2021.
Table 10-51 Black start zonal charges: January through June, 2020 and 2021107
Jan-Jun 2020

Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DUQ
DOM
DPL
EKPC
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
(Imp/Exp/Wheels)
Total

Revenue
Requirement
Charges$1,286,452$8,652,683$1,927,379$2,793,265$115,679$3,615,728$109,424$177,374$22,051$2,260,458$1,098,424$167,450$2,366,888$209,077$0$682,750$2,184,989$1,227,454$1,175,960$1,683,863$0$1,586,527$33,343,875

UpliftTotal
Charges
Charges$6,898 $1,293,350$24,095 $8,676,778$1,159 $1,928,537$8,483 $2,801,747$628$116,307$11,262 $3,626,990$14,120$123,544$12,764$190,137$0$22,051$20,791 $2,281,249$8,843 $1,107,267$1,641$169,091$3,058 $2,369,946$6,766$215,843$0$0$1,261$684,011$8,372 $2,193,361$2,657$1,230,111$161 $1,176,121$2,350 $1,686,214$0$0$6,610 $1,593,137$141,918 $33,485,793

Jan-Jun 2021
Peak Load
(MW)
2,737
22,498
9,596
12,567
6,706
20,949
3,259
5,052
2,662
19,931
4,098
3,074
6,057
2,986
NA
8,428
3,015
6,191
7,939
9,753
NA
7,879
165,375

Black Start
Rate($/MW-day)
$2.60
$2.12
$1.10
$1.22
$0.10
$0.95
$0.21
$0.21
$0.05
$0.63
$1.48
$0.30
$2.15
$0.40
NA
$0.45
$4.00
$1.09
$0.81
$0.47
NA
$1.11
$1.11

Revenue
Requirement
Charges$1,246,941$9,847,406$2,342,366$2,797,431$22,622$4,615,330$111,464$184,189$22,124$2,613,229$981,018$160,108$374,792$215,213$0$720,631$2,164,350$152,642$2,433,825$846,256$0$1,538,640$33,390,578

UpliftTotal
Charges
Charges$11,402 $1,258,343$38,346 $9,885,752$1,135 $2,343,500$0 $2,797,431$95$22,716$5,910 $4,621,240$13,958$125,422$12,598$196,787$0$22,124$40,029 $2,653,258$3,986$985,005$2,076$162,184$2,564$377,356$1,726$216,938$0$0$2,199$722,830$12,625 $2,176,976$607$153,249$0 $2,433,825$2,966$849,222$0$0$6,769 $1,545,409$158,989 $33,549,567

Peak Load
(MW)
2,635
21,615
8,638
12,4656,700
20,220
3,309
4,975
2,668
20,061
4,086
2,720
5,903
2,976
NA
8,148
2,911
5,887
7,260
9,557
NA
7,348
160,080

Black Start
Rate($/MW-day)
$2.64
$2.53
$1.50
$1.24
$0.02
$1.26
$0.21
$0.22
$0.05
$0.73
$1.33
$0.33
$0.35
$0.40
NA
$0.49
$4.13
$0.14
$1.85
$0.49
NA
$1.16
$1.16

107 Peak load for each zone is used to calculate the black start rate per MW day.

544

Section 10 Ancillary Services© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Table 10-52 provides a revenue requirement estimate by zone for the2021/2022, 2022/2023, and 2023/2024 Delivery Years.108 Revenue requirement
values are rounded up to the nearest $50,000 to reflect uncertainty about
future black start revenue requirement costs. These values are illustrative
only. The estimates are based on the best available data including current
black start unit revenue requirements, expected black start unit terminationand in service dates, changes in recovery rates, and owner provided costestimates of incoming black start units at the time of publication and maychange significantly.
Table 10-52 Black start zonal revenue requirement estimate: 2021/2022
through 2023/2024 Delivery Years109
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DUQ
DOM
DPL
EKPC
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
Total

2021 / 2022
Revenue Requirement$2,150,000$21,700,000$10,400,000$5,900,000$50,000$10,050,000$300,000$450,000$2,150,000$5,550,000$1,350,000$400,000$650,000$550,000$0$1,600,000$4,650,000$300,000$5,350,000$1,950,000$0$75,500,000

2022 / 2023
Revenue Requirement$2,150,000$21,500,000$10,350,000$5,900,000$50,000$9,400,000$250,000$350,000$2,100,000$5,350,000$1,250,000$300,000$550,000$450,000$0$1,350,000$4,550,000$200,000$5,200,000$1,850,000$0$73,100,000

2023 / 2024
Revenue Requirement$2,150,000$21,500,000$10,350,000$5,900,000$50,000$9,400,000$250,000$350,000$2,100,000$5,350,000$1,250,000$300,000$550,000$450,000$0$1,350,000$4,550,000$200,000$5,200,000$1,850,000$0$73,100,000

108 The System Restoration Strategy Task Force requested that the MMU provide estimated black start revenue requirements.
109 The 2023/2024 estimated revenue requirement is based on the CONE values for the 2022/2023 RPM Base Residual Auction because the2023/2024 RPM Base Residual Auction has not been run.

© 2021 Monitoring Analytics, LLC

CRF Issues
The capital recovery factor (CRF) defines the revenue requirement of black
start units when new equipment is added to provide black start capability.110
The CRF is a rate, which when multiplied by the investment, provides for a
return on and of capital over a defined time period. CRFs are calculated using
a formula (or a correctly defined standard financial model) that accounts
for the weighted average cost of capital and its components, including
depreciation and taxes. The PJM CRF table was created in 2007 as part of the
new RPM capacity market design and incorporated in Attachment DD to the
PJM OATT (Table 10-53). The CRF table provided for the accelerated returnof incremental investment in capacity resources based on concerns about thefact that some old coal units would be making substantial investments related
to pollution control. The CRF values were later added to the black start rules.111
The CRF table in the tariff includes assumptions about tax rates that are nolonger correct. The CRF values are significantly too high as a result. The PJM
tariff tables including CRF values should have been changed for both black
start and the capacity market when the tax laws changed in 2017.
Table 10-53 Existing CRF table for black start units
Age of Black Start Unit (Years)
1 to 56 to 1011 to 15
16+

Term of Black Start Unit
Commitment (Years)
20
15
10
5

Levelized CRF
0.125
0.146
0.198
0.363

The existing CRF table includes the column header, term of black start unit
commitment, which is misleading and incorrect. The column is simply thecost recovery period. Accelerated recovery reduces risk to black start units andshould not be the basis for a shorter commitment. Full payment of all costsof black start investment on an accelerated basis should not be a reason fora shortened commitment period. Regardless of the recovery period, paymentof the full costs of the black start investment should require commitment for
110 See OATT Schedule 6A para. 18.
111 Id.

2021 Quarterly State of the Market Report for PJM: January through June 545

2021 Quarterly State of the Market Report for PJM: January through June

the life of the unit.112 There is no need for such short recovery periods forblack start investment costs. Two periods, based on unit age, are more thanadequate.
The U.S. Internal Revenue Code changed significantly in December 2017. The
PJM CRF table did not change to reflect these changes. As a result, CRF values
have overcompensated black start units since the changes to the tax code.
The new depreciation rules allow for a more accelerated depreciation andtherefore lower taxes. The tax code also reduced the corporate tax rate to 21
percent which also reduces taxes.
Updated CRF rates, incorporating the tax code changes, should be implemented
immediately. The updated CRF rates should apply to all black start units
because the actual tax payments for all black start units were reduced by the
tax law changes. Without this change, black start units are receiving and willcontinue to receive an unexpected windfall.
Table 10-54 includes updated CRF values based on the new tax code. The
second column is the cost recovery period and not the commitment period.
Table 10-54 Updated CRF table for black start units
Age of Black Start Unit (Years)
1 to 56 to 1011 to 15
16+

Black Start Cost Recovery Period(Years)20
15
10
5

UpdatedLevelized CRF
0.101
0.116
0.147
0.246

Overcompensation amounts vary with the project investment and the CRF
recovery period (Table 10-55). For a new black start unit with an investment
cost of $21 million, the overcompensation is $12,180,000 over the 20 year
recovery period. For a new black start unit with an investment of $21 million,
the overcompensation is $12,285,000 over the five year recovery period.

112 PJM’s recent filing to revise Schedule 6A includes a required commitment to provide black start service for the life of the unit. See FERC
Docket No. ER21-1635.

546

Section 10 Ancillary Services

Table 10-55 Lifetime recovery of black start units with old and updated CRF
Example
1
2
3
1
2
3
1
2
3
1
2
3

Old CRF Rate
0.125
0.125
0.125
0.146
0.146
0.146
0.198
0.198
0.198
0.363
0.363
0.363

UpdatedCRF Rate
0.101
0.101
0.101
0.116
0.116
0.116
0.147
0.147
0.147
0.246
0.246
0.246

Project
Investment$9,000,000$15,000,000$21,000,000$9,000,000$15,000,000$21,000,000$9,000,000$15,000,000$21,000,000$9,000,000$15,000,000$21,000,000

Old CRF
Lifetime
Recovery$22,500,000$37,500,000$52,500,000$19,710,000$32,850,000$45,990,000$17,820,000$29,700,000$41,580,000$16,335,000$27,225,000$38,115,000

Updated CRF
Lifetime
Recovery$18,180,000$30,300,000$42,420,000$15,660,000$26,100,000$36,540,000$13,230,000$22,050,000$30,870,000$11,070,000$18,450,000$25,830,000

UpdatedLifetime
Difference$4,320,000$7,200,000$10,080,000$4,050,000$6,750,000$9,450,000$4,590,000$7,650,000$10,710,000$5,265,000$8,775,000$12,285,000

Table 10-56 shows the total excess payments to black start units that will
result if the CRF issue is not addressed. The table includes the excess payments
for units in service prior to the 2017 tax law change and excess payments
for units in service after the 2017 tax law change. For the pre 2017 units, theupdated CRF rates were changed to reflect only the change in the tax rate, andfor the post 2017 units, the updated CRF rates were changed to reflect boththe change in the tax rate and the change in the tax depreciation treatment.
Table 10-56 Lifetime difference of black start units with updated CRF
Years
Pre 2017 Units
Post 2017 Units
Total

Existing Annual
Revenue
Requirement Total$53,402,977$28,217,475$81,620,451

UpdatedAnnual Revenue
Requirement Total$46,637,692$19,902,490$66,540,182

Difference Per Year
Total
$6,765,285$8,314,985$15,080,269

UpdatedLifetime Difference
Total$38,078,930$58,811,154$96,890,084

For the future, the CRF should be updated and posted at least annually to reflectchanges in federal or state taxes, including depreciation treatment and tax
rates. The tariff should include an explicit statement of the formula and define
the components of the formula. Existing black start resources constructedprior to the new tax law and to which the new tax law depreciation rules did
not apply should use a CRF calculated using the depreciation rules applicable© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

to the investment in the resources, the current tax rate and the current interest
rate.

start service (unless they use direct current pumps). The MTSL is the amountof fuel at the bottom of a tank which cannot be recovered for use.

The MMU recommends that new CRF rates for black start units, incorporating
current tax code changes, be implemented immediately. The new CRF rates
should apply to all black start units, including those that are currently inservice and those not yet in service. The CRF rates for units going into service
since the change in the tax code should incorporate applicable changes todepreciation treatment and tax rates. The CRF rates for units constructed prior
to the new tax law and to which the new tax law depreciation rules did not
apply should incorporate only the applicable changes to the tax rate. The
black start units should be required to commit to providing black start service
for the life of the unit.

PJM has required that customers pay black start unit owners carrying cost
recovery for one hundred percent of the MTSL for tanks which are sharedwith units in the energy market. These tanks were sized to meet the needs ofthe generating units, which use significantly more fuel than the black start
units. In some instances the MTSL is greater than the total amount of fuelthat the black start unit needs to operate to meet its black start obligations.
When a black start diesel is added at the site of an oil fired generating unit,
the additional MTSL is zero.

On April 7, 2021, PJM filed with FERC to replace the CRF values with adescription of the components of the CRF formula.113 Rather than fix theinaccurate CRF values used for existing black units, PJM’s filing would makethe use of inaccurate values permanent. PJM should instead apply the filed
formula, including rebilling those units that have been overpaid. PJM should
include the CRF formula in the tariff in addition to the components of CRF sothat the tariff includes the complete filed rate. The MMU filed a protest to theApril 7th filing on April 28, 2021.114

NERC – CIP
Currently, no black start units have requested new or additional black start
NERC – CIP Capital Costs.115

Minimum Tank Suction Level (MTSL)

Figure 10-20 illustrates that the size of the oil tank does not change with theaddition of the black start unit. Figure 10-21 shows how the MTSL could be
proportionally divided between the generator and the black start unit. The
tank is 4,000,000 gallons with an MTSL of 800,000 gallons leaving 3,200,000
gallons of usable fuel. The black start unit running 16 hours using 12,000
gallons per hour would need a total of 192,000 gallons, or six percent of thetotal usable fuel. Assigning six percent of the MTSL (800,000 gallons) would
yield 48,000 gallons which could be assigned to the black start proportion for
the MTSL.
The MMU recommends that for oil tanks which are shared with otherresources that only a proportionate share of the MTSL be allocated for black
start units. The MMU further recommends that the PJM tariff be updated toclearly state how the MTSL will be calculated for black start units sharing oil
tanks. PJM has filed to correct the rules consistent with the Market Monitor’s
recommendation.116

Some units that participate in the PJM energy market have oil tanks. All oil
tanks at PJM units have a MTSL regardless of whether the units provide black
113 See Docket No. ER21-1635-000.
114 See Comments of the Independent Market Monitor for PJM, FERC Docket No. ER21-1635-000, which can be accessed at <http://www.
monitoringanalytics.com/filings/2021/‌IMM_Comments_Docket_No_ER21-1635_20210428.pdf>.
115 OATT Schedule 6A para. 21. “The Market Monitoring Unit shall include a Black Start Service summary in its annual State of the Market
report which will set forth a descriptive summary of the new or additional Black Start NERC-CIP Capital costs requested by Black Start
Units, and include a list of the types of capital costs requested and the overall cost of such capital improvements on an aggregate basis
such that no data is attributable to an individual Black Start Unit.”© 2021 Monitoring Analytics, LLC

116 See FERC Docket No. ER21-1635-000.

2021 Quarterly State of the Market Report for PJM: January through June 547

2021 Quarterly State of the Market Report for PJM: January through June

Figure 10-20 Oil tank MTSL not changed from addition of black start
generator

Figure 10-21 Oil tank black start MTSL portion
Tank Capacity: 4,000,000 gals

Minimum Tank Suction Level - Before Black Start
Usable Fuel – 3,200,000 galss

MTSL – 800,000 gals

Black Start MTSL Portion – 48,000 gals

Minimum Tank Suction Level - Shared

Reactive Power Service and Capability
Suppliers of reactive power are compensated separately for reactive power
service and reactive capability. Compensation for reactive power service
is determined based on real-time lost opportunity costs. Compensation forreactive capability is approved separately for each resource or resource groupby FERC per Schedule 2 of the OATT. Resources may obtain FERC approval
to recover a share of resources’ fixed costs by calculating a reactive revenue
requirement, the reactive capability rate, and to collect such rates from PJM
transmission customers.117
Any reactive service provided operationally that involves a MW reduction
outside of its normal operating range or a startup for reactive power will be
logged by PJM operators and paid uplift based on lost opportunity costs.

117 See “PJM Manual 27: Open Access Transmission Tariff Accounting,”§ 3.2 Reactive Supply and Voltage Control Credits, Rev. 93, (Aug. 31,
2020).

548

Section 10 Ancillary Services© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

Reactive Service, Reactive Supply and Voltage Control are provided
by generation and other sources of reactive power (such as static VAR
compensators and capacitor banks).118 PJM in its role as the independent
RTO and transmission provider determines the reactive capability it needsfrom all sources in order to reliably operate the grid. PJM, as part of its
Interconnection Agreement, requires that all resources over 20 MW be able
to operate at a power factor of 0.90 lagging to 0.95 leading throughout their
entire operating range. This requirement ensures that even under extreme
conditions every generator will be able to operate within the voltage schedule
assigned to them by PJM. Reactive power helps maintain appropriate voltages
on the transmission system and must be sourced locally.
Total reactive capability charges are the sum of FERC approved reactive
supply revenue requirements which are posted monthly on the PJM website.119
Zonal reactive supply revenue requirement charges are allocated monthly to
PJM customers proportionally to their zone and to any nonzone (i.e. outsideof the PJM Region) peak transmission use and daily average point to pointtransmission reservations.120 121
In 2016, FERC began to reexamine its policies on reactive compensation.122
Changes in the default capabilities of generators, disparities between nameplatevalues and tested values and questions about the way the allocation factors
have been calculated have called continued reliance on the AEP method into
question.123 The continued use of fleet rates rather than unit specific rates isalso an issue.

Recommended Market Approach to Reactive Costs
The best approach for recovering reactive capability costs is through markets
where markets are available as they are in PJM. The best approach forrecovering reactive capability costs in PJM is through the capacity market.
118 OATT Schedule 2.
119 See PJM. Markets & Operations: Billing, Settlements & Credit, “Reactive Revenue Requirements,”<http://www.pjm.com/~/media/marketsops/settlements/reactive-revenue-requirements-table-may-2016.ashx> (June 8, 2016).
120 OATT Schedule 2.
121 See “PJM Manual 27: Open Access Transmission Tariff Accounting,”§ 3.3 Reactive Supply and Voltage Control Charges, Rev. 93 (Aug. 31,
2020).
122 See Reactive Supply Compensation in Markets Operated by Regional Transmission Organizations and Independent System Operators,
Docket No. AD16-17-000 (March 17, 2016) (Notice of Workshop).
123 See 88 FERC ¶ 61,141 (1999).

© 2021 Monitoring Analytics, LLC

The capacity market already incorporates reactive costs and reactive revenues.
The treatment of reactive costs in the PJM market needs to be modified sothat the capacity market incorporates reactive costs and revenues in a more
efficient manner.
Reactive capability is an integral part of all generating units; no generating
unit is built without reactive capability.124 There is no reason that the fixed
costs of reactive capability either can be or should be separated from the total
fixed costs of a generating unit. There is no reason that reactive capability
should be compensated outside the markets when the units participate inorganized markets. Reactive capability is a precondition for participating inorganized markets. Resources must invest in the equipment needed to haveminimum reactive capability as a condition of receiving interconnection
service from PJM and other markets.125 The Commission has recently extended
the interconnection service requirement to have reactive capability to windand solar units, which had previously been exempt.126 Reactive capability
is a requirement for participating in organized markets and is therefore
appropriately treated as part of the gross cost of new entry in organizedmarkets.
The current FERC review provides an excellent opportunity to discard ananachronistic cost of service approach that has not been working well andthat is inconsistent with markets and is unnecessary in organized markets.
Increased reliance on markets for the recovery of reactive capability costs
would promote efficiency and consistency. Customers, market administratorsand regulators would be better served by a simpler and more effective
competition based approach. The MMU recommends that separate payments
for reactive capability be eliminated and the cost of reactive capability berecovered in the capacity market.
124 See Order No. 827, 155 FERC ¶ 61,277 at P 9 (2016) (“[T]he equipment needed for a wind generator to provide reactive power has
become more commercially available and less costly, such that the cost of installing equipment that is capable of providing reactive
power is comparable to the costs of a traditional generator.”).
125 See 18 CFR § 35.28(f)(1); Order No. 2003, FERC Stats. & Regs. ¶ 31,146, Appendix G (Large Generator Interconnection Agreement(LGIA)), order on reh’g, Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160, order on reh’g, Order No. 2003-B, FERC Stats. & Regs. ¶ 31,171(2004), order on reh’g, Order No. 2003-C, FERC Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom. Nat’l Ass’n of Regulatory Util. Comm’rs
v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008); Order No. 2006, FERC Stats. & Regs. ¶ 31,180, Attachment F(Small Generator Interconnection Agreement), order on reh’g, Order No. 2006-A, FERC Stats. & Regs. ¶ 31,196 (2005), order granting
clarification, Order No. 2006-B, FERC Stats. & Regs. ¶ 31,221 (2006).
126 Order No. 827, 155 FERC ¶ 61,277 (2016); see also 151 FERC ¶ 61,097 at P 28 (2015).

2021 Quarterly State of the Market Report for PJM: January through June 549

2021 Quarterly State of the Market Report for PJM: January through June

Improvements to Current Approach
Reactive compensation must be integrated into PJM’s competitive market
design. Reactive capability rates recover through cost of service rates exactly
the same investment that capacity markets price at market based rates.
If OATT Schedule 2 reactive capability payments are not eliminated, then the
MMU recommends, at a minimum, that steps be taken to ensure that payments
only go the generating units that specifically support PJM grid operations andare fully subject to PJM dispatch, are based on capability that PJM needs tomaintain system stability and do not constitute double recovery.
FERC has initiated a number of investigations into the basis for reactive rates,
and the MMU has intervened in and is participating in those proceedings.127
The only FERC proceeding that has provided an opportunity for the MMU
to raise its concerns at hearing has been Panda Stonewall LLC.128 The initialdecision issued in that case sidesteps the issues identified by the MMU, andthe error is repeated in the order on the initial decision.129 The MMU’s request
for rehearing is pending. These issues must be squarely addressed for PJM tohave an even minimally satisfactory market design related to compensating
investment in reactive capability that cannot be differentiated from investment
in capacity.

Power Factor Capped at PJM Determined Level of Need
Under the AEP method, units must establish their MVAR rating based on “thecapability of the generators to produce VARs.”130 Typically this has meantreliance on manufacturers’ specified nameplate power factor.131 More recently,
the Commission has, in the Wabash Orders, required that “reactive power
revenue requirement filings must include reactive power test reports.”132
Noting a difference between tested reactive MVAR ratings and nameplate
127 See e.g., FERC Dockets Nos. EL16-32, EL16-44, EL16-51, EL16-54, EL16-65, EL16-66, EL16-79, EL16-89, EL16-90, EL16-98, EL16-72, EL16100, EL16-103, EL16-118, EL16-1004, ER16-1456, ER16-2217, EL17-19, EL17-38, EL17-39, EL17-49, ER17-259 and ER17-801.
128 See Docket No. EL17-1821.
129 167 FERC ¶ 63,010 (2019), order on initial decision, 174 FERC ¶ 61,266 (2021).
130 AEP mimeo at 31.
131 See, e.g., id.
132 154 FERC ¶ 61,246 at P 28 (2016); see also 154 FERC ¶ 61,246 at P 29 (Wabash Orders).

550

Section 10 Ancillary Services

MVAR ratings, the Commission has, in a number of cases, set the issue of
MVAR rating degradation for hearing.133
The Commission has identified a significant issue. The MVAR rating has asignificant influence on the level of the requirements and should accuratelyreflect the MVAR capability actually available to maintain reliability. However,power ratings, whether based on nameplate or testing, do not establish MVAR
capability that is properly relevant to reactive capability rates in PJM. PJM
determines the level of reactive capability it needs in its role as the independent
RTO and transmission provider. Generation owners should not be permitted
through uncoordinated reactive capability rates to substitute their assessment
for PJM’s.
The most fundamental point about power factors is that PJM requires thatall generating units have a 0.90 power factor throughout their full operating
range in order to obtain interconnection service.134 There is no reason to pay
any provider of reactive capability based on a power factor exceeding the 0.90
power factor that PJM has determined is necessary.
The PJM required power factor value is the only value reasonably included
in reactive capability rates because that is what PJM has determined it needsfrom each generator. Generators should not be permitted to make investment
decisions that unnecessarily increase the cost of reactive capability. Individualowners have a conflict of interest concerning such decisions and are notauthorized under the OATT to change PJM’s determinations on the required
power factor.

Eligibility for Reactive Rates Under Schedule 2
Reactive capability rates should not be confused with compensation for
operating to provide reactive power at PJM’s direction. Reactive service is
supplied during normal operation as needed and directed by PJM dispatchers.
Most reactive service is provided with no impact to operational dispatch.
133 See, e.g., 154 FERC ¶ 61,087 at P 10 (2016) (“The Informational Filing contains information that raises concerns about the justness andreasonableness of Ironwood’s reactive power rate, including, but not limited to, the degradation of the Facility’s current MVAR capability
as compared with the MVAR capability that was originally used to calculate the revenue requirement for Reactive Service included in
Ironwood’s reactive power rate.”).
134 See supra footnote 27.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

When a need for reactive service requires that a unit’s MW output be reduced
outside of its normal operational range, or when a unit is started to provide
reactive power, it is logged by PJM dispatchers and will be paid reactive
service credits in the zone or zones where the reactive service was provided.
A generating facility is not eligible for reactive payments when it is notconnected directly to the PJM system and therefore does not provide reactive
capability to PJM under Schedule 2, and should not receive payments fora service that it does not and cannot provide. In a number of cases now
pending, the Market Monitor has challenged the eligibility of resources filingunder OATT Schedule 2 because they are interconnected to facilities that PJM
does not monitor and does not rely on to provide reactive capability.135
In another case, the issues of whether a battery incurs any incremental costs
to provide reactive and the applicability of the AEP method to a battery havebeen raised.136
The issue of eligibility is significant because the number of facilities
interconnecting at points that are not on the PJM system (off system) is
expected to increase. Such facilities do not contribute reactive capability to
PJM, and based on anticipated power factor levels and the way the AEP
method has been applied for calculating reactive rates under Schedule 2, such
facilities would receive significantly larger payments per MW than the facilities
that do provide reactive power capability useful to PJM.137 These payments
are for services not provided, but also would distort the PJM capacity market
by paying a large share of the fixed costs of such facilities as reactive. Thisapproach is a faulty and inefficient and noncompetitive market design.

Offset Cap on Reactive Capability Rates
In addition to effectively capping the appropriate level of the power factor,
the PJM market rules also effectively cap the appropriate level of reactive
capability rates overall.
135 See, e.g., FERC Docket Nos. ER21-2091, ER21-936, ER21-737, ER20-1863 & ER20-1851.
136 See FERC Docket No. ER21-864.
137 See American Electric Power Service Corp., 80 FERC ¶ 63,006 (1997), aff’d, 88 FERC ¶ 61,141 (1999).

© 2021 Monitoring Analytics, LLC

Under the current capacity market rules, the gross costs of the entire plant,
including any reactive costs, are included in the gross Cost of New Entry(CONE) and the revenues from reactive service capability rates are an offset to
the gross CONE. The result is that, conceptually, the cost of reactive includedin the offset is not part of net CONE.138 This is logically consistent with theseparate collection of reactive costs through a cost of service rate in that
there is no double counting if the revenue offset is done accurately. Under
this approach there is a separate collection of reactive capability costs. Thisapproach also requires that any capacity resource calculating unit specific net
revenues must include the cost of service reactive revenues in the calculation.
The revenue offset is defined as a fixed number in the OATT and is currently
set equal at $2,199/MW-year.139 This is the average annual reactive capability
revenue for combustion turbines from 2005 through 2007, based on the actual
costs reported to the Commission in reactive service filings.
The PJM market rules explicitly account for recovery of reactive revenues of$2,199 per MW-year. Reactive capability rates up to that level do not result indouble recovery. Reactive capability rates above that level do result in double
recovery because costs that would support a rate exceeding $2,199 per MWyear continue to be recoverable in the PJM Capacity Market.
The $2,199 offset is a simple rule that established a just and reasonable
reconciliation of different regulatory approaches in the same market design.
The offset assumes a defined level of revenues are received under cost ofservice rates and nets them from the parameters used in the capacity market.
Those parameters define the operation of the market so that just and reasonablecapacity prices are established. Reactive rates cannot be just and reasonable ifthey do not account for the market design in which PJM units operate.
To the extent that the Commission decides that PJM and other markets should
continue to rely on a cost of service method to compensate reactive capability,
the rules should be modified to improve the accuracy of the calculations ofreactive capability cost. Double compensation should not be permitted as a
138 See OATT Attachment DD § 5.10(a)(iv).
139 See OATT Attachment DD § 5.10(a)(v).

2021 Quarterly State of the Market Report for PJM: January through June 551

2021 Quarterly State of the Market Report for PJM: January through June

combined result of market based capacity prices and cost of service rates. No
recovery above the $2,199 per MW-year level should be provided as directcompensation for reactive capability under the current approach.
Reactive capability rate schedules must be accurate, and they must also
coordinate properly with the PJM market rules. Revenues received for reactive
capability are revenues for ancillary services that should be netted against
avoidable costs whenever avoidable cost rate offers are submitted in RPM
capacity market auctions.140 Participants have not been properly including
reactive revenues in capacity market offers, and the MMU has notified
participants of its compliance concerns. The identification of revenues forreactive capability on a unit specific basis is necessary for the calculationof accurate avoidable cost rate offers and is needed to avoid disputes that
could interfere with the orderly administration of RPM auctions. The MMU
has sought to address these issues through participation in proceedings at
FERC concerning reactive capability rates for PJM units.141

Losses
The estimated capability costs also include estimated heating losses relative
to MVAR output.142 Heating losses are variable costs and not fixed costs andshould not be included in the definition of reactive capability costs.143 Heating
losses can be accurately calculated for each hour of operation if each unit had
an accurate, recent D-curve test. Heating losses are variable costs and should
not be included in the cost of reactive capability. The production of reactive
power slightly reduces the MWh output of the generator as the generator
follows its D-curve. The value of this heating loss component is generally
estimated based on estimated operation and associated estimated losses andestimated market prices, treated as a fixed cost, and included in the cost ofreactive capability. Losses are minimal and occur during normal operations
and should not be treated as a fixed cost. Losses can be better and more
140 See OATT Attachment DD §§ 6.4, 6.8(d).
141 The MMUs has to date participated in nearly 150 reactive matters. See, e.g., FERC Dockets Nos. EL16-44 et al.; ER16-1456; EL16-57 et al.;EL16-51 et al.; ER16-1004; EL16-32; EL16-72; EL16-66; EL16-65; EL16-54; EL16-90 et al.; EL16-103 et al.; EL16-89 et al.; EL16-98 et al.;EL16-79 et al.; EL16-80 et al.; EL16-81 et al.; EL16-82 et al.; EL16-83 et al.; ER16-2217 et al.; EL17-19; EL16-118.
142 See, e.g., id. at P 10 n12, citing PPL Energy Plus, LLC, Letter Order, Docket No. ER08-1462-000 (Sept. 24, 2008); 125 FERC ¶ 61,280 at P
35 (2008).
143 See Transcript, Reactive Supply Compensation in Markets Operated by Regional Transmission System Operators Workshop, AD16-17000 (June 30, 2016) at 26:21–27:23.

552

Section 10 Ancillary Services

accurately accounted for as a variable cost based on actual unit operations
and market conditions.

Fleet Rates
Cost of service rates are established under Schedule 2 of the OATT and may
cover rates for single units or a fleet of units.144 Until the Commission tookcorrective action, fleet rates remained in place in PJM even when the actual
units in the fleet changed as a result of unit retirements or sales of units.145 New
rules require unit owners to give notice of fleet changes in an informational
filing or to file a new rate based on the remaining units, but do not yet require
unit specific reactive rates.146
Fleet rates create confusion about what revenue is properly attributable to each
unit in the fleet. Reactive rates should be stated separately for each unit, even
if multiple plants or units are considered in a single proceeding. The MMU filedwith the Commission to require unit specific rates when PJM proposed limited
reforms that could have corrected the oversight and compliance problems
posed by fleet rates.147 But PJM rules require fleet owners only to submit
informational filings when a reactive unit is transferred or deactivated.148 The
current rules do not require a rate filing, which would place the burden of
proof on the company and allow for cost review.149
The MMU also raised issues related to fleet rates in a settlement establishing afleet rate without specifying the actual portion of the fleet rate attributable toeach unit in the fleet.150 The approach could prevent or inhibit an appropriate
adjustment of the fleet requirement if a unit receiving an unspecified portionof such requirement is deactivated or transferred because third parties without
access to cost information would bear the burden of proof in a complaint
proceeding.151 The MMU also explained that the approach makes it impossible
to calculate cost-based offers from such units in the PJM Capacity Market. The
144 See, e.g., OATT Schedule 2; 114 FERC ¶ 61,318 (2006).
145 See 149 FERC ¶ 61,132 (2014); 151 FERC ¶ 61,224 (2015); OATT Schedule 2.
146 Id.
147 151 FERC ¶ 61,224 at P 29 (2015).
148 OATT Schedule 2.
149 Id.
150 See Letter Opposing Settlement, Docket No ER06-554 et al. (June 14, 2017).
151 Id.

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

settlement was approved over the MMU’s objection on the grounds that the
tariff does not prohibit fleet rates.152
The MMU recommends that fleet rates be eliminated and that compensation be
based on unit specific costs and rates and that rates be appropriately reduced
when units with reactive payments retire.

Reactive Costs
In the first six months of 2021, total reactive charges were $183.2 million,
a 4.81 percent increase from the $174.8 million for first six months of2020. Reactive capability charges increased from $174.6 million in the firstsix months of 2020 to $182.5 million in 2021 and reactive service charges
increased from $0.2 million in the first six months of 2020 to $0.7 million
in 2021. All $0.7 million in 2021 were paid for reactive service provided by 9units in 335 hours.
Table 10-57 shows reactive service charges in the first six months of 2020 and
2021, reactive capability charges and total charges. Reactive service charges
show charges to each zone for reactive service provided and not credits toplants in each zone. Reactive capability charges show charges to each zone
for reactive capability.

Table 10-57 Reactive service charges and reactive capability charges by zone:
January through June, 2020 and 2021

Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DOM
DPL
DUQ
EKPC
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
(Imp/Exp/Wheels)
Total

Jan-Jun 2020
Reactive
Reactive
Service
Capability
Charges
Charges Total Charges$0$2,148,065$2,148,065$0 $24,503,533 $24,503,533$0$8,720,081$8,720,081$0 $12,308,365 $12,308,365$0$3,475,593$3,475,593$0 $19,237,746 $19,237,746$0$1,409,138$1,409,138$0$4,773,572$4,773,572$0$20,080,331$20,080,331$10,508$5,083,932$5,094,440$0$285,574$285,574$16,326$1,091,005$1,107,331$171,332$3,729,705$3,901,036$4,631$3,069,238$3,073,869
$0
$0
$0
$0
$10,522,743$10,522,743$0$8,267,011$8,267,011$0$5,572,369$5,572,369$0 $17,538,674 $17,538,674$0$13,946,991$13,946,991
$0
$0
$0
$0
$8,825,232$8,825,232$202,796 $174,588,899 $174,791,695

Jan-Jun 2021
Reactive
Reactive
Service
Capability
Charges
Charges Total Charges$0$2,151,268$2,151,268$21,582 $24,952,838 $24,974,420$0$9,828,354$9,828,354$0 $12,690,936 $12,690,936$0$3,327,671$3,327,671$0$20,801,101$20,801,101$0$1,411,239$1,411,239$0$4,780,690$4,780,690$0 $23,324,289 $23,324,289$0$5,321,662$5,321,662$0$286,000$286,000$0$1,092,632$1,092,632$0$3,777,383$3,777,383$8,696$3,073,814$3,082,511
$0
$0
$0
$0
$10,489,676$10,489,676$0$8,605,617$8,605,617$0$5,135,938$5,135,938$705,618 $18,494,088$19,199,705$0$13,951,191$13,951,191
$0
$0
$0
$0
$8,963,378$8,963,378$735,896 $182,459,765 $183,195,661

Table 10-58 shows the units which have received reactive service credits forthe first six months of 2021.
Table 10-58 Reactive service credits by plant: January through June, 2021

152 162 FERC ¶ 61,029 (2018).

© 2021 Monitoring Analytics, LLC

Zone
AEP
AEP
AEP
METED
PPL
PPL
PPL
PPL
PPL
Total

Jan-Jun 2021
Plant
AEP CEREDO 1 CT
AEP CEREDO 4 CT
AEP CLINCH RIVER 2 F
ME MOUNTAIN 1 CT
PL HARWOOD 1-2 CT
PL HAZELTON 1 CT
PL HAZELTON 2 CT
PL HAZELTON 3 CT
PL HAZELTON 4 CT

Reactive Service Credits$1,565$1,340$18,677$8,696$16,031$65,744$265,634$197,731$160,478$735,897

2021 Quarterly State of the Market Report for PJM: January through June 553

2021 Quarterly State of the Market Report for PJM: January through June

Frequency Response
On February 15, 2018, the Commission issued Order No. 842, which modified
the pro forma large and small generator interconnection agreements andprocedures to require newly interconnecting generating facilities, bothsynchronous and nonsynchronous, to include equipment for primary frequency
response capability as a condition to receive interconnection service.153 Suchequipment must include a governor or equivalent controls with the capabilityof operating at a maximum 5 percent droop and ±0.036 Hz deadband (or theequivalent or better).
PJM filed revisions in compliance with Order No. 842 that substantively
incorporated the pro forma agreements into its market rules.154
The MMU recommends that the same capability be required of both newand existing resources. The MMU agrees with Order No. 842 that RTOs not
be required to provide additional compensation specifically for frequency
response. The current PJM market design provides compensation for all
capacity costs, including these, in the capacity market. The current market
design provides compensation, through heat rate adjusted energy offers,
for any costs associated with providing frequency response. Because thePJM market design already compensates resources for frequency response
capability and any costs associated with providing frequency response, any
separate filings submitted on behalf of resources for compensation under
section 205 of the Federal Power Act should be rejected as double recovery.

Frequency Control Definition
There are four distinct types of frequency control, distinguished by response
timeframe and operational nature: Inertial Response, Primary Frequency
Response, Secondary Frequency Control, and Tertiary Frequency Control.

• Inertial Response. Inertial response to frequency excursion is the naturalresistance of rotating mass turbine generators to change in their stored
kinetic energy. This response is immediate and resists short term changes

153 157 FERC ¶ 61,122 (2016).
154 See 164 FERC ¶ 61,224 (2018).

554

Section 10 Ancillary Services

to ACE from the instant of the disturbance up to twenty seconds after the
disturbance.

• Primary Frequency Response. Primary frequency response is a response to a

disturbance based on a local detection of frequency and local operational
control settings. Primary frequency response begins within a few seconds
and extends up to a minute. The purpose of primary frequency response
is to arrest and stabilize the system until other measures (secondary andtertiary frequency response) become active.

• Secondary Frequency Control. Secondary frequency control is called

regulation. In PJM it begins taking effect within 10 to 15 seconds andcan maintain itself for several minutes up to an hour in some cases.
It is controlled by PJM which detects the grid frequency, calculates a
counterbalancing signal, and transmits that signal to all regulating
resources.

• Tertiary Frequency Control. Tertiary frequency control and imbalance
control lasting 10 minutes to an hour is available in PJM as Primary
Reserve. It is initiated by an all call from the PJM control center.

VACAR Reserve Sharing Agreement
The VACAR Reserve Sharing Agreement (VRSA) is a combination of agreements
among the entities in the VACAR subregion including Dominion.155 VACAR isa subregion of the SERC Reliability Corporation (SERC) region. The agreement
remained in effect in 2020. The agreement requires that each entity maintain
primary reserves to meet the VACAR contingency reserve commitment(VACAR reserves) and deploy such reserves in the case of an emergency (e.g.
loss of a unit in VACAR).156 Dominion is the only party to the VRSA that is
also a transmission owner and a generation owner in PJM. The VRSA is not a
public agreement. PJM is not a party to the VRSA. However, as the reliability
coordinator for Dominion Virginia Power, PJM is responsible for scheduling
Dominion’s required reserves in the SERC region as described in the PJM
manuals.157
155 VRSA entities: Dominion, Duke Energy Progress, Duke Energy Carolinas, South Carolina Electric & Gas Company, South Carolina PublicService Authority and Cube Hydro Carolinas.
156 See SERC Regional Criteria, Contingency Reserve Policy, NERC Reliability Standard BAL-002 at 10-11.
157 See PJM. “Manual 13: Emergency Operations,” Rev. 78 (Jan. 27, 2021).

© 2021 Monitoring Analytics, LLC

Section 10 Ancillary Services

PJM procures synchronized reserves and primary reserves for the PJM
region, including Dominion. The synchronized reserve and primary reserve
requirements are equal to the largest single contingency and 150 percentof the largest contingency. The requirement is procured separately for the
RTO and the MidAtlanic Dominion area (MAD) when the largest contingency
is located outside of MAD. All units in PJM that meet the synchronized or
primary reserve operating parameter requirements are eligible to meet thesynchronized and primary requirements as long as PJM does not deselectthem.

Recommendations
The Market Monitor recommends that the details of VACAR Reserve Sharing
Agreement (VRSA) be made public, including any responsibilities assigned to
PJM and including the amount of reserves that Dominion commits to meet its
obligations under the VRSA.
The Market Monitor recommends that the VRSA be terminated and, if
necessary, replaced by a reserve sharing agreement between PJM and VACAR
South, similar to agreements between PJM and other bordering areas.

PJM procures Day-Ahead Scheduling Reserves (DASR) for the PJM region,
including Dominion, as Secondary Reserves. The DASR requirement iscalculated daily and is equal to the peak load forecast for the ReliabilityFirst
region (RFC) and EKPC times the sum of the forced outage rate and the load
forecast error, plus Dominion’s share of the VACAR contingency reserve
commitment. All units in PJM that meet the DASR operating parameterrequirements are eligible to meet the DASR requirement.158 There is norequirement that a specific amount of DASR be located in Dominion. Equation
10-1 shows the DASR requirement calculation.159
Equation 10-1: DASR Requirement Formula

IssuesPJM is expected to implement its ORDC proposal on May 1, 2022. Under
the ORDC, it will not be possible for Dominion to hold reserves to meet its
obligations under the VRSA without double counting the reserves Dominion
has in PJM or withholding such reserves from PJM. Under the ORDC proposal,
it will not be possible for Dominion to meet both the VRSA and the PJM
reserve rules.

158 DASR can be provided by units that do not clear the day-ahead energy market and can start within 30 minutes or by units that clear the
day-ahead energy market and can ramp up within 30 minutes.
159 During cold weather alerts and hot weather alerts, the DASR requirement is increased to procure additional reserves.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 555

2021 Quarterly State of the Market Report for PJM: January through June

556

Section 10 Ancillary Services© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Congestion and Marginal Losses
When there are binding transmission constraints and locational pricedifferences, load pays more for energy than generation is paid to producethat energy.1 The difference is congestion.2 As a result, congestion belongs toload and should be returned to load. Congestion is not the difference in CLMP
between nodes. Congestion is not the billing line item labeled congestion.3
The locational marginal price (LMP) is the incremental price of energy at a bus.
The LMP at a bus can be divided into three components: the system marginal
price (SMP) or energy component, the congestion component (CLMP), and themarginal loss component (MLMP). SMP, MLMP and CLMP are the simultaneous
products of the least cost, security constrained dispatch of system resources tomeet system load and the use of a load-weighted reference bus. The relativevalues of SMP and CLMP are arbitrary and depend on the reference bus.
SMP is defined as the incremental price of energy for the system, given thecurrent dispatch, at the load-weighted reference bus, or LMP net of losses andcongestion. SMP is the LMP at the load-weighted reference bus. The loadweighted reference bus is not a fixed location but varies with the distributionof load at system load buses. For SMP, energy means the component of LMP
not associated with a binding transmission constraint. All other locational
prices that result from the least cost, security constrained market solution are
higher or lower than this reference point price (SMP) as a result of binding
constraints. The reference bus is a point of reference. For a given market
solution, changing the reference bus does not change the LMP for any node on
the system, but changes only the elements of the nodal prices that are positiveor negative due to the binding constraints in that solution. CLMP is definedas the incremental price of meeting load at each bus when a transmission
constraint is binding, based on the shadow price associated with the relief ofa binding transmission constraint in the security constrained optimization.
(There can be multiple binding transmission constraints.) CLMPs are positiveor negative depending on location relative to binding constraints and relative
to the load-weighted reference bus. In an unconstrained system CLMPs will be
1 Load is generically referred to as withdrawals and generation is generically referred to as injections, unless specified otherwise.
2 The difference in losses is not part of congestion.
3 PJM billing examples can be found in 2020 State of the Market Report for PJM, Appendix F: Congestion and Marginal Losses.

© 2021 Monitoring Analytics, LLC

zero. This means that CLMP at a bus is not congestion. The difference between
CLMPs at buses is not congestion, it is just the absolute LMP difference between
the two buses caused by transmission constraints. CLMP is the portion of the
LMP at a bus that indicates whether the LMP at that bus is higher or lower
than the marginal price of energy SMP at the selected reference bus due tobinding transmission constraints. The relative values of SMP and CLMP arearbitrary and depend on the reference bus.
MLMP is defined as the incremental price of losses at a bus, based on marginalloss factors in the security constrained optimization. Losses refer to energy
lost to physical resistance in the transmission network as power is moved
from generation to load.
Total losses refer to total system wide transmission losses as a result ofmoving power from injections to withdrawals on the system. Marginal losses
are the incremental change in system losses caused by changes in load andgeneration.
Congestion is neither good nor bad, but is a direct measure of the extent
to which there are multiple marginal generating units with different offers
dispatched to serve load as a result of transmission constraints. Congestion
occurs when available, least-cost energy cannot be delivered to all load because
transmission facilities are not adequate to deliver that energy to one or moreareas, and higher cost units in the constrained area(s) must be dispatched tomeet the load.4 The result is that the price of energy in the constrained area(s)is higher than in the unconstrained area. Load in the constrained area pays the
single higher price for all the energy used, including energy from low cost andenergy from high cost generation, while generators are each paid the priceat their individual bus. Congestion is the difference between what load pays
based on the single higher price at load buses and what generators receive
based on the lower prices at the individual generator buses due to bindingtransmission constraints.
4 This is referred to as dispatching units out of economic merit order. Economic merit order is the order of all generator offers from lowest
to highest cost. Congestion occurs when loadings on transmission facilities mean the next unit in merit order cannot be used and ahigher cost unit must be used in its place. Dispatch within the constrained area follows merit order for the units available to relieve theconstraint.

2021 Quarterly State of the Market Report for PJM: January through June 557

2021 Quarterly State of the Market Report for PJM: January through June

The energy, marginal losses and congestion metrics must be interpreted
carefully.
In PJM accounting, the term total congestion refers to net implicit CLMP
charges plus net explicit CLMP charges plus net inadvertent CLMP charges.
The net implicit CLMP charges are the implicit withdrawal CLMP charges less
implicit injection CLMP credits.
As with congestion, total system energy costs are more precisely termed net
system energy costs and total marginal loss costs are more precisely termed
net marginal loss costs. Ignoring interchange, total generation MWh must be
greater than total load MWh in any hour in order to provide for losses. Since
the hourly integrated energy component of LMP is the same for every bus
within every hour, the net energy bill is negative (ignoring net interchange),with more generation credits than load payments in every hour.5
While PJM accounting focuses on CLMPs, the individual CLMP values atany bus are irrelevant to the calculation of congestion, as CLMPs are just an
artificial deconstruction of LMP based on a selected reference bus. Holding
aside the marginal loss component of LMP, differences in the LMPs arecaused by binding constraints in the least cost security constrained dispatch
market solution and total congestion is the net surplus revenue that remains
after all sources and sinks are credited or charged their LMPs. Changing thecomponents of LMP by electing a different reference bus does not change the
LMPs or the difference between LMPs for a given market solution, it merely
changes the components of the LMP.
Local congestion is the congestion paid by load at a specific bus or set of buses
and is calculated on a constraint specific basis. For a given market solution, achange in the elected reference bus does not change the LMP at any bus anddoes not change total congestion paid by load and does not change the local
congestion paid by load at a specific location. Holding aside the marginalloss component of LMP, local congestion is the sum of the total LMP charges
to load at the defined set of buses minus the sum of the total LMP credits

received by all generation that supplied that load, given the set of all bindingtransmission constraints, regardless of location. Local congestion reflects
the underlying characteristics of the complete power system as it affects thedefined area, including the nature and capability of transmission facilities,
the offers and geographic distribution of generation facilities, the level andgeographic distribution of incremental bids and offers and the geographic
and temporal distribution of load. Local congestion fully reflects the least
cost security constrained system solution and the LMPs that result from thatsolution.

Overview
Congestion Cost

• Total Congestion. Total congestion costs increased by $174.2 million

or 96.9 percent, from $179.8 million in the first six months of 2020 to$354.0 million in the first six months of 2021.

• Day-Ahead Congestion. Day-ahead congestion costs increased by $265.3

million or 112.2 percent, from $236.4 million in the first six months of2020 to $501.7 million in the first six months of 2021.

• Balancing Congestion. Negative balancing congestion costs increased

by $91.1 million, from -$56.6 million in the first six months of 2020
to -$147.7 million in the first six months of 2021. Negative balancing
explicit charges increased by $23.8 million, from -$37.0 million in thefirst six months of 2020 to -$60.8 million in the first six months of 2021.

• Real-Time Congestion. Real-time congestion costs increased by $403.9
million, from $239.9 million in the first six months of 2020 to $643.8
million in the first six months of 2021.

• Monthly Congestion. Monthly total congestion costs in the first six monthsof 2021 ranged from $29.1 million in January to $94.0 million in May.

• Geographic Differences in CLMP. Differences in CLMP among eastern,southern and western control zones in PJM were primarily a result ofcongestion on the Bagley - Raphael Road Line, the Three Mile Island

5 The total congestion and marginal losses for the first six months of 2021 were calculated as of July 10, 2021, and are subject to change,
based on continued PJM billing updates.

558

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses•

Transformer, the Harwood - Susquehanna Line, the Pleasant View –Ashburn Line and the Cumberland – Juniata Line.
Congestion Frequency. Congestion frequency continued to be significantly
higher in the day-ahead energy market than in the real-time energy
market in the first six months of 2021. The number of congestion event
hours in the day-ahead energy market was about three times the numberof congestion event hours in the real-time energy market.

• Total Marginal Loss Costs. Total marginal loss costs increased by $182.5

million or 94.3 percent, from $193.4 million in the first six months of2020 to $375.9 million in the first six months of 2021. The loss MWh in
PJM increased by 685.0 GWh or 10.1 percent, from 6,758.9 GWh in thefirst six months of 2020 to 7,443.9 GWh in the first six months of 2021.
The loss component of real-time LMP in the first six months of 2021 was$0.02, compared to $0.01 in the first six months of 2020.

Day-ahead congestion frequency decreased by 16.9 percent from 35,292
congestion event hours in the first six months of 2020 to 29,311 congestion
event hours in the first six months of 2021.

• Day-Ahead Marginal Loss Costs. Day-ahead marginal loss costs increased

Real-time congestion frequency increased by 3.6 percent from 10,829
congestion event hours in the first six months of 2020 to 11,216 congestion
event hours in the first six months of 2021.

• Balancing Marginal Loss Costs. Negative balancing marginal loss costs• Congested Facilities. The monthly average of daily day-ahead congestion

event hours decreased in November 2020 as a result of decreased
UTC activity due to a FERC order issued effective November 1, 2020,
directing PJM to charge uplift to up to congestion transactions.6 Dayahead, congestion event hours decreased on all types of facilities except
flowgates.

•

Marginal Loss Cost

The Bagley - Raphael Road Line was the largest contributor to congestion
costs in the first six months of 2021. With $20.9 million in total congestion
costs, it accounted for 5.9 percent of the total PJM congestion costs in thefirst six months of 2021.
CT Price Setting Logic and Closed Loop Interface Related Congestion. CT
Price Setting Logic caused -$0.2 million of day-ahead congestion in thefirst six months of 2021 and -$5.9 million of balancing congestion in thefirst six months of 2021. None of the closed loop interfaces was binding
in the first six months of 2021 or 2020.

• Zonal Congestion. AEP had the highest zonal congestion costs among

all control zones in the first six months of 2021. AEP had $61.3 million
in zonal congestion costs, comprised of $83.4 million in day-aheadcongestion costs and -$22.2 million in balancing congestion costs.

by $175.0 million or 79.8 percent, from $219.4 million in the first six
months of 2020 to $394.4 million in the first six months of 2021.
decreased by $7.5 million or 28.9 percent, from -$25.9 million in the firstsix months of 2020 to -$18.4 million in the first six months of 2021.

• Total Marginal Loss Surplus. The total marginal loss surplus increased by$74.4 million or 124.7 percent, from $59.7 million in the first six monthsof 2020, to $134.0 million in the first six months of 2021.

• Monthly Total Marginal Loss Costs. Monthly total marginal loss costs inthe first six months of 2021 ranged from $42.5 million in April to $102.7
million in February.

System Energy Cost

• Total System Energy Costs. Total system energy costs decreased by $106.8
million or 79.7 percent, from -$133.9 million in the first six months of2020 to -$240.7 million in the first six months of 2021.

• Day-Ahead System Energy Costs. Day-ahead system energy costs decreased
by $97.4 million or 55.5 percent, from -$175.6 million in the first six
months of 2020 to -$273.0 million in the first six months of 2021.

• Balancing System Energy Costs. Balancing system energy costs decreased

by $9.7 million or 23.6 percent, from $41.2 million in the first six monthsof 2020 to $31.4 million in the first six months of 2021.

6 172 FERC ¶ 61,046 (2020).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 559

2021 Quarterly State of the Market Report for PJM: January through June

• Monthly Total System Energy Costs. Monthly total system energy costs inthe first six months of 2021 ranged from -$63.0 million in February to-$28.5 million in April.

Conclusion
Congestion is defined as the total payments by load in excess of the total
payments to generation, excluding marginal losses. The level and distributionof congestion reflects the underlying characteristics of the power system,
including the nature and capability of transmission facilities, the offers andgeographic distribution of generation facilities, the level and geographic
distribution of incremental bids and offers and the geographic and temporal
distribution of load.
Total congestion costs increased by $174.2 million or 96.9 percent, from
$179.8 million in the first six months of 2020 to $354.0 million in the first six
months of 2021. The total day-ahead congestion costs and negative balancing
congestion costs increased significantly compared to the first six monthsof 2020. This was the combined result of higher demand and higher prices,cold weather in February of 2021, CT pricing logic, and transmission facility
outages in March and May.
The monthly total congestion costs ranged from $29.1 million in January to$94.0 million in May in the first six months of 2021.
The current ARR/FTR design does not serve as an efficient way to ensurethat load receives the rights to all congestion revenues. The congestion
offset for the 2020/2021 planning period was 46.2 percent. The cumulative
offset of congestion by ARRs for the 2011/2012 planning period through the2020/2021 planning period, using the rules effective for each planning period,
was 73.7 percent. Load has been underpaid by $2.4 billion from the 2011/2012
planning period through the 2020/2021 planning period.

IssuesClosed Loop Interfaces and CT Pricing Logic
PJM uses closed loop interfaces and CT pricing logic to force otherwise
uneconomic resources to be marginal and set price in the day-ahead or
real-time market solution. PJM uses CT pricing logic to create an artificial
constraint with a variable flow limit, paired with an artificial override of theinflexible resource’s economic minimum, to make the resource marginal in
PJM’s LMP security constrained pricing logic.
Through the assumption of artificial flexibility of the affected unit andartificially creating a constraint for which the otherwise inflexible resource
can be marginal, PJM’s use of CT pricing logic attempts to force the affectedresource bus LMP to match the marginal offer of the resource. PJM does
this by adjusting the constraint limit based on the output of the resource.
Sometimes the constraint limit does not match the flows on the constraint,
and the constraint violates instead of binding, resulting in prices set by thetransmission constraint penalty factor. In the case of a closed loop interface,
all buses within the interface are modeled with a distribution factor (dfax) of
1.0 to the constraint and therefore with the same constraint related congestion
component of price at the marginal resource’s bus. In the CT pricing logic case,the constraint affects the CLMP of downstream (constrained side) buses inproportion to their dfax to that constraint.7 One objective of making inflexible
resources marginal is to artificially minimize the uplift costs associated with
the inflexible resources that PJM commits for system security reasons.
The use of closed loop interfaces and CT pricing logic can be a source ofmodeling differences between the day-ahead and real-time markets. Whenclosed loop interfaces and CT pricing logic are not included in the day-aheadmarket in exactly the same way as in the real-time market, including specificconstraints and limits, the differences between the day-ahead and real-time
market model will result in positive or negative balancing congestion.

7 The constrained side means the higher priced side with a positive CLMP created by the constraint.

560

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Failure to model the same constraints in the day-ahead and real-time markets
results in pricing and congestion settlement differences between the dayahead and real-time market. Any modeling differences create false arbitrage
opportunities for virtual bids and contribute to negative balancing congestion.
Use of closed loop interfaces and CT price setting logic requires manipulationof the economic dispatch model. Closed loop interfaces and CT price setting
logic force higher cost inflexible units to be marginal. Unlike constraints that
restrict the use of lower cost resources in the system solution, the closed loop
interface and CT price setting logic constraints are forcing the use of higher
cost resources. The sign of the shadow price of this artificial constraint in
the optimization solution, unlike normal security constraints in a least costdispatch optimization, is therefore positive because relaxing this constraint
will cause system costs to go up, not down. Increasing the limit (relaxing)
for a closed loop interface or CT price setting logic constraint requires anincrease in the output from the high cost unit from within the artificiallyconstrained area, and a decrease in output from low price generation fromoutside the artificially constrained area. This means that increasing the limitof a closed loop interface or CT price setting logic constraint causes a netincrease in incremental cost for any increase in the flow limit of the constraint
and a positive, rather than the usual negative, shadow price for the modeledtransmission constraint.
The nature of the closed loop interface or CT price setting logic constraint
is that more power is produced in the artificial closed loop or constrained
area than would result without the closed loop. This means that there are
more high CLMP generation credits than high CLMP load charges associatedwith the constrained area within the closed loop interface or CT price setting
logic constraint. The rest of the system receives power from the closed loop/
constrained area, the lower cost generators outside the closed loop/constrained
area are backed down and prices are lower outside the loop than they would
have been without the closed loop. While all of the generation within theartificially constrained area is paid the higher CLMP in the form of generationcredits, a smaller amount of load (in some cases no load) pays this higher
CLMP in the form of load charges within the loop. The residual energy is© 2021 Monitoring Analytics, LLC

delivered and paid for at a lower CLMP outside the closed loop/constrained
area. The result is that PJM pays out more to generators in the closed loop
than it collects from load. The result of using closed loops and CT price setting
logic is that uneconomic generation costs that would otherwise be collected
as uplift are being realized as negative congestion. In the day-ahead market
this reduces the total congestion dollars that are available to FTR holders. In
the balancing market these costs are allocated directly to load as negativebalancing rather than to deviations as uplift charges.

Balancing Congestion Cost Calculation Logic Change
Effective April 1, 2018, PJM made a significant change to the calculation andallocation of balancing congestion costs.8
Prior to April 1, 2018, balancing implicit CLMP charges calculated at thezonal and aggregate level were determined by bus specific deviations between
day-ahead and real-time MWh priced at the bus specific congestion price inthe real-time energy market.
As of April 1, 2018, at the time of the introduction of five minute settlements,
PJM modified the calculation so that zonal and aggregate balancing implicit
CLMP charges are determined by netting the bus specific hourly deviations
across every bus in a zone or subzonal aggregate and pricing the resulting
deviation in zonal or aggregate total deviations at the zonal or aggregate
congestion price in the real-time energy market. As a result, the allocation ofbalancing implicit congestion was reduced for MW deviations associated withload and virtual bids that settle at zones and aggregates.
Another result of the change in rules was to increase negative balancing
charges billed to load on a load ratio basis. While total load deviations andassociated balancing charges at load aggregates were reduced by netting,the rules for determining balancing CLMP credits and charges to all otherbalancing MW deviations at all other bus or aggregates did not change.
This means that the change in rules resulted in a decrease in total balancing
implicit charges while having no effect on the calculation of total balancing
8 See PJM, “Manual 28: Operating Agreement Accounting,” Rev. 84 (Dec.17, 2020).

2021 Quarterly State of the Market Report for PJM: January through June 561

2021 Quarterly State of the Market Report for PJM: January through June

implicit credits. The net result has been an increase in negative balancing
congestion costs, which is the difference between balancing CLMP charges
from deviations at aggregates and zones (reduced due to the rule change) andbus specific balancing CLMP credits (not affected by the rule change). This hascaused an increase in total negative balancing charges.
The netting of zonal and aggregate deviations decreased the allocation ofbalancing charges to load deviations and increased total negative balancing
congestion. Negative balancing congestion is assigned to load and exports on
a load ratio share basis as the result of a FERC order.
Table 11-1 shows the actual total balancing implicit CLMP charges for the
first six months of each year from 2017 through 2021 based on the methods
in place at the time. Table 11-1 shows that the April 1, 2018, settlement rulecaused negative balancing congestion costs to increase for the first six monthsof each year from 2017 through 2021. Table 11-1 shows that the post April
1, 2018, settlement rule caused negative total balancing implicit charges toincrease by $10.9 million (14.4 percent) in the first six months of 2021.

using the new method. When the total day-ahead factor weighted real-time
bus CLMP is higher than real-time zonal CLMP, the balancing implicit CLMP
charges will be higher using the new method. Table 11-2 presents three cases
to explain the calculation. The day-ahead load factor or real-time load factor
for an aggregate equals the load at each bus divided by the total aggregateload.
Case 1 (Table 11-2) shows the case in which the total day-ahead factor weighted
real-time bus CLMP ($1.1) is less than the real-time zonal CLMP ($1.6). The
total balancing implicit CLMP charges using the new method (-$4.2) are lower
than under the old method ($1.8).
Case 2 (Table 11-2) shows the case in which the total day-ahead factor
weighted real-time bus CLMP ($1.9) is larger than the real-time zonal CLMP($1.5). The total balancing implicit CLMP charges using the new method ($2.0)
are higher than under the old method (-$1.2).

Table 11-1 Total balancing implicit CLMP charge (Dollars (Millions)) (oldmethod and new method): January through June, 2017 through 2021
Old Method(Jan - Jun)
2017
2018
2019
2020
2021

Withdrawal
Charges
$6.1
$17.2
$5.2
$1.4
($11.6)

Injection
Credits
$21.4
$46.1
$29.3
$19.2
$64.4

Balancing Implicit CLMP Charges ($ Million)
New Method

Total($15.4)($28.9)($24.1)($17.8)($76.0)Withdrawal
Charges
$5.0
$3.3
$0.2
($0.4)($25.2)

Injection
Credits
$21.7
$43.5
$28.0
$19.1
$61.7

Total
($16.8)($40.2)($27.7)($19.5)($86.9)

Method Used

Withdrawal
Charges
$6.1
$14.7
$0.2
($0.4)($25.3)

Injection
Credits
$21.4
$45.8
$28.0
$19.1
$61.6

Total
($15.4)($31.1)($27.7)($19.5)($86.9)ChangeBetween New
and Old($1.4)($11.3)($3.6)($1.8)($10.9)The differences in results between the old method and the new method result
from the use of zonal CLMP and zonal net deviations in place of the use ofbus specific CLMPs and bus specific deviations.
When the total day-ahead factor weighted real-time bus CLMP is lower thanreal-time zonal CLMP, the balancing implicit CLMP charges will be lower
562

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Case 3 (Table 11-2) shows that the total day-ahead factor weighted real-time bus CLMP ($1.6) is equal to the real-time zonal CLMP ($1.6). The total balancing
implicit CLMP charges using the new method (-$4.2) are equal under the old method (-$4.2).
Table 11-2 Example of balancing implicit CLMP charge calculation (old method and new method)
Balancing Implicit
Withdrawal Charges

Case 1
Bus A
Bus B
Zonal
Balancing Implicit Injection Credits
Balancing Implicit Congestion Charges
Case 2
Bus A
Bus B
Zonal
Balancing Implicit Injection Credits
Balancing Implicit Congestion Charges
Case 3
Bus A
Bus B
Zonal
Balancing Implicit Injection Credits
Balancing Implicit Congestion Charges

Real-Time
CLMP
$1.0
$2.0

$1.0
$2.0

$1.0
$2.0

Real-Time
Load
4.0
6.0
10.0

Real-Time
Load Factor
0.4
0.6

5.0
5.0
10.0

0.5
0.5

4.0
6.0
10.0

0.4
0.6

Real-Time
CLMP *
Real-Time
Load Factor
$0.4
$1.2
$1.6

Day-Ahead
Load Factor
0.9
0.1

$0.5
$1.0
$1.5

0.1
0.9

$0.4
$1.2
$1.6

0.4
0.6

Real-Time
CLMP *
Day-Ahead
Load Factor
$0.9
$0.2
$1.1

Day-Ahead
Load
10.8
1.2
12.0

Balancing
Load
(6.8)
4.8

$0.1
$1.8
$1.9

0.8
7.2
8.0

4.2
(2.2)

$0.4
$1.2
$1.6

4.8
7.2
12.0

(0.8)
(1.2)

Old Method($6.80)
$9.60
$2.8
$1.0
$1.8

New Method($3.20)$1.0($4.2)$4.20($4.40)($0.2)$1.0($1.2)

$3.00
$1.0
$2.0

($0.80)($2.40)($3.2)$1.0($4.2)($3.20)$1.0($4.2)

Locational Marginal Price (LMP)
Components
On June 1, 2007, PJM changed from a single node reference bus to a distributed load reference bus. While the use of a single node reference bus or a distributedload reference bus has no effect on the total LMP, the use of a single node reference bus or a distributed load reference bus does affect the components of LMP.
With a distributed load reference bus, the energy component of LMP is a load-weighted system price. No congestion component is normally included in theload-weighted reference bus price.
LMP at a bus reflects the incremental price of energy at that bus. LMP at any bus can be disaggregated into three components: the system marginal price (SMP),
marginal loss component (MLMP), and congestion component (CLMP).
SMP, MLMP and CLMP are a product of the least cost, security constrained dispatch of system resources to meet system load. SMP is the incremental cost of
system energy, given the current dispatch and given the choice of reference bus. SMP is LMP net of losses and congestion. Losses refer to energy lost to physical© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 563

2021 Quarterly State of the Market Report for PJM: January through June

resistance in the transmission and distribution network as power is moved
from generation to load. Marginal losses are the incremental change in system
power losses caused by changes in the system load and generation patterns.9
The first derivative of total losses with respect to the power flow is marginal
losses. Congestion cost reflects the incremental cost of relieving transmission
constraints while maintaining system power balance. Congestion occurs
when available, least-cost energy cannot be delivered to all loads because
transmission facilities are not adequate to deliver that energy. When the leastcost available energy cannot be delivered to load in a transmission constrained
area, higher cost units in the constrained area must be dispatched to meet that
load.10 The result is that the price of energy in the constrained area is higher
than in the unconstrained area because of the combination of transmission
limitations and the cost of local generation. Load in the constrained area pays
the higher price for all energy including energy from low cost generation andenergy from high cost generation. Congestion is the difference between the
total cost of energy paid by load in the transmission constrained area andthe total revenue received by generation to meet the load in the transmission
constrained area, net of losses. Congestion equals the sum of day-ahead andbalancing congestion.
Table 11-3 shows the PJM real-time, load-weighted, average LMP components
for January through June, 2008 through 2021.11
The real-time, load-weighted, average LMP increased $11.22 or 57.8 percent
from $19.40 in the first six months of 2020 to $30.62 in the first six monthsof 2021. The real-time, load-weighted, average congestion component was$0.02 in the first six months of 2020 and $0.03 in the first six months of
9 For additional information, see the MMU Technical Reference for PJM Markets, at “Marginal Losses,” <http://www.monitoringanalytics.
com/reports/Technical_References/references.‌shtml>.
10 This is referred to as dispatching units out of economic merit order. Economic merit order is the order of all generator offers from lowest
to highest cost. Congestion occurs when loadings on transmission facilities mean the next unit in merit order cannot be used and ahigher cost unit must be used in its place.
11 The PJM real-time, load-weighted price is weighted by accounting load, which differs from the state-estimated load used indetermination of the energy component (SMP). In the real-time energy market, the distributed load reference bus is weighted by stateestimated load in real time. When the LMP is calculated in real time, the energy component equals the system load-weighted price. But
real-time bus-specific loads are adjusted, after the fact, based on updated load information from meters. This meter adjusted load is
accounting load that is used in settlements and is used to calculate reported PJM load-weighted prices. This after the fact adjustment
means that the real-time energy market energy component of LMP (SMP) and the PJM real-time, load-weighted LMP are not equal. The
difference between the real-time energy component of LMP and the PJM wide real-time, load-weighted, average LMP is a result of thedifference between state-estimated and metered loads used to weight the load-weighted reference bus and the load-weighted LMP.
Without these adjustments, the congestion component of system average LMP would be zero.

564

Section 11 Congestion and Marginal Losses

2021. Using a load-weighted reference bus, the real-time, load-weighted,
average congestion component of LMP should be zero. PJM’s load-weighted
reference bus congestion component is zero at the time that LMPs are set
based on state estimator data. Metering updates during the settlement processchange the load weights after the fact, but the reference bus price (SMP) is
not updated with these changes over time. As a result, the average congestion
and loss components used in real-time settlement are not zero, although thesecomponents are not fully accurate. The real-time, load-weighted, average loss
component in the first six months of 2020 was $0.01 compared to $0.02 in thefirst six months of 2021. The real-time, load-weighted, average system energy
component increased by $11.19 or 57.8 percent from $19.37 in the first six
months of 2020 to $30.57 in the first six months of 2021.
Table 11-3 Real-time, load-weighted, average LMP components (Dollars per
MWh): January through June, 2008 through 202112(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Real-Time
LMP$74.77$42.48$45.75$48.47$31.21$37.96$69.92$42.30$27.09$29.81$42.44$27.49$19.40$30.62

EnergyComponent$74.66$42.40$45.65$48.40$31.17$37.92$69.95$42.24$27.04$29.78$42.37$27.45$19.37$30.57

Congestion
Component
$0.07
$0.05
$0.06
$0.05
$0.04
$0.02
($0.06)
$0.03
$0.03
$0.02
$0.04
$0.02
$0.02
$0.03

Loss
Component
$0.05
$0.03
$0.04
$0.03
$0.01
$0.02
$0.02
$0.02
$0.01
$0.01
$0.02
$0.02
$0.01
$0.02

12 Calculated values shown in Section 11, “Congestion and Marginal Losses,” are based on unrounded, underlying data and may differ from
calculations based on the rounded values in the tables.

© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Table 11-4 shows the PJM day-ahead, load-weighted, average LMP
components for the first six months of 2008 through 2021.13 The day-ahead,load-weighted, average LMP increased $11.77, or 61.2 percent, from $19.23 in
the first six months of 2020 to $31.00 in the first six months of 2021. The dayahead, load-weighted, average congestion component increased $0.14 from-$0.01 in the first six months of 2020 to $0.13 in the first six months of 2021.
The day-ahead, load-weighted, average loss component was -$0.01 in thefirst six months of 2020 and $0.02 in the first six months of 2021. The dayahead, load-weighted, average energy component increased $11.60, or 60.2
percent, from $19.25 in the first six months of 2020 to $30.85 in the first six
months of 2021. Using a load-weighted reference bus, the day-ahead, loadweighted, average congestion component of LMP should be zero. PJM’s loadweighted reference bus congestion component is zero based on day-ahead
firm load weights. Total billing however, includes price sensitive demand andvirtual load congestion related charges, which makes the total load weights
in accounting different than the load weights used to determine the SMP atthe load-weighted reference bus. The resulting load-weighted average pricefrom settlement for congestion and marginal losses components of price in
day ahead is therefore not zero, although this component is not fully accurate.

Table 11-4 Day-ahead, load-weighted, average LMP components (Dollars per
MWh): January through June, 2008 through 2021
(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Day-Ahead
LMP$73.71$42.21$46.12$47.12$31.84$38.23$70.66$43.26$27.33$30.02$40.96$27.97$19.23$31.00

EnergyComponent$74.10$42.47$46.04$47.32$31.76$38.14$70.37$42.95$27.22$30.02$40.86$27.92$19.25$30.85Congestion
Component($0.16)($0.14)$0.08($0.10)
$0.10
$0.09
$0.30
$0.33
$0.12
$0.02
$0.11
$0.06
($0.01)$0.13

Loss
Component($0.23)($0.12)($0.00)($0.11)($0.02)$0.00($0.01)($0.02)($0.01)($0.02)($0.01)($0.01)($0.01)$0.02

Table 11-5 shows the PJM real-time, load-weighted, average LMP by
constrained and unconstrained hours.
Table 11-5 Real-time, load-weighted, average LMP by constrained andunconstrained hours (Dollars per MWh): January 2020 through June 2021

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Avg

2020
Constrained
Unconstrained
Hours
Hours
$22.30$15.73$19.56$17.12$18.28$16.13$17.63$17.39$18.81$12.20$21.64$14.18$28.58$15.77$26.01$17.43$19.94$12.31$22.19$22.78$20.86$26.31$27.28$21.27$22.29$17.592021
Constrained
Unconstrained
Hours
Hours
$25.96$21.31$45.23$23.19$26.57$19.67$26.93$21.82$30.74$22.46$35.33$26.34$31.65$23.0413 In the real-time energy market, the energy component (SMP) equals the system load-weighted price, with the caveat about stateestimated versus metered load. However, in the day-ahead energy market the day-ahead energy component of LMP (SMP) and the
PJM day-ahead, load-weighted LMP are not equal. The difference between the day-ahead energy component of LMP and the PJM
day-ahead, load-weighted LMP is a result of the difference in the types of load used to weight the load-weighted reference bus and theload-weighted LMP. In the day-ahead energy market, the distributed load reference bus is weighted by fixed-demand bids only and the
day-ahead SMP is, therefore, a system fixed demand weighted price. The day-ahead, load-weighted LMP calculation uses all types ofdemand, including fixed, price-sensitive and decrement bids.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 565

2021 Quarterly State of the Market Report for PJM: January through June

Zonal Components
The real-time components of LMP for each control zone are presented in Table 11-6 for the first six months of 2020 and 2021. In the first six months of 2021,
BGE had the highest real-time congestion component of all control zones, $3.96, and JCPLC had the lowest real-time congestion component, -$4.80.
Table 11-6 Zonal real-time, load-weighted, average LMP components (Dollars per MWh): January through June, 2020 and 2021

ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC
PJM

566

Real-Time
LMP$17.99$19.93$20.06$20.25$21.29$18.01$20.96$20.35$18.10$20.08$20.47$20.10$18.53$18.57$19.08$18.81$17.64$20.55$17.56$18.11$18.39$19.402020 (Jan - Jun)
Energy Congestion
Component Component$19.37($1.27)$19.34$0.46$19.34$0.72$19.36$0.55$19.45$1.39$19.37($0.97)$19.46$0.55$19.38$0.97$19.44($1.50)$19.41$0.45$19.38$1.06$19.50$0.47$19.47($0.91)$19.38($0.60)$18.88$0.42$19.26($0.31)$19.34($1.42)$19.46$0.89$19.35($1.43)$19.30($1.09)$19.50($1.06)$19.37$0.02

Loss
Component($0.11)$0.13($0.01)$0.34$0.45($0.40)$0.95($0.00)
$0.15
$0.23
$0.03
$0.13
($0.03)($0.21)($0.22)($0.14)($0.29)$0.20($0.36)($0.10)($0.05)$0.01

Section 11 Congestion and Marginal Losses

Real-Time
LMP$26.61$31.12$30.26$29.29$35.61$29.22$33.33$34.10$33.56$32.49$29.43$31.90$26.46$28.41$28.79$27.96$26.17$33.57$26.77$29.39$33.02$30.622021 (Jan - Jun)
Energy Congestion
Component Component$30.76($4.35)$30.36$0.76$30.46($0.04)$30.40($1.16)$30.83$3.96$30.54($0.53)$30.61$1.45$30.64$3.09$30.84$2.09$30.67$1.71$30.49($0.49)$31.00$0.86$31.00($4.80)$30.53($2.01)$29.49($0.03)$30.20($1.89)$30.65($4.35)$30.89$2.17$30.45($3.31)$30.63($1.44)$31.02$1.79$30.57$0.03

Loss
Component$0.21($0.01)($0.16)$0.04$0.82($0.78)
$1.27
$0.36
$0.63
$0.12
($0.58)$0.04$0.26($0.10)($0.68)($0.36)($0.14)$0.51($0.37)
$0.19
$0.21
$0.02

© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

The day-ahead components of LMP for each control zone are presented in Table 11-7 for the first six months of 2020 and 2021. In the first six months of 2021,
BGE had the highest day-ahead congestion component of all control zones, $3.92, and PECO had the lowest day-ahead congestion component, -$3.88.
Table 11-7 Zonal day-ahead, load-weighted, average LMP components (Dollars per MWh): January through June, 2020 and 2021

ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
JCPLC
MEC
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC
PJM

Day-Ahead
LMP$17.53$19.81$19.77$20.03$21.45$18.08$20.94$20.14$18.17$20.15$20.21$20.09$17.85$18.19$19.52$19.05$17.24$20.65$17.26$17.75$18.32$19.232020 (Jan - Jun)
Energy Congestion
Component Component$19.25($1.56)$19.23$0.47$19.24$0.52$19.22$0.48$19.34$1.75$19.20($0.80)$19.31$0.73$19.27$0.93$19.39($1.30)$19.28$0.67$19.23$0.88$19.52$0.56$19.36($1.46)$19.28($0.81)$19.15$0.59$19.37($0.38)$19.25($1.67)$19.43$1.04$19.25($1.55)$19.22($1.35)$19.43($1.05)$19.25($0.01)© 2021 Monitoring Analytics, LLC

LossComponent($0.17)
$0.12
$0.01
$0.33
$0.35
($0.32)$0.89($0.06)
$0.07
$0.19
$0.10
$0.00
($0.06)($0.28)($0.23)$0.05($0.35)$0.19($0.44)($0.12)($0.06)($0.01)

Day-Ahead
LMP$27.21$31.48$30.73$30.53$35.71$29.30$33.82$33.97$32.34$33.16$30.20$32.27$27.27$29.15$31.43$29.45$26.56$33.87$27.45$28.57$32.25$31.002021 (Jan - Jun)
Energy Congestion
Component Component$30.96($3.78)$30.76$0.68$30.72$0.17$30.52($0.10)$30.99$3.92$30.73($0.79)$30.92$1.39$30.91$2.75$31.04$0.67$30.87$1.97$30.63$0.16$31.56$0.82$30.98($3.79)$30.70($1.28)$33.63($1.53)$30.77($1.15)$30.75($3.88)$31.11$2.20$30.55($2.51)$30.82($2.34)$31.58$0.51$30.85$0.13

Loss
Component
$0.03
$0.04
($0.15)$0.11$0.80($0.65)
$1.51
$0.31
$0.62
$0.31
($0.59)($0.12)$0.09($0.27)($0.66)($0.17)($0.31)$0.56($0.59)
$0.09
$0.17
$0.02

2021 Quarterly State of the Market Report for PJM: January through June 567

2021 Quarterly State of the Market Report for PJM: January through June

Hub Components
The real-time components of LMP for each hub are presented in Table 11-8 for the first six months of 2020 and 2021.14
Table 11-8 Hub real-time, average LMP components (Dollars per MWh): January through June, 2020 and 2021

AEP Gen Hub
AEP-DAY Hub
ATSI Gen Hub
Chicago Gen Hub
Chicago Hub
Dominion Hub
Eastern Hub
N Illinois Hub
New Jersey Hub
Ohio HubWest Interface Hub
Western Hub

Real-Time
LMP$18.81$19.18$19.30$16.90$17.22$18.93$17.44$17.14$17.54$19.20$19.12$18.872020 (Jan - Jun)
Energy Congestion
Component Component$18.67$0.43$18.67$0.40$18.67$0.55$18.67($1.18)$18.67($1.10)$18.67$0.44$18.67($1.34)$18.67($1.09)$18.67($1.03)$18.67$0.37$18.67$0.55$18.67$0.32

Loss
Component($0.30)$0.11$0.08($0.60)($0.35)($0.18)$0.10($0.44)($0.11)$0.15($0.10)($0.13)

Real-Time
LMP$27.83$29.77$27.60$27.05$27.64$31.21$30.99$27.50$26.28$30.02$28.80$28.852021 (Jan - Jun)
Energy Congestion
Component Component$29.12($0.44)$29.12$0.71$29.12($1.11)$29.12($0.97)$29.12($0.75)$29.12$1.98$29.12$1.40$29.12($0.75)$29.12($2.96)$29.12$0.90$29.12$0.09$29.12($0.04)Loss
Component($0.86)($0.07)($0.42)($1.10)($0.73)$0.10$0.47($0.87)$0.12($0.00)($0.41)($0.23)The day-ahead components of LMP for each hub are presented in Table 11-9 for the first six months of 2020 and 2021.
Table 11-9 Hub day-ahead, average LMP components (Dollars per MWh): January through June, 2020 and 2021

AEP Gen Hub
AEP-DAY Hub
ATSI Gen Hub
Chicago Gen Hub
Chicago Hub
Dominion Hub
Eastern Hub
N Illinois Hub
New Jersey Hub
Ohio HubWest Interface Hub
Western Hub

Day-Ahead
LMP$18.72$19.11$19.19$17.06$17.43$18.88$17.38$17.32$17.12$19.11$19.03$18.972020 (Jan - Jun)
Energy Congestion
Component Component$18.58$0.42$18.58$0.42$18.58$0.52$18.58($1.01)$18.58($0.89)$18.58$0.53$18.58($1.25)$18.58($0.88)$18.58($1.33)$18.58$0.41$18.58$0.54$18.58$0.43

Loss
Component($0.28)$0.11$0.09($0.52)($0.27)($0.24)$0.05($0.38)($0.13)$0.12($0.09)($0.03)

Day-Ahead
LMP$28.72$30.02$28.93$27.31$27.88$30.98$29.63$27.68$26.35$30.11$29.64$29.592021 (Jan - Jun)
Energy Congestion
Component Component$29.35$0.15$29.35$0.64$29.35($0.13)$29.35($1.08)$29.35($0.89)$29.35$1.57$29.35($0.18)$29.35($0.92)$29.35($3.00)$29.35$0.68$29.35$0.64$29.35$0.38

LossComponent($0.78)$0.02($0.30)($0.97)($0.58)$0.06$0.46($0.75)($0.00)$0.08($0.35)($0.14)14 The real-time components of LMP are the simple average of the hourly components for each hub. Some hubs include only generation buses and do not include load buses. The real-time components of LMP were previously reported as the real-time, load-weighted, average of the hourlycomponents of LMP.

568

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Congestion
Congestion Accounting
In PJM accounting, total congestion costs equal net implicit CLMP charges,
plus net explicit CLMP charges, plus net inadvertent CLMP charges. Implicit
CLMP charges equal implicit withdrawal charges less implicit injection credits.
Explicit CLMP charges are the net CLMP charges associated with the injection
credits and withdrawal charges for point to point energy transactions.
Inadvertent CLMP charges are not directly attributable to specific participantsthat are distributed on a load ratio basis. Each of these categories of congestion
costs is comprised of day-ahead and balancing congestion costs.
While PJM accounting focuses on CLMPs, the individual CLMP values atany bus are irrelevant to the calculation of congestion, as CLMPs are just an
artificial deconstruction of LMP based on a selected reference bus. Holding
aside the marginal loss component of LMP, differences in the LMPs arecaused by binding constraints in the least cost security constrained dispatch
market solution and total congestion is the net surplus revenue that remains
after all sources and sinks are credited or charged their LMPs. Changing thecomponents of LMP by electing a different reference bus does not change the
LMPs or the difference between LMPs for a given market solution or actual
congestion, it merely changes the components of the LMP.
Congestion occurs in the day-ahead and real-time energy markets.15 Dayahead congestion costs are based on day-ahead MWh while balancing
congestion costs are based on deviations between day-ahead and real-time
MWh priced at the congestion price in the real-time energy market.
Implicit CLMP charges are the CLMP charges calculated for energy injected
or withdrawn at a location. The explicit CLMP charges are the CLMP charges
calculated for transactions with a defined source and a sink. For example,
implicit CLMP charges are calculated for network load and explicit CLMP
charges are calculated for up to congestion transactions (UTCs). Inadvertent
CLMP charges are CLMP charges resulting from the differences between the
15 When the term congestion charge is used in documents by PJM’s Market Settlement Operations, it has the same meaning as the term
congestion costs as used here.

© 2021 Monitoring Analytics, LLC

net actual energy flow and the net scheduled energy flow into or out of thePJM control area each hour.
CLMP charges and CLMP credits are calculated for both the day-ahead andbalancing energy markets.

• Day-Ahead Implicit Load CLMP Charges. Day-ahead implicit withdrawal

charges are calculated for all cleared demand, decrement bids and dayahead energy market sale transactions. Day-ahead implicit withdrawal
charges are calculated using MW and the load bus CLMP, the decrement
bid CLMP or the CLMP at the source of the sale transaction.

• Day-Ahead Implicit Generation CLMP Credits. Day-ahead implicit injection

credits are calculated for all cleared generation, increment offers andday-ahead energy market purchase transactions.16 Day-ahead implicit
injection credits are calculated using MW and the generator bus CLMP,
the increment offer’s CLMP or the CLMP at the sink of the purchasetransaction.

• Balancing Implicit Load CLMP Charges. Balancing implicit withdrawal

charges are calculated for all deviations between a PJM member’s realtime load and energy sale transactions and their day-ahead cleared
demand, decrement bids and energy sale transactions. Balancing implicit
withdrawal charges are calculated using MW deviations and the real-time
CLMP for each aggregate where a deviation exists.

• Balancing Implicit Generation CLMP Credits. Balancing implicit injection

credits are calculated for all deviations between a PJM member’s realtime generation and energy purchase transactions and the day-ahead
cleared generation, increment offers and energy purchase transactions.
Balancing implicit injection credits are calculated using MW deviations
and the real-time CLMP for each aggregate where a deviation exists.

16 Internal bilateral transactions are included in the tariff definitions of Market Participant Energy Injections and Market Participant Energy
Withdrawals. The purchase part of an internal bilateral transaction is an injection to the buyer and the sale part of an internal bilateraltransaction is a withdrawal to the seller. The tariff (Attachment K) also says market participants will be charged implicit CLMP charges
for all Market Participant Energy Withdrawals and will be credited implicit CLMP credits for all Market Participant Energy Injections.
The seller of an internal bilateral transaction will be charged implicit CLMP charges at the source and the buyer of an internal bilateraltransaction will be credited implicit CLMP credits at the sink. Internal bilateral transaction CLMP credits and charges sum to zero, as the
IBT is merely a transfer of ownership injection and withdrawal MW and associated charges and credits between participants, meaningthat the sum of all MW and all credits and all charges with and without IBTs are the same.

2021 Quarterly State of the Market Report for PJM: January through June 569

2021 Quarterly State of the Market Report for PJM: January through June

• Explicit CLMP Charges. Explicit CLMP charges are the net CLMP costs•

associated with point to point energy transactions. Day-ahead explicit
CLMP charges equal the product of the transacted MW and CLMP
differences between sources (origins) and sinks (destinations) in the dayahead energy market. Balancing explicit CLMP charges equal the productof the deviations between the real-time and day-ahead transacted MW andthe differences between the real-time CLMP at the transactions’ sources
and sinks. Explicit CLMP charges are calculated for internal purchase,import and export transaction, and up to congestion transactions (UTCs.)
Inadvertent CLMP Charges. Inadvertent CLMP charges are charges
resulting from the differences between the net actual energy flow andthe net scheduled energy flow into or out of the PJM control area eachhour. This inadvertent interchange of energy may be positive or negative,
where positive interchange typically results in a charge while negativeinterchange typically results in a credit. Inadvertent CLMP charges arecommon costs, not directly attributable to specific participants that are
distributed on a load ratio basis.17

The congestion accounting calculation equations are in Table 11-10.
Table 11-10 Congestion accounting calculations
Congestion Category
Day-Ahead Implicit Withdrawal CLMP Charges
Day-Ahead Implicit Injection CLMP Credits
Day-Ahead Explicit CLMP Charges
Day-Ahead Total Congestion Costs

Balancing Implicit Withdrawal CLMP Charges
Balancing Implicit Injection CLMP Credits
Balancing Explicit CLMP Costs
Balancing Total Congestion Costs
Total Congestion Costs

Calculation
Day-Ahead Demand MWh * Day-Ahead CLMP
Day-Ahead Supply MWh * Day-Ahead CLMP
Day-Ahead Transaction MW * (Day-Ahead Sink CLMP - DayAhead Source CLMP)
Day-Ahead Implicit Withdrawal CLMP Charges - Day-Ahead
Implicit Injection CLMP Credits + Day-Ahead Explicit CLMP
Charges
Balancing Demand MWh * Real-Time CLMP
Balancing Supply MWh * Real-Time CLMP
Balancing Transaction MW * (Real-Time Sink CLMP - Real-Time
Source CLMP)
Balancing Implicit Withdrawal CLMP Charges - Balancing
Implicit Injection CLMP Credits + Balancing Explicit CLMP Costs
Day-Ahead Total Congestion Costs + Balancing Total Congestion
Costs

MWh Category
Day-Ahead Demand MWh
Day-Ahead Supply MWh

Definition
Cleared Demand, Decrement Bids, Energy Sale Transactions
Cleared Generation, Increment Bids, Energy PurchaseTransactions

Real-Time Demand MWh
Real-Time Supply MWh

Load and Energy Sale Transactions
Generation and Energy Purchase Transactions

Balancing Demand MWh
Balancing Supply MWh

Real-Time Demand MWh - Day-Ahead Demand MWh
Real-Time Supply MWh - Day-Ahead Supply MWh

PJM billing items include Day-Ahead Transmission Congestion Charges, DayAhead Transmission Congestion Credits, Balancing Transmission Congestion
Charges, and Balancing Transmission Congestion Credits. Those line items arecalculated for each PJM member. The congestion bill shows the CLMP charges
or credits collected from the PJM market participants. However, the sum of anindividual customer’s CLMP credits or charges on the customer’s bill is not ameasure of the congestion paid by that customer.
The congestion paid by a customer is the difference between what thecustomer paid for energy and what all network sources of that energy were
paid to serve that customer. A load customer’s congestion bill, in contrast,
17 PJM Operating Agreement Schedule 1 §3.7.

570

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

merely indicates whether the LMP they paid for their withdrawals is higher
or lower than the system energy price due to transmission constraints. The
customer’s bill is correct, but the bill does not measure congestion paid by
the customer, only how much the customer was charged and credited for their
MW positions. The congestion costs associated with specific constraints are
the sum of the total day-ahead and balancing congestion costs associatedwith those constraints. Zonal congestion is calculated on a constraint byconstraint basis. The congestion calculations are the total difference between
what the zonal load pays in CLMP charges and what the generation that serves
that load is paid, regardless of whether the zone is a net importer or a net
exporter of generation. Congestion costs can be both positive and negativeand CLMP charges and CLMP credits can be both positive and negative. CLMP
charges, positive or negative, are paid by withdrawals and CLMP credits,
positive or negative, are paid to injections. Total congestion costs (the sumof charges and credits), when positive, measure the net congestion payment
by a participant group and when negative, measure the net congestion credit
paid to a participant group. Explicit CLMP charges, when positive, measure
the congestion payment to a PJM member and when negative, measure thecongestion credit paid to a PJM member. Explicit CLMP charges are calculated
for up to congestion transactions (UTCs).
The congestion accounting definitions can be misleading. Load pays
congestion. Congestion is the difference between what load pays forenergy and what generation is paid for energy due to binding transmission
constraints. Generation does not pay congestion. Some generation receives a
price lower than SMP and some generation receives a price greater than SMP
but that does not mean that generation is paying congestion. It means onlythat generation is being paid an LMP that is higher or lower than the systemload-weighted average LMP.
The CLMP is calculated with respect to the LMP at the system reference bus,
also called the system marginal price (SMP). When a transmission constraint
occurs, the resulting CLMP is positive on one side of the constraint andnegative on the other side of the constraint and the corresponding congestion
costs are positive or negative. For each transmission constraint, the CLMP

© 2021 Monitoring Analytics, LLC

reflects the cost of a constraint at a pricing node and is equal to the product of
the constraint shadow price and the distribution factor from the constraint to
the pricing node. The total CLMP at a pricing node is the sum of all constraint
contributions to LMP and is equal to the difference between the actual LMP
that results from transmission constraints, excluding losses, and the SMP. If
an area experiences lower prices because of a constraint, the CLMP in thatarea is negative.18
Load-weighted LMP components are calculated relative to a load-weighted,
average LMP. At the load-weighted reference bus, which represents the load
center of the system, the LMP includes no congestion or loss components, bydefinition. The load weighted, average CLMP across all load buses, calculated
relative to that reference bus, is equal to, or very close to, zero, with non-zero
results caused by state estimator error and after the fact meter updates. The
sum of load related CLMP charges is logically zero and the small reported
differences are the result of accounting issues. A positive CLMP at a load
bus indicates that the load at that bus has a total energy price higher than
the average LMP, due to transmission constraints. A negative CLMP at a load
bus indicates that the load at that bus has a total energy price lower than the
average LMP, due to transmission constraints. The LMPs at the load buses area function of marginal generation bus LMPs determined through the least
cost security constrained economic dispatch which accounts for transmission
constraints and marginal losses. Due to transmission constraints, the average
generation weighted CLMP for generation resources is lower than the LMP atthe load-weighted reference bus price. Calculated relative to the load reference
bus which has a CLMP of zero, this means that the average of the generation
bus CLMPs is negative. This means that total generation CLMP credits arenegative.
Figure 11-1 shows the weighted average CLMPs of generation and load in
the day-ahead market. Figure 11-1 shows that in January 2019 through June
2021, day-ahead generation weighted CLMPs were generally negative andday-ahead, load weighted CLMPs were generally positive, indicating thatload was charged a higher weighted average LMP for energy as a result of
18 For an example of the congestion accounting methods used in this section, see MMU Technical Reference for PJM Markets, at “FTRs andARRs,” <http://www.‌monitoringanalytics.com/reports/Technical_References/docs/2010-som-pjm-technical-reference.pdf>.

2021 Quarterly State of the Market Report for PJM: January through June 571

2021 Quarterly State of the Market Report for PJM: January through Junetransmission constraints than the weighted average LMP generation was paid
to provide that energy. This means that total CLMP load payments are higher
than total CLMP generation credits. The difference in load payments andgeneration credits (load charges minus generation credits) is congestion (Table
11-13 and Table 11-14). This result is a product of the least cost, security
constrained dispatch and the use of a load-weighted reference bus that is used
for the determination of the components of LMP. More generally, in a least
cost, security constrained market solution the weighted average LMP at loadbuses is higher than the weighted average price at generation buses.
The day-ahead, generation weighted CLMPs were significantly negative fortwo hours on May 4, 2021 due to high shadow prices of two constraints
caused by a transmission outage in the DOM Zone.
Figure 11-1 Day-ahead generation weighted CLMPs and day-ahead loadweighted CLMPs: January 2019 through June 2021

Total congestion costs in PJM in the first six months of 2021 were $354.0
million, comprised of implicit withdrawal charges of $143.2 million, explicit
charges of -$25.5 million and implicit injection credits of -$236.2 million.
Total congestion is the difference between what load pays for energy andwhat generation is paid for energy, due to binding transmission constraints.
Table 11-11 shows total congestion for the first six months of 2008 through2021. Total congestion costs in Table 11-11 include congestion associated with
PJM facilities and those associated with reciprocal, coordinated flowgates in
MISO and in NYISO.19 20
Table 11-11 Total congestion costs (Dollars (Millions)): January through June,2008 through 2021
Congestion Costs (Millions)(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

$12.00$6.00$0.00-$6.00-$12.00-$18.00-$24.00
CLMP

Total Congestion-$30.00-$36.00-$42.00

Congestion Cost
$1,166
$408
$644
$570
$263
$306
$1,442
$919
$479
$286
$897
$254
$180
$354

Percent Change Total PJM BillingNA$16,549(65.0%)$13,457
57.8%$16,314(11.5%)$18,685(53.8%)$13,991
16.3%$15,571371.3%$31,060(36.3%)$23,390(47.8%)$18,290(40.4%)$18,960
214.0%$25,780(71.7%)$20,070(29.2%)$15,570
96.9%$20,410Percent of PJM
Billing
7.0%
3.0%
3.9%
3.1%
1.9%
2.0%
4.6%
3.9%
2.6%
1.5%
3.5%
1.3%
1.2%
1.7%

-$48.00-$54.00-$60.00-$66.00

Day-ahead Generation Weighted CLMP
Day-ahead Load Weighted CLMP-$72.00

CLMP charges and credits are not congestion. CLMP charges and credits reflectmarginal energy price differences caused by binding system constraints.
Congestion is the sum of all congestion related charges and credits. In a twosettlement system all virtual bids have net zero MW after their day-ahead andbalancing positions are cleared, which means that virtual bids are fully settled
19 See “Joint Operating Agreement Between the Midwest Independent Transmission System Operator, Inc. and PJM Interconnection, L.L.C.,”(December 11, 2008) Section 6.1, Effective Date: May 30, 2016. <http://www.pjm.com/documents/agreements.aspx>.
20 See “NYISO Tariffs New York Independent System Operator, Inc.,” (June 21, 2017) 35.12.1, Effective Date: May 1, 2017. <http://www.pjm.
com/documents/agreements.aspx>.

572

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

in terms of CLMP credits and charges at the close of the market for any particular day, with either a net loss or profit due to differences between day-ahead andreal-time prices. Net payouts (negative credits) to virtual bids appear as negative adjustments to either day-ahead or balancing congestion and net charges tovirtual bids appear as positive adjustments to either day-ahead or balancing congestion.
Table 11-12 shows total congestion by day-ahead and balancing component for the first six months of 2008 through 2021.
Table 11-12 Total CLMP credits and charges by accounting category (Dollars (Millions)): January through June, 2008 through 2021

(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Implicit
Withdrawal
Charges$727.6$159.3$151.5$256.0$56.8$133.2$392.5$428.5$201.9$47.1$211.8$100.4$28.9$168.4

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges($589.4)$86.7($299.4)$63.1($544.1)$38.1($420.3)$25.6($267.4)$65.4($306.1)$87.8($1,353.6)($54.1)($655.2)$9.5($293.4)$18.7($246.0)$3.8($745.0)($40.3)($188.3)$22.9($174.6)$32.9($297.9)$35.4

CLMP Credits and Charges (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges$1,403.8($102.4)$68.2($67.1)$521.7($17.0)($2.4)($99.0)$733.8($7.3)$18.6($63.9)$701.9$31.1$56.0($107.0)$389.6($5.0)$19.5($101.8)$527.1($8.4)$90.4($122.3)$1,691.9$64.4$219.9($94.2)$1,093.2
$10.7
$68.8
($116.5)$514.0$0.4$11.5($23.7)$296.8
$6.1
$21.5
$4.1
$916.5
$14.7
$45.8
$11.2
$311.5$0.2$28.0($29.7)$236.4($0.4)$19.1($37.0)$501.7($25.3)$61.6($60.8)

Total($237.7)($113.6)($89.8)($131.9)($126.4)($221.1)($249.7)($174.6)($34.8)($11.3)($19.9)($57.4)($56.6)($147.7)

Inadvertent
Charges$0.0$0.0($0.0)$0.0$0.0($0.0)
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

Congestion
Costs$1,166.1$408.2$644.0$570.0$263.3$306.0$1,442.3$918.6$479.1$285.5$896.6$254.1$179.8$354.0Charges and Credits versus Congestion: Virtual Transactions, Load and Generation
In PJM’s two settlement system, there is a day-ahead market and a real-time, balancing market, that make up a market day.
In a two settlement system all virtual bids have net zero MW after their day-ahead and balancing positions are cleared, which means that virtual bids are fully
settled in terms of CLMP credits and charges at the close of each market day, with either a net loss or profit due to differences between day-ahead and real-time
prices. Net payouts (negative credits) to virtual bids appear as negative adjustments to either day-ahead or balancing congestion and net charges to virtual bids
appear as positive adjustments to either day-ahead or balancing congestion.
Unlike virtual bids, physical load and generation have net MW at the close of a market day’s day-ahead and balancing settlement.
Generation does not pay congestion. Some generation receives a price lower than SMP and some generation receives a price greater than SMP but that does notmean that generation is paying congestion. It means that generation is being paid an LMP that is higher or lower than the system load-weighted, average LMP.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 573

2021 Quarterly State of the Market Report for PJM: January through June

The residual difference between total load charges (day-ahead and balancing) and generation credits (day-ahead and balancing) after virtual bids have settled
their day-ahead and balancing positions is congestion. That is, congestion is the difference between what withdrawals (load) are paying for energy and what
injections (generation) are being paid for energy due to binding transmission constraints, after virtual bids are settled at the end of the market day. Load is thesource of the net surplus after generation is paid and virtuals are settled at the end of the market day. Load pays congestion.
Table 11-13 and Table 11-14 show the total CLMP charges and credits for each transaction type in the first six months of 2021 and 2020. Table 11-13 shows thatin the first six months of 2021 DECs paid $25.1 million in CLMP charges in the day-ahead market, were paid $48.2 million in CLMP credits in the balancing
energy market, resulting in a net payment of $23.1 million in total CLMP credits. In the first six months of 2021, INCs paid $13.4 million in CLMP charges in the
day-ahead market, were paid $26.2 million in CLMP credits in the balancing energy market resulting in a net payment of $12.9 million in total CLMP credits.
In the first six months of 2021, up to congestion (UTCs) paid $32.2 million in CLMP charges in the day-ahead market, were paid $60.7 million in CLMP credits
in the balancing market resulting in a total payment of $28.5 million in total CLMP credits.
Table 11-13 Total CLMP credits and charges by transaction type (Dollars (Millions)): January through June, 2021

Transaction TypeDEC
DemandDemand Response
Explicit Congestion Only
Explicit Congestion and Loss Only
ExportGeneration
ImportINC
Internal Bilateral
Up to Congestion
Wheel In
Wheel Out
Total

574

Implicit
Withdrawal
Charges
$25.1
$23.7
$0.0
$0.0
$0.0
($4.7)
$0.0
$0.0
$0.0
$124.2
$0.0
$0.0
$0.0
$168.4

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$1.5
$0.0
($0.1)$0.0($0.2)($410.3)$0.0($0.4)$0.0($13.4)$0.0$126.2
$2.0
$0.0
$32.2
$0.0
$0.0
$0.0
$0.0
($297.9)$35.4

Section 11 Congestion and Marginal Losses

CLMP Credits and Charges (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges$25.1($48.2)
$0.0
$0.0
$23.7
$16.7
$0.0
$0.0
$0.0
($0.0)
$0.0
$0.0
$1.5
$0.0
$0.0
($0.2)($0.1)$0.0$0.0($0.0)($4.9)
$6.4
$0.0
$0.0
$410.3
$0.0
$31.5
$0.0
$0.4
$0.0
$4.1
$0.0
$13.4
$0.0
$26.2
$0.0
($0.0)($0.9)($0.9)
$0.0
$32.2
$0.0
$0.0
($60.7)
$0.0
$0.0
$0.8
$0.1
$0.0
$0.8
$0.0
$0.0
$501.7($25.3)$61.6($60.8)

Total($48.2)$16.7($0.0)($0.2)($0.0)$6.4($31.5)($4.1)($26.2)($0.0)($60.7)($0.7)$0.8($147.7)

Inadvertent
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

Grand
Total
($23.1)
$40.4
$0.0
$1.4
($0.1)$1.5$378.8($3.7)($12.9)($0.0)($28.5)($0.7)$0.8$354.0© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Table 11-14 Total CLMP credits and charges by transaction type (Dollars (Millions)): January through June, 2020

Transaction TypeDEC
DemandDemand Response
Explicit Congestion Only
Explicit Congestion and Loss Only
ExportGeneration
ImportINC
Internal Bilateral
Up to Congestion
Wheel In
Wheel Out
Total

Implicit
Withdrawal
Charges$0.5($5.9)
$0.0
$0.0
$0.0
($13.9)
$0.0
$0.0
$0.0
$48.2
$0.0
$0.0
$0.0
$28.9

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$1.0
$0.0
$0.1
$0.0
($0.1)($213.1)$0.0($0.3)$0.0($10.3)
$0.0
$49.1
$0.9
$0.0
$31.0
$0.0
$0.0
$0.0
$0.0
($174.6)$32.9

CLMP Credits and Charges (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges$0.5($2.3)$0.0$0.0($5.9)
$6.4
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$1.0
$0.0
$0.0
($0.4)
$0.1
$0.0
$0.0
$0.0
($14.0)($3.7)$0.0$0.4$213.1
$0.0
$2.5
$0.0
$0.3
$0.0
($0.2)($0.0)
$10.3
$0.0
$17.7
$0.0
($0.0)($0.7)($0.7)
$0.0
$31.0
$0.0
$0.0
($36.8)$0.0$0.0($0.2)($0.3)$0.0($0.2)$0.0$0.0$236.4($0.4)$19.1($37.0)Total($2.3)$6.4$0.0($0.4)$0.0($3.3)($2.5)$0.2($17.7)$0.0($36.8)($0.1)($0.2)($56.6)

Inadvertent
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

Grand
Total
($1.8)
$0.6
$0.0
$0.6
$0.1
($17.3)$210.5$0.5($7.4)$0.0($5.8)($0.1)($0.2)$179.8

Table 11-15 shows the change in total CLMP credits and charges incurred by transaction type from the first six months of 2020 to the first six months of 2021.
Total negative CLMP credits incurred by generation increased by $168.3 million, and total CLMP charges incurred by demand increased by $39.9 million. The total
CLMP credits to up to congestion transactions (UTCs) increased by $22.7 million in the first six months of 2021. Total day-ahead CLMP charges to UTCs increased
by $1.3 million in the first six months of 2021. Over the same period balancing CLMP credits to UTCs increased by $23.9 million in the first six months of 2021.
Table 11-15 Change in total CLMP credits and charges by transaction type (Dollars (Millions)): January through June, 2020 to 2021

Transaction TypeDEC
DemandDemand Response
Explicit Congestion Only
Explicit Congestion and Loss Only
ExportGeneration
ImportINC
Internal Bilateral
Up to Congestion
Wheel In
Wheel Out
Total

© 2021 Monitoring Analytics, LLC

Implicit
Withdrawal
Charges
$24.6
$29.6
$0.0
$0.0
$0.0
$9.2
$0.0
$0.0
$0.0
$76.1
$0.0
$0.0
$0.0
$139.5

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.5
$0.0
($0.2)$0.0($0.1)($197.2)$0.0($0.1)$0.0($3.1)
$0.0
$77.1
$1.1
$0.0
$1.3
$0.0
$0.0
$0.0
$0.0
($123.3)$2.5

Change in CLMP Credits and Charges (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges$24.6($45.9)
$0.0
$0.0
$29.6
$10.3
$0.0
$0.0
$0.0
($0.0)
$0.0
$0.0
$0.5
$0.0
$0.0
$0.2
($0.2)$0.0$0.0($0.0)
$9.1
$10.1
$0.0
($0.4)$197.2
$0.0
$28.9
$0.0
$0.1
$0.0
$4.3
$0.0
$3.1
$0.0
$8.5
$0.0
($0.0)($0.2)($0.2)
$0.0
$1.3
$0.0
$0.0
($23.9)
$0.0
$0.0
$1.0
$0.3
$0.0
$1.0
$0.0
$0.0
$265.3($24.8)$42.5($23.8)

Total($45.9)$10.3($0.0)$0.2($0.0)$9.7($28.9)($4.3)($8.5)($0.0)($23.9)($0.6)$1.0($91.1)

Inadvertent
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

Grand
Total
($21.3)$39.9($0.0)$0.7($0.2)$18.8$168.3($4.2)($5.5)($0.0)($22.7)($0.6)$1.0$174.22021 Quarterly State of the Market Report for PJM: January through June 575

2021 Quarterly State of the Market Report for PJM: January through June

Figure 11-2 shows the change in up to congestion balancing explicit CLMP
charges from January 2014 through June 2021. Figure 11-2 shows that UTCs
account for almost all balancing explicit CLMP charges in PJM. As shown in
Figure 11-2, UTCs are generally paid balancing CLMP credits, which take theform of negative balancing CLMP charges being allocated to UTC positions. In
the first six months of 2021, 99.8 percent (-$60.7 million out of -$60.8 million)of negative balancing explicit CLMP charges was incurred by UTCs and 0.2
percent (-$0.1 out of -$60.8 million) was incurred by Explicit Congestion
Only, Export, Import and Wheel In transactions (Table 11-13). The vertical line
at February 22, 2018, marks the date on which the FERC order that limited
UTC trading to hubs, residual metered load, and interfaces was effective.21 The
vertical line at November 1, 2020, marks the date on which the FERC orderthat required PJM to allocate uplift to up to congestion transactions was
effective.22

Figure 11-2 Monthly balancing explicit CLMP charges incurred by UTC:
January 2014 through June 2021
$40
$30
$20
$10

CLMP Charges (Millions)UTCs and Negative Balancing Explicit CLMP Charges

$0
-$10
-$20
-$30
-$40
-$50
-$60

Up to Congestion

Total Balancing Explicit CLMP Charges

22-Feb-18

1-Nov-20

Balancing congestion is caused by settling real-time deviations from dayahead positions at real-time prices. Whether balancing congestion is positiveor negative depends on the differences between the day-ahead and real-time
market models including modeled constraints, the transfer capability (linelimits) of the modeled constraints and the differences in deviations between
day-ahead and real-time flows that result. The deviations are priced at thereal-time LMPs.

21 For additional information about the FERC order, see the 2020 State of the Market Report for PJM, Appendix F: Congestion and Marginal
Losses.
22 172 FERC ¶ 61,046 (2020).

576

Section 11 Congestion and Marginal Losses

For example, one source of negative balancing congestion is that the PJM
system has less transmission transfer capability in the real-time market thanis modeled in the day-ahead market. In order to reduce processing time in
the presence of large number of virtual bids and offers, PJM only enforces
or models a subset of its physical transmission limits in the day-ahead© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

market. Transmission constraints not modeled in the day-ahead market haveunlimited transfer capability in the day-ahead market model. The inclusion of
the actual, lower transmission capability in the real-time market requires theuse of more high cost generation and the use of less low cost generation toserve load, which means a decrease in congestion.23 The reduction in real-timecongestion compared to day-ahead congestion creates negative balancing
congestion.
As a day-ahead spread bid, UTCs can take advantage of and profit from LMP
differences caused by modeling differences between the day-ahead and realtime market. UTCs clear between source and sink points with little or no
price difference in the day-ahead market, and settle the resulting deviations
at higher real-time price differences in the real-time market. The result isnegative balancing congestion caused by and paid to UTCs in the form of
CLMP credits. This is an example of false arbitrage because the UTCs cannot
cause prices to converge and the profits to decrease. As a result of the FERC
order requiring load to pay balancing congestion, load is responsible forpaying the balancing congestion caused by UTCs.24
Table 11-17 provides an example of how UTCs can profit from differences in
day-ahead and real-time models and generate negative balancing congestion.
In the example, Bus A and Bus B are linked by a transmission line. In the
day-ahead market the transmission limit is modeled as 9,999 MW (no limit
is enforced in the day-ahead market solution). In the real-time market thephysical limit between bus A and bus B is 50 MW. Generation at A has a priceof $1.00 and Generation at B has a price of $6. There is 100 MW of load at bus
A and 100 MW of load at bus B. There is a UTC of 200 MW that will sourceat bus A and sink at bus B if the spread in the prices between A and B is lessthan $1.
As a result of the fact that the transmission capability between A and B isunlimited in the day-ahead market, all of load at A and B can be met with
23 Although it seems counter intuitive, as the amount of low cost generation decreases and the amount of high cost generation increases,
the difference between load payments to generation and the payments received by generators goes down. High cost generation receives
what load pays.
24 On September 15, 2016, FERC ordered PJM to allocate balancing congestion to load, rather than to FTRs, to modify PJM’s Stage 1A ARR
allocation process and to continue to use portfolio netting. 153 FERC ¶ 61,180.

© 2021 Monitoring Analytics, LLC

the $1 generation at bus A. The constraint between A and B does not bind in
day-ahead so the price at A and B is $1. The price spread between bus A andbus B is zero, which is less than the UTC spread requirement of $1, so the UTC
clears. The UTC causes a 200 MW injection at A and 200 MW withdrawal at B,
creating 200 MW of flow between bus A and bus B. The 300 MW of combined
flow from generation at A and UTC injections at A to the load and UTC sink at
B does not exceed the DA modeled limit between A and B. This means that all
200 MW of the UTC injection at A and 200 MW of withdrawal at B can clear
without forcing a price spread between A and B. Total day-ahead congestion,
which is the difference between CLMP charges and credits, is zero. There is no
price difference between the two nodes and every MW of injection and every
MW of withdrawal at bus A and bus B settles at the same price.
In the real-time market, the transmission line between bus A and bus B has a
50 MW limit. The UTC does not physically exist in the real-time market andtherefore has deviations at Bus A (-200 MW) and at Bus B (+200 MW). The
UTC must buy at bus A at the real-time price and sell at bus B at the real-time
price to settle its deviations. The load at A (100 MW) and B (100 MW) does
not change, so there are no load deviations. With only 50 MW of transmission
capability between A and B, the generation at A cannot be used to meet totalload on the system. Generation from A meets the load at A (100 MW) and can
supply only 50 MW of the 100 MW of load at B. Due to the binding constraint
between A and B, the remaining 50 MW of load at B must be met with local
generation at B at a cost of $6 and the price at A remains $1.
The UTC must buy 200 MW at A at the real-time price of $1 and sell 200 MW
at B at the real-time price of $6. The UTC pays $200 at A and is paid $1,200
at B. The result is a net payment to the UTC of $1,000 in balancing credits.
Table 11-16 shows the balancing credits and charges associated with the realtime deviations in the example. Total congestion (day-ahead plus balancing
congestion) in this example is negative $1,250. Total CLMP credits (payments) togeneration and the UTC exceed the total charges collected from load. The negativebalancing congestion that results is paid by the load under the FERC order.25
25 153 FERC ¶ 61,180.

2021 Quarterly State of the Market Report for PJM: January through June 577

2021 Quarterly State of the Market Report for PJM: January through June

The UTC did not and could not contribute to price convergence between the
day-ahead and real-time market and did not and could not improve efficiency
in system dispatch or commitment. The UTC took advantage of the modelingdifferences between the day-ahead and real-time markets. The UTC did
significantly increase payments by load. Load was required to pay the UTC$1,000 in negative balancing, over and above the costs of generation that wasneeded to meet real-time load. The differences in modeling would have resulted
in only $250 in negative balancing congestion if there had been no UTCs.
Table 11-16 Example of UTC causing and profiting from negative balancing
congestion
PricesLMP DALMP RT
Day-Ahead MW
Day-Ahead Generation
Day-Ahead Load
Day-Ahead UTC (+/-)
Total MWDay-Ahead Credits and Charges
Total DA Gen Credits
Total DA Load Charges
Total DA UTC Credits
Total DA Credits
Total Day-Ahead Congestion (Charges - Credits)
Balancing Deviation MW
RT GEN Deviations
RT Load Deviations
DA UTC (+/-)
Total Deviations
Balancing Credits and Charges
Total BA Gen Credits
Total BA Load Charges
Total BA UTC Credits
Total BA Credits
Total Balancing Congestion (Charges - Credits)

578

Bus A
$1.00
$1.00
Bus A
200
(100)
200
300
Bus A
$200.00$100.00$200.00$300.00

Transfer Capability(Line Limit MW)
9,999
50

Bus A
(50)
0
(200)
(250)
Bus A
($50.00)$0.00($200.00)($250.00)

Section 11 Congestion and Marginal Losses

Bus B
$1.00
$6.00
Bus B
0
(100)
(200)
(300)
Bus B
$0.00
$100.00($200.00)($300.00)

Zonal and Load Aggregate Congestion
Zonal, and load aggregate, congestion is calculated on a constraint specificbasis for a specific location or set of load pricing nodes (a zone or an aggregate).
Local congestion is the difference between what load pays for energy andwhat generation is paid for energy due to individual binding transmission
constraints. Local congestion includes all energy charges or credits incurred
to serve a specific load, zone or load aggregate. Local congestion calculations
account for the total difference between what the specified load pays andwhat the generation that serves that load is paid, regardless of whether thezone is a net importer or a net exporter of generation.

Total MW
200
(200)
0
0
Total Day-Ahead Congestion

$0.00
$0.00
Total Deviations

Bus B
50
0
200
250
0
Bus B Balancing Congestion Credits$300.00$250.00$0.00$1,200.00$1,000.00$1,500.00$1,250.00($1,250.00)

Local congestion is calculated on a constraint specific basis.
Congestion is the total congestion payments by load at thebuses within a defined area minus total CLMP credits received
by generation that supplied that load, given the transmission
constraints. Congestion reflects the underlying characteristics ofthe entire power system as it affects the defined area, including
the nature and capability of transmission facilities, the offers
and geographic distribution of generation facilities, the level andgeographic distribution of decremental bids and incremental offers
and the geographic and temporal distribution of load.
On a system wide basis, congestion results from transmission
constraints that prevent the lowest cost generation from serving
some load that must be served by higher cost generation.

The total congestion caused by a constraint is equal to the productof the constraint shadow price times the net flow on the binding
constraint. Total congestion caused by the constraint can also be
calculated using the CLMPs caused by the constraint at every bus
and the net MW injections or MW withdrawals at every affectedbus. Congestion associated with a specific constraint is equal to load CLMP
charges (CLMP of that specific constraint at each bus times load MW at eachbus) caused by that constraint in excess of generation CLMP credits (CLMP© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Table 11-17 CLMP credits and charges and total congestion revenue collectedby zone (Dollars (Millions)): January through June, 2021of that specific constraint at each bus times generation MW at
each bus) caused by that constraint.
Constraint specific CLMPs are determined relative to areference bus, where there is no congestion and no losses.
For purposes of calculating the congestion from an individual
constraint, the reference bus for each constraint calculation is
the point that is just upstream of the constraint (the bus withthe greatest negative price effect from the constraint), allowing
any positive price effects of the constraint to be reflected as apositive CLMP.
In order to define the load that is actually paying congestion,congestion is appropriately assigned to downstream (positive
CLMP) load buses that paid the congestion caused by theconstraint, in proportion to the CLMP charges collected fromthat load due to that constraint. The congestion collected fromeach load bus due to a constraint is equal to the CLMP causedby that constraint times the MW of load at that load bus.
This calculation is done for both day-ahead congestion andbalancing congestion.

Control
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
EXT
JCPLC
MEC
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC
Total

Table 11-17 shows day-ahead and balancing congestion byzone for the first six months of 2021. AEP had the largest zonal
congestion costs among all control zones in the first six months of 2021.
AEP had $61.3 million in zonal congestion costs, comprised of $83.4 million
in zonal day-ahead congestion costs and -$22.2 million in zonal balancing
congestion costs. The Bagley - Raphael Road Line, the Three Mile Island
Transformer, the Bentonha - West Street Line, the Conastone Transformer, and
the Pleasant View – Ashburn Line contributed $14.9 million, or 24.3 percentof the AEP zonal congestion costs.26

Implicit
Withdrawal
Charges
$1.4
$23.6
$12.2
$10.2
$6.9
$14.2
$1.5
$24.1
$20.8
$1.9
$1.0
$1.3
$5.0
$3.2
$4.4
$0.1
$6.1
$9.2
$6.1
$7.5
$6.8
$1.1
$168.4

CLMP Credits and Charges (Millions)
Day-Ahead
Balancing
Implicit
Implicit
Implicit
Injection
Explicit
Withdrawal
Injection
Explicit
Credits
Charges
Total
Charges
Credits
Charges($2.4)$0.3$4.1($0.2)$0.6($0.6)($54.3)$5.5$83.4($3.5)$9.3($9.3)($20.2)$2.1$34.5($1.4)$3.6($3.5)($26.8)$2.7$39.7($1.7)$4.6($4.6)($10.2)$1.2$18.3($0.7)$2.1($2.4)($42.5)$4.7$61.3($2.5)$7.3($6.9)($7.2)$0.7$9.3($0.5)$1.3($1.3)($36.4)$3.9$64.4($2.4)$8.4($8.1)($2.7)$1.6$25.0($1.6)$1.0($1.3)($12.0)$1.1$15.0($0.7)$2.0($2.2)($4.2)$0.3$5.5($0.3)$0.9($0.9)($5.3)$0.5$7.1($0.4)$1.1($1.1)($7.5)$1.2$13.6($2.7)$4.5($3.4)($6.5)$0.7$10.3($0.5)$1.3($1.4)($5.7)$0.6$10.7($0.9)$1.2($1.2)($0.3)$0.1$0.5($0.0)$0.1($0.1)($5.8)$1.0$12.9($0.6)$2.1($1.4)($11.2)$1.4$21.8($1.0)$2.5($2.6)($9.0)$1.0$16.2($0.7)$2.0($2.0)($14.9)$2.1$24.4($1.1)$2.6($2.8)($12.5)$1.8$21.1($1.6)$3.1($3.5)($0.4)$1.1$2.5($0.1)$0.1($0.1)($297.9)$35.4$501.7($25.3)$61.6($60.8)Total($1.4)($22.2)($8.5)($10.9)($5.2)($16.7)($3.1)($18.9)($3.9)($4.9)($2.2)($2.5)($10.6)($3.2)($3.3)($0.2)($4.2)($6.1)($4.7)($6.5)($8.3)($0.3)($147.7)

Congestion
Costs
$2.7
$61.3
$26.0
$28.7
$13.0
$44.7
$6.2
$45.5
$21.2
$10.1
$3.4
$4.6
$3.0
$7.2
$7.4
$0.3
$8.8
$15.7
$11.5
$17.9
$12.8
$2.2
$354.0

Table 11-18 shows the congestion costs by zone for the first six months of2020.
26 For additional information about the top 20 constraints that affected each zone, see the 2020 State of the Market Report for PJM,
Appendix F: Congestion and Marginal Losses.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 579

2021 Quarterly State of the Market Report for PJM: January through June

Table 11-18 CLMP credits and charges and total congestion revenue collected by zone (Dollars (Millions)): January through June, 2020

Control
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
EXT
JCPLC
MEC
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC
Total

Implicit
Withdrawal
Charges
$0.4
$0.7
$4.8
$2.1
$2.2
($2.7)($0.2)
$5.2
$3.9
$0.1
($0.1)
$0.0
$0.7
$0.9
$1.2
$0.0
$2.3
$0.9
$1.8
$2.7
$2.0
$0.1
$28.9

CLMP Credits and Charges (Millions)
Day-Ahead
Balancing
Implicit
Implicit
Implicit
Injection
Explicit
Withdrawal
Injection
Explicit
Credits
Charges
Total
Charges
Credits
Charges($1.4)$0.4$2.2($0.0)$0.2($0.4)($32.6)$5.4$38.8($0.0)$2.9($5.9)($10.0)$1.9$16.6($0.0)$1.2($2.4)($15.4)$2.8$20.3($0.0)$1.5($3.1)($5.1)$1.0$8.3($0.0)$0.7($1.4)($29.2)
$6.0
$32.5
$0.0
$2.3
($4.0)($4.5)$0.8$5.1($0.0)$0.4($0.8)($20.5)
$3.2
$28.8
$0.0
$2.5
($4.8)($2.5)$1.0$7.4($0.0)$0.4($0.9)($6.1)$1.1$7.4($0.0)$0.6($1.3)($2.8)$0.4$3.1($0.0)$0.3($0.7)($3.3)$0.6$4.0($0.0)$0.3($0.6)($5.0)$1.1$6.7($0.0)$0.9($1.7)($4.1)$0.7$5.7($0.0)$0.4($0.9)($3.2)$0.5$4.8($0.0)$0.7($0.7)($0.2)
$0.3
$0.5
$0.0
$0.0
($0.0)($2.8)$0.7$5.8($0.0)$0.4($0.8)($6.9)$1.1$8.9($0.1)$0.8($1.7)($4.5)$0.9$7.2($0.0)$0.6($1.3)($7.2)$1.8$11.7($0.1)$0.9($1.8)($7.0)$1.3$10.3($0.1)$0.9($1.8)($0.2)$0.1$0.4($0.0)$0.0($0.1)($174.6)$32.9$236.4($0.4)$19.1($37.0)Total($0.6)($8.9)($3.6)($4.6)($2.1)($6.2)($1.2)($7.3)($1.4)($1.9)($1.0)($0.9)($2.5)($1.4)($1.4)($0.1)($1.3)($2.6)($1.9)($2.8)($2.8)($0.1)($56.6)

Congestion
Costs
$1.6
$29.9
$13.0
$15.7
$6.2
$26.2
$3.9
$21.5
$6.1
$5.5
$2.1
$3.1
$4.2
$4.3
$3.4
$0.4
$4.5
$6.3
$5.3
$8.9
$7.5
$0.3
$179.8In cases where the constraint causes net negative congestion and/or there is no load bus on the constrained side of a binding constraint, the congestion of theconstraint is handled as a special case. In the first six months of 2021, the total congestion costs associated with the special cases were -$3.7 million or -1.0
percent of the total congestion costs. Table 11-17 and Table 11-18 include congestion allocations from these special case constraints.
There are five categories of constraint specific allocation special cases: congestion associated with constraints with no downstream load bus (no load bus);
congestion associated with constraints with downstream load buses with zero value CLMPs (zero CLMP); congestion associated with closed loop interfaces(closed loop interfaces); congestion associated with CT price setting logic; and congestion associated with nontransmission facility constraints in the day-aheadenergy market and/or any unaccounted for difference between PJM billed CLMP charges and calculated congestion costs including rounding errors (unclassified).
Table 11-19 and Table 11-20 show total congestion by type of special case, congestion, and total congestion by zone. Closed loop interfaces and CT pricing
logic generally result in negative congestion on a constraint specific basis. PJM’s use of both the closed loop interfaces and CT Pricing Logic forces the affectedresource bus LMP to match the marginal offer of the resource. This causes higher CLMP payments to the affected generation than the CLMP load charges to any

580

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

affected load, resulting in negative congestion associated with the constraint. None of the closed loop interfaces were binding in the first six months of 2021
and 2020.
Table 11-19 CLMP charges and credits and total congestion collected by zone and special case logic (Dollars (Millions)): January through June, 2021
CLMP Credits and Charges (Millions)
Day-AheadControl
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
EXT
JCPLC
MEC
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC
Total

Load Bus
Zero CLMP
$0.0
$0.0
$0.0
$0.0
$0.0
$0.8
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.3
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$1.2

CT Price
Setting
Logic($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.2)© 2021 Monitoring Analytics, LLC

ClosedLoopInterfaces
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

No LoadBuses Unclassified$0.0($0.0)$0.2($0.0)$0.2($0.0)$0.0($0.0)$0.0($0.0)$2.4($0.0)$0.0($0.0)$0.0($0.0)$0.0($0.0)$0.1($0.0)$0.0($0.0)$0.0($0.0)$0.0($0.0)$0.0($0.0)$0.4($0.0)$0.1($0.0)$0.0($0.0)$0.0($0.0)$0.0($0.0)$0.0($0.0)$0.0($0.0)$0.0($0.0)$3.5($0.0)

Balancing

Contribution
$4.1
$83.3
$34.3
$39.7
$18.3
$58.1
$9.3
$64.4
$25.0
$14.9
$5.5
$7.1
$13.3
$10.3
$10.3
$0.4
$12.9
$21.8
$16.2
$24.4
$21.1
$2.5
$497.3

Total
$4.1
$83.4
$34.5
$39.7
$18.3
$61.3
$9.3
$64.4
$25.0
$15.0
$5.5
$7.1
$13.6
$10.3
$10.7
$0.5
$12.9
$21.8
$16.2
$24.4
$21.1
$2.5
$501.7

Load Bus
Zero CLMP
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
($0.0)$0.0$0.0($0.0)
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
($0.0)$0.0$0.0($0.0)CT Price
Setting
Logic($0.0)($0.5)($0.2)($0.3)($0.1)($0.4)($0.1)($0.4)($0.1)($0.1)($0.0)($0.1)($2.7)($0.1)($0.1)($0.0)($0.1)($0.2)($0.1)($0.2)($0.2)($0.0)($5.9)

ClosedLoopInterfaces
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

No LoadBuses Unclassified($0.0)($0.0)($0.0)($0.3)($0.0)($0.1)($0.0)($0.1)$0.0($0.1)$0.0($0.2)($0.0)($0.0)$0.0($0.2)($0.0)($0.0)$0.0($0.1)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.6)($0.0)($0.0)($0.1)$0.0($0.1)($0.0)($0.1)($0.0)($0.1)($0.0)($0.0)($0.6)($1.6)

Contribution($1.4)($21.4)($8.1)($10.6)($5.1)($16.1)($3.0)($18.3)($3.8)($4.8)($2.1)($2.4)($7.8)($3.0)($3.2)($0.2)($3.4)($5.8)($4.6)($6.2)($8.0)($0.3)($139.6)

Total($1.4)($22.2)($8.5)($10.9)($5.2)($16.7)($3.1)($18.9)($3.9)($4.9)($2.2)($2.5)($10.6)($3.2)($3.3)($0.2)($4.2)($6.1)($4.7)($6.5)($8.3)($0.3)($147.7)

Grand
Total
$2.7
$61.3
$26.0
$28.7
$13.0
$44.7
$6.2
$45.5
$21.2
$10.1
$3.4
$4.6
$3.0
$7.2
$7.4
$0.3
$8.8
$15.7
$11.5
$17.9
$12.8
$2.2
$354.0Special
Cases
Total($0.1)($0.6)($0.2)($0.4)($0.2)$2.6($0.1)($0.6)($0.1)($0.0)($0.1)($0.1)($2.4)($0.1)$0.3$0.1($0.7)($0.2)($0.2)($0.2)($0.2)($0.0)($3.7)

Percentof Special
Cases(2.1%)(1.1%)(0.7%)(1.4%)(1.4%)
5.9%(1.8%)(1.4%)(0.6%)(0.4%)(2.3%)(2.1%)(79.5%)(1.8%)
3.7%
20.9%(8.3%)(1.5%)(1.3%)(1.2%)(1.9%)(0.3%)(1.0%)

2021 Quarterly State of the Market Report for PJM: January through June 581

2021 Quarterly State of the Market Report for PJM: January through June

Table 11-20 CLMP charges and credits and congestion collected by zone and special case logic (Dollars (Millions)): January through June, 2020
CLMP Credits and Charges (Millions)
Day-AheadControl
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
EXT
JCPLC
MEC
OVEC
PE
PECO
PEPCO
PPL
PSEG
REC
Total

Load Bus
Zero CLMP
$0.0
$0.0
$0.0
$0.0
$0.0
$0.3
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.6
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.9

CT Price
Setting
Logic($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)$0.0($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)

ClosedLoopInterfaces
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

No LoadBuses Unclassified
$0.0
$0.0
$0.1
$0.4
$0.0
$0.2
$0.0
$0.2
$0.0
$0.1
$1.1
$0.3
$0.0
$0.1
$1.4
$0.3
$0.0
$0.0
$0.0
$0.1
$0.0
$0.0
$0.0
$0.0
$0.0
$0.1
$0.0
$0.1
$0.5
$0.0
$0.2
$0.0
$0.0
$0.1
$0.0
$0.1
$0.0
$0.1
$0.0
$0.1
$0.0
$0.1
$0.0
$0.0
$3.3
$2.3

Balancing

Contribution
$2.2
$38.3
$16.5
$20.1
$8.2
$30.8
$5.0
$27.2
$7.4
$7.3
$3.1
$3.9
$6.1
$5.6
$4.4
$0.3
$5.7
$8.8
$7.1
$11.6
$10.2
$0.4
$229.9

Total
$2.2
$38.8
$16.6
$20.3
$8.3
$32.5
$5.1
$28.8
$7.4
$7.4
$3.1
$4.0
$6.7
$5.7
$4.8
$0.5
$5.8
$8.9
$7.2
$11.7
$10.3
$0.4
$236.4

Load Bus
Zero CLMP($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)CT Price
Setting
Logic($0.0)($0.0)($0.0)($0.0)($0.0)($0.1)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.2)

ClosedLoopInterfaces
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

No LoadBuses Unclassified($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.3)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.4)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.0)($0.8)($0.2)

Contribution($0.6)($8.8)($3.6)($4.6)($2.1)($6.1)($1.2)($7.0)($1.3)($1.8)($1.0)($0.9)($2.5)($1.4)($1.1)($0.1)($1.3)($2.6)($1.9)($2.8)($2.7)($0.1)($55.4)Total($0.6)($8.9)($3.6)($4.6)($2.1)($6.2)($1.2)($7.3)($1.4)($1.9)($1.0)($0.9)($2.5)($1.4)($1.4)($0.1)($1.3)($2.6)($1.9)($2.8)($2.8)($0.1)($56.6)

Grand
Total
$1.6
$29.9
$13.0
$15.7
$6.2
$26.2
$3.9
$21.5
$6.1
$5.5
$2.1
$3.1
$4.2
$4.3
$3.4
$0.4
$4.5
$6.3
$5.3
$8.9
$7.5
$0.3
$179.8Special
Cases
Total
$0.0
$0.4
$0.1
$0.2
$0.1
$1.6
$0.0
$1.3
$0.0
$0.1
$0.0
$0.0
$0.7
$0.0
$0.1
$0.2
$0.0
$0.1
$0.1
$0.1
$0.1
$0.0
$5.3

Percentof Special
Cases
1.0%
1.3%
0.9%
1.0%
0.9%
6.1%
1.0%
6.3%
0.6%
1.1%
1.5%
0.9%
15.5%
0.9%
3.9%
53.1%
0.8%
1.1%
1.0%
1.1%
1.0%
1.1%
2.9%

Monthly Congestion
Table 11-21 shows day-ahead, balancing and inadvertent congestion costs by month for January 2020 through June 2021. Compared to the first six months of
2020, total congestion costs decreased in January, and increased in February through June. Total day-ahead congestion costs increased in every month fromJanuary through June and total negative balancing congestion costs increased in every month from January through June except for May.
In the first six months of 2021, May had the highest day-ahead congestion costs. The top two constraints that contributed most to day-ahead costs were thePleasant View - Ashburn Line and the Pleasant View Transformer. The high shadow prices of the two constraints were a result of a transmission outage on May
4, 2021, in the DOM zone.
In the first six months of 2021, February had the highest negative balancing congestion costs, as the combined result of cold weather, higher demand and higher
prices. CT pricing logic also contributed to the higher negative balancing congestion costs in the first six months of 2021 compared to the first six months

582

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Lossesof 2020. The top three constraints that contributed most to the negativebalancing congestion costs resulting from CT pricing logic were the Terminal
Transformer, the Coffeen North – Roxford Flowgate and the Bergenfield –Leonia Line.

Figure 11-3 shows PJM monthly total congestion cost for January 2008
through June 2021.
Figure 11-3 Monthly total congestion cost (Dollars (Millions)): January 2008
through June 2021

Table 11-21 Monthly congestion costs by market (Dollars (Millions)): January
2020 through June 2021

$800

2021
Inadvertent
BalancingCharges($24.1)($0.0)($53.4)$0.0($25.8)$0.0($18.0)($0.0)($10.5)$0.0($15.9)$0.0($147.7)

$0.0

Total
$29.1
$36.9
$55.2
$63.8
$94.0
$75.1

$354.0Monthly Total Congestion Cost

$700
$600
Congestion (Millions)

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

DayAhead
$43.3
$28.7
$31.4
$24.2
$46.1
$62.8
$105.6
$82.5
$78.1
$52.5
$41.3
$66.2
$662.5Congestion Costs (Millions)2020
Inadvertent
DayBalancing
Charges
Total
Ahead($5.6)
$0.0
$37.6
$53.2
($7.0)($0.0)$21.7$90.3($5.6)($0.0)$25.8$81.0($8.2)
$0.0
$16.0
$81.8
($19.5)$0.0$26.6$104.4($10.7)
$0.0
$52.0
$91.0
($23.8)$0.0$81.7($14.0)($0.0)$68.5($11.9)$0.0$66.1($9.3)$0.0$43.2($7.7)$0.0$33.6($10.4)$0.0$55.8($133.8)$0.0$528.7$501.7

$900

$500
$400
$300
$200
$100

$0

Table 11-22 shows monthly total CLMP credits and charges for each virtualtransaction type in January 2020 through June 2021. Virtual transaction CLMP
charges, when positive, are the total CLMP charges to the virtual transactions
and when negative, are the total CLMP credits to the virtual transactions.
The negative totals in Table 11-22 show that virtuals were paid, in net, CLMP
credits in the first six months of 2021 and 2020. In the first six months of2021, 44.2 percent of the total credits to virtuals went to UTCs, compared to38.8 percent in the first six months of 2020.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 583

2021 Quarterly State of the Market Report for PJM: January through June

Table 11-22 Monthly CLMP charges by virtual transaction type (Dollars(Millions)): January 2020 through June 2021
DEC
Year
2020

2021

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total
Jan
Feb
Mar
Apr
May
Jun
Total

DayAhead$0.2$0.2($0.8)($0.6)
$0.6
$1.0
$5.1
$5.1
$2.5
$1.0
($1.1)
$3.0
$16.1
$3.0
$11.8
$6.7
($1.1)
$0.5
$4.2
$25.1

Balancing($0.6)($0.2)($0.1)$0.8($0.6)($1.6)($3.7)($7.4)($5.9)($2.0)$1.4($6.2)($26.2)($8.0)($24.7)($7.7)$1.9($3.1)($6.5)($48.2)

CLMP Credits and Charges (Millions)
INC
DayTotal
Ahead Balancing
Total($0.4)$1.4($1.8)($0.4)($0.1)$1.3($1.5)($0.1)($0.9)$1.3($1.6)($0.2)$0.2$1.9($5.0)($3.0)$0.0$2.7($5.1)($2.4)($0.6)$1.7($2.8)($1.2)$1.4$0.9($3.5)($2.6)($2.4)$0.6($1.9)($1.3)($3.4)$1.7($1.5)$0.1($1.0)$1.6($3.2)($1.6)$0.3$3.0($5.4)($2.5)($3.2)($1.0)($1.3)($2.4)($10.1)$17.0($34.6)($17.6)($5.0)$0.5($0.1)$0.4($12.9)$0.6($4.0)($3.5)($1.0)$4.0($8.1)($4.2)$0.8$4.9($8.4)($3.5)($2.7)$2.4($2.6)($0.2)($2.3)$0.9($2.9)($2.0)($23.1)$13.4($26.2)($12.9)Up to Congestion
DayAhead Balancing
Total
$3.7
($2.9)$0.8$4.8($6.1)($1.3)$4.8($5.3)($0.5)$2.7($3.4)($0.7)$7.3($11.7)($4.4)$7.7($7.4)$0.3$9.1($16.2)($7.1)$5.8($7.6)($1.8)$6.9($5.3)$1.6$2.8($3.8)($1.1)$2.7($3.4)($0.7)$2.5($4.3)($1.8)$60.8($77.5)($16.7)$4.0($10.0)($6.0)$7.9($20.9)($13.0)$4.9($6.0)($1.1)$3.1($7.2)($4.2)$5.5($7.4)($1.9)$6.8($9.2)($2.3)$32.2($60.7)($28.5)Congested Facilities
A congestion event exists when a unit or units must be dispatched out of meritorder to control for the potential impact of a contingency on a monitoredfacility or to control an actual overload. A congestion event hour exists whena specific facility is constrained for one or more five-minute intervals within
an hour. A congestion event hour differs from a constrained hour, which is
any hour during which one or more facilities are congested. If two facilities
are constrained during an hour the result is one constrained hour and twocongestion event hours. Constraints are often simultaneous, so the number ofcongestion event hours usually exceeds the number of constrained hours andthe number of congestion event hours usually exceeds the number of hours
in a year.

584

Section 11 Congestion and Marginal Losses

Grand
Total
($0.0)($1.5)($1.6)($3.5)($6.8)($1.5)($8.3)($5.5)($1.7)($3.7)($2.9)($7.4)($44.4)($10.5)($29.4)($6.2)($6.8)($4.8)($6.6)($64.4)In order to have a consistent metric for real-time and day-aheadcongestion frequency, real-time congestion frequency is measured
using the convention that an hour is constrained if any of its
component five-minute intervals is constrained. This is consistent
with the way in which PJM reports real-time congestion.
In the first six months of 2021, there were 29,311 day-ahead,congestion event hours compared to 35,292 day-ahead congestion
event hours in the first six months of 2020. Of the day-aheadcongestion event hours in the first six months of 2021, only
4,960 (16.9 percent) were also constrained in the real-time energy
market (Table 11-25). In the first six months of 2021, there were
11,216 real-time, congestion event hours compared to 10,829
real-time, congestion event hours in the first six months of 2020.
Of the real-time congestion event hours in the first six months of2021, 4,983 (44.4 percent) were also constrained in the day-aheadenergy market (Table 11-26).

The top five constraints by congestion costs contributed $90.8
million, or 25.7 percent, of the total PJM congestion costs inthe first six months of 2021. The top five constraints were theBagley - Raphael Road Line, the Three Mile Island Transformer, the Harwood- Susquehanna Line, the Pleasant View - Ashburn Line, and the Cumberland- Juniata Line.
Four of the top 10 constraints by congestion costs are located in the BGE
Zone in the first six months of 2021 compared to two in the first six monthsof 2020 (Figure 11-4).

Congestion by Facility Type and Voltage
Day-ahead, congestion event hours decreased on all types of facilities except
flowgates. Interfaces decreased 1,697 congestion event hours from 1,733 dayahead, congestion event hours in the first six months of 2020 to 36 day-aheadcongestion event hours in the first six months of 2021 (Table 11-25). Of the
1,697 congestion event hours decrease in 2021 relative to 2020, 82.6 percent© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Lossesof the decreased hours were a result of the reduction in congestion event hours on the PA Central Interface associated with a reduction in scheduled transmission
outages.27
Real-time, congestion event hours increased on lines and flowgates and decreased on transformers and interfaces in the first six months of 2021 (Table 11-26).
Interfaces decreased 1,225 congestion event hours from 1,285 real-time, congestion event hours in the first six months of 2020 to 60 real-time congestion event
hours in the first six months of 2021. Of the 1,225 congestion event hours decrease, 95.1 percent of the decreased hours were on the PA Central Interface.
Day-ahead congestion costs increased on all types of facilities except interfaces in the first six months of 2021 compared to the first six months of 2020 (Table
11-23). The decrease of day-ahead congestion costs on interfaces was primarily a result of the decrease in day-ahead congestion event hours on the PA Central
Interface.
Negative balancing congestion costs increased on lines and transformers and decreased on interfaces and flowgates in the first six months of 2021 compared to
the first six months of 2020 (Table 11-24). Table 11-23 provides congestion event hour subtotals and congestion cost subtotals comparing the first six monthsof 2021 results by facility type: line, transformer, interface, flowgate and unclassified facilities.28 29
Table 11-23 Congestion summary (By facility type): January through June, 2021

Type
Flowgate
InterfaceLine
Transformer
Other
Unclassified
Total

Implicit
Withdrawal
Charges($10.4)$0.1$121.3
$35.1
$22.3
$0.0
$168.4

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges($61.0)$3.5($1.6)$0.1($177.7)$26.0($53.8)$3.5($3.8)$2.3$0.0($0.0)($297.9)$35.4

CLMP Credits and Charges (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges
$54.1
$0.8
$14.2
($9.6)$1.9($0.0)$0.2($0.2)$324.9($17.3)$36.0($44.4)$92.4($12.4)$4.0($4.3)
$28.4
$3.8
$6.5
($1.4)($0.0)($0.1)$0.6($0.9)$501.7($25.3)$61.6($60.8)

Event Hours

Total($23.0)($0.4)($97.7)($20.8)($4.2)($1.6)($147.7)

Congestion
Costs
$31.1
$1.5
$227.2$71.6$24.2($1.6)$354.0

DayAhead Real-Time
3,996
2,402
36
60
20,184
6,602
3,330
882
1,765
1,270
NA
NA
29,311
11,21627 The PA Central was created by PJM on October 1, 2018 to control for voltage contingencies associated with partially overlapping outages of three associated interface lines: Lackawanna - Hopatcong 500 kV line, Sunbury - Juniata 500 kV line and the Susquehanna - Wescosville 500 kV
line. Scheduled outages caused PJM to enforce PA Central for potential voltage drop contingencies in the area.
28 Unclassified are congestion costs related to nontransmission facility constraints in the day-ahead energy market and any unaccounted for difference between PJM billed CLMP charges and calculated congestion costs including rounding errors. Nontransmission facility constraints include
day-ahead market only constraints such as constraints on virtual transactions and constraints associated with phase-angle regulators.
29 The term flowgate refers to MISO reciprocal coordinated flowgates and NYISO M2M flowgates.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 585

2021 Quarterly State of the Market Report for PJM: January through June

Table 11-24 Congestion summary (By facility type): January through June, 2020

Type
Flowgate
InterfaceLine
Transformer
Other
Unclassified
Total

Implicit
Withdrawal
Charges($14.7)
$2.4
$32.7
$0.1
$8.6
($0.2)$28.9

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges($41.1)$11.4($14.7)$1.1($92.2)$14.5($21.6)$4.1($2.8)$1.5($2.1)$0.3($174.6)$32.9

CLMP Credits and Charges (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges$37.8($1.8)$2.8($23.8)
$18.2
$0.1
$2.3
($1.9)$139.4($0.0)$10.5($8.9)
$25.8
$0.1
$1.8
($0.9)
$12.9
$1.1
$1.7
($1.5)$2.3($0.0)$0.0($0.2)$236.4($0.4)$19.1($37.0)

Event Hours

Total($28.3)($4.0)($19.4)($2.6)($2.0)($0.2)($56.6)

Congestion
Costs
$9.5
$14.2
$120.0
$23.2
$10.8
$2.0
$179.8

DayAhead Real-Time
3,528
2,006
1,733
1,285
22,854
6,134
5,277
960
1,900
444
NA
NA
35,292
10,829

Table 11-25 and Table 11-26 compare day-ahead and real-time congestion event hours. Among the hours for which a facility is constrained in the day-aheadenergy market, the number of hours during which the facility is also constrained in the real-time energy market are presented in Table 11-25. In the first six
months of 2021, there were 29,311 congestion event hours in the day-ahead energy market. Of those day-ahead congestion event hours, only 4,960 (16.9
percent) were also constrained in the real-time energy market. In the first six months of 2020, of the 35,292 day-ahead congestion event hours, only 5,259 (14.9
percent) were binding in the real-time energy market.30
Among the hours for which a facility was constrained in the real-time energy market, the number of hours during which the facility was also constrained in
the day-ahead energy market are presented in Table 11-26. In the first six months of 2021, of the 11,216 congestion event hours in the real-time energy market,
4,983 (44.4 percent) were also constrained in the day-ahead energy market. In the first six months of 2020, of the 10,829 real-time congestion event hours,
5,350 (49.4 percent) were also in the day-ahead energy market.
Congestion frequency continued to be significantly higher in the day-ahead energy market than in the real-time energy market in the first six months of 2021.
The number of congestion event hours in the day-ahead energy market was about three times the number of congestion event hours in the real-time energy
market.
In the real-time market, PJM has the ability to model and monitor almost all PJM transmission facilities. In the day-ahead market, PJM can model and monitor
only a portion of PJM transmission facilities. This difference in modeling is the basis of false arbitrage and the source of significant virtual profits. While moreconstraints are modeled and monitored in the PJM real-time market than the day-ahead market, there is significantly more network flow in the day-aheadmarket than in the real-time market as a result of virtual bids and offers. Virtual bids and offers also contribute to day-ahead market flows that do not alignwith realized real-time physical flows. The number of congestion event hours in the day-ahead energy market was about three times the number of congestion
event hours in the real-time energy market, despite the fact that only a portion of PJM transmission facilities are modeled in the day-ahead market.

30 Constraints are mapped to transmission facilities. In the day-ahead energy market, within a given hour, a single facility may be associated with multiple constraints. In such situations, the same facility accounts for more than one constraint-hour for a given hour in the day-ahead energy
market. Similarly in the real-time market a facility may account for more than one constraint-hour within a given hour.

586

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Table 11-25 Congestion event hours (day-ahead against real-time): January through June, 2020 and 2021
Congestion Event Hours

Type
Interface
Transformer
Flowgate
Line
Other
Total

Day-Ahead
Constrained
1,733
5,277
3,528
22,8541,900
35,2922020 (Jan - Jun)
Corresponding
Real-Time
Constrained
1,016
521
683
2,807
232
5,259

Day-Ahead
Percent Constrained
58.6%
36
9.9%
3,330
19.4%
3,996
12.3%
20,184
12.2%
1,765
14.9%
29,3112021 (Jan - Jun)
Corresponding
Real-Time
Constrained
7
538
893
2,877
645
4,960

Percent
19.4%
16.2%
22.3%
14.3%
36.5%
16.9%

Table 11-26 Congestion event hours (real-time against day-ahead): January through June, 2020 and 2021
Congestion Event Hours

Type
Interface
Transformer
Flowgate
Line
Other
Total

Real-Time
Constrained
1,285
960
2,006
6,134
444
10,8292020 (Jan - Jun)
Corresponding
Day-Ahead
Constrained
1,053
544
685
2,835
233
5,350

© 2021 Monitoring Analytics, LLC

Real-Time
Percent Constrained
81.9%
60
56.7%
882
34.1%
2,402
46.2%
6,602
52.5%
1,270
49.4%
11,2162021 (Jan - Jun)
Corresponding
Day-Ahead
Constrained
7
543
893
2,895
645
4,983

Percent
11.7%
61.6%
37.2%
43.9%
50.8%
44.4%

2021 Quarterly State of the Market Report for PJM: January through June 587

2021 Quarterly State of the Market Report for PJM: January through June

Table 11-27 shows congestion costs by facility voltage class for the first six months of 2021. Congestion costs in the first six months of 2021 increased for all
facility voltage classes except 161 kV facilities compared to the first six months of 2020.
Table 11-27 Congestion summary (By facility voltage): January through June, 2021

Voltage (kV)
765
500
345
230
161
138
115
69
34
13.8
Unclassified
Total

Implicit
Withdrawal
Charges($0.3)$23.3($8.1)$110.8($2.1)
$24.9
$9.1
$10.8
$0.0
$0.0
$0.0
$168.4

Day-Ahead
Implicit
Injection
Explicit
Credits
Costs($1.2)$0.2($27.4)$2.0($39.1)$3.7($87.5)$16.5($6.8)$0.3($115.2)$9.6($18.0)$1.1($2.7)
$2.0
$0.0
$0.0
$0.0
$0.0
$0.0
($0.0)($297.9)$35.4

CLMP Credits and Charges (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Costs$1.1($0.5)$0.3($0.4)
$52.7
$1.9
$4.9
($0.4)$34.7($4.6)$5.0($7.0)$214.8($18.9)$20.4($27.9)$5.0($0.2)$0.6($0.9)$149.7($2.1)$24.4($22.1)$28.2($0.8)$2.3($0.6)
$15.5
$0.1
$3.2
($0.6)
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
($0.0)($0.1)$0.6($0.9)$501.7($25.3)$61.6($60.8)

Event Hours

Total($1.2)($3.4)($16.6)($67.2)($1.7)($48.7)($3.7)($3.7)$0.0$0.0($1.6)($147.7)

Congestion
Costs($0.1)$49.4$18.1$147.6$3.3$101.0
$24.4
$11.8
$0.0
$0.0
($1.6)$354.0

DayAhead
18
1,352
2,442
8,068
295
11,151
2,202
3,783
0
0
9,999
39,310

RealTime
5
1,086
1,000
3,687
287
4,169
694
288
0
0
9,999
21,215

Table 11-28 Congestion summary (By facility voltage): January through June, 2020

Voltage (kV)
765
500
345
230
161
138
115
69
34
13.8
Unclassified
Total

588

Implicit
Withdrawal
Charges$0.0$9.8($2.6)$40.1($7.1)($25.6)
$11.1
$3.4
$0.0
($0.0)($0.2)$28.9

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges$0.0$0.0($33.1)$2.5($10.8)$6.0($36.0)$5.5($19.2)$3.3($72.6)
$13.6
$0.7
$0.6
($1.3)
$1.0
$0.0
$0.0
($0.1)$0.0($2.1)$0.3($174.6)$32.9

CLMP Credits and Charges (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges
$0.0
$0.0
$0.0
$0.0
$45.5
$0.3
$6.1
($3.4)$14.3($0.3)$0.7($4.0)
$81.6
$1.1
$3.5
($2.3)$15.4($0.1)$2.1($7.4)$60.5($0.8)$6.1($19.3)$11.0($0.6)$0.6($0.2)$5.6($0.1)$0.0($0.2)
$0.0
$0.0
$0.0
$0.0
$0.1
$0.0
$0.0
$0.0
$2.3
($0.0)$0.0($0.2)$236.4($0.4)$19.1($37.0)Section 11 Congestion and Marginal Losses

Event Hours

Total
$0.0
($9.1)($5.0)($4.7)($9.5)($26.2)($1.5)($0.4)$0.0$0.0($0.2)($56.6)

Congestion
Costs
$0.0
$36.4
$9.3
$77.0
$5.9
$34.3
$9.5
$5.3
$0.0
$0.1
$2.0
$179.8

DayAhead
0
3,412
3,708
8,343
1,208
9,835
3,643
5,085
3
55
9,999
45,291

RealTime
0
2,009
324
3,030
811
2,866
1,638
151
0
0
9,999
20,828© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Constraint Frequency
Table 11-29 lists the constraints for the first six months of 2020 and 2021 that were most frequently binding and Table 11-30 shows the constraints which
experienced the largest change in congestion event hours from the first six months of 2020 to the first six months of 2021. In Table 11-29, constraints arepresented in descending order of total day-ahead event hours and real-time event hours for the first six months of 2021. In Table 11-30, the constraints arepresented in descending order of absolute value of day-ahead event hour changes plus real-time event hour changes from the first six months of 2020 to thefirst six months of 2021.
Table 11-29 Top 25 constraints: January through June, 2020 and 2021

No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25

Constraint
Cedar Grove Sub - William
Bagley - Raphael Road
Nottingham
Berwick - Koonsville
East Lima - Haviland
Northwest Tap - Purdue
Harwood - Susquehanna
Three Mile Island
Brighton
Face RockViennaNorth Coulterville
East Side - North Delphos
Bagley - Graceton
Graceton - Safe Harbor
Ramapo (ConEd) - S Mahwah (RECO)
Sandburg
Haumesser Road - Steward
Quad Cities
Cumberland - Juniata
Benton Harbor - Crystal
Gardners - Texas Eastern
Cayuga Starbus
Easton - Emuni
Essex - McCarter© 2021 Monitoring Analytics, LLC

Type
Line
Line
Other
Line
Line
Flowgate
Line
Transformer
Other
Other
Transformer
Flowgate
Line
Line
Line
Line
Flowgate
Line
Transformer
Line
Line
Line
FlowgateLine
Line

Event Hours
Day-Ahead
Real-Time(Jan - Jun)
(Jan - Jun)
2020
2021 Change
2020
2021 Change
0
1,143
1,143
0
570
570
23
1,004
981
0
679
679
726
816
90
263
460
197
254
1,112
858
1
1
0
203
697
494
0
312
312
7
453
446
16
468
452
845
608
(237)
327
309
(18)
382
635
253
152
226
74
0
283
283
0
500
500
665
587
(78)
44
176
132
0
555
555
0
144
144
0
380
380
0
288
288
0
498
498
0
156
156
1,523
371 (1,152)
577
275
(302)
289
497
208
94
134
40
33
546
513
0
0
0
176
243
67
110
273
163
266
267
1
255
242
(13)
476
503
27
0
0
0
129
363
234
70
139
69
0
404
404
12
97
85
376
431
55
4
52
48
0
265
265
0
205
205
1,188
452
(736)
9
5
(4)
0
328
328
0
106
106

Percent of Annual Hours
Day-Ahead
Real-Time(Jan - Jun)
(Jan - Jun)
2020
2021 Change
2020
2021 Change
0.0%
26%
26%
0%
13%
13%
1%
23%
23%
0%
16%
16%
17%
19%
2%
6%
11%
5%
6%
26%
20%
0%
0%
0%
5%
16%
11%
0%
7%
7%
0%
10%
10%
0%
11%
10%
19%
14%
(5%)
7%
7%
(0%)
9%
15%
6%
3%
5%
2%
0%
7%
7%
0%
12%
12%
15%
14%
(2%)
1%
4%
3%
0%
13%
13%
0%
3%
3%
0%
9%
9%
0%
7%
7%
0%
11%
11%
0%
4%
4%
35%
9% (26%)
13%
6%
(7%)
7%
11%
5%
2%
3%
1%
1%
13%
12%
0%
0%
0%
4%
6%
2%
3%
6%
4%
6%
6%
0%
6%
6%
(0%)
11%
12%
1%
0%
0%
0%
3%
8%
5%
2%
3%
2%
0%
9%
9%
0%
2%
2%
9%
10%
1%
0%
1%
1%
0%
6%
6%
0%
5%
5%
27%
10% (17%)
0%
0%
(0%)
0%
8%
8%
0%
2%
2%

2021 Quarterly State of the Market Report for PJM: January through June 589

2021 Quarterly State of the Market Report for PJM: January through June

Table 11-30 Top 25 constraints year to year change in occurrence: January through June, 2020 and 2021

No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25

590

Constraint
PA Central
Lenox - North Meshoppen
Cedar Grove Sub - William
Bagley - Raphael Road
Bagley - Graceton
Logtown - North Delphos
DoeX530
MountainNorthwest Tap - Purdue
Berwick - Koonsville
East Lima - Haviland
Brighton
Easton - Emuni
Easton - East Muni
ViennaNorth Coulterville
Paradise - BR Tap
East Side - North Delphos
Trenton - College Crn
Sayreville - SayrevillePeters - Union Jct
Conastone - Peach Bottom
Ironwood - North Lebanon
Prince George
Ramapo (ConEd) - S Mahwah (RECO)

Type
Interface
Line
Line
Line
Line
Line
Transformer
Transformer
Flowgate
Line
Line
Other
Line
Line
Transformer
Flowgate
Flowgate
Line
Line
Line
Line
Line
Line
Transformer
Line

Section 11 Congestion and Marginal Losses

Event Hours
Day-Ahead
Real-Time(Jan - Jun)
(Jan - Jun)
2020
2021 Change
2020
2021 Change
1,402
0 (1,402)
1,196
31 (1,165)
1,087
106
(981)
1,107
52 (1,055)
0
1,143
1,143
0
570
570
23
1,004
981
0
679
679
1,523
371 (1,152)
577
275
(302)
950
0
(950)
417
0
(417)
1,309
60 (1,249)
0
0
0
1,110
149
(961)
0
0
0
7
453
446
16
468
452
254
1,112
858
1
1
0
203
697
494
0
312
312
0
283
283
0
500
500
1,188
452
(736)
9
5
(4)
713
0
(713)
0
0
0
0
555
555
0
144
144
0
380
380
0
288
288
402
32
(370)
298
8
(290)
0
498
498
0
156
156
616
9
(607)
0
0
0
637
31
(606)
0
0
0
438
0
(438)
107
0
(107)
527
0
(527)
11
0
(11)
134
7
(127)
411
0
(411)
272
0
(272)
258
0
(258)
33
546
513
0
0
0

Percent of Annual Hours
Day-Ahead
Real-Time(Jan - Jun)
(Jan - Jun)
2020
2021 Change
2020
2021 Change
32%
0% (32%)27%
1% (27%)25%
2% (22%)25%
1% (24%)
0%
26%
26%
0%
13%
13%
1%
23%
23%
0%
16%
16%
35%
9% (26%)
13%
6%
(7%)
22%
0% (22%)
10%
0%
(10%)
30%
1% (29%)
0%
0%
0%
25%
3% (22%)
0%
0%
0%
0%
10%
10%
0%
11%
10%
6%
26%
20%
0%
0%
0%
5%
16%
11%
0%
7%
7%
0%
7%
7%
0%
12%
12%
27%
10% (17%)
0%
0%
(0%)
16%
0% (16%)
0%
0%
0%
0%
13%
13%
0%
3%
3%
0%
9%
9%
0%
7%
7%
9%
1%
(8%)
7%
0%
(7%)
0%
11%
11%
0%
4%
4%
14%
0% (14%)
0%
0%
0%
15%
1% (14%)
0%
0%
0%
10%
0%
(10%)
2%
0%
(2%)
12%
0% (12%)
0%
0%
(0%)
3%
0%
(3%)
9%
0%
(9%)
6%
0%
(6%)
6%
0%
(6%)
1%
13%
12%
0%
0%
0%

© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Constraint Costs
Table 11-31 and Table 11-32 show the top constraints contributing to congestion costs by facility for the first six months of 2021 and 2020. The Bagley - RaphaelRoad Line was the largest contributor to congestion costs in the first six months of 2021, with $20.9 million in total congestion costs and 5.9 percent of thetotal PJM congestion costs in the first six months of 2021. This was mainly caused by transmission outages in the BGE Zone associated with RTEP projects.
Table 11-31 Top 25 constraints affecting congestion costs: January through June, 202131

No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25

Constraint
Bagley - Raphael Road
Three Mile Island
Harwood - Susquehanna
Pleasant View - Ashburn
Cumberland - Juniata
ViennaConastone
Nottingham
Bagley - Graceton
Conastone - Northwest
Pleasant View
Graceton - Safe Harbor
East Lima - Haviland
Five Forks - Rock Ridge Tap
Cedar Grove Sub - William
Brighton
Bergenfield - Leonia
Brambleton - Evergreen Mills
Ashburn - Cochran Mill
East Side - North Delphos
Dauphin - Juniata
Krendale - Shanor Manor
Yukon
Smithton - Yukon
Preston - Tanyard
Top 25 Total
All Other Constraints
Total

Type
Line
Transformer
Line
Line
Line
Transformer
Transformer
Other
Line
Line
Transformer
Line
Line
Line
Line
Other
Line
Line
Line
Line
Line
Line
Transformer
Line
Line

Location
BGE
500
PPL
DOM
PPL
DPL
500
PECO
BGE
BGE
DOM
BGE
AEP
BGE
PSEG
500
PSEG
DOM
DOM
AEP
PPL
APS
500
APS
DPL

Implicit
Withdrawal
Charges
$18.9
$8.7
$3.7
$18.1
$2.6
$13.1
$8.2
$14.8
$8.7
$6.1
$2.8
$7.2
($14.8)
$2.2
$8.7
$7.2
$0.0
$1.5
$5.6
($9.9)($0.6)($2.6)($1.3)($0.6)$5.8$114.1$54.3$168.4

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges($2.7)$1.7($10.2)$0.7($16.2)
$0.8
$1.3
$0.4
($12.4)$1.1($8.5)$0.5($6.9)
$0.1
$1.3
$1.4
($1.6)$0.5($3.9)$0.2($8.1)$0.1($0.4)$0.6($22.7)$0.7($4.7)$0.5($9.6)
$5.2
$0.8
$0.6
$0.0
$0.0
($4.1)
$0.2
$0.2
$0.2
($15.3)$0.1($5.3)$0.5($7.8)($0.1)($6.4)$0.3($4.7)
$0.4
$1.5
$0.4
($146.5)$17.1($151.4)$18.3($297.9)$35.4

CLMP Credits and Charges (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges
$23.4
$1.7
$2.2
($2.1)
$19.6
$0.2
$0.2
($0.3)$20.6($0.2)$0.8($0.9)
$17.2
$0.6
$0.7
($0.7)$16.1($0.2)($0.8)($1.3)$22.1($9.6)($2.2)
$0.4
$15.3
$0.1
$0.3
($0.1)
$14.8
$0.0
$0.0
$0.0
$10.7
$0.3
$0.6
($0.0)
$10.2
$0.2
$0.2
($0.0)
$10.9
$1.1
$2.1
($1.4)
$8.2
$0.4
$0.4
($0.1)$8.6($0.6)$0.2($0.3)
$7.5
$0.2
$0.4
($0.1)$23.5($9.9)$8.9($11.7)
$7.0
$1.6
$2.1
$0.1
$0.0
($3.4)$1.1($1.9)
$5.7
$0.0
$0.0
$0.0
$5.6
$0.0
$0.0
$0.0
$5.6
($0.1)($0.1)($0.2)
$5.2
$0.0
$0.0
$0.0
$5.1
$0.0
($0.0)($0.0)$5.4($0.0)
$0.8
$0.5
$4.5
$0.3
$0.1
($0.2)$4.7($0.2)$0.1$0.0$277.7($17.6)$17.9($20.5)$224.0($7.7)$43.7($40.3)$501.7($25.3)$61.6($60.8)Total($2.5)($0.3)($1.8)($0.8)($0.7)($7.0)($0.3)$0.0($0.4)$0.0($2.5)($0.1)($1.0)($0.3)($30.5)($0.5)($6.4)$0.0$0.0($0.2)$0.0($0.0)($0.4)$0.0($0.3)($56.0)($91.7)($147.7)

Congestion
Costs
$20.9
$19.3
$18.8
$16.4
$15.4
$15.1
$15.0
$14.8
$10.4
$10.2
$8.5
$8.1
$7.5
$7.2
($7.0)$6.6($6.4)
$5.7
$5.6
$5.4
$5.2
$5.1
$5.0
$4.5
$4.4
$221.7$132.3$354.0Percent of Total
PJM Congestion
Costs
5.9%
5.5%
5.3%
4.6%
4.4%
4.3%
4.2%
4.2%
2.9%
2.9%
2.4%
2.3%
2.1%
2.0%
(2.0%)
1.9%(1.8%)
1.6%
1.6%
1.5%
1.5%
1.4%
1.4%
1.3%
1.2%
62.6%
37.4%
100.0%

31 All flowgates are mapped to MISO as Location if they are flowgates coordinated by both PJM and MISO regardless of the location of the flowgates.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 591

2021 Quarterly State of the Market Report for PJM: January through June

Table 11-32 Top 25 constraints affecting congestion costs: January through June, 202032

No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25

Constraint
Bagley - Graceton
Harwood - Susquehanna
PA Central
Conastone - Peach Bottom
Yukon
Pleasant View - Ashburn
Logtown - North Delphos
Three Mile Island
Cumberland - Juniata
Nottingham
Maple - Long Plant Tap
Paradise - BR Tap
Mohomet - ChampTP
Danville - East Danville
Quad Cities - Cordova
Conastone - Northwest
Nottingham
Collins
Lenox - North Meshoppen
Smithton - Yukon
Grant - Greentown
Seward - Towanda
Conastone - Graceton
Graceton - Safe Harbor
Powerton - Towerline
Top 25 Total
All Other Constraints
Total

Type
Line
Line
InterfaceLine
Transformer
Line
Line
Transformer
Line
Other
Flowgate
Flowgate
Flowgate
Line
FlowgateLine
OtherTransformer
Line
Line
Line
Line
Line
Line
Flowgate

Location
BGE
PPL
500
500
500
DOM
AEP
500
PPL
PECO
MISO
MISO
MISO
AEP
MISO
BGE
ATSI
COMED
PE
APS
AEP
PE
BGE
BGE
MISO

Implicit
Withdrawal
Charges
$18.1
$0.8
$1.1
$6.9
($3.2)$5.1($15.3)$2.4($1.3)$4.8($0.7)($2.9)($0.6)($2.1)($1.9)$3.5$3.3($0.1)($0.5)($1.1)($0.6)
$10.2
$0.2
$2.2
($1.3)
$27.3
$1.6
$28.9

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges($0.5)$1.3($14.9)$0.5($13.0)$0.8($1.5)$0.3($12.4)$0.6($1.6)$0.2($25.1)$2.1($2.1)$0.4($5.5)
$0.3
$1.3
$0.6
($1.9)$1.3($6.9)($0.1)($3.9)$1.9($5.6)$0.0($3.8)
$1.1
$0.4
$0.3
$0.8
$0.4
($1.2)$1.5($3.4)$0.0($3.0)$0.5($2.0)
$0.9
$8.1
$0.1
($2.0)
$0.0
$0.2
$0.3
($2.3)$1.1($101.7)$16.7($72.9)$16.1($174.6)$32.9

CLMP Credits and Charges (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges
$19.9
$0.0
$0.4
($0.4)$16.3($0.2)$0.4($0.3)
$14.9
$0.3
$1.7
($1.3)
$8.7
$0.0
$0.0
$0.0
$9.8
($0.1)$1.5($1.0)
$7.0
$0.4
$0.8
($0.2)$11.9($0.1)$2.9($2.8)
$5.0
$0.5
$0.2
($0.0)$4.5$0.0($0.0)($0.2)
$4.1
$0.0
$0.0
$0.0
$2.6
($1.3)$0.4($5.0)$3.8$0.0($0.0)($0.2)$5.3($0.1)($0.4)($1.9)
$3.5
$0.1
$0.2
($0.0)
$3.0
$0.0
$0.0
$0.0
$3.4
$0.1
$0.2
($0.3)$2.9$0.2($0.1)($0.4)
$2.6
$0.0
$0.0
$0.0
$2.9
$0.1
$0.5
$0.0
$2.5
$0.0
$0.0
($0.1)
$2.3
$0.0
$0.0
$0.0
$2.3
$0.0
$0.0
$0.0
$2.2
$0.0
$0.0
$0.0
$2.3
$0.1
$0.1
($0.0)$2.1$0.0($0.0)($0.0)$145.7$0.0$8.6($14.2)$90.6($0.4)$10.6($22.9)$236.4($0.4)$19.1($37.0)Total($0.7)($0.9)($2.7)$0.0($2.5)($0.6)($5.8)$0.2($0.2)$0.0($6.6)($0.1)($1.7)($0.1)$0.0($0.4)($0.1)$0.0($0.4)($0.0)
$0.0
$0.0
$0.0
($0.1)$0.0($22.7)($33.9)($56.6)

Congestion
Costs
$19.2
$15.4
$12.2
$8.7
$7.3
$6.3
$6.1
$5.2
$4.3
$4.1
($4.1)
$3.7
$3.6
$3.4
$3.0
$3.0
$2.8
$2.6
$2.6
$2.4
$2.3
$2.3
$2.2
$2.2
$2.1
$123.0$56.8$179.8Percent of Total
PJM Congestion
Costs
10.7%
8.6%
6.8%
4.8%
4.0%
3.5%
3.4%
2.9%
2.4%
2.3%
(2.3%)
2.1%
2.0%
1.9%
1.6%
1.6%
1.6%
1.4%
1.4%
1.4%
1.3%
1.3%
1.2%
1.2%
1.2%
68.4%
31.6%
100.0%

32 All flowgates are mapped to MISO as Location if they are flowgates coordinated by both PJM and MISO regardless the location of the flowgates.

592

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Figure 11-4 shows the locations of the top 10 constraints by total congestion
costs on a contour map of the real-time, load-weighted average CLMP in thefirst six months of 2021. Four of the top 10 constraints are located in the BGE
Zone: the Bagley - Raphael Road Line, the Conastone Transformer, the Bagley- Graceton Line and the Conastone – Northwest Line. Multiple constraints in
the BGE Control Zone have been in the top 10 constraints by total congestion
costs since 2016 as a result of RTEP projects in the BGE Zone.

Figure 11-5 shows the locations of the top 10 constraints by balancing
congestion costs on a contour map of the real-time, load-weighted, average
CLMP in the first six months of 2021.
Figure 11-5 Location of top 10 constraints by balancing congestion costs:
January through June, 2021

Figure 11-4 Location of the top 10 constraints by total congestion costs:
January through June, 2021

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 593

2021 Quarterly State of the Market Report for PJM: January through June

Figure 11-6 shows the locations of the top 10 constraints by day-aheadcongestion costs on a contour map of the day-ahead, load-weighted, average
CLMP in the first six months of 2021.
Figure 11-6 Location of the top 10 constraints by day-ahead congestion
costs: January through June, 2021

event hours in the first six months of 2020 to 29,311 congestion event hours
in the first six months of 2021 (Table 11-25).
Figure 11-7 shows the daily day-ahead and real-time congestion event hours
for January 2014 through June 2021.
Figure 11-7 Daily congestion event hours: January 2014 through June 2021
1,800
1,600

Day-Ahead
Real-Time
September 7, 2014

1,400

December 7, 2015
February 22, 2018
November 1, 2020

1,200

Hours

1,000
800
600
400

Congestion Event Summary: Impact of Changes in
UTC Volumes
UTCs have a significant impact on congestion events in the day-ahead market
and, as a result, contribute to differences between day-ahead and real-timecongestion events. The greater the volume of UTCs, the greater the numberof congestion events in the day-ahead market and the greater the differences
between the day-ahead and real-time congestion events.33

200
0

In the first six months of 2021, the average hourly cleared UTC MW decreasedby 59.8 percent, compared to the first six months of 2020. Day-aheadcongestion event hours decreased by 16.9 percent from 35,292 congestion
33 A series of FERC orders has affected UTC activity which has in turn affected congestion events in the day-ahead market. See Appendix F:
Congestion and Marginal Losses.

594

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Marginal Losses
Marginal Loss Accounting
Marginal losses occur in the day-ahead and real-time energy markets.
PJM calculates marginal loss costs for each PJM member. The loss cost isbased on the applicable day-ahead and real-time marginal loss componentof LMP (MLMP). Losses are the difference between what load (withdrawals)
pay for energy and what generation (injections) are paid for energy, due totransmission line losses.
Losses increase with distance between sources and sinks and the amount of
power moved. Total loss collected (loss surplus) increases with load, holding
distance and resistance constant. Every incremental increase in load has to be
met with a slightly larger increment of generation. The result is that the totalenergy losses increase as load increases.
Ignoring interchange, total generation MWh must be greater than total load
MWh in any hour in order to provide for losses. Total marginal loss costs,
analogous to total congestion costs, are equal to the net of the withdrawal
loss charges minus injection loss credits, plus explicit loss charges, incurred inboth the day-ahead energy market and the balancing energy market.
Total marginal loss costs can be more accurately thought of as net marginalloss costs. Total marginal loss costs equal implicit marginal loss charges plus
explicit marginal loss charges plus net inadvertent loss charges. Implicit
marginal loss charges equal withdrawal loss charges minus injection loss credits.
Net explicit marginal loss costs are the net marginal loss costs associated withpoint to point energy transactions. Net inadvertent loss charges are the losses
associated with the hourly difference between the net actual energy flow andthe net scheduled energy flow into or out of the PJM control area.34 Unlike
the other categories of marginal loss accounting, inadvertent loss charges arecosts not directly attributable to specific participants. Inadvertent loss charges
are assigned to participants based on real-time load (excluding losses) ratio

34 PJM Operating Agreement Schedule 1 §3.7.

© 2021 Monitoring Analytics, LLC

share.35 Each of these categories of marginal loss costs is comprised of dayahead and balancing marginal loss costs.
The accounting definitions can be misleading. Load pays losses. Losses are
the difference between what load pays for energy and what generation is paid
for energy due to losses. Generation does not pay losses. Some generation
receives a price lower than SMP and some generation receives a price greaterthan SMP due to the MLMP but that does not mean that generation is paying
or being paid losses. It means that generation is being paid an LMP that ishigher or lower than the system load-weighted, average LMP due to losses on
the system.
While PJM accounting focuses on MLMPs, the individual MLMP values atany bus are irrelevant to the calculation of total losses. Total losses are thenet surplus revenue that remains after all sources and sinks are credited or
charged their LMPs. Changing the components of LMP by electing a different
reference bus does not change the LMPs or the difference between LMPs for agiven market solution or losses, it merely changes the components of the LMP.
The MLMP component of LMP is the marginal cost of energy, due to losses
associated with serving load at the bus. The MLMP at the load weighted
reference bus is the marginal cost of energy at the load weighted reference bus(holding the proportion of load at every bus constant). Due to losses, MLMP
is non zero at the load reference bus. The LMP at the load reference bus is thesystem marginal price of energy (SMP) plus the marginal cost of energy due
to losses at the reference bus.
Load-weighted LMP components are calculated relative to a load-weighted,
average LMP. LMPs at specific load buses will reflect the fact that marginal
generators must produce more (or less) energy due to losses to serve that bus
than is needed to serve the load weighted reference bus. The LMP at any bus isa function of the SMP, losses and congestion. Relative to the system marginal
price (SMP) at the load weighted reference bus, the loss factor can be either
positive or negative.
35 Id.

2021 Quarterly State of the Market Report for PJM: January through June 595

2021 Quarterly State of the Market Report for PJM: January through JuneAt the load-weighted reference bus, the LMP includes no congestion component,
but does include a loss component. The load weighted, average MLMP acrossall load buses, calculated relative to that reference bus is positive. The LMPs
at the load buses are a function of marginal generation bus LMPs determinedthrough the least cost security constrained economic dispatch which accounts
for transmission constraints and marginal losses.
Other than the effect on the optimal dispatch point, LMP at the marginal
generator bus, and therefore the payment to the generator, is not affected bymarginal losses. By paying for losses based on marginal instead of average
losses at the load bus, a revenue over collection occurs.
The residual difference between total marginal loss related load charges (dayahead and balancing) and marginal loss related generation credits (day-ahead
and balancing) after virtual bids have settled their marginal loss related
credits and charges for their day-ahead and balancing positions is total loss.
That is, losses are the difference between what withdrawals (load) are paying
for energy and what injections (generation) are being paid for energy due tolosses, after virtual bids marginal loss related charges and credits are settled
at the end of the market day. Load is the source of the net loss surplus aftergeneration is paid and virtuals are settled at the end of the market day. Loadpays losses. Generation does not pay losses.
Day-ahead marginal loss costs are based on day-ahead MWh priced at themarginal loss price component of LMP. Balancing marginal loss costs are
based on the load or generation deviations between the day-ahead and realtime energy markets priced at the marginal loss price component of LMP in
the real-time energy market. If a participant has real-time generation or loadthat is greater than its day-ahead generation or load then the deviation will
be positive. If there is a positive load deviation at a bus where the real-time
LMP has a positive marginal loss component, positive balancing marginal loss
costs will result. Similarly, if there is a positive load deviation at a bus wherereal-time LMP has a negative marginal loss component, negative balancing
marginal loss costs will result. If a participant has real-time generation or loadthat is less than its day-ahead generation or load then the deviation will be

596

Section 11 Congestion and Marginal Losses

negative. If there is a negative load deviation at a bus where real-time LMP
has a positive marginal loss component, negative balancing marginal loss
costs will result. Similarly, if there is a negative load deviation at a bus wherereal-time LMP has a negative marginal loss component, positive balancing
marginal loss costs will result.
The total marginal loss surplus is the remaining loss amount from collectionof marginal losses, after accounting for total system energy costs and net
residual market adjustments. The marginal loss surplus is allocated to PJM
market participants based on real-time load plus export ratio share as marginalloss credits.36

Day-Ahead Implicit Load MLMP Charges• Day-Ahead Implicit Load MLMP Charges. Day-ahead implicit load MLMP

charges are calculated for all cleared demand, decrement bids and dayahead energy market sale transactions. Day-ahead implicit load MLMP
charges are calculated using MW and the load bus MLMP, the decrementbid MLMP or the MLMP at the source of the sale transaction.

• Day-Ahead Implicit Generation MLMP Credits. Day-ahead implicit

generation MLMP credits are calculated for all cleared generation andincrement offers and day-ahead energy market purchase transactions.
Day-ahead implicit generation MLMP credits are calculated using MW
and the generator bus MLMP, the increment offer MLMP or the MLMP at
the sink of the purchase transaction.

• Balancing Implicit Load MLMP Charges. Balancing implicit load MLMP

charges are calculated for all deviations between a PJM member’s realtime load and energy sale transactions and their day-ahead cleared
demand, decrement bids and energy sale transactions. Balancing implicit
load MLMP charges are calculated using MW deviations and the real-time
MLMP for each bus where a deviation exists.

• Balancing Implicit Generation MLMP Credits. Balancing implicit Generation
MLMP credits are calculated for all deviations between a PJM member’s
real-time generation and energy purchase transactions and the day-ahead

36 See PJM. “Manual 28: Operating Agreement Accounting,” Rev. 84 (Dec. 17, 2020).

© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

cleared generation, increment offers and energy purchase transactions.
Balancing implicit Generation MLMP credits are calculated using MW
deviations and the real-time MLMP for each bus where a deviation exists.

• Explicit Loss Charges. Explicit loss charges are the net loss costs associated•with point to point energy transactions, including UTCs. These costs
equal the product of the transacted MW and MLMP differences between
sources (origins) and sinks (destinations) in the day-ahead energy market.
Balancing energy market explicit loss costs equal the product of thedifferences between the real-time and day-ahead transacted MW and thedifferences between the real-time MLMP at the transactions’ sources andsinks.
Inadvertent Loss Charges. Inadvertent loss charges are the net loss charges
resulting from the differences between the net actual energy flow andthe net scheduled energy flow into or out of the PJM control area eachhour. This inadvertent interchange of energy may be positive or negative,
where positive interchange typically results in a charge while negativeinterchange typically results in a credit. Inadvertent loss charges arecommon costs, not directly attributable to specific participants, that are
distributed on a load plus export ratio basis.37

Total Marginal Loss Cost
Total marginal loss is the difference between what withdrawals (load) pay
for energy and what injections (generation) are paid for energy due to losses,
after generation is paid and virtuals’ marginal loss related charges and credits
are settled. Load pays losses.

Monthly marginal loss costs in the first six months of 2021 ranged from $42.5
million in April to $102.7 million in February. Total marginal loss surplus
increased in the first six months of 2021 by $74.4 million or 124.7 percent
from $59.7 million in the first six months of 2020 to $134.0 million in thefirst six months of 2021.
Table 11-33 shows the total marginal loss component costs and the total PJM
billing for the first six months of 2008 through 2021.
Table 11-33 Total loss component costs (Dollars (Millions)): January throughJune, 2008 through 202138(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Loss
Costs
$1,271
$705
$751
$701
$445
$494
$1,006
$608
$306
$321
$521
$325
$193
$376

Percent
ChangeNA(44.6%)
6.5%(6.6%)(36.6%)
11.2%
103.5%(39.5%)(49.7%)
4.8%
62.6%(37.7%)(40.5%)
94.3%

Total
PJM Billing$16,549$13,457$16,314$18,685$13,991$15,571$31,060$23,390$18,290$18,960$25,780$20,070$15,570$20,410Percent of
PJM Billing
7.7%
5.2%
4.6%
3.8%
3.2%
3.2%
3.2%
2.6%
1.7%
1.7%
2.0%
1.6%
1.2%
1.8%

The total marginal loss cost in PJM for the first six months of 2021 was $375.9
million, which was comprised of implicit load MLMP charges of -$4.8 million
minus implicit generation MLMP credits of -$384.1 million plus explicit loss
charges of -$3.4 million plus inadvertent loss charges of $0.0 million (Table
11-34).

37 PJM Operating Agreement Schedule 1 §3.7.

© 2021 Monitoring Analytics, LLC

38 The loss costs include net inadvertent charges.

2021 Quarterly State of the Market Report for PJM: January through June 597

2021 Quarterly State of the Market Report for PJM: January through June

Table 11-34 shows PJM total marginal loss costs by accounting category for the first six months of 2008 through 2021. Table 11-35 shows PJM total marginalloss costs by accounting category by market for the first six months of 2008 through 2021.
Table 11-34 Total marginal loss costs by accounting category (Dollars (Millions)): January through June, 2008 through 2021

(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Implicit
Withdrawal
Charges($130.8)($42.2)($15.7)($70.6)($17.9)$8.6($35.7)($15.4)($19.5)($24.9)($22.9)($22.9)($18.5)($4.8)

Marginal Loss Costs (Millions)
Implicit
Injection
Explicit
Credits
Charges($1,349.6)$52.4($726.4)$20.7($750.5)$16.2($755.3)$16.8($473.4)($10.6)($512.4)($26.6)($1,083.3)($41.4)($635.5)($11.9)($338.7)($13.4)($363.5)($17.9)($550.3)($6.0)($354.6)($6.6)($219.3)($7.3)($384.1)($3.4)

Inadvertent
Charges$0.0$0.0($0.0)$0.0$0.0($0.0)
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

Total
$1,271.2$704.8$750.9$701.5$444.9$494.5$1,006.2$608.3$305.8$320.6$521.4$325.0$193.4$375.9

Table 11-35 Total marginal loss costs by market (Dollars (Millions)): January through June, 2008 through 2021

(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

598

Implicit
Withdrawal
Charges($64.9)($43.8)($27.2)($90.4)($30.4)($7.2)($75.4)($33.2)($23.3)($29.6)($26.3)($23.1)($19.0)($4.5)

Day-Ahead
Implicit
Injection Explicit
Credits Charges($1,299.8)$64.3($723.3)$44.6($751.6)$33.5($774.1)$44.3($481.4)$15.5($528.2)$25.0($1,118.8)$51.6($643.0)$15.6($339.8)$18.9($364.1)$30.2($543.9)$16.7($352.1)$22.7($219.8)$18.6($382.4)$16.5

Marginal Loss Costs (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection Explicit
Total
Charges
Credits Charges$1,299.2($65.9)($49.8)($11.9)$724.1$1.5($3.1)($23.9)$757.9$11.4$1.2($17.3)$728.1$19.8$18.8($27.5)$466.5$12.5$8.0($26.1)$546.0$15.9$15.8($51.6)$1,095.0
$39.7
$35.6
($93.0)$625.4$17.8$7.4($27.5)$335.4$3.9$1.1($32.4)$364.7$4.6$0.6($48.1)$534.4$3.4($6.3)($22.7)$351.7$0.1($2.5)($29.3)$219.4$0.5$0.5($26.0)$394.4($0.3)($1.7)($19.8)

Section 11 Congestion and Marginal Losses

Total($28.0)($19.3)($7.0)($26.6)($21.6)($51.6)($88.8)($17.1)($29.5)($44.0)($12.9)($26.7)($25.9)($18.4)

Inadvertent
Charges$0.0$0.0($0.0)$0.0$0.0($0.0)
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

Grand
Total
$1,271.2$704.8$750.9$701.5$444.9$494.5$1,006.2$608.3$305.8$320.6$521.4$325.0$193.4$375.9© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Table 11-36 and Table 11-37 show PJM accounting based total loss costs for each transaction type in the first six months of 2021 and 2020.
Virtual transaction loss costs, when positive, measure the total loss costs to virtual transactions and when negative, measure the total loss credits to virtualtransaction. In the first six months of 2021, DECs paid $1.4 million in LLMP charges in the day-ahead market, were paid $0.1 million in LLMP credits in thebalancing energy market and paid $1.4 million in total LLMP charges. In the first six months of 2021, INCs paid $5.7 million in LLMP charges in the day-aheadmarket, were paid $6.5 million in LLMP credits in the balancing energy market and were paid $0.7 million in total LLMP credits. In the first six months of 2021,
up to congestion paid $16.7 million in LLMP charges in the day-ahead market, were paid $20.1 million in LLMP credits in the balancing energy market andreceived $3.4 million in total LLMP credits.
Table 11-36 Total loss costs by transaction type (Dollars (Millions)): January through June, 2021

Transaction TypeDEC
DemandDemand Response
Explicit Congestion and Loss Only
ExportGeneration
ImportINC
Internal Bilateral
Up to Congestion
Wheel In
Total

Implicit
Withdrawal
Charges
$1.4
$6.3
$0.0
$0.0
($8.2)
$0.0
$0.0
$0.0
($4.0)$0.0$0.0($4.5)

Day-Ahead
Implicit
Injection Explicit
Credits Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
($0.4)$0.0($0.0)($372.2)$0.0($0.7)$0.0($5.7)$0.0($3.8)
$0.2
$0.0
$16.7
$0.0
$0.0
($382.4)$16.5

Marginal Loss Costs (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection Explicit
Total
Charges
Credits Charges$1.4($0.1)
$0.0
$0.0
$6.3
$2.9
$0.0
$0.0
$0.0
($0.0)$0.0$0.0($0.4)$0.0$0.0($0.0)($8.3)($2.3)$0.0$0.3$372.2$0.0($5.8)
$0.0
$0.7
$0.0
($1.5)
$0.0
$5.7
$0.0
$6.5
$0.0
($0.0)($0.8)($0.8)
$0.0
$16.7
$0.0
$0.0
($20.1)
$0.0
$0.0
$0.0
($0.0)$394.4($0.3)($1.7)($19.8)Total($0.1)$2.9($0.0)($0.0)($2.0)$5.8$1.5($6.5)($0.0)($20.1)($0.0)($18.4)

Inadvertent
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

Grand
Total
$1.4
$9.2
$0.0
($0.4)($10.3)$378.0$2.2($0.7)($0.0)($3.4)($0.0)$375.9

Table 11-37 Total loss costs by transaction type (Dollars (Millions)): January through June, 2020

Transaction TypeDEC
DemandDemand Response
Explicit Congestion and Loss Only
ExportGeneration
ImportINC
Internal Bilateral
Up to Congestion
Wheel In
Total

© 2021 Monitoring Analytics, LLC

Implicit
Withdrawal
Charges($1.1)($1.8)($0.0)$0.0($4.8)
$0.0
$0.0
$0.0
($11.3)$0.0$0.0($19.0)Day-Ahead
Implicit
Injection Explicit
Credits Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
($0.1)$0.0$0.0($204.6)$0.0($0.4)$0.0($3.7)$0.0($11.1)
$0.2
$0.0
$18.6
$0.0
$0.0
($219.8)$18.6

Marginal Loss Costs (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection Explicit
Total
Charges
Credits Charges($1.1)
$1.7
$0.0
$0.0
($1.8)
$1.4
$0.0
$0.0
($0.0)
$0.0
$0.0
$0.0
($0.1)$0.0$0.0($0.0)($4.8)($2.1)$0.0$0.2$204.6$0.0($3.0)
$0.0
$0.4
$0.0
($0.5)($0.0)
$3.7
$0.0
$4.4
$0.0
$0.0
($0.5)($0.5)
$0.0
$18.6
$0.0
$0.0
($26.2)
$0.0
$0.0
$0.0
($0.0)$219.4$0.5$0.5($26.0)

Total
$1.7
$1.4
$0.0
($0.0)($1.9)$3.0$0.5($4.4)($0.0)($26.2)($0.0)($25.9)Inadvertent
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0

Grand
Total
$0.6
($0.4)($0.0)($0.1)($6.7)$207.5$0.9($0.7)($0.0)($7.6)($0.0)$193.42021 Quarterly State of the Market Report for PJM: January through June 599

2021 Quarterly State of the Market Report for PJM: January through June

Monthly Marginal Loss Costs
Table 11-38 shows a monthly summary of marginal loss costs by market typefor January 2020 through June 2021.
Table 11-38 Monthly marginal loss costs (Millions): January 2020 throughJune 2021
2021
Inadvertent
BalancingCharges($2.1)($0.0)($5.1)$0.0($3.7)$0.0($1.8)($0.0)($3.0)$0.0($2.8)$0.0($18.4)$0.0

Figure 11-8 Monthly marginal loss cost (Dollars (Millions)): January 2008
through June 2021
$450
$400

Total
$59.9
$102.7
$47.2
$42.5
$50.4
$73.3

$375.9Monthly Marginal Loss Cost

$350

Marginal Loss Cost (Millions)

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

DayAhead
$49.8
$39.8
$32.4
$25.9
$30.4
$41.0
$73.2
$59.8
$39.1
$37.0
$37.8
$59.9
$526.3

Marginal Loss Costs (Millions)2020
Inadvertent
DayBalancing
Charges
Total
Ahead($5.3)($0.0)$44.5$62.0($4.6)($0.0)$35.2$107.7($3.5)($0.0)$28.8$50.8($3.4)($0.0)$22.5$44.4($4.8)
$0.0
$25.7
$53.4
($4.3)
$0.0
$36.7
$76.1
($6.1)$0.0$67.0($5.8)($0.0)$54.0($4.4)$0.0$34.8($3.0)$0.0$34.0($1.4)$0.0$36.4($1.1)$0.0$58.8($47.7)$0.0$478.5$394.4

Figure 11-8 shows PJM monthly marginal loss costs for January 2008 throughJune 2021.

$300
$250
$200
$150
$100
$50
$0

600

Section 11 Congestion and Marginal Losses© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Table 11-39 shows the monthly total loss charges for each virtual transaction
type for January 2020 through June 2021.

energy component of LMP is the same for every bus within every hour, thenet energy bill is negative (ignoring net interchange), with more injection
credits than withdrawal charges in every hour. The greater the level of load
Table 11-39 Monthly loss charges by virtual transaction type (Dollars
the greater the difference between energy charges collected from load (SMP
(Millions)): January 2020 through June 2021
x load MW) and credited to generation (SMP x generation MW).
Marginal Loss Charges (Millions)
Total system energy costs plus total marginal loss costs plus net
DEC
INC
Up to Congestion
residual market adjustments equal marginal loss credits which are
DayDayDayGrandYear
Ahead Balancing
Total
Ahead Balancing
Total
Ahead Balancing
Total
Total
distributed to the PJM market participants according to the ratio
2020 Jan($0.1)$0.1($0.0)$0.7($0.9)($0.2)$3.7($5.2)($1.5)($1.7)of their real-time load plus their real-time exports to total PJM
Feb($0.1)
$0.2
$0.0
$0.6
($0.8)($0.2)$3.2($4.4)($1.2)($1.3)
real-time load plus real-time exports as marginal loss credits.
Mar($0.3)
$0.4
$0.1
$0.6
($0.7)($0.1)$2.5($3.7)($1.2)($1.3)
Apr($0.2)
$0.4
$0.1
$0.6
($0.7)($0.1)$2.3($3.5)($1.2)($1.1)The net residual market adjustment is calculated as known dayMay($0.1)
$0.2
$0.1
$0.8
($0.8)$0.0$3.7($4.8)($1.1)($0.9)
ahead error value minus day-ahead loss MW congestion valueJun($0.2)
$0.5
$0.2
$0.5
($0.6)($0.1)$3.1($4.6)($1.4)($1.3)
Jul($0.3)
$0.8
$0.4
$0.9
($0.9)($0.0)$5.1($6.5)($1.4)($1.0)and minus balancing loss MW congestion value.

2021

Aug
Sep
Oct
Nov
Dec
Total
Jan
Feb
Mar
Apr
May
Jun
Total

($0.1)($0.1)$0.0($0.5)$0.3($1.8)
$0.3
$1.1
$0.2
($0.3)($0.0)
$0.1
$1.4

$0.4
$0.2
$0.1
$0.6
$0.1
$3.9
($0.1)($0.7)
$0.2
$0.3
$0.1
$0.1
($0.1)

$0.3
$0.2
$0.2
$0.1
$0.4
$2.1
$0.2
$0.4
$0.4
$0.1
$0.0
$0.2
$1.4

$0.6
$0.5
$0.7
$0.7
$0.7
$7.7
$0.8
$0.8
$1.2
$1.2
$1.0
$0.7
$5.7

($0.7)($0.6)($0.8)($0.8)($0.9)($9.0)($1.1)($0.9)($1.3)($1.1)($1.1)($1.0)($6.5)($0.1)($0.1)($0.1)($0.0)($0.3)($1.3)($0.3)($0.1)($0.2)$0.0($0.1)($0.2)($0.7)

$4.1
$2.8
$2.5
$1.6
$1.9
$36.5
$2.2
$4.5
$2.5
$1.8
$2.5
$3.2
$16.7

($6.2)($4.2)($3.0)($2.1)($2.4)($50.6)($2.6)($4.7)($3.2)($2.2)($3.2)($4.2)($20.1)($2.2)($1.4)($0.6)($0.4)($0.5)($14.1)($0.4)($0.2)($0.7)($0.4)($0.7)($1.1)($3.4)($2.0)($1.4)($0.5)($0.4)($0.4)($13.3)($0.5)$0.1($0.5)($0.2)($0.7)($1.0)($2.8)

Table 11-40 shows the total system energy costs, the total marginalloss costs collected, the net residual market adjustments andtotal marginal loss surplus redistributed for the first six monthsof 2008 through 2021. The total marginal loss surplus increased$74.4 million or 124.7 percent in the first six months of 2021
from the first six months of 2020.

Marginal Loss Costs and Loss Credits
Total marginal loss surplus is calculated by adding the total system energy
costs, the total marginal loss costs and net residual market adjustments. The
total system energy costs are equal to the net implicit energy charges (implicit
withdrawal charges minus implicit injection credits) plus net inadvertentenergy charges. Total marginal loss costs are equal to the net implicit marginalloss charges (implicit load MLMP charges less implicit generation MLMP
credits) plus net explicit loss charges plus net inadvertent loss charges.
Ignoring interchange, total generation MWh must be greater than total load
MWh in any hour in order to provide for losses. Since the hourly integrated© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 601

2021 Quarterly State of the Market Report for PJM: January through June

Table 11-40 Marginal loss surplus (Dollars (Millions)): January through June,2008 through 202139(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

SystemEnergy Cost($610.2)($343.6)($372.8)($393.9)($262.0)($332.6)($677.2)($397.6)($204.2)($222.2)($345.2)($218.9)($133.9)($240.7)

Marginal Loss Surplus (Millions)
Net Residual Market Adjustments
Day-Ahead
Balancing
Total
Loss MW
Loss MW Marginal Loss
Marginal Known DayAhead Error
Congestion
Congestion
Loss Costs
Surplus$1,271.2
$0.0
$0.0
$0.0
$661.0$704.8($0.0)($0.4)($0.1)$361.7$750.9$0.0($1.2)($0.0)$379.4$701.5$0.0$0.6($0.0)$306.9$444.9($0.0)($0.9)$0.0$183.7$494.5
$0.1
$0.8
$0.0
$161.1$1,006.2
$0.0
$3.9
$0.1
$325.0$608.3($0.3)$3.7($0.1)$206.7$305.8$0.0$1.3($0.1)$100.5$320.6$0.0$0.3($0.1)$98.2$521.4($0.0)$1.3($0.0)$175.0$325.0($0.0)$0.7($0.0)$105.4$193.4($0.0)($0.1)($0.0)$59.7$375.9($0.0)$1.3($0.0)$134.0

System Energy Costs
Energy Accounting

explicit energy charges of $0.0 million and inadvertent energy charges of$0.9 million. The monthly system energy costs for the first six months of 2021
ranged from -$63.0 million in February to -$28.5 million in April.
Table 11-41 shows total system energy costs and total PJM billing, for the firstsix months of 2008 through 2021.
Table 11-41 Total system energy costs (Dollars (Millions)): January throughJune, 2008 through 202140(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

System Energy
Costs($610)($344)($373)($394)($262)($333)($677)($398)($204)($222)($345)($219)($134)($241)

Percent
ChangeNA(43.7%)
8.5%
5.7%(33.5%)
26.9%
103.6%(41.3%)(48.6%)
8.8%
55.3%(36.6%)(38.8%)
79.7%

Total
PJM Billing$16,549$13,457$16,314$18,685$13,991$15,571$31,060$23,390$18,290$18,960$25,780$20,070$15,570$20,410Percent of
PJM Billing(3.7%)(2.6%)(2.3%)(2.1%)(1.9%)(2.1%)(2.2%)(1.7%)(1.1%)(1.2%)(1.3%)(1.1%)(0.9%)(1.2%)The system energy component of LMP is the system reference bus LMP, also
called the system marginal price (SMP). The system energy cost is based on
the day-ahead and real-time energy components of LMP. Total system energy
costs, analogous to total congestion costs or total loss costs, are equal to
the withdrawal energy charges minus injection energy credits, incurred inboth the day-ahead energy market and the balancing energy market, plus net
inadvertent energy charges. Total system energy costs can be more accurately
thought of as net system energy costs.

Total System Energy Costs
The total system energy cost for the first six months of 2021 was -$240.7
million, which was comprised of implicit withdrawal energy charges of$16,239.3 million, implicit injection energy credits of $16,480.9 million,
39 The net residual market adjustments included in the table are comprised of the known day-ahead error value minus the sum of the dayahead loss MW congestion value, balancing loss MW congestion value and measurement error caused by missing data.

602

Section 11 Congestion and Marginal Losses

40 The system energy costs include net inadvertent charges.

© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

System energy costs for the first six months of 2008 through 2021 are shown in Table 11-42 and Table 11-43. Table 11-42 shows PJM system energy costs byaccounting category and Table 11-43 shows PJM system energy costs by market category.
Table 11-42 Total system energy costs by accounting category (Dollars (Millions)): January through June, 2008 through 2021

(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Implicit
Withdrawal
Charges$61,281.2$22,815.7$25,040.9$23,524.8$16,823.4$20,488.2$39,885.0$24,267.0$14,857.8$16,768.7$23,080.9$15,347.6$10,156.0$16,239.3

System Energy Costs (Millions)
Implicit
Injection
Explicit
Credits
Charges$61,891.4$0.0$23,162.1$0.0$25,406.7$0.0$23,932.1$0.0$17,092.7$0.0$20,819.3$0.0$40,556.7$0.0$24,667.1$0.0$15,062.3$0.0$16,991.8$0.0$23,430.9$0.0$15,567.8$0.0$10,290.4$0.0$16,480.9$0.0Inadvertent
Charges$0.0$2.9($7.1)$13.3$7.2($1.5)($5.4)
$2.5
$0.4
$0.9
$4.9
$1.3
$0.5
$0.9

Total
($610.2)($343.6)($372.8)($393.9)($262.0)($332.6)($677.2)($397.6)($204.2)($222.2)($345.2)($218.9)($133.9)($240.7)

Table 11-43 Total system energy costs by market (Dollars (Millions)): January through June, 2008 through 2021

(Jan - Jun)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021

Implicit
Withdrawal
Charges$42,539.7$22,893.0$25,072.6$23,685.6$16,907.0$20,543.4$39,831.7$24,389.1$14,970.7$16,974.1$23,126.4$15,552.6$10,275.1$16,373.1© 2021 Monitoring Analytics, LLC

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges$43,214.3$0.0$23,278.1$0.0$25,450.1$0.0$24,076.3$0.0$17,148.9$0.0$20,895.6$0.0$40,780.0$0.0$24,858.0$0.0$15,252.9$0.0$17,296.6$0.0$23,506.8$0.0$15,820.6$0.0$10,450.7$0.0$16,646.1$0.0

System Energy Costs (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges($674.6)$18,741.5$18,677.1$0.0($385.1)($77.3)($116.0)$0.0($377.5)($31.6)($43.4)$0.0($390.6)($160.8)($144.1)$0.0($241.9)($83.6)($56.2)$0.0($352.2)($55.1)($76.3)$0.0($948.3)$53.3($223.3)$0.0($468.9)($122.1)($190.9)$0.0($282.3)($112.9)($190.6)$0.0($322.5)($205.3)($304.8)$0.0($380.4)($45.5)($75.9)$0.0($268.0)($205.0)($252.7)$0.0($175.6)($119.1)($160.3)$0.0($273.0)($133.8)($165.2)
$0.0

Total
$64.5
$38.7
$11.8
($16.7)($27.4)$21.2$276.6
$68.8
$77.7
$99.4
$30.3
$47.7
$41.2
$31.4

Inadvertent
Charges$0.0$2.9($7.1)$13.3$7.2($1.5)($5.4)
$2.5
$0.4
$0.9
$4.9
$1.3
$0.5
$0.9

Grand
Total
($610.2)($343.6)($372.8)($393.9)($262.0)($332.6)($677.2)($397.6)($204.2)($222.2)($345.2)($218.9)($133.9)($240.7)2021 Quarterly State of the Market Report for PJM: January through June 603

2021 Quarterly State of the Market Report for PJM: January through June

Table 11-44 and Table 11-45 show the total system energy costs for each transaction type in the first six months of 2021 and 2020. In the first six months of2021, generation was paid $12,334.0 million and demand paid $11,508.4 million in net energy payment. In the first six months of 2020, generation was paid
$7,301.8 million and demand paid $6,836.2 million in net energy payment.
Table 11-44 Total system energy costs by transaction type (Dollars (Millions)): January through June, 2021

Transaction TypeDEC
DemandDemand Response
ExportGeneration
ImportINC
Internal Bilateral
Wheel In
Wheel Out
Total

Implicit
Withdrawal
Charges$605.4$11,349.4($0.3)$416.3
$0.0
$0.0
$0.0
$4,002.2$0.0$0.0$16,373.1

System Energy Costs (Millions)
Day-Ahead
Balancing
Implicit
Implicit
Implicit
Injection
Explicit
Withdrawal
Injection
Explicit
Credits
Charges
Total
Charges
Credits
Charges$0.0$0.0$605.4($602.2)
$0.0
$0.0
$0.0
$0.0 $11,349.4$159.0
$0.0
$0.0
$0.0
$0.0
($0.3)
$0.2
$0.0
$0.0
$0.0
$0.0
$416.3$277.4$0.0$0.0$12,307.5$0.0 ($12,307.5)
$0.0
$26.5
$0.0
$28.1
$0.0
($28.1)
$0.0
$82.6
$0.0
$308.3$0.0($308.3)$0.0($305.9)$0.0$4,002.2
$0.0
$0.0
$21.4
$21.4
$0.0
$0.0
$0.0
$0.0
$0.0
$10.3
$0.0
$0.0
$0.0
$0.0
$10.3
$0.0
$0.0
$16,646.1$0.0($273.0)($133.8)($165.2)
$0.0

Total
($602.2)$159.0$0.2$277.4($26.5)($82.6)$305.9$0.0($10.3)
$10.3
$31.4

Grand
Total
$3.3
$11,508.4($0.0)$693.8($12,334.0)($110.7)($2.3)$0.0($10.3)$10.3($241.6)

Table 11-45 Total system energy costs by transaction type by (Dollars (Millions)): January through June, 2020

Transaction TypeDEC
DemandDemand Response
ExportGeneration
ImportINC
Internal Bilateral
Wheel In
Wheel Out
Total

604

Implicit
Withdrawal
Charges$313.5$6,800.3($0.1)$254.7
$0.0
$0.0
$0.0
$2,906.7$0.0$0.0$10,275.1

Day-Ahead
Implicit
Injection
Explicit
Credits
Charges
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$7,313.8
$0.0
$20.1
$0.0
$210.1$0.0$2,906.7
$0.0
$0.0
$0.0
$0.0
$0.0
$10,450.7$0.0

Section 11 Congestion and Marginal Losses

System Energy Costs (Millions)
Balancing
Implicit
Implicit
Withdrawal
Injection
Explicit
Total
Charges
Credits
Charges$313.5($319.7)$0.0$0.0$6,800.3
$36.0
$0.0
$0.0
($0.1)
$0.1
$0.0
$0.0
$254.7$138.4$0.0$0.0($7,313.8)$0.0($12.0)$0.0($20.1)
$0.0
$36.0
$0.0
($210.1)$0.0($210.4)
$0.0
$0.0
$12.3
$12.3
$0.0
$0.0
$0.0
$13.9
$0.0
$0.0
$13.9
$0.0
$0.0
($175.6)($119.1)($160.3)
$0.0

Total
($319.7)$36.0$0.1$138.4$12.0($36.0)$210.4$0.0($13.9)
$13.9
$41.2

Grand
Total
($6.2)$6,836.2$0.0$393.1($7,301.8)($56.1)$0.3$0.0($13.9)$13.9($134.4)© 2021 Monitoring Analytics, LLC

Section 11 Congestion and Marginal Losses

Table 11-46 shows a monthly summary of system energy costs by market typefor January 2020 through June 2021. Total balancing system energy costsin the first six months of 2021 decreased from the first six months of 2020.
Monthly total system energy costs in the first six months of 2021 ranged from-$63.0 million in February to -$28.5 million in April.
Table 11-46 Monthly system energy costs (Dollars (Millions)): January 2020
through June 2021

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total

DayAhead($40.0)($30.7)($25.5)($21.1)($25.4)($32.8)($52.4)($44.9)($30.7)($29.4)($27.3)($41.2)($401.4)

System Energy Costs (Millions)2020
Inadvertent
DayBalancing
Charges
Total
Ahead
$9.4
($0.1)($30.7)($42.7)$6.8($0.3)($24.2)($73.5)$5.2($0.1)($20.4)($35.8)$5.2($0.0)($15.9)($30.4)$6.9$0.4($18.1)($37.8)$7.6$0.6($24.6)($52.8)$9.0$0.9($42.5)$9.9($0.2)($35.2)$7.6$0.6($22.5)$7.3$0.3($21.9)$2.3$0.1($24.9)$2.7$0.2($38.3)$79.9$2.5($319.0)($273.0)2021
Inadvertent
BalancingCharges$5.0($0.1)
$9.8
$0.7
$5.0
$0.0
$2.0
($0.1)
$4.6
$0.1
$5.0
$0.3

Total
($37.8)($63.0)($30.8)($28.5)($33.1)($47.5)

$0

-$50

-$100

-$150

-$200

-$250
Monthly System Energy Cost

-$300

$31.4

$0.9

($240.7)

Figure 11-9 shows PJM monthly system energy costs for January throughJune, 2008 through 2021. Ignoring interchange, total generation MWh must
be greater than total load MWh in any hour in order to provide for losses.
Since the hourly integrated energy component of LMP (SMP) is the same forevery bus in the market in every hour, the net energy bill is always negative(ignoring net interchange): (SMP x withdrawals + SMP x injections) < 0.)Assuming power balance is maintained in the presence of losses, the greater
the level of load the greater the difference between energy charges collectedfrom load (SMP x load MW) and credited to generation (SMP x generation
MW). With higher load levels, there are generally higher SMPs and morenegative total energy charges.

© 2021 Monitoring Analytics, LLC

Figure 11-9 Monthly system energy costs (Millions): January 2008 throughJune 2021

System Energy Cost (Millions)

Monthly System Energy Costs

Table 11-47 shows the monthly total system energy costs for each virtualtransaction type in the first six months of 2021 and year of 2020. In the firstsix months of 2021, DECs paid $605.4 million in energy charges in the dayahead market, were paid $602.2 million in energy credits in the balancing
energy market and paid $3.3 million in total energy charges. In the first six
months of 2021, INCs were paid $308.3 million in energy credits in the dayahead market, paid $305.9 million in energy charges in the balancing market
and were paid $2.3 million in total energy credits. In the first six months of
2020, DECs paid $313.5 million in energy charges in the day-ahead market,
were paid $319.7 million in energy credits in the balancing energy market andwere paid $6.2 million in total energy credits. In the first six months of 2020,
INCs were paid $210.1 million in energy credits in the day-ahead market,
paid $210.4 million in energy charges in the balancing energy market andpaid $0.3 million in total energy charges. The system energy costs are zero

2021 Quarterly State of the Market Report for PJM: January through June 605

2021 Quarterly State of the Market Report for PJM: January through Junefor UTCs because the system energy costs for UTCs equal the difference in theenergy component between source and sink and the energy component is thesame at all buses.
Table 11-47 Monthly energy charges by virtual transaction type (Dollars(Millions)): January 2020 through June 2021
DEC
Year
2020

2021

606

Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total
Jan
Feb
Mar
Apr
May
Jun
Total

DayAhead
$44.4
$43.0
$43.9
$42.4
$59.9
$79.9
$116.8
$99.9
$77.6
$78.9
$72.4
$92.6
$851.8$76.5$167.0
$83.8
$73.2
$81.7
$123.2$605.4

Balancing($43.3)($42.4)($44.0)($43.8)($62.4)($83.8)($119.2)($105.4)($76.2)($81.4)($74.8)($95.1)($871.8)($76.2)($157.6)($89.0)($70.5)($81.3)($127.6)($602.2)

Energy Charges (Millions)
INC
DayTotal
Ahead Balancing$1.0($44.0)$43.2$0.6($34.5)$33.5($0.1)($32.1)$31.7($1.4)($32.4)$33.6($2.5)($34.7)$35.2($3.9)($32.4)$33.2($2.4)($48.7)$49.9($5.5)($35.0)$35.7$1.4($33.4)$32.6($2.5)($39.2)$40.9($2.4)($38.4)$38.8($2.5)($40.5)$41.4($20.0)($445.5)$449.8$0.3($41.9)$41.6$9.4($54.4)$51.4($5.2)($50.9)$53.3$2.7($62.3)$60.6$0.5($52.7)$52.5($4.4)($46.1)$46.5$3.3($308.3)$305.9Section 11 Congestion and Marginal Losses

Total($0.8)($1.0)($0.4)
$1.2
$0.5
$0.8
$1.2
$0.7
($0.8)
$1.7
$0.4
$0.9
$4.3
($0.3)($3.0)$2.4($1.7)($0.2)$0.4($2.3)

Grand
Total
$0.2
($0.3)($0.5)($0.2)($2.0)($3.1)($1.2)($4.8)$0.6($0.8)($2.1)($1.6)($15.7)($0.0)$6.5($2.8)$1.0$0.2($4.0)$0.9© 2021 Monitoring Analytics, LLC

Section 12 Planning

Generation and Transmission Planning1
Overview
Generation Interconnection Planning
Existing Generation Mix•

As of June 30, 2021, PJM had a total installed capacity of 196,804.7
MW, of which 49,210.4 MW (25.0 percent) are coal fired steam units,
50,508.7 MW (25.7 percent) are combined cycle units and 33,452.6 MW(17.0 percent) are nuclear units. This measure of installed capacity differsfrom capacity market installed capacity because it includes energy onlyunits, excludes all external units, and uses nameplate values for solar andwind resources.

• Of the 196,804.7 MW of installed capacity, 72,239.7 MW (36.7 percent)are from units older than 40 years, of which 37,799.4 MW (52.3 percent)are coal fired steam units, 191.0 MW (0.3 percent) are combined cycle
units and 17,342.6 MW (24.0 percent) are nuclear units.

Generation Retirements2• There are 51,429.8 MW of generation that have been, or are planned tobe, retired between 2011 and 2024, of which 36,120.2 MW (70.2 percent)are coal fired steam units. Coal unit retirements are primarily a result of
the inability of coal units to compete with efficient combined cycle units
burning low cost natural gas.

• In the first six months of 2021, 1,251.4 MW of generation retired. The

largest generators that retired in the first six months of 2021 were the667.0 MW Chalk Point Unit 1 and 2 coal fired steam units located in the
PEPCO Zone. Of the 1,251.4 MW of generation that retired, 667.0 MW(53.3 percent) were located in the PEPCO Zone.

• As of June 30, 2021, there are 10,161.0 MW of generation that haverequested retirement after June 30, 2021, of which 5,280.6 MW (52.0

1 Totals presented in this section include corrections to historical data and may not match totals presented in previous reports.
2 See PJM. Planning. “Generator Deactivations,” (Accessed on June 30, 2021) <http://www.pjm.com/‌planning/services-requests/gendeactivations.aspx>.

© 2021 Monitoring Analytics, LLC

percent) are located in the COMED Zone. Of the generation requesting
retirement in the COMED Zone, 4,086.5 MW (77.4 percent) are nuclear
units.

Generation Queue3• There were 173,182.4 MW in generation queues, in the status of active,

under construction or suspended, at the end of 2020. In the first six
months of 2021, the AG2 queue window closed and the AH1 queue
window opened. As projects move through the queue process, projects canbe removed from the queue due to incomplete or invalid data, withdrawn
by the market participant or placed in service. On June 30, 2021, there
were 217,381.6 MW in generation queues, in the status of active, underconstruction or suspended, an increase of 44,199.2 MW (25.5 percent)from the end of 2020.4• As of June 30, 2021, 6,483 projects, representing 711,962.4 MW, haveentered the queue process since its inception in 1998. Of those, 985
projects, representing 74,169.9 MW, went into service. Of the projects thatentered the queue process, 3,145 projects, representing 420,410.9 MW(59.0 percent of the MW) withdrew prior to completion. Such projects may
create barriers to entry for projects that would otherwise be completed bytaking up queue positions, increasing interconnection costs and creating
uncertainty.

• As of June 30, 2021, 217,381.6 MW were in generation request queues inthe status of active, under construction or suspended. Based on historicalcompletion rates, 39,081.6 MW (17.9 percent) of new generation in thequeue are expected to go into service.

• The number of queue entries has increased during the past several years,

primarily renewable projects. Of the 3,831 projects entered from January
2015 through June 2021, 2,879 projects (75.2 percent) were renewable. Of
the 641 projects entered in the first six months of 2021, 483 projects (75.4
percent) were renewable. Renewable projects make up 77.4 percent of all
projects in the queue and those projects account for 73.8 percent of the3 See PJM. Planning. “New Services Queue,” (Accessed on June 30, 2021) <https://www.pjm.com/‌planning/services-requests/
interconnection-queues.aspx>.
4 The queue totals in this report are the winter net MW energy for the interconnection requests (“MW Energy”) as shown in the queue.

2021 Quarterly State of the Market Report for PJM: January through June 607

2021 Quarterly State of the Market Report for PJM: January through June

nameplate MW currently active, suspended or under construction in thequeue as of June 30, 2021.
But of the 160,392.1 MW of renewable projects in the queue, only 7,714.3
MW (4.8 percent) of capacity resources are expected to go into service,
based on both historical completion rates and average derate factors forwind and solar.

Regional Transmission Expansion Plan (RTEP)
Market Efficiency Process• There are significant issues with PJM’s benefit/cost analysis that should•

be addressed prior to approval of additional projects. PJM’s benefit/cost
analysis does not correctly account for the costs of increased congestion
associated with market efficiency projects.
Through June 30, 2021, PJM has completed four market efficiency cycles
under Order No. 1000.5

PJM MISO Interregional Market Efficiency Process (IMEP)• PJM and MISO developed a process to facilitate the construction ofinterregional projects in response to the Commission’s concerns about
interregional coordination along the PJM-MISO seam. This process,called the Interregional Market Efficiency Process (IMEP), operates on
a two year study schedule and is designed to address forward looking
congestion.

But the use of an inaccurate cost-benefit method by PJM and the correct
method by MISO results in an over allocation of the costs associated withjoint PJM/MISO projects to PJM participants and in some cases approvalof projects that do not pass an accurate cost-benefit test.

5 See Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, FERC Stats. &Regs. ¶ 31,323 (2011) (Order No. 1000), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132 (2012).

608

Section 12 Planning

PJM MISO Targeted Market Efficiency Process (TMEP)• PJM and MISO developed the Targeted Market Efficiency Process (TMEP)

to facilitate the resolution of historic congestion issues that could be
addressed through small, quick implementation projects.

Supplemental Transmission Projects• Supplemental projects are defined to be “transmission expansions or

enhancements that are not required for compliance with PJM criteria
and are not state public policy projects according to the PJM Operating
Agreement. These projects are used as inputs to RTEP models, but are notrequired for reliability, economic efficiency or operational performance
criteria, as determined by PJM.”6 Supplemental projects are exempt fromthe competitive planning process.

• The average number of supplemental projects in each expected in service

year increased by 785.0 percent, from 20 for years 1998 through 2007(pre Order No. 8907) to 177 for years 2008 through 2021 (post Order 890).

End of Life Transmission Projects• An end of life transmission project is a project submitted for the purposeof replacing existing infrastructure that is at, or is approaching, the end ofits useful life. End of life transmission projects should be included in the
RTEP process and should be subject to a transparent, robust and clearly
defined mechanism to permit competition to build the project. Under thecurrent approach, end of life projects are excluded from competition.

Board Authorized Transmission Upgrades• The Transmission Expansion Advisory Committee (TEAC) reviews internaland external proposals to improve transmission reliability throughout
PJM. These proposals, which include reliability baseline, network, market
efficiency and targeted market efficiency projects, as well as scopechanges and project cancellations, but exclude supplemental and end of

6 See PJM. “Transmission Construction Status,” (Accessed on June 30, 2021) <http://www.pjm.com/‌planning/rtep-upgrades-status/
construct-status.aspx>.
7 See Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 118 FERC ¶ 61,119, order on reh’g, Order No.
890-A, 121 FERC ¶ 61,297 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶61,228, order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).

© 2021 Monitoring Analytics, LLC

Section 12 Planning

life projects, are periodically presented to the PJM Board of Managers for
authorization.8 In the first six months of 2021, the PJM Board approved$680.6 million in upgrades. As of June 30, 2021, the PJM Board has
approved $38.5 billion in system enhancements since 1999.

Transmission Competition• The MMU makes several recommendations related to the competitivetransmission planning process. The recommendations include improved
process transparency, incorporation of competition between transmission
and generation alternatives and the removal of barriers to competition
from nonincumbent transmission. These recommendations would help
ensure that the process is an open and transparent process that results inthe most competitive solutions.

• On May 24, 2018, the PJM Markets and Reliability Committee (MRC)

approved a motion that required PJM, with input from the MMU, todevelop a comparative framework to evaluate the quality and effectivenessof competitive transmission proposals with binding cost containment
proposals compared to proposals from incumbent and nonincumbent
transmission companies without cost containment provisions.

Qualifying Transmission Upgrades (QTU)• A Qualifying Transmission Upgrade (QTU) is an upgrade to the transmission

system that increases the Capacity Emergency Transfer Limit (CETL) into
an LDA and can be offered into capacity auctions as capacity. Once a
QTU is in service, the upgrade is eligible to continue to offer the approved
incremental import capability into future RPM Auctions. As of June 30,
2021, no QTUs have cleared a Base Residual Auction or an Incremental
Auction.

Transmission Facility Outages• PJM maintains a list of reportable transmission facilities. When thereportable transmission facilities need to be taken out of service, PJM

8 Supplemental Projects, including the end of life subset of supplemental projects, do not require PJM Board of Managers authorization.

© 2021 Monitoring Analytics, LLC

transmission owners are required to report planned transmission facility
outages as early as possible. PJM processes the transmission facility
outage requests according to rules in PJM’s Manual 3 to decide if theoutage is on time or late and whether or not they will allow the outage.9• There were 20,671 transmission outage requests submitted in the2020/2021 planning period. Of the requested outages, 78.0 percent of therequested outages were planned for less than or equal to five days and7.6 percent of requested outages were planned for greater than 30 days.
Of the requested outages, 41.4 percent were late according to the rules in
PJM’s Manual 3.

Recommendations
Generation Retirements• The MMU recommends that the question of whether Capacity

Interconnection Rights (CIRs) should persist after the retirement of a unit
be addressed. The rules need to ensure that incumbents cannot exploit
control of CIRs to block or postpone entry of competitors.10 (Priority: Low.
First reported 2013. Status: Partially adopted, 2012.)

Generation Queue• The MMU recommends that barriers to entry be addressed in a timely

manner in order to help ensure that the capacity market will result in theentry of new capacity to meet the needs of PJM market participants andreflect the uncertainty and resultant risks in the cost of new entry used toestablish the capacity market demand curve in RPM. (Priority: Low. First
reported 2012. Status: Not adopted.)• The MMU recommends improvements in queue management includingthat PJM establish a review process to ensure that projects are removed
from the queue if they are not viable, as well as a process to allow
commercially viable projects to advance in the queue ahead of projects

9 See PJM. “PJM Manual 03: Transmission Operations,” Rev. 59 (May 27, 2021).
10 See “Comments of the Independent Market Monitor for PJM,” Docket No. ER12-1177 (March 12, 2012) <http://www.monitoringanalytics.
com/Filings/2012/IMM_Comments_ER12-1177-000_20120312.PDF>.

2021 Quarterly State of the Market Report for PJM: January through June 609

2021 Quarterly State of the Market Report for PJM: January through June

which have failed to make progress, subject to rules to prevent gaming.
(Priority: Medium. First reported 2013. Status: Partially adopted.)• The MMU recommends continuing analysis of the study phase of PJM’stransmission planning to reduce the need for postponements of study
results, to decrease study completion times, and to improve the likelihoodthat a project at a given phase in the study process will successfully
go into service. (Priority: Medium. First reported 2014. Status: Partiallyadopted.)• The MMU recommends outsourcing interconnection studies to anindependent party to avoid potential conflicts of interest. Currently,
these studies are performed by incumbent transmission owners under
PJM’s direction. This creates potential conflicts of interest, particularly
when transmission owners are vertically integrated and the owner oftransmission also owns generation. (Priority: Low. First reported 2013.
Status: Not adopted.)Market Efficiency Process• The MMU recommends that the market efficiency process be eliminatedbecause it is not consistent with a competitive market design. (Priority:
Medium. First reported 2019. Status: Not adopted.)• The MMU recommends that, if the market efficiency process is retained,
PJM modify the rules governing benefit/cost analysis, the evaluation
process for selecting among competing market efficiency projects andcost allocation for economic projects in order to ensure that all costs,
including increased congestion costs and the risk of project cost increases,
in all zones are included in order to ensure that the correct metrics areused for defining benefits. (Priority: Medium. First reported 2018. Status:
Not adopted.)Comparative Cost Framework• The MMU recommends that PJM modify the project proposal templates
to include data necessary to perform a detailed project lifetime financial
analysis. The required data includes, but is not limited to: capital

610

Section 12 Planning

expenditure; capital structure; return on equity; cost of debt; tax
assumptions; ongoing capital expenditures; ongoing maintenance; andexpected life. (Priority: Medium. First reported 2020. Status: Not adopted.)Transmission Competition• The MMU recommends, to increase the role of competition, that theexemption of supplemental projects from the Order No. 1000 competitive
process be terminated and that the basis for all such exemptions bereviewed and modified to ensure that the supplemental project designation
is not used to exempt transmission projects from a transparent, robust andclearly defined mechanism to permit competition to build such projects orto effectively replace the RTEP process. (Priority: Medium. First reported
2017. Status: Not adopted. Rejected by FERC.)11• The MMU recommends, to increase the role of competition, that theexemption of end of life projects from the Order No. 1000 competitive
process be terminated and that end of life transmission projects be
included in the RTEP process and should be subject to a transparent,robust and clearly defined mechanism to permit competition to build
such projects. (Priority: Medium. First reported 2019. Status: Not adopted.
Rejected by FERC.)12• The MMU recommends that PJM enhance the transparency and queue
management process for nonincumbent transmission investment. Issues
related to data access and complete explanations of cost impacts should
be addressed. The goal should be to remove barriers to competition fromnonincumbent transmission providers. (Priority: Medium. First reported
2015. Status: Not adopted.)• The MMU recommends that PJM continue to incorporate the principlethat the goal of transmission planning should be the incorporation oftransmission investment decisions into market driven processes as muchas possible. (Priority: Low. First reported 2001. Status: Not adopted.)

11 The FERC accepted tariff provisions that exclude supplemental projects from competition in the RTEP. 162 FERC ¶ 61,129 (2018), reh’gdenied, 164 FERC ¶ 61,217 (2018).
12 In recent decisions addressing competing proposals on end of life projects, the Commission accepted a transmission owner proposal
excluding end of life projects from competition in the RTEP process, 172 FERC ¶ 61,136 (2020), reh’g denied, 173 FERC ¶ 61,225 (2020),
and rejected a proposal from PJM stakeholders that would have included end of life projects in competition in the RTEP process, 173
FERC ¶ 61,242 (2020).

© 2021 Monitoring Analytics, LLC

Section 12 Planning• The MMU recommends the creation of a mechanism to permit a direct• The MMU recommends consideration of changing the minimum• The MMU recommends that PJM establish fair terms of access to rights ofTransmission Line Ratingscomparison, or competition, between transmission and generation
alternatives, including which alternative is less costly and who bears therisks associated with each alternative. (Priority: Low. First reported 2013.
Status: Not adopted.)

way and property, such as at substations, in order to remove any barriers toentry and permit competition between incumbent transmission providers
and nonincumbent transmission providers in the RTEP. (Priority: Medium.
First reported 2014. Status: Not adopted.)• The MMU recommends that rules be implemented to permit competition

to provide financing for transmission projects. This competition could
reduce the cost of capital for transmission projects and significantly
reduce total costs to customers. (Priority: Low. First reported 2013. Status:
Not adopted.)• The MMU recommends that rules be implemented to require that project

distribution factor in the allocation from 0.01 to 0.00 and adding athreshold minimum usage impact on the line.13 (Priority: Medium. First
reported 2015. Status: Not adopted.)• The MMU recommends that all PJM transmission owners use the same

methods to define line ratings, subject to NERC standards and guidelines,
subject to review by NERC and approval by FERC. (Priority: Medium. First
reported 2019. Status: Not adopted.)Transmission Facility Outages• The MMU recommends that PJM reevaluate all transmission outage

tickets as on time or late as if they were new requests when an outage
is rescheduled, and apply the standard rules for late submissions to any
such outages. (Priority: Low. First reported 2014. Status: Not adopted.)

cost caps on new transmission projects be part of the evaluation ofcompeting projects. (Priority: Medium. First reported 2015. Status:
Adopted 2020.)• The MMU recommends that PJM draft a clear definition of the congestiontransmission assets for any reason. (Priority: High. First reported 2020.
Status: Not adopted.)• The MMU recommends that PJM modify the rules to reduce or eliminate• The MMU recommends that storage resources not be includable as
Cost Allocation• The MMU recommends a comprehensive review of the ways in which thesolution based dfax is implemented. The goal for such a process would beto ensure that the most rational and efficient approach to implementing
the solution based dfax method is used in PJM. Such an approach shouldallocate costs consistent with benefits and appropriately calibrate the
incentives for investment in new transmission capability. No replacement
approach should be approved until all potential alternatives, including
the status quo, are thoroughly reviewed. (Priority: Medium. First reported
2020. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

analysis required for transmission outage requests to include in Manual
3 after appropriate review. (Priority: Low. First reported 2015. Status: Not
adopted.)the approval of late outage requests submitted or rescheduled after the
FTR auction bidding opening date. (Priority: Low. First reported 2015.
Status: Not adopted.)• The MMU recommends that PJM not permit transmission owners to divide

long duration outages into smaller segments to avoid complying withthe requirements for long duration outages. (Priority: Low. First reported
2015. Status: Not adopted.)

13 See the 2015 State of the Market Report for PJM, Volume II, Section 12: Generation and Transmission Planning, at p. 463, Cost Allocation
Issues.

2021 Quarterly State of the Market Report for PJM: January through June 611

2021 Quarterly State of the Market Report for PJM: January through June

Conclusion
The goal of PJM market design should be to enhance competition and to ensurethat competition is the driver for all the key elements of PJM markets. But
transmission investments have not been fully incorporated into competitivemarkets. The construction of new transmission facilities has significant
impacts on the energy and capacity markets. But when generating units retireor load increases, there is no market mechanism in place that would require
direct competition between transmission and generation to meet loads in theaffected area. In addition, despite FERC Order No. 1000, there is not yet atransparent, robust and clearly defined mechanism to permit competition tobuild transmission projects, to ensure that competitors provide a total project
cost cap, or to obtain least cost financing through the capital markets.
The MMU recognizes that the Commission has recently issued orders that areinconsistent with the recommendations of the MMU and that PJM cannot
unilaterally modify those directives. It remains the recommendation of the
MMU that the PJM rules for competitive transmission development throughthe RTEP should build upon FERC Order No. 1000 to create real competition
between incumbent transmission providers and nonincumbent transmission
providers. The ability of transmission owners to block competition for
supplemental projects and end of life projects and reasons for that policy
should be reevaluated. PJM should enhance the transparency and queue
management process for nonincumbent transmission investment. Issues related
to data access and complete explanations of cost impacts should be addressed.
The goal should be to remove barriers to competition from nonincumbent
transmission. Another element of opening competition would be to considertransmission owners’ ownership of property and rights of way at or aroundtransmission substations. In many cases, the land acquired included property
intended to support future expansion of the grid. Incumbents have included
the costs of the property in their rate base, paid for by customers. Because PJM
now has the responsibility for planning the development of the grid under its
RTEP process, property bought to facilitate future expansion should be a partof the RTEP process and be made available to all providers on equal terms.

612

Section 12 Planning

The process for determining the reasonableness or purpose of supplemental
transmission projects that are asserted to be not needed for reliability,
economic efficiency or operational performance as defined under the RTEP
process needs additional oversight and transparency. If there is a need for a
supplemental project, that need should be clearly defined and there should bea transparent, robust and clearly defined mechanism to permit competition tobuild the project. If there is no defined need for of a supplemental project for
reliability, economic efficiency or operational performance then the project
should not be included in rates.
Managing the generation queues is a highly complex process. The PJM queue
evaluation process has been substantially improved in recent years and it ismore efficient and effective as a result. The PJM queue evaluation process
should continue to be improved to help ensure that barriers to competition for
new generation investments are not created. Issues that need to be addressed
include the ownership rights to CIRs, whether transmission owners should
perform interconnection studies, and improvements in queue management toensure that projects are removed from the queue if they are not viable, as well asa process to allow commercially viable projects to advance in the queue aheadof projects which have failed to make progress. But the behavior of project
developers also creates issues with queue management. When developers
put multiple projects in the queue to maintain their own optionality whileplanning to build only one they also affect all the projects that follow them inthe queue. Project developers may also enter speculative projects in the queue
and then put the project in suspended status while they address financing. The
incentives for such behavior should also be addressed, including appropriate
nonrefundable fees, appropriate credit requirements, appropriate limits on theuse of the suspended option and appropriate milestone requirements.
The addition of a planned transmission project changes the parameters of thecapacity auction for the area, changes the amount of capacity needed in thearea, changes the capacity market supply and demand fundamentals in thearea and may effectively forestall the ability of generation to compete. But
there is no mechanism to permit a direct comparison, let alone competition,
between transmission and generation alternatives. There is no mechanism© 2021 Monitoring Analytics, LLC

Section 12 Planningto evaluate whether the generation or transmission alternative is less costly,
whether there is more risk associated with the generation or transmission
alternatives, or who bears the risks associated with each alternative. Creatingsuch a mechanism should be an explicit goal of PJM market design.

analysis is effectively meaningless and low estimated costs may result ininappropriately favoring transmission projects over market generation projects.
The risk of cost increases for transmission projects should be incorporated in
the cost benefit analysis.

The current market efficiency process does exactly the opposite by permitting
transmission projects to be approved without competition from generation.
The broader issue is that the market efficiency project approach explicitly
allows transmission projects to compete against future generation projects, but
without allowing the generation projects to compete. Projecting speculativetransmission related benefits for 15 years based on the existing generation
fleet and existing patterns of congestion eliminates the potential for new
generation to respond to market signals. The market efficiency process allows
assets built under the cost of service regulatory paradigm to displace generation
assets built under the competitive market paradigm. In addition, there are
significant issues with PJM’s current benefit/cost analysis which cause it toconsistently overstate the potential benefits of market efficiency projects. The
MMU recommends that the market efficiency process be eliminated.

There are currently no market incentives for transmission owners to submit
and complete transmission outages in a timely and efficient manner. Requiringtransmission owners to pay does not create an effective incentive whenthose payments are passed through to transmission customers. The process
for the submission of planned transmission outages needs to be carefully
reviewed and redesigned to limit the ability of transmission owners to submit
transmission outages that are late for FTR auction bid submission dates andare late for the day-ahead energy market. The submission of late transmission
outages can inappropriately affect market outcomes when market participants
do not have the ability to modify market bids and offers.

In addition, the use of an inaccurate cost-benefit method by PJM and thecorrect method by MISO results in an over allocation of the costs associatedwith joint PJM/MISO projects to PJM participants and in some cases approvalof projects that do not pass an accurate cost-benefit test.

Table 12-1 shows the existing PJM capacity by control zone and unit type.14
As of June 30, 2021, PJM had an installed capacity of 196,804.7 MW, ofwhich 49,210.4 MW (25.0 percent) are coal fired steam units, 50,508.7 MW(25.7 percent) are combined cycle units and 33,452.6 MW (17.0 percent) are
nuclear units. This measure of installed capacity differs from capacity market
installed capacity because it includes energy only units, external units anduses nameplate values for solar and wind resources.

If it is retained, there are significant issues with PJM’s benefit/cost analysis
that should be addressed prior to approval of additional projects. The current
benefit/cost analysis for a regional project, for example, explicitly andincorrectly ignores the increased congestion in zones that results from an
RTEP project when calculating the energy market benefits. All costs should
be included in all zones and LDAs. The definition of benefits should also be
reevaluated.
The benefit/cost analysis should also account for the fact that the transmission
project costs are not subject to cost caps and may exceed the estimated costs
by a wide margin. When actual costs exceed estimated costs, the cost benefit

Generation Interconnection Planning
Existing Generation Mix

The AEP Zone has the most installed capacity of any PJM zone. Of the196,804.7 MW of PJM installed capacity, 31,668.1 MW (16.1 percent) arein the AEP Zone, of which 13,463.0 MW (42.5 percent) are coal fired steam
units, 6,990.0 MW (22.1 percent) are combined cycle units and 2,071.0 MW(6.5 percent) are nuclear units.

14 The unit type RICE refers to Reciprocating Internal Combustion Engines.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 613

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-1 Existing capacity: June 30, 2021 (By zone and unit type (MW))15
Zone
Battery
ACEC
0.0
AEP
4.0
APS
80.4
ATSI
0.0
BGE
0.0
COMED
149.5
DAY
0.0
DUKE
18.0
DUQ
0.0
DOM
0.0
DPL
0.0
EKPC
0.0
JCPLC
40.0
MEC
0.0
OVEC
0.0
PECO
0.0
PE
28.4
PEPCO
0.0
PPL
20.0
PSEG
7.7
XIC
0.0
Total
347.9

Combined
Cycle
901.9
6,990.0
2,843.7
3,495.5
0.0
2,271.1
0.0
522.2
101.0
9,138.0
1,742.5
0.0
2,229.5
2,646.0
0.0
4,089.0
1,900.0
1,736.5
5,558.5
4,343.3
0.050,508.7

CT Natural
Gas CT - Oil
544.7
26.0
4,108.2
16.2
1,223.3
0.0
958.0
629.0
267.6
228.8
6,673.3
226.2
897.5
0.0
598.0
56.0
0.0
15.0
3,835.3
256.4
978.2
478.2
774.0
0.0
531.1
225.6
2.0
398.5
0.0
0.0
0.0
828.0
350.5
57.0
764.2
308.0
304.6
286.2
1,039.2
0.0
858.6
0.0
24,708.3 4,035.1

CT Other
0.0
4.8
2.0
6.4
0.0
0.0
0.0
0.0
0.0
10.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
20.6
0.0
0.0
43.8

Fuel
Cell
1.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
30.0
0.0
0.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32.0

Hydro - Hydro Pumped Run ofStorage
River
0.0
0.0
66.0
420.9
0.0
129.2
0.0
0.0
0.0
0.4
0.0
0.0
0.0
0.0
0.0
112.0
0.0
6.3
3,003.0
586.3
0.0
0.0
0.0
136.0
140.0
0.0
0.0
19.0
0.0
0.0
1,070.0
572.0
513.0
77.8
0.0
0.0
0.0
706.6
0.0
5.0
0.0
269.1
4,792.0 3,040.6

Nuclear0.0
2,071.0
0.0
2,134.0
1,716.0
10,473.50.0
0.0
1,777.0
3,581.3
0.0
0.0
0.0
0.0
0.0
4,546.8
0.0
0.0
2,520.0
3,493.0
1,140.033,452.6

RICE Natural
Gas
0.0
0.0
29.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
120.1
0.0
12.0
0.0
0.0
161.7

RICE Oil
4.0
0.0
0.0
18.5
0.0
0.0
34.0
0.0
0.0
39.0
88.0
0.0
0.0
0.0
0.0
2.0
28.0
0.0
5.0
0.0
0.0
218.5

RICE Solar + Solar +Other
Solar Storage
Wind
8.9
64.1
0.0
0.0
20.4
264.7
0.0
0.0
18.3
114.4
0.0
0.0
46.1
0.0
0.0
0.0
4.2
1.1
0.0
0.0
30.3
9.0
0.0
0.0
0.0
1.1
0.0
0.0
4.8
200.0
0.0
0.0
0.0
0.0
0.0
0.0
106.4 2,512.1
0.0
0.0
14.1
320.4
0.0
0.0
0.0
0.0
0.0
0.0
14.1
391.7
0.0
0.0
33.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.9
3.0
0.0
0.0
17.8
13.5
0.0
0.0
11.1
2.5
0.0
0.0
14.7
35.0
0.0
0.0
9.0
224.6
0.0
0.0
0.0
0.0
0.0
0.0
354.4 4,157.2
0.0
0.0

Steam Coal
458.9
13,463.0
5,299.0
2,264.0
1,578.0
3,840.1
0.0
1,857.0565.0
3,499.2
410.0
1,687.0
0.0
115.0
2,388.8
0.0
6,053.5
1,229.0
2,547.9
0.0
1,955.0
49,210.4

Steam Natural Steam SteamWind +
Gas- Oil - OtherWind Storage
0.0
0.0
0.0
7.5
0.0
738.0
0.0
0.0 3,500.9
0.0
0.0
0.0
0.0
875.1
0.0
325.0
0.0
0.0
0.0
0.0
143.5
397.0
57.0
0.0
0.0
1,326.0
0.0
0.0 4,831.0
0.0
0.0
0.0
0.0
0.0
0.0
47.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35.0
800.0
368.4
587.0
0.0
710.0
153.0
70.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
60.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
762.0
0.0
103.0
0.0
0.0
610.0
0.0
42.0 1,100.4
0.0
1,164.1
0.0
52.0
0.0
0.0
2,449.0
0.0
29.0
216.5
0.0
3.0
0.0
179.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
8,312.6 1,350.0
960.5 11,118.4
0.0

Total
2,017.5
31,668.1
10,615.0
9,876.5
4,393.6
29,830.0
932.6
3,415.0
2,464.3
28,357.4
4,994.4
2,597.0
3,572.5
3,273.9
2,388.8
11,976.7
10,912.0
5,267.4
14,725.6
9,303.8
4,222.7
196,804.7

15 The capacity described in this section refers to all capacity in PJM at the summer installed capacity rating, regardless of whether the capacity entered the RPM Auction.

614

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-2 shows the installed capacity by state for each fuel type. Pennsylvania has the most installed capacity of any PJM state. Of the 196,804.7 MW of
installed capacity, 48,847.9 MW (24.8 percent) are in Pennsylvania, of which 9,281.4 MW (19.0 percent) are coal fired steam units, 18,138.2 MW (37.1 percent)are combined cycle units and 8,843.8 MW (18.1 percent) are nuclear units.
Table 12-2 Existing capacity: June 30, 2021 (By state and unit type (MW))
State
DC
DE
IL
IN
KY
MD
MI
NC
NJ
OH
PA
TN
VA
WV
XIC
Total

Battery
0.0
0.0
149.5
0.0
0.0
20.0
0.0
0.0
47.7
22.0
49.9
0.0
0.0
58.9
0.0
347.9

Combined
Cycle
19.5
742.5
2,271.1
1,835.0
0.0
2,717.0
1,200.0
165.0
7,474.7
6,972.7
18,138.2
0.0
8,973.0
0.0
0.050,508.7

CT Natural
Gas CT - Oil
0.0
0.0
325.5
116.3
6,673.3
226.2
441.4
0.0
1,618.1
0.0
1,684.5
552.7
0.0
0.0
0.0
0.0
2,115.0251.6
4,201.2
701.2
1,544.5 1,584.7
0.0
0.0
4,172.3
591.4
1,073.9
11.0
858.6
0.0
24,708.3 4,035.1

CT Other
0.0
0.0
0.0
0.0
0.0
0.0
4.8
0.0
0.0
6.4
20.6
0.0
12.0
0.0
0.0
43.8

Fuel
Cell
0.0
30.0
0.0
0.0
0.0
0.0
0.0
0.0
2.0
0.0
0.0
0.0
0.0
0.0
0.0
32.0

Hydro - Hydro Pumped Run ofStorage
River
0.0
0.0
0.0
0.0
0.0
0.0
0.0
8.2
0.0
136.0
0.0
0.4
0.0
11.8
0.0
315.0
140.0
5.0
0.0
200.0
1,583.0 1,445.7
0.0
0.0
3,069.0
460.1
0.0
189.3
0.0
269.1
4,792.0 3,040.6

Nuclear0.0
0.0
10,473.5
0.0
0.0
1,716.0
2,071.0
0.0
3,493.0
2,134.0
8,843.8
0.0
3,581.3
0.0
1,140.033,452.6

RICE Natural
Gas
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
161.7
0.0
0.0
0.0
0.0
161.7

RICE Oil
0.0
0.0
0.0
0.0
0.0
76.0
0.0
18.0
4.0
47.0
40.5
0.0
33.0
0.0
0.0
218.5

RICE Solar + Solar +Other
Solar Storage
Wind
0.0
0.0
0.0
0.0
8.1
0.0
0.0
0.0
30.3
9.0
0.0
0.0
3.2
30.1
0.0
0.0
0.0
0.0
0.0
0.0
21.3
333.4
0.0
0.0
3.2
4.6
0.0
0.0
0.0
921.5
0.0
0.0
32.0
680.4
0.0
0.0
50.9
351.1
0.0
0.0
85.1
106.5
0.0
0.0
0.0
0.0
0.0
0.0
112.4 1,700.6
0.0
0.0
8.0
20.0
0.0
0.0
0.0
0.0
0.0
0.0
354.4 4,157.2
0.0
0.0

Steam Coal
0.0
410.0
3,840.1
3,923.8
1,687.0
2,987.0
0.0
0.0
458.9
9,689.0
9,281.4
0.0
2,494.2
12,484.0
1,955.0
49,210.4

Steam Natural Steam SteamWind +
Gas- Oil - OtherWind Storage
0.0
0.0
0.0
0.0
0.0
710.0
0.0
70.0
0.0
0.0
1,326.0
0.0
0.0 4,831.0
0.0
0.0
0.0
0.0 2,353.2
0.0
278.0
0.0
0.0
0.0
0.0
1,307.6
550.0
109.0
295.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
208.0
0.0
3.0
0.0
179.1
7.5
0.0
47.0
0.0
0.0 1,147.7
0.0
4,146.0
0.0
234.0 1,582.3
0.0
0.0
0.0
0.0
0.0
0.0
495.0
800.0
368.4
12.0
0.0
0.0
0.0
0.0
681.7
0.0
0.0
0.0
0.0
0.0
0.0
8,312.6 1,350.0
960.5 11,118.4
0.0

Total
19.5
2,412.4
29,830.0
8,594.9
3,719.1
12,369.9
3,295.4
1,627.5
14,893.8
25,570.2
48,847.9
0.0
26,874.7
14,526.8
4,222.7
196,804.7

Table 12-3 and Figure 12-1 show the age of existing PJM generators, by unit type, as of June 30, 2021. Of the 196,804.7 MW of installed capacity, 72,239.7 MW(36.7 percent) are from units older than 40 years, of which 37,799.4 MW (52.3 percent) are coal fired steam units, 191.0 MW (0.3 percent) are combined cycle
units and 17,342.6 MW (24.0 percent) are nuclear units.
Table 12-3 Capacity (MW) by unit type and age (years): June 30, 2021
Age (years)
Less than 20
20 to 40
40 to 60
Greater than 60
Total

Battery
347.9
0.0
0.0
0.0
347.9

Combined
Cycle
45,136.4
5,181.3
191.0
0.0
50,508.7© 2021 Monitoring Analytics, LLC

CT Natural
Gas CT - Oil
11,427.9
44.7
12,758.1
915.3
522.3 3,075.1
0.0
0.0
24,708.3 4,035.1

CT Other
43.8
0.0
0.0
0.0
43.8

Fuel
Cell
32.0
0.0
0.0
0.0
32.0

Hydro - Hydro Pumped Run ofStorage
River
0.0
297.2
3,003.0
427.2
1,789.0
340.0
0.0 1,976.2
4,792.0 3,040.6

Nuclear0.0
16,110.0
17,342.6
0.033,452.6

RICE Natural
Gas
149.7
12.0
0.0
0.0
161.7

RICE Oil
20.0
25.0
173.5
0.0
218.5

RICE Solar + Solar +Other
Solar Storage
Wind
283.4 4,157.2
0.0
0.0
71.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
354.4 4,157.2
0.0
0.0

Steam Coal
3,475.0
7,956.0
34,613.6
3,165.8
49,210.4

Steam Natural Steam SteamWind +
Gas- Oil - OtherWind Storage
82.0
0.0
47.4 11,118.4
0.0
600.0
0.0
843.1
0.0
0.0
5,869.1 1,350.0
70.0
0.0
0.0
1,761.5
0.0
0.0
0.0
0.0
8,312.6 1,350.0
960.5 11,118.4
0.0

Total
76,663.0
47,902.0
65,336.2
6,903.5
196,804.7

2021 Quarterly State of the Market Report for PJM: January through June 615

2021 Quarterly State of the Market Report for PJM: January through June

Figure 12-1 Capacity (MW) by age (years): June 30, 2021
60,000Less than 20 years

50,00020 to 40 years

Figure 12-2 Map of unit additions (less than 20 MW): January 1, 2011
through June 30, 2021

40 to 60 years
Greater than 60 years

40,000MW in Service

Figure 12-2 is a map of units, less than 20 MW in size, that came online
between January 1, 2011 and June 30, 2021. A mapping to these unit names
is in Table 12-4.

30,00020,00010,0000Unit Type

616

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-4 Unit identification for map of unit additions (less than 20 MW): January 1, 2011 through June 30, 2021
ID
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55

Unit
ACE CAPE MAY COUNTY 1 LF
ACE CATES ROAD 2 SP
ACE CEDAR BRANCH 1 SP
ACE EGG HARBOR-KELLOGG 1 FC
ACE GALLOWAY LANDFILL 2 SP
ACE MAYS LANDING 1 SP
ACE MIDTOWN THERMAL 2 CT
ACE OAK FAIRTON 1 SP
ACE PEAR STREET 1 SP
ACE PILESGROVE 1 SP
ACE PILESGROVE 2 SP
ACE PITTSGROVE 1 SP
ACE SEASHORE 1 SP
ACE TANSBORO ROAD 1 FC
AEP BALLS GAP 1 BT
AEP CHARLESTON 1 LF
AEP CLOYDS MT 1 LF
AEP DEERCREEK 1 SP
AEP EAST WATERVLIET 1 SP
AEP OLIVE 1 SP
AEP ORCHARD HILLS 1 LF
AEP RALEIGH COUNTY 1 LF
AEP TRENT 1 BT
AEP TWINBRANCH 1 SP
AEP ZANESVILLE 2 LF
AP BAKER POINT 1 SP
AP DOUBLE TOLLGATE SP
AP HP HOOD 1 CT
AP LETZBURG - ELK HILL 2 SP
AP MAHONING CREEK 1 H
AP MT ST MARYS PV PARK 2 SP
AP PINESBURG 1 SP
AP STATE COLLEGE 1 BT
BC ALPHA RIDGE 1 LF
BC BRIGHTON DAM 1 H
BC KINGSVILLE 1 SP
BC MILLERSVILLE 1 LF
COM COUNTRYSIDE 1 LF
COM DIXON LEE 5 LF
COM GRAND RIDGE 6 BT
COM MAGID GLOVE 1 BT
COM MORRIS 1 LF
COM ORCHARD 1 LF
COM SOLBERG 1 BT
DEOK BECKJORD 1 BT
DEOK BECKJORD 2 BT
DEOK BROWN COUNTY 1 LF
DEOK CLINTON 1 BT
DEOK WILLEY 1 BT
DPL BLOOM ENERGY 1 FC
DPL BUCKTOWN 1 SP
DPL CHURCH HILL 1 SP
DPL COSTEN 1 SP
DPL HEBRON 1 SP
DPL WORCESTER NORTH 1 SP

© 2021 Monitoring Analytics, LLC

ID
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110

Unit
DPL WORCESTER SOUTH 2 SP
DPL WYE MILLS 1 SP
FE DOVETAIL 1 CT
FE ERIE COUNTY 1 LF
FE GENEVA 1 LF
FE LORAIN 1 LF
FE MAHONING 1 LF
FE WARREN-EVERGREEN 1 CT
JC AUGUSTA 1 SP
JC BEAVER RUN 3 SP
JC BERNARDS TOWNSHIP 1 SP
JC BRICKYARD 4 SP
JC COPPER HILL 4 SP
JC CYPHERS ROAD 5 SP
JC DIXSOLAR 51 SP
JC DIXSOLAR 52 SP
JC DOMIN LANE 1 SPJC DURBAN AVENUE 1 SP
JC E FLEMINGTON 5 SPJC EAST AMWELL 7 SP
JC EGYPT 3 SP
JC FISCHER 8 SP
JC FOUL RIFT ROAD 1 SP
JC FRANKFORD 4 SP
JC FRANKLIN 7 SP
JC FREEMALL 1 FC
JC FRENCHES 2 SP
JC FRENCHTOWN 1 SP
JC FRENCHTOWN 2 SP
JC FRENCHTOWN 3 SP
JC HANOVER 2 SPJC HARMONY 1 SP
JC HIGH STREET 6 SP
JC HOFFMAN STATION ROAD 2 SP
JC HOLLAND 4 SP
JC HOLMDEL 9 SP
JC HOWELL 1 SP
JC JACOBSTOWN 1 SP
JC JUNCTION ROAD 6 SP
JC LAKEHURST 3 SP
JC LEBANON 1 SP
JC MANALAPAN 1 SP
JC MILLHURST 3 SP
JC MUDDY FORGE 3 SP
JC NORTH HANOVER 4 SP
JC NORTH PARK 1 SP
JC NORTH PARK 2 SP
JC NORTH RUN 11 SP
JC OLD BRIDGE 1 SP
JC PAUCH 3 SP
JC PEMBERTON 1 SP
JC PEMBERTON 2 SP
JC QUAKERTOWN 9 SP
JC RICHLINE 3 SP
JC RINGOES 1 SP

ID
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165

Unit
JC SUSSEX 1 LF
JC TINTON FALLS 3 SP
JC UPPER FREEHOLD 1 SP
JC WANTAGE 2 SP
JC WARREN 1 SP
JC WASHBURN AVE 4 SP
ME GLENDON 1 LF
ME READING HOSPITAL 1 CT
PE MORRIS ROAD 1 D
PEP CAPITAL POWER PLANT 1 CT
PEP ROLLINS AVENUE 3 SP
PL DART CONTAINER 1-2 LF
PL HOLTWOOD 11
PL HOLTWOOD 13
PL KEYSTONE 1 SP
PL PA SOLAR 1 SP
PL TURKEY HILL 1 WF
PN ALPACA GLORY BARN 1 D
PN GARRETT 1 BT
PN LAUREL HIGHLANDS 2 LF
PN MEYERSDALE 2 BT
PN MILAN ENERGY 1 D
PN NORTH MESHOPPEN 1 CTPN OXBOW CREEK ENERGY CENTER 1 D
PN WHITETAIL 1 SP
PS ALDENE SOLAR 1 SP
PS ATHENIA SOLAR 1 SP
PS BAYONNE 1 SP
PS BAYONNE SOLAR 2 SP
PS BELLEVILLE SOLAR 1 SP
PS BENNETTS SOLAR 1 SP
PS BLACK ROCK 1 SP
PS BRIDGEWATER SOLAR 2 SP
PS CALDWELL PUMP 2 BT
PS CAMPUS DRIVE 2 SP
PS CEDAR GROVE SOLAR 1 SP
PS CEDAR LANE FLORENCE 6 SP
PS COOK ROAD SOLAR 2 SP
PS COOPER HOSPITAL 1 BT
PS COOPER HOSPITAL 15 SP
PS CRANBURY 2 SP
PS CROSSWIC 1 SP
PS CROSSWIC 2 SP
PS DEVILSBROOK 1 SP
PS DOREMUS SOLAR 1 SP
PS E RUTHERFORD SOLAR 1 SPPS EASTAMPTON 1 SP
PS EDISON 1 SP
PS ESSEX 105 CT
PS FAIRLAWN SOLAR 1 SP
PS FOODBANK 1 SP
PS FORTY NINTH SOLAR 1 SP
PS GLOUCESTER SOLAR 1 SP
PS HACKENSACK 1 SP
PS HIGHLAND PARK 3 BT

ID
166
167
168
169
170
171
172
173
174
175
176
177
178
179
180
181
182
183
184
185
186
187
188
189
190
191
192
193
194
195
196
197
198
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
214
215
216
217
218
219
220

Unit
PS HIGHLAND PARK 4 SP
PS HILLSDALE SOLAR 1 SP
PS HINCHMANS SOLAR 1 SP
PS HOBOKEN SOLAR 2 SP
PS HOPEWELL 1 SP
PS HOPEWELL 2 BT
PS JACKSON SOLAR 1 SP
PS KINSLEY BEAVER 2 SP
PS KINSLEY DEPTFORD 1 SPPS KUSER SOLAR 1 SP
PS LANDFILL 5 SP
PS LAWNSIDE 14 BT
PS LEONIA SOLAR 1 SP
PS LUMBERTON STACY HAINES 5 SP
PS MANTUA CREEK 7 BT
PS MARION SOLAR 1 SP
PS MATRIX PA SOLAR 2 SP
PS MAYWOOD SOLAR 1 SP
PS METRO HQ 2 SP
PS MIDDLESEX 1 SP
PS MILL CREEK 1 SP
PS MOORESTOWN 1 SP
PS MT LAUREL 1 SP
PS NEW MILFORD SOLAR 1 SP
PS NEW ROAD 1 SP
PS NEWARK SOLAR 1 SP
PS NEWARK SOLAR 3 SP
PS NIXON LANE 2 SP
PS NORTH AMERICAN 4 SP
PS NORTH AVE SOLAR 1 SP
PS OWENS CORNING 1 SP
PS PARKLANDS 1 SP
PS PATERSON PLANK ROAD 1 SP
PS PENNINGTON 3 BT
PS PENNINGTON 4 SP
PS PENNSAUKEN 1 LF
PS PENNSAUKEN 3 SP
PS PRINCETON HOSPITAL 1 CT
PS RARITAN CENTER 3 SP
PS REEVES EAST 3 SP
PS REEVES SOUTH 1 SP
PS REEVES WEST 4 SP
PS RIDER UNIVERSITY 3 SP
PS RIVER ROAD 2 SP
PS ROSELAND SOLAR 1 SP
PS SADDLE BROOK SOLAR 1 SP
PS SPRINGFIELD SOLAR 1 SP
PS SUNNYMEADE SOLAR 1 SP
PS TAYLORS LANE 1 SP
PS THOROFARE SOLAR 2 SP
PS TURNPIKE 1 SP
PS W CALDWELL SOLAR 1 SP
PS W CALDWELL SOLAR 2 SP
PS WALDWICK SOLAR 1 SP
PS WEST ORANGE SOLAR 1 SP

ID
221
222
223
224
225
226
227
228
229
230
231
232
233
234
235
236

Unit
PS WEST PEMBERTON 1 SPVP BUCKINGHAM 1 SPVP GARDNER FARMS 1 SPVP GARDYS MILL ROAD 5 SP
VP HOLLYFIELD 1 SPVP MURPHY 1 SP
VP NORTHEAST 2 LF
VP OCCOQUAN 1 LF
VP OCCOQUAN 2 LF
VP OCEANA 1 SP
VP PULLER 1 SPVP REMINGTON 1 SP
VP TWITTYS CREEK 1 SPVP VIRGINIA OFFSHORE 1 WF
VP WAN - GLOUCESTER 1 SP
VP WHITAKERS 1 SP

2021 Quarterly State of the Market Report for PJM: January through June 617

2021 Quarterly State of the Market Report for PJM: January through June

Figure 12-3 is a map of units, 20 MW or greater in size, that came online between January 1, 2011 and June 30, 2021. A mapping to these unit names is in
Table 12-5.
Figure 12-3 Map of unit additions (20 MW or greater): January 1, 2011 through June 30, 2021

618

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-5 Unit identification for map of unit additions (20 MW or greater): January 1, 2011 through June 30, 2021
ID
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50

Unit
ACE CLAYVILLE 1 CT
ACE VINELAND 11 CT
ACE WEST DEPTFORD CROWN POINT 1 CC
AEP ALTAVISTA 1 SP
AEP BITTER RIDGE 1 WF
AEP BLUE CREEK 3 WF
AEP BLUFF POINT 2 WF
AEP CARROLL COUNTY 1 CC
AEP CARROLL COUNTY 2 CC
AEP DRESDEN 1 CC
AEP FOWLER RIDGE 4 WF
AEP HARDIN 2 SP
AEP HEADWATERS 1 WF
AEP HEADWATERS 2 WF
AEP HOG CREEK 1 WF
AEP MEADOW LAKE 5 WF
AEP MEADOW LAKE 6 WF
AEP PAULDING 3 WF
AEP PAULDING 41 WF
AEP PAULDING 42 WF
AEP SCIOTO RIDGE 1 WF
AEP ST JOSEPH ENERGY CENTER 1 CC
AEP ST JOSEPH SOLAR PARK 1 SP
AEP TIMBER2 1 WF
AEP TRISHE 1 WF
AEP VIRGINIA CITY 1 F
AEP WILDCAT 1A WF
AEP WILDCAT 1B WF
AP BEECH RIDGE 2 WF
AP BEECH RIDGE 3 BT
AP FAIR WIND 2 WF
AP FOURMILE RIDGE 1 WF
AP GREENE COUNTY 1 CC
AP LAUREL MOUNTAIN 1 BT
AP LAUREL MOUNTAIN 1 WF
AP MARLOWE 1 SP
AP NORTH LONGVIEW 1 F
AP PINNACLE 1 WF
AP ROTH ROCK 1 WF
AP SOUTH CHESTNUT 1 WF
AP ST THOMAS 1 SP
AP ST THOMAS 2 SP
AP TWIN RIDGES 1 WF
AP WARRIOR RUN 2 BT
AP WESTMORELAND 1 CC
AP WILLOW ISLAND 1 H
BC PERRYMAN 6 CT
COM 942 NELSON 1 CC
COM 942 NELSON 2 CC
COM BISHOP HILL SP in PJM WF© 2021 Monitoring Analytics, LLC

ID
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100

Unit
COM BLOOMING GROVE 1 WF1COM BRIGHT STALK 1 WF
COM GRAND RIDGE 7 BT
COM GREEN RIVER 1 WF
COM GREEN RIVER 2 WF
COM HILLTOPPER 1 WF
COM JOLIET 1 BT
COM KELLY CREEK 1 WF
COM LEE DEKALB 3 BT
COM LONE TREE 3 WF
COM MARENGO 1 BT
COM MCHENRY 1 BT
COM MINONK 1 WF
COM OTTER CREEK 1 WF
COM PILOT HILL 1 WF
COM RADFORDS RUN 1 WF
COM SHADY OAKS 1 WF
COM WALNUT RIDGE 1 WF
COM WEST CHICAGO 3 BT
COM WHITNEY HILL 2 WF
DAY TAIT 8 BT
DEOK HILLCREST 1 SP
DEOK MELDAHL DAM 1 H
DEOK MIDDLETOWN ENERGY 1 CC
DEOK YANKEE 1 F
DPL CHERRYDALE 1 SP
DPL DEMEC - CLAYTON 2 CT
DPL DORCHESTER COUNTY 1 SP
DPL GARRISON EC 1 CC
DPL GREAT BAY KINGS CREEK 1 SP
DPL GREAT BAY KINGS CREEK 2 SP
DPL OAK HALL 1 SP
DPL RED LION 1 FC
DPL WILDCAT POINT 1 CC
FE FREMONT 1 SCCTFE FREMONT 2 SCCTFE FREMONT ENERGY CENTER 3 CC
FE HICKORY RUN 1 CC
FE LORDSTOWN ENERGY CENTER 1 CC
FE LORDSTOWN ENERGY CENTER 2 CC
FE OREGON ENERGY CENTER 1 CC
JC EDGE ROAD 5 BT
JC HAMILTON ROAD 5 SPJC OAK RIDGE 3 SP
JC PLUMSTED ENERGY 6 BT
JC WOODBRIDGE 1 CCJC WOODBRIDGE 2 CC
ME BIRDSBORO 1 CC
PE DELTA 1-4 CC
PE DELTA 5-7 CC

ID
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150

Unit
PEP KEYS ENERGY CENTER 1 CC
PEP ST CHARLES - KELSON RIDGE 1 CC
PEP ST CHARLES-KELSON RIDGE 1 CC
PEP ST CHARLES-KELSON RIDGE 2 CC
PL HAZEL 1 FW
PL HOLTWOOD 18
PL HOLTWOOD 19
PL HUMMEL STATION 1 CC
PL HUNLOCK CC
PL LACKAWANNA COUNTY 1 CC
PL LACKAWANNA COUNTY 2 CC
PL LACKAWANNA COUNTY 3 CC
PL MOXIE FREEDOM 11 CC
PL MOXIE FREEDOM 21 CC
PL PA SOLAR 2 SP
PL PATRIOT 1 F
PL PATRIOT 2 F
PN BEAVER DAM 1 D
PN BIG LEVEL 1 WF
PN CHESTNUT FLATS 1 WF
PN FAIRVIEW 1 CC
PN FAIRVIEW 2 CC
PN HIGHLAND NORTH 2 WF
PN LAUREL HILLS 1 WF
PN LIBERTY ASYLUM 10 F
PN LIBERTY ASYLUM 20 F
PN MEHOOPANY 1 WF
PN MEHOOPANY 2 WF
PN PATTON 1 WF
PN PGCOGEN 2 CT
PN RINGER HILL 1 WF
PN SANDY RIDGE 1 WF
PN SUGAR RUN 2 CT
PS KEARNY 131 CT
PS KEARNY 132 CT
PS KEARNY 133 CT
PS KEARNY 134 CT
PS KEARNY 141 CT
PS KEARNY 142 CT
PS NEWARK ENERGY CENTER 10 CC
PS SEWAREN 7 CC
VP AULANDER HOLLOMAN 1 SP
VP BEAR GARDEN
VP BLUESTONE FARM 1 SP
VP BRIEL FARM 1 SP
VP BRUNSWICK 1CC
VP BUTCHER CREEK 1 SP
VP CHESTNUT 1 SP
VP COLONIAL TRAIL WEST 1 SP
VP CONETOE 2 SP

ID
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
169
170
171
172
173
174
175
176
177
178
179
180
181
182

Unit
VP CORRECTIONAL 1 SP
VP DESERT 1 WF
VP DESPER 1 SP
VP DOSWELL 2 CT
VP DOSWELL 3 CT
VP DRY BREAD 1 SP
VP ELIZABETH CITY 1 SP
VP GREENSVILLE 1 CC
VP GUTENBERG - OCONECHE 1 SPVP HARTS MILL 1 SP
VP IVORY LANE 1 SP
VP KELFORD 1 SP
VP MACKEYS 1 SP
VP MECHANICSVILLE 2 SP
VP MOCCASIN CREEK 1 SP
VP MONTROSS 1 SP
VP MORGAN CORNER 1 SP
VP NEW CREEK 1 WF
VP NEWSOMS 1 SP
VP PANDA STONEWALL 1 CC
VP PECAN 1 SP
VP POWHATAN 2 SP
VP RANCHLAND 2 SP
VP SAPONY 1 SP
VP SOUTH BOSTON 1 F
VP SPOTSYLVANIA 1 SPVP SPRING GROVE 1 SPVP SUMMIT FARMS 1 SP
VP UNION CAMP 9-10 F
VP WARREN COUNTY FRONT ROYAL CC
VP WATER STRIDER 1 SPVP WILKINSON ENERGY CENTER 1 SP

2021 Quarterly State of the Market Report for PJM: January through June 619

2021 Quarterly State of the Market Report for PJM: January through June

Generation Retirements16 17Generating units generally plan to retire when they are not economic and do
not expect to be economic. The MMU performs an analysis of the economics
of all units that plan to retire in order to verify that the units are noteconomic and there is no potential exercise of market power through physicalwithholding that could advantage the owner’s portfolio.18 The definition of
economic is that unit net revenues are greater than or equal to the unit’s
avoidable or going forward costs.
PJM does not have the authority to order generating plants to continue
operating. PJM’s responsibility is to ensure system reliability. When a unit
retirement creates reliability issues based on existing and planned generation
facilities and on existing and planned transmission facilities, PJM identifies
transmission solutions.19

unit should be addressed. Even if the policy treatment of such CIRs remains
unchanged, the rules need to ensure that incumbents cannot exploit controlof CIRs to block or postpone entry of competitors.
In May 2012, PJM stakeholders (through the Interconnection Process Senior
Task Force (IPSTF)) modified the rules to reduce the length of time for which
CIRs are retained by the current owner after unit retirements from three years
to one.21 The MMU recognized the progress made in this rule change, but it
did not fully address the issues. The MMU recommends that the questionof whether CIRs should persist after the retirement of a unit, or conversion
from CP to energy only status, be addressed. The rules need to ensure thatincumbents cannot exploit control of CIRs to block or postpone entry ofcompetitors.22

Rules that preserve the Capacity Interconnection Rights (CIRs) associated withretired units, and with the conversion from Capacity Performance (CP) toenergy only status, impose significant costs on new entrants. Currently, CIRs
persist for one year if unused, and they can be further extended, at no cost, if
assigned to a new project in the interconnection queue at the same point ofinterconnection.20 There are currently no rules governing the retention of CIRs
when units want to convert to energy only status or require time to upgrade
to retain CP status. The rules governing conversion or upgrades should be thesame as the rules governing retired units. Reforms that require the holders
of CIRs to use or lose them, and/or impose costs to holding or transferring
them, could make new entry appropriately more attractive. The economic andpolicy rationale for extending CIRs for inactive units is not clear. Incumbent
providers receive a significant advantage simply by imposing on new entrants
the entire cost of system upgrades needed to accommodate new entrants.
The policy question of whether CIRs should persist after the retirement of a
16 See PJM. Planning. “Generator Deactivations,” (Accessed on June 30, 2021) <http://www.pjm.com/‌planning/services-requests/gendeactivations.aspx>.
17 Generation retirements reported in this section do not include external units. Therefore, retirement totals reported in this section may
not match totals reported elsewhere in this report where external units are included.
18 See OATT Part V and Attachment M–Appendix § IV.
19 See PJM. “Explaining Power Plant Retirements in PJM,” at <http://learn.pjm.com/three-priorities/‌planning-for-the-future/explainingpower-plant-retirements.aspx>.
20 See OATT § 230.3.3.

620

Section 12 Planning

21 See PJM Interconnection, L.L.C., Docket No. ER12-1177 (Feb. 29, 2012).
22 See “Comments of the Independent Market Monitor for PJM,” Docket No. ER12-1177-000 (March 12, 2012) <http://www.
monitoringanalytics.com/Filings/2012/IMM_Comments_ER12-1177-000_20120312.‌PDF>.

© 2021 Monitoring Analytics, LLC

Section 12 Planning

Generation Retirements 2011 through 2024
Table 12-6 shows that as of June 30, 2021, there are 51,429.8 MW of generation that have been, or are planned to be, retired between 2011 and 2024, of which
36,120.2 MW (70.2 percent) are coal fired steam units. Retirements are primarily a result of the inability of coal and other units to compete with efficient
combined cycle units burning low cost gas.
Table 12-6 Summary of unit retirements by unit type (MW): 2011 through 2024

Retirements 2011Retirements 2012Retirements 2013
Retirements 2014
Retirements 2015
Retirements 2016Retirements 2017Retirements 2018
Retirements 2019
Retirements 2020
Retirements 2021
Planned Retirements (July 2021 and later)
Total© 2021 Monitoring Analytics, LLC

Battery
0.0
0.0
0.0
0.0
0.0
0.0
40.0
1.0
0.0
0.0
4.0
0.0
45.0

Combined
Cycle
0.0
0.0
0.0
0.0
0.0
0.0
0.0
425.0
0.0
0.0
67.0
51.0
543.0

CT Natural
Gas
0.0
250.0
0.0
136.0
1,319.0
0.0
0.0
0.0
346.8
232.5
0.0
80.0
2,364.3

CT - Oil
128.3
240.0
0.0
422.0
856.2
65.0
0.0
38.0
51.4
24.0
0.0
49.0
1,873.9

CT Other
0.0
0.0
0.0
0.0
2.0
6.0
0.0
1.6
6.4
6.0
0.0
0.0
22.0

Hydro Fuel Pumped
Cell Storage
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.5

Hydro Run ofRiver Nuclear
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
614.5
0.0
805.0
0.0
0.0
0.0
0.0
0.0 4,086.5
0.0 5,506.0

RICE Natural RICE - RICE Gas
Oil Other
0.0
2.7
0.0
0.0
0.0
0.0
0.0
5.9
7.0
0.0
0.0
15.3
0.0
10.3
0.0
0.0
8.0
3.9
0.0
0.0
0.8
0.0
17.2
6.9
0.0
0.0
15.9
0.0
0.0
14.7
0.0
0.0
8.0
0.0
0.0
2.4
0.0
44.1
74.9

Solar
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

Solar +
Storage
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

Solar
Steam + Steam - Natural Steam - Steam Wind
Coal
Gas
Oil
Other
0.0
543.0
522.5
0.0
0.0
0.0 5,907.9
0.0
548.0
16.0
0.0 2,589.9
82.0
166.0
8.0
0.0 2,239.0
158.0
0.0
0.0
0.0 7,064.8
0.0
0.0
0.0
0.0
243.0
74.0
0.0
0.0
0.0 2,038.0
34.0
0.0
0.0
0.0 3,186.5
996.0
148.0
108.0
0.0 4,113.8
97.0
10.0
10.0
0.0 2,131.8
0.0
786.0
60.0
0.0 1,020.4
102.0
0.0
50.0
0.0 5,042.1
850.0
0.0
0.0
0.0 36,120.2 2,915.5 1,658.0
252.0

Wind
0.0
0.0
0.0
0.0
10.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
10.4

Wind +
Storage
Total
0.0 1,196.5
0.0 6,961.9
0.0 2,858.8
0.0 2,970.3
0.0 9,262.7
0.0
400.4
0.0 2,112.8
0.0 5,542.7
0.0 5,456.3
0.0 3,255.0
0.0 1,251.4
0.0 10,161.0
0.0 51,429.8

2021 Quarterly State of the Market Report for PJM: January through June 621

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-7 shows the capacity, average size, and average age of units retiring in PJM, from 2011 through 2024, while Table 12-8 shows these retirements bystate. Of the 51,429.8 MW of units that has been, or are planned to be, retired between 2011 and 2024, 36,120.2 MW (70.2 percent) are coal fired steam units.
These coal fired steam units have an average age of 52.7 years and an average size of 202.9 MW. Over half of the retiring coal fired steam units, 52.9 percent,are located in Ohio or Pennsylvania.
Table 12-7 Retirements by unit type: 2011 through 2024
Unit Type
Battery
Combined Cycle
Combustion Turbine
Natural Gas
Oil
Other
Fuel Cell
Hydro
Pumped Storage
Run of River
Nuclear
RICE
Natural Gas
Oil
Other
Solar
Solar + Storage
Solar + Wind
Steam
Coal
Natural Gas
Oil
Other
Wind
Wind + Storage
Total

622

Number of
Units
4
4
117
60
51
6
0
1
1
0
6
29
0
10
19
0
0
0
211
178
19
6
8
1
0
373

Section 12 Planning

Avg. Size
(MW)
11.3
135.8
26.6
39.4
36.7
3.7
0.0
0.5
0.5
0.0
917.7
4.2
0.0
4.4
3.9
0
0
0
166.0
202.9
153.4
276.3
31.5
10.4
0
137.9

Avg. Age at
Retirement(Years)
5.9
29.1
34.9
40.9
44.5
19.2
0.0
113.8
113.8
0.0
44.6
28.5
0.0
45.7
11.2
0
0
0
45.5
52.7
60.0
45.6
23.8
15.6
0
45.7

Total MW45.0
543.0
4,260.2
2,364.3
1,873.9
22.0
0.0
0.5
0.5
0.0
5,506.0
119.0
0.0
44.1
74.9
0
0
0
40,945.7
36,120.2
2,915.5
1,658.0
252.0
10.4
0
51,429.8

Percent
0.1%
1.1%
8.3%
4.6%
3.6%
0.0%
0.0%
0.0%
0.0%
0.0%
10.7%
0.2%
0.0%
0.1%
0.1%
0.0%
0.0%
0.0%
79.6%
70.2%
5.7%
3.2%
0.5%
0.0%
0.0%
100.0%© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-8 Retirements (MW) by unit type and state: 2011 through 2024
State
DC
DE
IL
IN
KY
MD
NC
NJ
OH
PA
TN
VA
WV
Total

Battery
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42.0
1.0
0.0
0.0
2.0
45.0

CT Combined Natural
Cycle
Gas CT - Oil
0.0
0.0
240.0
0.0
0.0
0.0
0.0
296.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
347.5
104.0
0.0
0.0
31.0
225.0 1,590.0 1,040.2
0.0
0.0
307.0
51.0
50.8
72.0
0.0
0.0
0.0
267.0
80.0
79.7
0.0
0.0
0.0
543.0 2,364.3 1,873.9

CT Other
0.0
0.0
0.0
0.0
0.0
1.6
0.0
6.4
0.0
14.0
0.0
0.0
0.0
22.0

Fuel
Cell
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

Hydro - Hydro RICE Pumped Run of
NaturalStorageRiver Nuclear
Gas
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0 4,086.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.5
0.0
614.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
805.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.5
0.0 5,506.0
0.0

RICE Oil
0.0
0.0
0.0
0.0
0.0
0.0
0.0
8.0
19.3
13.9
0.0
2.9
0.0
44.1

RICE Other
0.0
0.0
20.4
0.0
0.0
3.2
0.0
19.5
5.4
18.0
0.0
8.4
0.0
74.9

Solar
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

Solar + Solar +Storage
Wind
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

Steam Coal
0.0
664.0
2,818.1
982.0
995.0
3,068.0
324.5
1,543.0
13,817.4
5,299.3
0.0
3,917.9
2,691.0
36,120.2

Steam Natural Steam SteamGas- Oil - Other
0.0
548.0
0.0
136.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
171.0
0.0
0.0
0.0
0.0
0.0
932.5
148.0
10.0
0.0
0.0
0.0
1,133.0
176.0
109.0
0.0
0.0
50.0
543.0
786.0
83.0
0.0
0.0
0.0
2,915.5 1,658.0
252.0Wind +
Wind Storage
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
10.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
10.4
0.0

Total
788.0
800.0
7,221.0982.0
995.0
3,695.3
355.5
6,137.6
14,191.1
7,753.4
50.0
5,767.9
2,693.0
51,429.8

Figure 12-4 is a map of unit retirements between 2011 and 2024, with a mapping to unit names in Table 12-9.
Figure 12-4 Map of unit retirements: 2011 through 2024

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 623

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-9 Unit identification for map of unit retirements: 2011 through 2024
ID
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55

624

Unit
AES Beaver Valley
Albright 1
Albright 2Albright 3
Armstrong 1
Armstrong 2
Arnold (Green Mtn. Wind Farm
Ashtabula 5
Avon Lake 10
Avon Lake 7
Avon Lake 9
BC Landfill
BL England 1
BL England 2
BL England 3
BL England Diesel Units 1-4
Balls Gap Battery Facility
Barbados AES Battery
Bay Shore 2
Bay Shore 3
Bay Shore 4
Bayonne Cogen Plant (CC)
Beckjord Battery Unit 2
Bellefontaine Landfill Generating Station
Bellemeade
Benning 15
Benning 16
Bergen 3
Bethlehem Renewable Energy Generator (Landfill)
Big Sandy 2
Birchwood Plant
Bremo 3
Bremo 4
Brunner Island Diesels
Brunot Island 1B
Brunot Island 1C
Buchanan 1-2
Buggs Island 1 (Mecklenberg)
Buggs Island 2 (Mecklenberg)
Burger 3
Burger EMD
Burlington 8,11
Burlington 9
Buzzard Point East Banks 1,2,4-8
Buzzard Point West Banks 1-9
Byron 1
Byron 2
Cambria CoGen
Cedar 1
Cedar 2
Chalk Point Unit 1
Chalk Point Unit 2
Chesapeake 1-4
Chesapeake 7-10
Chesterfield 3

Section 12 Planning

ID
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110

Unit
Chesterfield 4
Chesterfield 5
Chesterfield 6
Cheswick 1
Clinch River 3
Columbia Dam Hydro
Conesville 3
Conesville 4
Conesville 5
Conesville 6Countryside Landfill
Crane 1
Crane 2Crane GT1
Crawford 7
Crawford 8
Cromby 1
Cromby 2
Cromby D
Dale 1-2
Dale 3
Dale 4
Deepwater 1
Deepwater 6
Dickerson Unit 1
Dickerson Unit 2
Dickerson Unit 3
Dixon Lee Landfill Generator
Dresden 2
Dresden 3
Eastlake 1
Eastlake 2
Eastlake 3
Eastlake 4
Eastlake 5
Eastlake 6
Eddystone 1
Eddystone 2
Edgecomb NUG (Rocky 1-2)
Edison 1-3
Elmwood Park Power
Elrama 1
Elrama 2
Elrama 3
Elrama 4
Essex 10-11
Essex 12Evergreen Power United Corstack
FRACKVILLE WHEELABRATOR 1
Fairless Hills Landfill A
Fairless Hills Landfill B
Fauquier County Landfill
Fisk Street 19
GUDE Landfill
Gilbert 1-4

ID
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165

Unit
Glen Gardner 1-8
Glen Lyn 5-6
Gould Street Generation Station
Harrisburg 4 CT
Harwood 1-2
Hatfield’s Ferry 1
Hatfield’s Ferry 2
Hatfield’s Ferry 3
Hopewell James River Cogeneration
Howard Down 10
Hudson 1
Hudson 2
Hurt NUG
Hutchings 1-3, 5-6
Hutchings 4
Indian River 1
Indian River 3
Indian River 4
Ingenco Petersburg
Kammer 1-3
Kanawha River 1-2
Kearny 10
Kearny 11
Kearny 9
Keystone Recovery (Units 1 - 7)
Killen 2
Killen CT
Kimberly Clark Generator
Kinsley Landfill
Kitty Hawk GT 1
Kitty Hawk GT 2
Koppers Co. IPP
Lake Kingman
Lake Shore 18
Lake Shore EMD
MEA NUG (WVU)
MH50 Markus Hook Co-gen
Mad River CTs A
Mad River CTs B
Mansfield 1
Mansfield 2
Mansfield 3
Martins Creek CT 4
McKee 1
McKee 2
McKee 3Mercer 1
Mercer 2
Mercer 3
Miami Fort 6
Middle 1-3
Missouri Ave B,C,D
Mitchell 2
Mitchell 3Modern Power Landfill NUG

ID
166
167
168
169
170
171
172
173
174
175
176
177
178
179
180
181
182
183
184
185
186
187
188
189
190
191
192
193
194
195
196
197
198
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
214
215
216
217
218
219
220

Unit
Monmouth NUG landfill
Montour ATG
Morgantown Unit 1
Morgantown Unit 2
Morris Landfill Generator
Muskingum River 1-5
National Park 1
Niles 1
Niles 2
Northeastern Power NEPCO
Notch Cliff GT1
Notch Cliff GT2
Notch Cliff GT3
Notch Cliff GT4
Notch Cliff GT5
Notch Cliff GT6
Notch Cliff GT7
Notch Cliff GT8
Oaks Landfill
Occoquan 1 LF
Oyster Creek
Pennsbury Generator Landfill 1
Pennsbury Generator Landfill 2
Perryman 2
Picway 5
Piney Creek NUG
Portland 1
Portland 2
Possum Point 3
Possum Point 4
Possum Point 5
Potomac River 1
Potomac River 2
Potomac River 3
Potomac River 4
Potomac River 5
Pottstown LF (Moser)
R Paul Smith 3
R Paul Smith 4
Reichs Ford Road Landfill Generator
Riverside 4Riverside 6
Riverside 7
Riverside 8Riversville 5Riversville 6
Roanoke Valley 1
Roanoke Valley 2
Rolling Hills Landfill Generator
SMART Paper
Salem County LF
Sammis 1-4
Schuylkill 1
Schuylkill Diesel
Sewaren 1

ID
221
222
223
224
225
226
227
228
229
230
231
232
233
234
235
236
237
238
239
240
241
242
243
244
245
246
247
248
249
250
251
252
253
254
255
256
257
258
259
260
261
262
263
264
265
266
267
268
269
270
271
272
273
274
275

Unit
Sewaren 2
Sewaren 3
Sewaren 4
Sewaren 6
Southeast Chicago CT11
Southeast Chicago CT12Southeast Chicago CT5
Southeast Chicago CT6
Southeast Chicago CT7
Southeast Chicago CT8Southeast Chicago GT10Southeast Chicago GT9Sporn 1-4
Sporn 5
Spruance NUG1 (Rich 1-2)
Spruance NUG2 (Rich 3-4)
State Line 3
State Line 4
Stuart 1
Stuart 2
Stuart 3
Stuart 4
Stuart Diesels 1-4
Stuart Diesels 1-4
Sunbury 1-4
Sussex County LF
Tait Battery
Tanners Creek 1-4
Three Mile Island Unit 1
Titus 1
Titus 2
Titus 3
Viking Energy NUG
Wagner 2
Walter C Beckjord 1
Walter C Beckjord 2
Walter C Beckjord 3
Walter C Beckjord 4
Walter C Beckjord 5-6
Walter C Beckjord GT 1-4
Warren County Landfill
Warren County NUG
Waukegan 7
Waukegan 8
Werner 1-4
West Kingsport LF
Westport 5
Will County 3
Will County 4
Willow Island 1
Willow Island 2
Winnebago Landfill
York Generation Facility
Yorktown 1-2
Zanesville Landfill© 2021 Monitoring Analytics, LLC

Section 12 Planning

Current Year Generation Retirements
Table 12-10 shows that in the first six months of 2021, 1,251.4 MW of generation retired. The largest generators that retired in the first six months of 2021
were the 667.0 MW Chalk Point Unit 1 and 2 coal fired steam units located in the PEPCO Zone. Of the 1,251.4 MW of generation that retired, 667.0 MW (53.3
percent) were located in the PEPCO Zone.
Table 12-10 Unit deactivations: January through June, 2021
Company
Ares Management LP
Biogas Energy Solutions, LLC
Galt Power Inc.
General Electric Company
Riverstone Holdings LLC
American Electric Power Company, Inc.
Domtar Corporation
City of DoverGenOn Energy, Inc.
GenOn Energy, Inc.
Total

© 2021 Monitoring Analytics, LLC

Unit Name
Spruance NUG1 (aka Spruance 1 Rich 1-2)
Countryside Landfill
Beckjord Battery Unit 2
Birchwood Plant
Elmwood Park Power
Balls Gap Battery Facility
West Kingsport LF
McKee 3
Chalk Point Unit 1
Chalk Point Unit 2

ICAP (MW)Unit Type
115.5
Steam-Coal
8.0
RICE-Other
2.0
Battery
237.9
Steam-Coal
67.0
Combined Cycle
2.0
Battery
50.0
Steam-Other
102.0 Steam-Natural Gas
331.0
Steam-Coal
336.0
Steam-Coal
1,251.4

Zone Name
DOM
COMED
DUKE
DOM
PSEG
AEP
AEP
DPL
PEPCO
PEPCO

Age (Years)
28.7
8.5
5.3
24.3
32.0
4.2
14.7
46.1
56.9
56.3

Retirement Date
12-Jan-21
27-Jan-21
03-Feb-21
01-Mar-21
12-Mar-21
22-Apr-21
31-May-21
01-Jun-21
01-Jun-21
01-Jun-21

2021 Quarterly State of the Market Report for PJM: January through June 625

2021 Quarterly State of the Market Report for PJM: January through June

Planned Generation Retirements
Table 12-11 shows that, as of June 30, 2021, there are 10,161.0 MW of generation that have requested retirement after June 30, 2021. Of the 10,161.0 MW
requesting retirement, 5,042.1 MW (49.6 percent) are coal fired steam units and 4,086.5 MW (40.2 percent) are nuclear units. Of the 10,161.0 MW of planned
retirements, 5,280.6 MW (52.0 percent) are located in the COMED Zone. Of the generation requesting retirement in the COMED Zone, 4,086.5 MW (77.4 percent)are nuclear units and 1,194.1 MW (22.6 percent) are coal fired steam units.
Table 12-11 Planned retirement of units: June 30, 2021
Company
Riverstone Holdings LLC
Northeast Maryland Waste Disposal Authority
Exelon Corporation
GenOn Energy, Inc.
GenOn Energy, Inc.
GenOn Energy, Inc.
Exelon Corporation
Exelon Corporation
Exelon Corporation
NRG Energy Inc
Riverstone Holdings LLC
GenOn Energy, Inc.
GenOn Energy, Inc.
NRG Energy Inc
NRG Energy Inc
NRG Energy Inc
Riverstone Holdings LLC
Dominion Energy, Inc.
Dominion Energy, Inc.
LS Power Equity Partners, L.P.
Total

Unit Name
Harwood 1-2
Oaks Landfill
Byron 1
Avon Lake 10
Avon Lake 9
Cheswick 1
Byron 2
Dresden 2
Dresden 3
Indian River 4
Martins Creek CT 4
Morgantown Unit 1
Morgantown Unit 2
Waukegan 7
Waukegan 8
Will County 4York Generation Facility
Chesterfield 5
Chesterfield 6
Buchanan 1-2

ICAP (MW)Unit Type
28.0
CT-Oil2.4
RICE-Other
1,164.0
Nuclear
21.0
CT-Oil638.0
Steam-Coal
565.0
Steam-Coal
1,136.0
Nuclear883.5
Nuclear903.0
Nuclear410.0
Steam-Coal
850.0 Steam-Natural Gas
610.0
Steam-Coal
619.0
Steam-Coal
328.0
Steam-Coal
356.1
Steam-Coal
510.0
Steam-Coal
51.0
Combined Cycle
336.0
Steam-Coal
670.0
Steam-Coal
80.0
CT-Natural Gas
10,161.0

Zone Name
PPL
PEPCO
COMED
ATSI
ATSI
DUQ
COMED
COMED
COMED
DPL
PPL
PEPCO
PEPCO
COMED
COMED
COMED
MEC
DOM
DOM
AEP

Projected
Deactivation Date
31-May-21
01-Jul-21
14-Sep-21
15-Sep-21
15-Sep-21
15-Sep-21
16-Sep-21
08-Nov-21
29-Nov-21
31-May-22
31-May-22
31-May-22
31-May-22
31-May-22
31-May-22
31-May-22
31-May-22
31-May-23
31-May-23
01-Jun-23

Generation Queue23
Any entity that requests interconnection of a new generating facility, including increases to the capacity of an existing generating unit, or that requests
interconnection of a merchant transmission facility, must follow the process defined in the PJM tariff to obtain interconnection service.24 PJM’s process isdesigned to ensure that new generation is added in a reliable and systematic manner. The process is complex and time consuming at least in part as a resultof the required analyses. The cost, time and uncertainty associated with interconnecting to the grid may create barriers to entry for potential entrants. But the
behavior of project developers also creates issues with queue management and exacerbates the barriers.

23 The queue totals in this report are the winter net MW energy for the interconnection requests (“MW Energy”) as shown in the queue.
24 See OATT Parts IV & VI.

626

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Generation request queues are groups of proposed projects, including
new units, reratings of existing units, capacity resources and energy only
resources. Each queue is open for a fixed amount of time. Studies commenceon all projects in a given queue when that queue closes. Queues A and B wereopen for one year. Queues C through T were open for six months. Startingin February 2008, Queues U through Y1 were open for three months. In May
2012, the duration of the queue period was reset to six months, starting with
Queue Y2. Queue AG2 opened on October 1, 2020 and closed on March 31,
2021 and Queue AH1 opened on April 1, 2021 and will close on September
30, 2021.
Projects that do not meet submission requirements are removed from thequeue. All projects that have entered a queue and have met the submission
requirements have a status assigned. Projects listed as active are undergoing
one of the studies (feasibility, system impact, facility) required to proceed. Other
status options are under construction, suspended, and in service. A project
cannot be suspended until it has reached the status of under construction. Any
project that entered the queue before February 1, 2011, can be suspended for
up to three years. Projects that entered the queue after February 1, 2011, face
an additional restriction in that the suspension period is reduced to one year
if they affect any project later in the queue.25 When a project is suspended,
PJM extends the scheduled milestones by the duration of the suspension. If,
at any time, a milestone is not met, PJM will initiate the termination of theInterconnection Service Agreement (ISA) and the corresponding cancellation
costs must be paid by the customer.26

projects to advance in the queue ahead of projects which have failed to makeprogress, subject to rules to prevent gaming.

Process Timelines
In the study phase of the interconnection planning process, a series of studies
are performed to determine the feasibility, impact, and cost of projects in thequeue. Table 12-12 is an overview of PJM’s study process. System impact andfacilities studies are often redone when a project is withdrawn in order todetermine the impact on the projects remaining in the queue.
In 2016, the PJM Earlier Queue Submitted Task Force stakeholder group madechanges to the interconnection process to address some of the issues related todelays observed in the various stages of the study phase. The changes became
effective with the AC2 Queue that closed on March 31, 2017. The MMU
recommends continuing analysis of the study phase of PJM’s transmission
planning to reduce the need for postponements of study results, to decrease
study completion times, and to improve the likelihood that a project at a given
phase in the study process will successfully go into service.

The PJM queue evaluation process has been substantially improved in recent
years and it is more efficient and effective as a result.27 The PJM queue
evaluation process should continue to be improved to help ensure thatbarriers to competition from new generation investments are not created.
The MMU recommends improvements in queue management including thatPJM establish a review process to ensure that projects are removed from thequeue if they are not viable, as well as a process to allow commercially viable
25 See PJM. “PJM Manual 14C: Generation and Transmission Interconnection Process,” Rev. 14 (January 27, 2021).
26 PJM does not track the duration of suspensions or PJM termination of projects.
27 See PJM Interconnection, L.L.C., Docket No. ER12-1177 (Feb. 29, 2012).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 627

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-12 Generation planning process
Process Step
Feasibility Study
System Impact Study
Facilities Study
Schedule of Work
Construction (only for new generation)

Start on
Close of current queue
Upon acceptance of the System Impact Study
Agreement
Upon acceptance of the Facilities Study Agreement
Upon acceptance of Interconnection Service
Agreement (ISA)
Upon acceptance of Interconnection Construction
Service Agreement (ICSA)

Financial Obligation
Cost of study (partially refundable deposit)
Cost of study (partially refundable deposit)

Days for PJM toComplete90
120

Days for Applicant to
Decide Whether toContinue
30
30

Cost of study (refundable deposit)
Letter of credit for upgrade costs

VariesVaries

60
37

None

VariesNA

Process improvements have allowed PJM to continue to meet the deadlines forfeasibility and system impact studies despite the increase in interconnection
requests. The increase in the number of projects submitted in the queue
combined with the rules for evaluating projects have contributed to asignificant backlog in performing timely facility studies. The facility study
includes the conceptual design, stability analyses and determines the network
upgrades, and the costs associated with those upgrades. Modifications toproposed facilities and restudies resulting from the withdrawal of projects
from the queue also affect the time to complete a facility study. In 2020,
PJM conducted interconnection process workshops designed to review current
processes, receive input and recommendations from stakeholders and todevelop improvements to the process, including ways to resolve the current
interconnection study backlog. That work has continued during the first six
months of 2021.

PJM has added capacity steadily since markets were implemented on April 1,
1999.28
There were 173,182.4 MW in generation queues, in the status of active, underconstruction or suspended, at the end of 2020. In the first six months of2021, the AG2 queue window closed and the AH1 queue window opened. As
projects move through the queue process, projects can be removed from thequeue due to incomplete or invalid data, withdrawn by the market participant
or placed in service. On June 30, 2021, there were 217,381.6 MW in generation
queues, in the status of active, under construction or suspended, an increaseof 44,199.2 MW (25.5 percent) from December 31, 2020. Table 12-13 shows
MW in queues by expected completion year and MW changes in the queue
between December 31, 2020, and June 30, 2021, for ongoing projects, i.e.
projects with the status active, under construction or suspended.29

Planned Generation Additions
Expected net revenues provide incentives to build new generation to serve
PJM markets. The amount of planned new generation in PJM reflects investors’
perception of the incentives provided by the combination of revenues fromthe PJM energy, capacity and ancillary service markets. On June 30, 2021,
217,381.6 MW were in generation request queues for construction through2029. Although it is clear that not all generation in the queues will be built,

628

Section 12 Planning

28 See “PJM Generation Capacity and Funding Sources 2007/2008 through 2021/2022 Delivery Years,” <http://www.monitoringanalytics.
com/reports/Reports/2020/IMM_2020_PJM_Generation_Capacity_and_Funding_Sources_20072008_through_20212022_DY_20200915.
pdf>.
29 Expected completion dates are entered when the project enters the queue. Actual completion dates are generally different than expectedcompletion dates.

© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-13 Queue comparison by expected completion year (MW): December
31, 2020 and June 30, 202130
Year
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
Total

As of 12/31/2020
0.0
0.0
0.0
0.0
16.1
20.0
0.0
0.0
19.4
658.1
1,825.6
7,362.8
11,427.1
30,714.5
41,359.1
40,831.9
19,065.5
3,995.6
2,645.2
2,100.1
0.0
800.1
162,841.0

As of 06/30/2021
0.0
0.0
0.0
0.0
16.1
20.0
0.0
0.0
3.4
544.1
830.2
6,500.6
9,334.3
30,504.4
43,960.9
52,632.5
50,524.6
12,414.1
7,196.2
2,100.1
0.0
800.1
217,381.6

Year Change
MW
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
(16.0)(114.0)(995.4)(862.2)(2,092.8)(210.1)
2,601.9
11,800.6
31,459.1
8,418.5
4,551.0
0.0
0.0
0.054,540.6

Percent
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
(82.5%)(17.3%)(54.5%)(11.7%)(18.3%)(0.7%)
6.3%
28.9%
165.0%
210.7%
172.0%
0.0%
0.0%
0.0%
33.5%

Table 12-14 shows the project status changes in more detail and how scheduled
queue MW have changed between December 31, 2020, and June 30, 2021. For
example, 55,323.1 MW entered the queue in the first six months of 2021. Of
those 55,323.1 MW, 782.5 MW have been withdrawn. Of the total 156,286.4
MW marked as active on December 31, 2020, 7,948.4 MW were withdrawn,
2,946.8 MW were suspended, 2,218.3 MW started construction, and 203.5 MW
went into service by June 30, 2021. Analysis of projects that were suspendedon December 31, 2020 show that 946.0 MW came out of suspension and are
now active as of June 30, 2021.

Table 12-14 Change in project status (MW): December 31, 2020 to June 30,
2021
Status at 12/31/2020(Entered during 2021)
ActiveIn Service
Under Construction
Suspended
Withdrawn
Total

Total at12/31/2020
0.0
156,286.4
73,092.3
9,570.8
7,017.3
410,672.5
656,639.2

Active54,540.6
142,969.4
0.0
12.1
946.0
90.0
198,558.1

Status at 6/30/2021
Under
In Service Construction Suspended
0.0
0.0
0.0
203.5
2,218.3
2,946.8
73,090.2
0.0
0.0
876.2
8,661.9
0.0
0.0
400.0
4,596.5
0.0
0.0
0.0
74,169.9
11,280.2
7,543.3

Withdrawn
782.5
7,948.4
2.1
20.6
1,074.8
410,582.5
420,410.9

On June 30, 2021, 217,381.6 MW were in generation request queues in thestatus of active, suspended or under construction. Table 12-15 shows eachstatus by unit type. Of the 198,558.1 MW in the status of Active on June30, 2021, 10,652.3 MW (5.4 percent) were combined cycle projects. Of the
11,280.2 MW in the status of under construction, 7,840.3 MW (69.5 percent)were combined cycle projects. A significant amount of renewable hybrid
projects (defined as solar + storage, solar + wind and wind + storage projects)
have entered the queue in recent years. Of the 198,558.1 MW in the status ofActive on June 30, 2021, 25,761.6 MW (13.0 percent) were renewable hybrid
projects. Of the 11,280.2 MW in the status of under construction, 5.7 MW(0.05 percent) were renewable hybrid projects.

30 Wind and solar capacity in Table 12-11 through Table 12-15 have not been adjusted to reflect derating.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 629

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-15 Current project status (MW) by unit type: June 30, 2021

ActiveSuspended
Under Construction
Total

Battery
27,850.8
34.0
0.0
27,884.8

Combined
Cycle
10,652.3
4,316.0
7,840.3
22,808.6

CT NaturalGas
4,576.9
1,055.0
349.4
5,981.3

CT - Oil
18.0
0.0
13.0
31.0

CT Other Fuel Cell
6.0
0.0
0.0
0.0
0.0
3.0
6.0
3.0

Hydro Pumped
Storage
730.0
0.0
0.0
730.0

Hydro Run of
River
124.9
0.0
0.0
124.9

Nuclear
145.5
0.0
44.0
189.5

RICE Natural
Gas RICE - Oil
0.0
0.0
0.0
0.0
1.3
0.0
1.3
0.0

RICE Other
Solar
0.0 96,285.7
0.0
1,174.5
0.0
2,677.4
0.0 100,137.6

Solar +
Storage
25,552.6
120.0
5.7
25,678.3

Solar +
Wind
209.0
0.0
0.0
209.0

Steam Coal
40.0
0.0
36.0
76.0

Steam Natural
Gas
11.0
0.0
0.0
11.0

Steam
- Oil
0.0
0.0
0.0
0.0

Steam Other
20.0
0.0
0.0
20.0

Wind
32,335.5
737.6
310.0
33,383.1

Wind +
Storage
Total
0.0 198,558.1
106.3
7,543.3
0.0 11,280.2
106.3 217,381.6

A significant shift in the distribution of unit types within the PJM footprint continues to develop as natural gas fired units and renewable, hybrid and otherintermittent resources enter the queue and coal fired steam units retire. As of June 30, 2021, of the 217,381.6 MW in the generation request queues in the statusof active, suspended or under construction, 100,137.6 MW (46.1 percent) were solar projects, 33,383.1 MW (15.4 percent) were wind projects, 28,802.2 MW (13.2
percent) were natural gas fired projects (including combined cycle units, CTs, RICE units, and natural gas fired steam units), 25,993.6 MW (12.0 percent) wererenewable hybrid projects (solar + storage, solar + wind and wind + storage units), and 76.0 MW (.03 percent) were coal fired steam projects.
As of June 30, 2021, there are 5,042.1 MW of coal fired steam units and 930 MW of natural gas units slated for deactivation between July 1, 2021, and December
31, 2024 (See Table 12-11). The ongoing replacement of coal fired steam units by natural gas units will continue to significantly affect future congestion, therole of firm and interruptible gas supply, and natural gas supply infrastructure. The small but growing level of renewables, hybrids and other intermittents will
also have increasingly significant impacts on the energy and capacity markets.
Table 12-16 shows the total MW in the status of active, in service, under construction, suspended, or withdrawn for each queue since the beginning of the RTEP
process and the total MW that had been included in each queue. All items in queues A-R are either in service or have been withdrawn. As of June 30, 2021,
there are 217,381.6 MW in queues that are not yet in service or withdrawn, of which 3.5 percent are suspended, 5.2 percent are under construction and 91.3
percent have not begun construction.

630

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-16 Queue totals by status (MW): June 30, 202131
Queue
A Expired 31-Jan-98
B Expired 31-Jan-99
C Expired 31-Jul-99
D Expired 31-Jan-00
E Expired 31-Jul-00
F Expired 31-Jan-01
G Expired 31-Jul-01
H Expired 31-Jan-02
I Expired 31-Jul-02
J Expired 31-Jan-03
K Expired 31-Jul-03
L Expired 31-Jan-04
M Expired 31-Jul-04
N Expired 31-Jan-05
O Expired 31-Jul-05
P Expired 31-Jan-06
Q Expired 31-Jul-06
R Expired 31-Jan-07
S Expired 31-Jul-07
T Expired 31-Jan-08
U1 Expired 30-Apr-08
U2 Expired 31-Jul-08
U3 Expired 31-Oct-08
U4 Expired 31-Jan-09
V1 Expired 30-Apr-09
V2 Expired 31-Jul-09
V3 Expired 31-Oct-09
V4 Expired 31-Jan-10
W1 Expired 30-Apr-10
W2 Expired 31-Jul-10
W3 Expired 31-Oct-10
W4 Expired 31-Jan-11
X1 Expired 30-Apr-11
X2 Expired 31-Jul-11
X3 Expired 31-Oct-11
X4 Expired 31-Jan-12
Y1 Expired 30-Apr-12
Y2 Expired 31-Oct-12
Y3 Expired 30-Apr-13
Z1 Expired 31-Oct-13
Z2 Expired 30-Apr-14
AA1 Expired 31-Oct-14
AA2 Expired 30-Apr-15
AB1 Expired 31-Oct-15
AB2 Expired 31-Mar-16
AC1 Expired 30-Sep-16
AC2 Expired 30-Apr-17
AD1 Expired 30-Sep-17
AD2 Expired 31-Mar-18
AE1 Expired 30-Sep-18
AE2 Expired 31-Mar-19
AF1 Expired 30-Sep-19
AF2 Expired 31-Mar-20
AG1 Expired 30-Sep-20
AG2 Expired 31-Mar-21
AH1 Through 30-Sep-21
Total

Active
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
70.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
200.0
0.0
0.0
12.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
38.0
0.0
904.6
682.0
2,795.6
1,468.8
5,650.5
2,517.4
5,466.4
6,313.3
15,881.7
22,409.2
22,154.4
21,432.0
33,188.8
55,823.4
1,549.8
198,558.1

In Service
9,094.0
4,643.4
531.0
850.6
795.2
52.0
1,189.6
702.5
103.0
42.0
93.1
256.5
504.8
2,398.8
1,890.2
3,290.3
3,147.9
1,892.5
3,543.5
4,196.5
218.9
777.5
333.0
85.2
197.9
989.9
912.0
748.8
567.4
351.7
508.7
1,415.8
1,103.8
3,706.4
89.2
2,948.9
1,795.5
1,657.2
1,425.5
3,074.5
3,063.0
3,526.9
1,310.6
1,283.0
912.3
999.6
323.8
228.9
290.6
50.6
50.0
2.4
3.0
0.0
0.0
0.0
74,169.9

Under
Construction
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
16.1
220.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
20.0
0.0
0.0
0.0
205.0
0.0
0.0
1,302.0
1,510.0
1,379.3
2,282.3
3,364.8
272.7
156.6
443.1
39.9
3.8
61.4
3.2
0.0
0.0
0.0
11,280.2

Suspended
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
100.0
200.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
72.0
0.0
0.0
975.3
10.0
0.0
1,189.0
3,065.0
445.0
508.6
349.9
255.0
144.0
27.6
90.4
64.3
27.3
20.0
0.0
0.0
7,543.3

Withdrawn
17,252.0
14,958.8
3,558.3
7,358.0
8,021.8
3,092.5
17,961.8
8,421.9
3,728.4
846.0
485.3
4,033.7
3,705.6
8,129.3
5,466.8
5,320.5
11,385.7
20,708.9
12,396.5
23,313.3
7,937.8
16,218.6
2,535.6
4,745.0
2,572.8
3,625.1
3,822.7
3,508.0
5,139.5
3,051.7
8,683.8
4,152.6
6,200.6
5,578.4
7,665.9
2,419.4
6,207.7
9,636.5
4,609.2
4,037.0
3,027.8
6,335.4
11,374.7
11,923.0
10,057.4
9,518.9
9,137.8
5,195.7
13,178.9
17,907.1
11,294.9
6,635.4
6,782.7
4,591.0953.8
3.7
420,410.9

Total
26,346.0
19,602.2
4,089.3
8,208.6
8,817.0
3,144.5
19,151.4
9,124.4
3,831.4
888.0
578.4
4,290.2
4,210.4
10,528.0
7,357.0
8,610.8
14,533.6
22,601.4
16,010.0
27,509.8
8,156.7
16,996.1
2,968.6
5,030.2
2,770.7
4,631.1
4,954.7
4,456.8
5,706.9
3,403.4
9,204.6
5,568.4
7,304.4
9,284.7
7,775.1
5,368.3
8,075.2
11,293.7
6,239.6
8,124.8
6,100.8
12,068.9
16,066.3
20,445.9
15,165.8
20,042.2
12,601.6
11,302.6
20,369.933,907.0
33,848.2
28,917.9
28,248.1
37,799.9
56,777.2
1,553.5
711,962.4

31 Projects listed as partially in service are counted as in service for the purposes of this analysis.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 631

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-17 shows the projects with a status of active, suspended or under construction, by unit type, and control zone. As of June 30, 2021, 217,381.6 MW
were in generation request queues for construction through 2029. Table 12-17 also shows the planned retirements for each zone.
Table 12-17 Queue totals for projects (active, suspended and under construction) by LDA, control zone and unit type (MW): June 30, 202132
LDA
EMAAC

SWMAAC
WMAAC

Non-MAAC

Zone
ACEC
DPL
JCPLC
PECO
PSEG
REC
EMAAC Total
BGE
PEPCO
SWMAAC Total
MEC
PE
PPL
WMAAC Total
AEP
APS
ATSI
COMED
DAY
DUKE
DLCO
DOM
EKPC
OVEC
RMU
Non-MAAC Total
Total

Battery
1,238.0
769.0
813.8
0.0
1,077.0
0.0
3,897.8
863.5
301.0
1,164.5
405.2
530.8
475.0
1,411.0
6,218.8872.8
1,140.3
3,046.1
175.0
277.2
55.0
9,500.3
126.0
0.0
0.0
21,411.5
27,884.8

CT NaturalCC
Gas CT - Oil
7.6
230.0
0.0
451.0
0.0
0.0
35.0
0.0
0.0
0.0
0.0
0.0
51.1
675.0
0.0
0.0
0.0
0.0
544.7
905.0
0.0
0.0
144.6
14.0
0.0
57.3
4.0
0.0
201.9
18.0
75.0
13.5
7.5
248.0
585.5
0.0
106.6
0.0
0.0
429.6
599.0
7.5
6,015.0 1,110.1
0.0
5,684.7
112.0
0.0
3,597.0
523.7
5.5
3,712.6 1,125.2
0.0
1,150.0
43.5
0.0
0.0
0.0
0.0
0.0
222.9
0.0
1,675.0 1,138.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
21,834.3 4,275.4
5.5
22,808.6 5,981.3
31.0

CT Other
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
6.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
6.0
6.0

Fuel
Cell
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.0
0.0
3.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.0

Hydro - Hydro RICE Pumped Run of
NaturalStorageRiver Nuclear
Gas
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
30.0
0.0
0.0
0.0
0.0
0.0
44.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
30.0
0.0
44.0
0.0
0.0
0.0
45.5
1.3
0.0
0.0
0.0
0.0
0.0
0.0
45.5
1.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
700.0
0.0
100.0
0.0
700.0
0.0
100.0
0.0
0.0
51.0
0.0
0.0
0.0
15.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
12.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
46.8
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
124.9
0.0
0.0
730.0
124.9
189.5
1.3

RICE Oil
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

RICE Other
Solar
0.0
839.6
0.0
1,957.2
0.0
375.7
0.0
55.8
0.0
61.2
0.0
0.0
0.0
3,289.5
0.0
154.9
0.0
215.1
0.0
370.1
0.0
914.7
0.0
4,206.7
0.0
2,325.7
0.0
7,447.2
0.0 32,866.6
0.0
4,704.6
0.0
4,776.0
0.0
8,470.5
0.0
3,372.5
0.0
533.9
0.0
58.9
0.0 29,306.5
0.0
4,771.4
0.0
170.0
0.0
0.0
0.0 89,030.9
0.0 100,137.6

Solar + Solar +Storage
Wind
60.0
0.0
170.0
0.0
180.0
0.0
5.0
0.0
23.8
0.0
0.0
0.0
438.8
0.0
0.0
0.0
562.5
0.0
562.5
0.0
177.1
0.0
838.4
0.0
437.0
0.0
1,452.4
0.0
9,999.2
0.0
2,079.3
0.0
570.9
0.0
2,099.9
199.0
189.0
0.0
0.0
10.0
37.5
0.0
5,792.7
0.0
2,456.3
0.0
0.0
0.0
0.0
0.0
23,224.6
209.0
25,678.3
209.0

Steam Steam Natural- Coal
Gas
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
5.0
0.0
0.0
0.0
5.0
0.0
0.0
0.0
6.0
0.0
6.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
76.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
76.0
0.0
76.0
11.0

Steam Steam- Oil - Other
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
20.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
20.0
0.0
20.0

Total
Wind +
Queue
Wind Storage Capacity
3,441.6
0.0
5,816.8
4,123.5
0.0
7,470.7
4,269.2
0.0
5,703.6
0.0
0.0
104.8
1,300.0
0.0
3,193.1
0.0
0.0
0.0
13,134.3
0.0 22,289.00.0
0.0
1,223.8
0.0
0.0
1,145.90.0
0.0
2,369.8
0.0
0.0
1,593.0
260.2
0.0
6,672.6
514.9
90.0
4,749.2
775.1
90.0 13,014.8
3,830.4
0.0 60,173.0
567.0
16.3 14,051.6
816.1
0.0 11,429.5
8,843.1
0.0 27,508.5
0.0
0.0
4,930.0
0.0
0.0
821.1
0.0
0.0
441.1
5,417.2
0.0 52,829.6
0.0
0.0
7,353.7
0.0
0.0
170.0
0.0
0.0
0.0
19,473.7
16.3 179,708.1
33,383.1
106.3 217,381.6

PlannedRetirements
0.0
410.0
0.0
0.0
0.0
0.0
410.0
0.0
1,231.4
1,231.4
51.0
0.0
878.0
929.0
80.0
0.0
659.0
5,280.6
0.0
0.0
565.0
1,006.0
0.0
0.0
0.0
7,590.6
10,161.0

Since wind resources cannot be dispatched on demand, PJM rules previously required that the unforced capacity of wind resources be derated to 20 percent ofnameplate capacity until actual generation data are available. Beginning with Queue U, PJM derated wind resources to 13 percent of nameplate capacity until
there was operational data to support a different conclusion.33 PJM derated solar resources to 38 percent of nameplate capacity. Effective June 1, 2017, PJM
adjusted the derates of wind and solar resources. The capacity factor derates for wind resources are dependent on the wind farm locations and have an averagederate of 16.2 percent. The capacity factor derates for solar resources are dependent on the solar installation type and have an average derate of 46.7 percent.
Using the average derate factors, based on the derating of 33,383.1 MW of wind resources to 5,408.1 MW, 100,137.6 MW of solar resources to 46,764.2 MW,
25,673.3 MW of solar + storage resources to 11,991.8 MW, 209 MW of solar + wind resources to 11.4 MW and 106.3 MW of wind + storage resources to 89.1
MW, the 217,381.6 MW currently under construction, suspended or active in the queue would be reduced to 122,146.2 MW.

32 This data includes only projects with a status of active, under construction, or suspended.
33 See PJM. “PJM Manual 14B: PJM Region Transmission Planning Process,” Rev. 49 (June 23, 2021).

632

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Withdrawn Projects
The queue contains a substantial number of projects that are not likely to
be built. The queue process results in a substantial number of projects thatare withdrawn. Manual 14B requires PJM to apply a commercial probability
factor at the feasibility study stage to improve the accuracy of capacity andcost estimates. The commercial probability factor is based on the historicalincidence of projects dropping out of the queue at the impact study stage,
but the actual calculation of commercial probability factors is less thantransparent.34 The impact and facilities studies are performed using the fullamount of planned generation in the queues. The actual withdrawal rates areshown in Table 12-18 and Table 12-19.
Table 12-18 shows the milestone status when projects were withdrawn,
for all withdrawn projects. Of the 3,145 projects withdrawn as of June 30,
2021, 1,568 (50.9 percent) were withdrawn before the system impact study
was completed. Once a Construction Service Agreement (CSA) is executed,
the financial obligation for any necessary transmission upgrades cannot be
retracted. Of the 3,145 projects withdrawn, 601 (19.1 percent) were withdrawn
after the completion of a Construction Service Agreement.
Table 12-18 Last milestone at time of withdrawal: January 1, 1997 throughJune 30, 2021
Milestone Completed
Never Started
Feasibility Study
System Impact Study
Facilities Study
Construction Service Agreement (CSA) or beyond
Total

Projects
Withdrawn
535
1,033
676
300
601
3,145

Percent Average Days
17.0%
79
32.8%
267
21.5%
713
9.5%
1,133
19.1%
1,359
100.0%

Maximum
Days
868
1,633
3,248
4,107
7,864

Average Time in Queue
Table 12-19 shows the time spent at various stages in the queue process andthe completion time for the studies performed. For completed projects, there
is an average time of 1,080 days, or 2.9 years, between entering a queue and
34 See PJM. “PJM Manual 14B: PJM Region Transmission Planning Process,” Rev. 49 (June 23, 2021).

© 2021 Monitoring Analytics, LLC

going into service. For withdrawn projects, there is an average time of 622
days, or 1.7 years, between entering a queue and withdrawing.
Table 12-19 Project queue times by status (days): June 30, 202135
StatusActiveIn-Service
Suspended
Under Construction
Withdrawn

Average (Days)
262
1,080
1,301
1,195
622

Standard Deviation
430
789
931
809
735

Minimum
0
0
0
105
0

Maximum
4,852
5,306
4,292
4,050
7,864

Table 12-20 presents information on the time in the stages of the queue forthose projects not yet in service or already withdrawn. Of the 2,353 projects inthe queue as of June 30, 2021, 459 (19.5 percent) had a completed feasibility
study and 398 (16.9 percent) had a completed construction service agreement.
Table 12-20 Project queue times by milestone (days): June 30, 2021
Milestone Reached
Under Review
Feasibility Study
System Impact Study
Facilities Study
Construction Service Agreement (CSA) or beyond
Total

Number ofPercent of
Projects Total Projects Average Days
691
29.4%
0
459
19.5%
52
772
32.8%
428
33
1.4%
1,052
398
16.9%
961
2,353
100.0%

Maximum
Days
0
1,072
2,069
2,434
4,852

Table 12-21 shows the time spent in the queue by fuel type, and year the
project entered the queue, for projects that are in service. The time from whena project enters the queue to the time the project goes in service has generally
been decreasing compared to the period prior to 2017. For example, for abattery project entering the queue in 2015, there was an average of 1,082
days from the time it entered the queue until it went in service, compared toonly 293 days when entering the queue in 2018, but the time increased to 600
days in 2019.

35 The queue data shows that some projects were withdrawn and a withdrawal date was not identified. These projects were removed for the
purposes of this analysis.

2021 Quarterly State of the Market Report for PJM: January through June 633

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-21 Average time in queue (days) by fuel type and year submitted (InService Projects): June 30, 202136
Unit Type
BatteryCC
CT - Natural Gas
CT - OilCT - Other
Fuel Cell
Hydro - Pumped Storage
Hydro - Run of River
Nuclear
RICE - Natural Gas
RICE - Oil
RICE - Other
Solar
Solar + Storage
Solar + Wind
Steam - Coal
Steam - Natural Gas
Steam - Oil
Steam - Other
WInd
Wind + Storage

2010
983
1,310
1,131
717
729

2011
609
1,551
804
634

2012
417
1,663
953
259
954

1,325
885

638
1,701

745

256
2,748

838
2,711

2014
789
1,106
734

2015
1,082
838
901

2016
941
746
1,192

1,248

718

360
827
1,402

643

1,702

614
1,234
1,053

1,332

1,479
969

241
1,014

627
1,003

513

1,010
1,182

1,589

866

1,385
1,313

2013
692
1,419
1,021

643
1,750

332

580

2017
383
828
657

2018
293
309
688

426

606

798
1,849
622
1,416

491
1,124

583

853
421

677
751

647

1,205

1,463

1,443

1,200

2019
600
512
255

2020

488

296

319

250

759

466
830
553

2021

the calculation of the SIS completion rate, but not in thecalculation of the FSA or CSA completion rates. Similarly,
if a project was withdrawn after the completion of its FSA,
but before the completion of the CSA, the totals would be
included in the calculation of the SIS and FSA completion
rates, but not in the calculation of the CSA completion
rate. The completion rates show that of all battery projects
to ever enter the queue and complete the system impact
study stage, 14.9 percent of the queued MW have gone into
service. The completion rate for battery projects increases
to 36.2 percent when battery projects complete the facility
study agreement and further increases to 43.2 percent
when battery projects complete the construction service
agreement. Of all battery projects to enter the queue, only
0.8 percent of the queued MW have gone into service.

561

Completion Rates
The probability of a project going into service increases as each step of theplanning process is completed.
Table 12-22 shows the historic completion rates (MW energy) by unit type forprojects that have completed the system impact study (SIS), facilities study
agreement (FSA) and construction service agreement (CSA) milestones as wellas the historic completion rates for all projects including those withdrawn
before reaching the SIS milestone. For each unit type, the total MW in service
was divided by the total energy MW entered in the queue. To calculate thecompletion rates for projects that reached the individual milestones, only
those projects that reached a final status of withdrawn or in service were
evaluated. For example, if a project was withdrawn after the completion of
its SIS, but before the completion of the FSA, the totals would be included in
36 A blank cell in this table means that no project of that fuel type, which was submitted to the queue in that year, subsequently went inservice.

634

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-22 Historic completion rates (MW energy) by unit type for projects with a completed SIS, FSA and CSA: June 30, 2021
Unit Type
BatteryCC
CT - Natural Gas
CT - OilCT - Other
Fuel Cell
Hydro - Pumped Storage
Hydro - Run of River
Nuclear
RICE - Natural Gas
RICE - Oil
RICE - Other
Solar
Solar + Storage
Solar + Wind
Steam - Coal
Steam - Natural Gas
Steam - Oil
Steam - Other
Wind
Wind + Storage

Completion Rate
(SIS)
14.9%
31.9%
66.8%
35.6%
12.3%
30.6%
100.0%
42.8%
35.2%
30.7%
34.0%
89.0%
15.9%
0.1%
0.0%
13.6%
91.1%
0.0%
30.4%
0.2%
0.0%

Completion Rate
(FSA)
36.2%
49.5%
82.3%
60.2%
18.6%
31.6%
100.0%
60.7%
42.1%
42.9%
59.7%
91.4%
36.9%
54.5%
0.0%
25.4%
91.1%
0.0%
39.9%
100.0%
0.0%

Completion Rate
(CSA)
43.2%
77.3%
85.9%
90.8%
29.5%
31.6%
100.0%
68.1%
51.3%
47.6%
59.7%
92.0%
46.2%
54.5%
0.0%
37.5%
91.1%
0.0%
47.8%
100.0%
0.0%

Completion Rate
(ALL)
0.8%
14.0%
42.0%
25.4%
10.7%
43.6%
24.1%
20.9%
28.6%
26.4%
26.2%
78.1%
2.6%
0.0%
0.0%
6.2%
90.0%
0.0%
27.1%
0.0%
0.0%

On June 30, 2021, 217,381.6 MW were in generation request queues in the status of active, under construction or suspended. Of the total 217,381.6 MW in thequeue, 116,419.3 MW (53.6 percent) have reached at least the SIS milestone and 100,962.3 MW (46.4 percent) have not received a completed SIS. Based on
historical completion rates, (applying the unit type specific completion rates for those projects that have reached the SIS, FSA or CSA milestone, and using theoverall completion rates for those projects that have not yet reached the SIS milestone), 39,081.6 MW (17.9 percent) of new generation in the queue are expected
to go into service.
Table 12-23 shows the percent of all project MW, by unit type, to go in service by year submitted to the queue. Of all battery projects that entered the queue in2010, 65.5 percent reached the status of in service by June 30, 2021. Of all battery projects that entered the queue in 2016, only 1.3 percent have reached thestatus of in service as of June 30, 2021.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 635

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-23 Percent of all projects (MW energy) to go in service by unit type and year submitted to the queue: June 30, 2021
Unit Type
BatteryCC
CT - Natural Gas
CT - OilCT - Other
Fuel Cell
Hydro - Pumped Storage
Hydro - Run of River
Nuclear
RICE - Natural Gas
RICE - Oil
RICE - Other
Solar
Solar + Storage
Solar + Wind
Steam - Coal
Steam - Natural Gas
Steam - Oil
Steam - Other
WInd
Wind + Storage
All

2010
2011
2012
2013
65.5%
8.3% 15.1% 43.9%
14.6% 24.5% 30.8% 35.6%
100.0% 98.3% 89.7% 23.5%
100.0%
N/A
1.2%
0.0%
28.8% 27.1% 36.1% 100.0%
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
0.0%
0.0% 57.6% 49.6%
15.5%
1.6%
0.0% 100.0%
N/A
N/A 100.0% 66.7%
0.0%
0.0%
N/A
N/A
100.0% 100.0% 100.0% 100.0%
10.7%
7.1% 16.9% 24.4%
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
100.0%
0.0%
1.4% 68.4%
N/A
N/A
N/A 100.0%
0.0%
0.0%
0.0%
0.0%
0.5% 61.2% 16.6%
0.0%
6.1%
3.4%
2.5%
5.8%
N/A
N/A
N/A
N/A
11.7% 18.9% 26.5% 32.7%

2014
2015
2016
2017
2018
21.5%
7.7%
1.3%
4.1%
0.3%
43.7%
3.7%
2.2%
3.8%
1.2%
32.0%
0.2%
8.2% 16.8%
4.3%
0.0%
N/A
N/A
N/A
0.0%
0.0% 100.0%
N/A
0.0%
N/A
N/A 67.4% 12.5%
0.0%
N/A
N/A 100.0%
N/A
N/A
0.0%
11.2%
N/A 100.0% 26.8% 100.0%
N/A
N/A
0.0% 71.6%
0.0%
5.4%
6.2%
0.0%
5.4%
N/A
N/A 30.8%
N/A
N/A
N/A
79.7% 25.5%
2.8%
0.0% 100.0%
30.7% 17.8%
7.2%
0.5%
0.3%
N/A
0.0%
0.0%
0.0%
0.0%
N/A
N/A
N/A
N/A
N/A
1.2% 23.4% 37.5% 100.0%
0.0%
0.0% 100.0% 100.0% 100.0%
N/A
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
N/A
N/A
N/A
N/A
20.7% 12.5% 12.3%
2.6%
0.0%
N/A
N/A
0.0%
0.0%
N/A
34.3%
7.1%
5.3%
2.3%
0.6%

2019
0.0%
0.5%
0.0%
0.0%
N/A
0.0%
0.0%
0.0%
N/A
N/A
N/A
N/A
0.0%
0.0%
N/A
0.0%
N/A
0.0%
N/A
0.0%
N/A
0.0%

2020
0.0%
N/A
0.5%
0.0%
N/A
N/A
N/A
0.0%
0.0%
N/A
N/A
N/A
0.0%
0.0%
0.0%
N/A
0.0%
0.0%
N/A
0.0%
N/A
0.0%

2021
0.0%
0.0%
0.0%
N/A
0.0%
N/A
0.0%
0.0%
N/A
N/A
N/A
N/A
0.0%
0.0%
0.0%
N/A
N/A
0.0%
0.0%
0.0%
N/A
0.0%

Queue Analysis by Fuel Group
The time it takes to complete a study depends on the backlog and the number of projects in the queue, but not on the size of the project. Table 12-24 shows
the number of projects that entered the queue by year and by fuel group. The fuel groups are nuclear units, renewable units (including solar, hydro, biomass,
renewable hybrid and wind) and traditional units (all other fuels). The number of queue entries has increased during the past several years, primarily by
renewable projects. Of the 3,831 projects entered from January 2015 through June 2021, 2,879 projects (75.2 percent) were renewable. Of the 641 projects enteredin the first six months of 2021, 483 projects (75.4 percent) were renewable.

636

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-24 Number of projects entered in the queue: June 30, 2021
Year Entered
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Total

Nuclear
2
0
1
2
4
3
1
4
3
9
9
3
10
5
6
2
1
0
0
2
2
1
0
2
0
72

Fuel Group
Renewable
0
0
5
3
6
15
34
17
75
67
65
102
107
370
264
59
54
100
134
298
293
343
544
784
483
4,222

Traditional
11
18
84
78
81
33
18
33
55
81
145
111
56
66
85
98
99
92
175
99
60
96
153
204
158
2,189

Total
13
18
90
83
91
51
53
54
133
157
219
216
173
441
355
159
154
192
309
399
355
440
697
990
641
6,483

Historical completion rates for renewable projects may not be an accurate
predictor of completion rates for current renewable projects. The outcomes for
current projects will provide additional information and improve the ability
to assess the likely future generation mix based on the type of projects in thequeue.
While renewables currently make up the majority of both projects andnameplate MW in the queue, historical completion rates and derating factors
must be accounted for when evaluating the share of capacity resources thatare likely to be contributed by renewables (Table 12-22). Table 12-26 shows
the total MW of all projects in the queue as of June 30, 2021, in the statusof active, suspended and under construction, by unit type. Table 12-26 also
shows the total MW for each fuel type adjusted based on current historicalcompletion rates and for the average solar and wind derates. Of the 22,808.6
MW of combined cycle projects in the queue, 14,211.6 MW (62.3 percent)are expected to go in service based on historical completion rates as of June30, 2021. Of the 160,392.1 MW of renewable projects in the queue, only
19,384.5 MW (12.2 percent) are expected to go in service based on historicalcompletion rates. Of the 160,392.1 MW of renewable projects in the queue,
only 7,714.3 MW (4.8 percent) of capacity resources are expected to go into
service, based on both historical completion rates and average derate factors
for wind and solar.

As of June 30, 2021, renewable projects make up 77.4 percent of all projects
in the queue and those projects account for 73.8 percent of the nameplate MW
currently active, suspended or under construction in the queue as of June 30,
2021 (Table 12-25).
Table 12-25 Queue details by fuel group: June 30, 2021
Fuel Group
NuclearRenewable
Traditional
Total

Number of Projects
6
1,822
525
2,353

© 2021 Monitoring Analytics, LLC

Percent of Projects
0.3%
77.4%
22.3%
100.0%

MW
189.5
160,372.1
56,820.0
217,381.6

Percent MW
0.1%
73.8%
26.1%
100.0%

2021 Quarterly State of the Market Report for PJM: January through June 637

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-26 Queue totals for projects (active, suspended and underconstruction) by unit type adjusted based on current historical completion
rates and average solar and wind derates (MW): June 30, 2021
Unit Type
BatteryCC
CT - Natural Gas
CT - OilCT - Other
Fuel Cell
Hydro - Pumped Storage
Hydro - Run of River
Nuclear
RICE - Natural Gas
RICE - Oil
RICE - Other
Solar
Solar + Storage
Solar + Wind
Steam - Coal
Steam - Natural Gas
Steam - Oil
Steam - Other
Wind
Wind + Storage
Total

638

MW in Queue
27,884.8
22,808.6
5,981.3
31.0
6.0
3.0
730.0
124.9
189.5
1.3
0.0
0.0
100,137.6
25,678.3
209.0
76.0
11.0
0.0
20.0
33,383.1
106.3
217,381.6

Section 12 Planning

Completion Rate Adjusted MW
in Queue
1,198.8
14,211.6
3,915.3
21.7
0.6
0.9
707.2
56.8
73.8
0.6
0.0
0.0
12,492.1
261.3
0.0
25.9
10.0
0.0
5.4
6,099.6
0.0
39,081.6

Completion Rate and Derate
Adjusted MW in Queue
1,198.8
14,211.6
3,915.3
21.7
0.6
0.9
707.2
56.8
73.8
0.6
0.0
0.0
5,833.8
122.0
0.0
25.9
10.0
0.0
5.4
988.1
0.0
27,172.6

Queue Analysis by Unit Type and Project Classification
Table 12-27 shows the current status of all generation queue projects by unit
type and project classification from January 1, 1997, through June 30, 2021.
As of June 30, 2021, 6,483 projects, representing 711,962.4 MW, have entered
the queue process since its inception. Of those, 985 projects, representing
74,169.9 MW, went into service. Of the projects that entered the queue process,
3,145 projects, representing 420,410.9 MW (59.0 percent of the MW) withdrewprior to completion. Such projects may create barriers to entry for projects
that would otherwise be completed by taking up queue positions, increasing
interconnection costs and creating uncertainty.
A total of 5,209 projects have been classified as new generation and 1,274
projects have been classified as upgrades. Natural gas, wind, solar andrenewable hybrid projects (including solar + storage, solar + wind and wind
+ storage) have accounted for 5,144 projects (79.3 percent) of all 6,483
generation queue projects to enter the queue since January 1, 1997.

© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-27 Status of all generation queue projects: January 1, 1997 through June 30, 2021

Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

Project
Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeBattery
23
7
0
0
4
0
178
41
256
137
461
185

CC
62
103
7
10
6
2
431
96
9
17
515
228

CT Natural
Gas
48
110
2
16
1
2
28
16
8
26
87
170

CT - CT Oil Other
10
25
15
5
0
0
8
0
0
0
0
0
9
81
13
13
1
1
2
1
20
107
38
19

Fuel
Cell
3
0
0
1
0
0
26
2
0
1
29
4

Hydro Pumped
Storage
0
3
0
0
0
0
2
0
2
1
4
4

Number of Projects
Hydro
- Run
RICE of
Natural RICE - RICE Solar +River Nuclear
Gas
Oil Other Solar Storage
10
2
10
0
55
173
1
19
42
9
2
16
33
0
0
0
1
0
0
30
2
0
1
0
0
0
15
1
0
0
0
0
0
31
2
0
0
0
0
0
5
0
43
9
28
12
16 1,369
64
5
13
0
2
3
56
1
6
0
0
0
0 1,120
245
2
5
0
0
0
207
31
59
11
39
12
71 2,723
314
26
61
9
4
19
316
33

Solar
+ SteamWind - Coal
0
8
0
55
0
0
0
1
0
0
0
0
0
55
0
15
2
0
0
3
2
63
0
74

Steam SteamNatural SteamGas - Oil Other
5
0
4
10
0
8
0
0
0
0
0
0
0
0
0
0
0
0
1
0
34
0
0
2
1
0
1
2
0
0
7
0
39
12
0
10

Wind +
Wind Storage
96
0
13
0
2
0
0
0
6
1
0
1
451
0
30
0
90
0
17
1
645
1
60
2

Total
535
450
44
53
51
10
2,837
308
1,742
453
5,209
1,274

Table 12-28 shows the totals in Table 12-27 by share of classification as new generation or upgrade. Within a unit type the shares of upgrades add to 100 percent
and the shares of new generation add to 100 percent. For example, 73.1 percent of all hydro run of river projects classified as upgrades are currently in service
in PJM, 19.2 percent of hydro run of river upgrades were withdrawn and 7.7 percent of hydro run of river upgrades are active in the queue.
Table 12-28 Status of all generation queue projects as a percent of total projects by classification: January 1, 1997 through June 30, 2021

Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveProject
Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
Upgrade© 2021 Monitoring Analytics, LLC

Battery
5.0%
3.8%
0.0%
0.0%
0.9%
0.0%
38.6%
22.2%
55.5%
74.1%

CC
12.0%
45.2%
1.4%
4.4%
1.2%
0.9%
83.7%
42.1%
1.7%
7.5%

CT Natural
Gas CT - Oil
55.2%
50.0%
64.7%
39.5%
2.3%
0.0%
9.4%
21.1%
1.1%
0.0%
1.2%
0.0%
32.2%
45.0%
9.4%
34.2%
9.2%
5.0%
15.3%
5.3%

CT Other Fuel Cell
23.4%
10.3%
26.3%
0.0%
0.0%
0.0%
0.0%
25.0%
0.0%
0.0%
0.0%
0.0%
75.7%
89.7%
68.4%
50.0%
0.9%
0.0%
5.3%
25.0%

Hydro - Hydro RICE Pumped Run of
NaturalStorageRiver Nuclear
Gas
0.0%
16.9%
18.2%
25.6%
75.0%
73.1%
68.9% 100.0%
0.0%
0.0%
0.0%
2.6%
0.0%
0.0%
1.6%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
50.0%
72.9%
81.8%
71.8%
0.0%
19.2%
21.3%
0.0%
50.0%
10.2%
0.0%
0.0%
25.0%
7.7%
8.2%
0.0%

Percent of Projects
RICE Oil
0.0%
50.0%
0.0%
0.0%
0.0%
0.0%
100.0%
50.0%
0.0%
0.0%

RICE Other
77.5%
84.2%
0.0%
0.0%
0.0%
0.0%
22.5%
15.8%
0.0%
0.0%

Solar
6.4%
10.4%
1.1%
4.7%
1.1%
1.6%
50.3%
17.7%
41.1%
65.5%

Solar +
Storage
0.3%
0.0%
0.6%
3.0%
0.6%
0.0%
20.4%
3.0%
78.0%
93.9%

Steam Solar + Steam - Natural
Wind
Coal
Gas
0.0%
12.7%
71.4%
0.0%
74.3%
83.3%
0.0%
0.0%
0.0%
0.0%
1.4%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
87.3%
14.3%
0.0%
20.3%
0.0%
100.0%
0.0%
14.3%
0.0%
4.1%
16.7%

Steam Steam - Oil
Other
0.0%
10.3%
0.0%
80.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
87.2%
0.0%
20.0%
0.0%
2.6%
0.0%
0.0%

Wind +
Wind Storage
14.9%
0.0%
21.7%
0.0%
0.3%
0.0%
0.0%
0.0%
0.9% 100.0%
0.0%
50.0%
69.9%
0.0%
50.0%
0.0%
14.0%
0.0%
28.3%
50.0%

Total
10.3%
35.3%
0.8%
4.2%
1.0%
0.8%
54.5%
24.2%
33.4%
35.6%

2021 Quarterly State of the Market Report for PJM: January through June 639

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-29 shows the total MW of projects in the PJM generation queue by unit type and project classification. For example, the 451 new generation windprojects that have been withdrawn from the queue as of June 30, 2021, (as shown in Table 12-27) constitute 78,416.2 MW. The 431 new generation combined
cycle projects that have been withdrawn in the same time period constitute 215,469.7 MW.
Table 12-29 Status of all generation (MW) in the generation queue: January 1, 1997 through June 30, 2021

Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

Project
Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeCT Natural
BatteryCC
Gas CT - Oil
224.4 33,703.0 6,664.4
676.5
44.4
6,658.8 2,744.5
127.8
0.0
6,596.9
219.4
0.0
0.0
1,243.4
130.0
13.0
34.0
4,236.0
675.0
0.0
0.0
80.0
380.0
0.0
4,194.5 215,469.7 4,281.7 1,721.0
884.3 11,590.4
670.6
589.0
24,397.4
8,483.0 3,032.7
14.0
3,453.3
2,169.3 1,544.2
4.0
28,850.3 268,488.6 14,873.2 2,411.5
4,382.0 21,741.9 5,469.3
733.8

CT Other Fuel Cell
151.3
1.9
12.3
0.0
0.0
0.0
0.0
3.0
0.0
0.0
0.0
0.0
1,244.2
5.5
72.5
0.9
6.0
0.0
0.0
0.0
1,401.6
7.4
84.8
3.9

Hydro - Hydro RICE Pumped Run of
NaturalStorageRiver Nuclear
Gas
0.0
371.5 1,639.0
156.4
390.0
387.6 2,310.8
17.3
0.0
0.0
0.0
1.3
0.0
0.0
44.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
500.0 2,054.4 8,161.0
479.9
0.0
105.1
966.0
0.0
700.0
70.7
0.0
0.0
30.0
54.2
145.5
0.0
1,200.0 2,496.5 9,800.0
637.6
420.0
546.9 3,466.3
17.3

Project MW
RICE Oil
0.0
27.3
0.0
0.0
0.0
0.0
63.9
13.0
0.0
0.0
63.9
40.3

RICE Solar +Other
Solar Storage
440.1
2,705.2
1.1
50.7
69.5
0.0
0.0
2,387.6
2.6
0.0
289.8
3.2
0.0
1,105.9
120.0
0.0
68.6
0.0
88.6 42,427.6 7,669.0
10.0
1,603.4
3.7
0.0 88,588.2 24,505.4
0.0
7,697.5 1,047.2
528.7 137,214.5 32,298.0
60.7
9,728.8 1,054.1

Steam Solar + Steam - Natural
Wind
Coal
Gas
0.0 1,343.0
723.0
0.0
965.5
225.5
0.0
0.0
0.0
0.0
36.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0 33,511.6
27.0
0.0
885.0
0.0
209.0
0.0
5.0
0.0
40.0
6.0
209.0 34,854.6
755.0
0.0 1,926.5
231.5

Steam Steam Wind +
- Oil
Other
Wind Storage
Total
0.0
60.9 10,369.6
0.0 59,231.3
0.0
667.8
238.7
0.0 14,938.5
0.0
0.0
310.0
0.0
9,517.8
0.0
0.0
0.0
0.0
1,762.4
0.0
0.0
737.6
90.0
6,998.4
0.0
0.0
0.0
16.3
544.9
0.0 1,050.9 78,416.2
0.0 401,366.5
0.0
37.1
1,613.4
0.0 19,044.4
0.0
20.0 30,305.5
0.0 180,336.9
0.0
0.0
2,030.1
0.0 18,221.3
0.0 1,131.8 120,138.8
90.0 657,450.9
0.0
704.9
3,882.2
16.3 54,511.5

Table 12-30 shows the MW totals in Table 12-29 by share by classification as new generation or upgrade. Within a unit type the shares of upgrades add to 100
percent and the shares of new generation add to 100 percent. For example, 65.3 percent of wind project MW classified as new generation have been withdrawn
from the queue between January 1, 1997, and June 30, 2021.
Table 12-30 Status of all generation queue projects as percent of total MW in project classification: January 1, 1997 through June 30, 2021

Project Status
In Service
Under Construction
Suspended
Withdrawn
Active640

Project
Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeSection 12 Planning

Battery
0.8%
1.0%
0.0%
0.0%
0.1%
0.0%
14.5%
20.2%
84.6%
78.8%

CC
12.6%
30.6%
2.5%
5.7%
1.6%
0.4%
80.3%
53.3%
3.2%
10.0%

CT Natural
Gas CT - Oil
44.8%
28.1%
50.2%
17.4%
1.5%
0.0%
2.4%
1.8%
4.5%
0.0%
6.9%
0.0%
28.8%
71.4%
12.3%
80.3%
20.4%
0.6%
28.2%
0.5%

CT Other Fuel Cell
10.8%
26.2%
14.5%
0.0%
0.0%
0.0%
0.0%
76.0%
0.0%
0.0%
0.0%
0.0%
88.8%
73.8%
85.5%
24.0%
0.4%
0.0%
0.0%
0.0%

Percent of Total Projects by Classification
Hydro - Hydro RICE Pumped Run of
Natural RICE - RICE Solar +StorageRiver Nuclear
Gas
Oil
Other
Solar Storage
0.0%
14.9%
16.7%
24.5%
0.0%
83.2%
2.0%
0.0%
92.9%
70.9%
66.7% 100.0%
67.7%
83.5%
0.7%
0.0%
0.0%
0.0%
0.0%
0.2%
0.0%
0.0%
1.7%
0.0%
0.0%
0.0%
1.3%
0.0%
0.0%
0.0%
3.0%
0.3%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.8%
0.4%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.7%
0.0%
41.7%
82.3%
83.3%
75.3% 100.0%
16.8%
30.9%
23.7%
0.0%
19.2%
27.9%
0.0%
32.3%
16.5%
16.5%
0.4%
58.3%
2.8%
0.0%
0.0%
0.0%
0.0%
64.6%
75.9%
7.1%
9.9%
4.2%
0.0%
0.0%
0.0%
79.1%
99.3%

Steam Solar + Steam - Natural
Wind
Coal
Gas
0.0%
3.9%
95.8%
0.0%
50.1%
97.4%
0.0%
0.0%
0.0%
0.0%
1.9%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
96.1%
3.6%
0.0%
45.9%
0.0%
100.0%
0.0%
0.7%
0.0%
2.1%
2.6%

Steam Steam - Oil
Other
0.0%
5.4%
0.0%
94.7%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
92.9%
0.0%
5.3%
0.0%
1.8%
0.0%
0.0%

Wind +
Wind Storage
8.6%
0.0%
6.1%
0.0%
0.3%
0.0%
0.0%
0.0%
0.6% 100.0%
0.0% 100.0%
65.3%
0.0%
41.6%
0.0%
25.2%
0.0%
52.3%
0.0%

Total
9.0%
27.4%
1.4%
3.2%
1.1%
1.0%
61.0%
34.9%
27.4%
33.4%

© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-31 shows the project MW that entered the PJM generation queue by unit type and year of entry. Since 2016, 77.9 percent of all new projects entering
the generation queue have been combined cycle (13.6 percent), wind (16.0 percent) or solar projects (45.2 percent). Prior to 2015, no renewable hybrid units(solar + storage, solar + wind and wind + storage) entered the queue. In the time period from January 1, 2015 through June 30, 2021, 33,665.4 MW have entered
the queue.
Table 12-31 Queue project MW by unit type and queue entry year: January 1, 1997 through June 30, 2021
Year
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Total

Battery
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
121.0
34.0
72.4
24.1
142.6
217.4
246.9
546.9
111.1
24.6
1,513.7
5,743.2
11,193.9
13,240.4
33,232.3

CC4,148.0
7,006.0
29,412.7
21,144.8
25,411.7
4,154.0
2,361.4
3,610.0
5,824.6
4,188.1
13,944.6
26,001.0
5,548.4
9,185.4
19,744.0
18,014.8
10,493.1
11,704.5
27,540.8
18,802.5
5,477.6
11,080.1
3,332.5
0.0
2,100.0
290,230.5

CT Natural
CT Gas CT - Oil
Other
321.0
315.0
0.0
1,775.00.0
0.0
2,412.1
0.0
10.0
493.6
31.5
8.8
264.0
0.0
0.0
11.7
0.0
70.5
10.0
8.0
0.8
43.3
20.0
49.1
961.0
281.0
51.4
454.3
607.5
73.1
941.2
215.9
149.5
129.7 1,113.0
488.8
14.0
66.0
214.2
176.0
7.9
117.3
29.5
0.0
174.6
282.1
42.5
48.4
1,201.8
5.0
11.2
1,532.5401.0
7.7
1,324.5
0.0
0.9
1,392.0
0.0
0.0
691.0
0.0
4.1
2,647.4
14.0
0.0
1,572.1
13.0
0.0
552.6
4.0
0.0
1,110.1
0.0
6.0
20,342.5 3,145.3 1,486.3© 2021 Monitoring Analytics, LLC

Fuel
Cell
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2.3
3.4
2.7
0.0
3.0
0.0
0.0
11.3

Hydro - Hydro Pumped Run ofStorage
River
0.0
0.0
0.0
0.0
0.0
196.0
0.0
0.0
0.0
107.0
0.0
293.0
0.0
2.0
0.0
0.0
340.0
174.2
0.0
159.0
16.0
161.6
0.0 1,254.5
0.0
133.9
0.0
132.6
0.0
30.0
0.0
11.8
0.0
89.4
0.0
60.5
34.0
0.0
0.0
12.5
0.0
20.5
700.0
2.4
500.0
99.0
0.0
80.2
30.0
23.5
1,620.0 3,043.4

Nuclear
50.0
0.0
45.0
95.0
90.0
236.0
0.0
1,911.0
242.0
6,894.0
368.0
105.0
1,933.8
426.0
182.0
369.0
102.0
0.0
0.0
50.3
39.1
28.1
0.0
100.0
0.0
13,266.3

RICE Natural
Gas
0.0
0.0
0.0
0.0
0.0
8.0
29.0
0.0
21.5
0.0
0.0
6.0
4.5
0.0
0.0
37.2
59.7
48.0
320.4
23.5
97.1
0.0
0.0
0.0
0.0
654.9

RICE Oil
0.0
0.0
0.0
0.0
0.0
23.3
0.0
35.5
0.0
0.0
0.0
0.0
16.0
2.4
14.0
0.0
0.0
0.0
13.0
0.0
0.0
0.0
0.0
0.0
0.0
104.2

RICE Other
0.0
0.0
0.0
1.2
15.6
4.5
27.5
17.5
65.1
93.0
56.5
32.0
15.2
57.8
75.3
4.0
1.6
17.7
31.4
38.9
33.8
0.8
0.0
0.0
0.0
589.4

Solar
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.3
66.3
636.5
3,672.6
2,014.0
284.6
231.7
1,590.0
2,922.9
11,605.5
13,656.7
19,734.1
27,416.5
37,803.0
25,305.6
146,943.3

Solar + Solar +Storage
Wind
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2.0
0.0
85.6
0.0
424.9
0.0
4,573.9
0.0
9,596.1
0.0
10,118.9
199.0
8,550.8
10.0
33,352.1
209.0

Steam Coal
6.0
0.0
47.0
37.0
1,244.6
1,895.0522.0
1,187.0
6,360.0
9,586.0
9,078.0
1,198.0
1,273.064.0
357.0
1,837.0
158.0
1,730.5
47.0
80.0
14.0
49.0
11.0
0.0
0.0
36,781.1

Steam Natural
Gas
0.0
0.0
0.0
2.5
10.0
0.0
0.0
0.0
0.0
0.0
190.0
0.0
5.5
0.0
0.0
0.0
40.0
27.0
606.5
77.0
17.0
0.0
0.0
11.0
0.0
986.5

Steam SteamWind +- Oil - OtherWind Storage
Total
0.0
0.0
0.0
0.0
4,840.0
0.0
0.0
0.0
0.0
8,781.0
0.0
525.0
115.4
0.0 32,763.2
0.0
0.0
95.6
0.0 21,909.9
0.0
0.0
252.9
0.0 27,395.8
0.0
0.0
790.9
0.0
7,486.9
0.0
165.0
997.0
0.0
4,122.7
0.0
0.0
1,614.7
0.0
8,488.1
0.0
24.0
6,020.0
0.0 20,364.9
0.0
258.5
7,650.7
0.0 29,964.2
0.0
50.5 18,525.6
0.0 43,700.6
0.0
192.3 11,016.1
0.0 41,723.7
0.0
148.0
6,672.6
0.0 16,715.6
0.0
173.5
9,803.4
0.0 23,891.3
0.0
49.0
5,576.4
0.0 28,269.9
0.0
143.1
1,529.8
0.0 22,746.8
0.0
44.7
1,407.9
0.0 14,063.4
0.0
43.1
1,689.7
0.0 19,099.0
0.0
0.0
2,160.6
0.0 35,553.0
0.0
0.0
3,448.7
16.3 35,747.2
0.0
0.0
5,137.0
90.0 25,730.2
0.0
0.0 17,710.4
0.0 58,053.8
0.0
0.0 11,585.4
0.0 59,871.8
0.0
0.0
6,915.9
0.0 66,978.4
0.0
20.0
3,304.4
0.0 53,700.7
0.0 1,836.7 124,021.0
106.3 711,962.4

2021 Quarterly State of the Market Report for PJM: January through June 641

2021 Quarterly State of the Market Report for PJM: January through June

Combined Cycle Project Analysis
Table 12-32 shows the status of all combined cycle projects by number of projects that entered PJM generation queues from January 1, 1997, through June30, 2021, by zone. Of the 51 combined cycle projects classified as new generation or upgrade currently active, suspended or under construction in the PJM
generation queue, 12 projects (23.5 percent) are located in the AEP Zone.
Table 12-32 Status of all combined cycle queue projects by zone (number of projects): January 1, 1997 through June 30, 2021
Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

Project Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
Upgrade

ACEC
1
3
0
0
0
0
23
7
0
1
24
11

AEP
4
12
3
4
0
0
19
7
3
2
29
25

APS
2
7
1
2
2
1
45
9
2
4
52
23

ATSI
3
5
1
0
2
0
13
3
0
1
19
9

BGE COMED
2
1
0
5
0
2
0
0
0
1
0
0
8
14
0
4
0
2
0
2
10
20
0
11

DAY DUKE
0
2
0
0
0
0
0
0
1
0
0
0
0
1
0
1
0
0
0
0
1
3
0
1

DUQ
0
0
0
0
0
0
2
0
0
0
2
0

Number of Projects
DOM
DPL EKPC JCPLC
7
2
0
7
16
5
0
6
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
18
17
3
26
11
4
0
7
1
0
0
0
1
1
0
0
26
19
3
33
28
10
0
14

MEC
4
3
0
1
0
0
25
7
0
0
29
11

OVEC
0
0
0
0
0
0
0
0
0
0
0
0

PECO
5
12
0
1
0
0
43
3
0
0
48
16

PE
2
4
0
0
0
0
40
5
1
2
43
11

PEPCO
4
4
0
0
0
0
34
5
0
1
38
10

PPL
10
7
0
1
0
0
42
8
0
2
52
18

PSEG
6
14
0
1
0
0
56
15
0
0
62
30

REC
0
0
0
0
0
0
2
0
0
0
2
0

Total
62
103
7
10
6
2
431
96
9
17
515
228

Table 12-33 shows the status of all combined cycle projects by MW that entered PJM generation queues from January 1, 1997, through June 30, 2021, by zone.
Of the 22,808.6 MW of combined cycle projects classified as new generation or upgrade currently active, suspended or under construction in the PJM generation
queue, 6,015.0 MW (26.4 percent) are located in the AEP Zone.
Table 12-33 Status of all combined cycle queue projects by zone (MW): January 1, 1997 through June 30, 2021
Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

642

Project Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeSection 12 Planning

ACEC
5
4
0
0
0
0
1
2
1
1
7
7

AEP
0
10
0
0
0
0
6
2
2
1
8
13

APS
6
8
0
1
0
1
0
1
0
1
6
12

ATSI
0
2
0
2
0
0
0
1
0
5
0
10

BGE COMED
3
0
0
12
0
0
0
4
0
0
0
1
1
1
0
2
1
0
0
9
5
1
0
28

DAY DUKE
0
0
5
0
0
0
0
0
0
0
0
0
1
0
2
0
0
0
2
0
1
0
9
0

DUQ
0
0
2
0
0
0
0
1
0
1
2
2

Number of Projects
DOM
DPL EKPC JCPLC
3
7
0
2
28
7
0
4
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
4
0
1
1
3
0
0
0
2
0
0
0
0
0
0
0
9
7
1
3
31
7
0
5

MEC
1
1
0
4
0
0
0
1
0
0
1
6

OVEC
0
0
0
0
0
0
0
0
0
0
0
0

PECO
2
4
0
0
0
0
1
0
0
0
3
4

PE
4
4
0
4
0
0
5
1
2
1
11
10

PEPCO
2
3
0
0
0
0
0
0
0
5
2
8

PPL
4
4
0
0
0
0
1
0
0
0
5
4

PSEG
9
14
0
0
1
0
5
0
0
0
15
14

REC
0
0
0
0
0
0
0
0
0
0
0
0

Total
48
110
2
16
1
2
28
16
8
26
87
170

© 2021 Monitoring Analytics, LLC

Section 12 Planning

Combustion Turbine - Natural Gas Project Analysis
Table 12-34 shows the status of all combustion turbine natural gas projects by number of projects that entered PJM generation queues from January 1, 1997,
through June 30, 2021, by zone. Of the 55 combustion turbine natural gas projects classified as new generation or upgrade currently active, suspended or underconstruction in the PJM generation queue, 14 projects (25.5 percent) are located in the COMED Zone.
Table 12-34 Status of all combustion turbine - natural gas generation queue projects by zone (number of projects): January 1, 1997 through June 30, 2021
Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

Project Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
Upgrade

ACEC
5
4
0
0
0
0
1
2
1
1
7
7

AEP
0
10
0
0
0
0
6
2
2
1
8
13

APS
6
8
0
1
0
1
0
1
0
1
6
12

ATSI
0
2
0
2
0
0
0
1
0
5
0
10

BGE COMED
3
0
0
12
0
0
0
4
0
0
0
1
1
1
0
2
1
0
0
9
5
1
0
28

DAY DUKE
0
0
5
0
0
0
0
0
0
0
0
0
1
0
2
0
0
0
2
0
1
0
9
0

DUQ
0
0
2
0
0
0
0
1
0
1
2
2

Number of Projects
DOM
DPL EKPC JCPLC
3
7
0
2
28
7
0
4
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
4
0
1
1
3
0
0
0
2
0
0
0
0
0
0
0
9
7
1
3
31
7
0
5

MEC
1
1
0
4
0
0
0
1
0
0
1
6

OVEC
0
0
0
0
0
0
0
0
0
0
0
0

PECO
2
4
0
0
0
0
1
0
0
0
3
4

PE
4
4
0
4
0
0
5
1
2
1
11
10

PEPCO
2
3
0
0
0
0
0
0
0
5
2
8

PPL
4
4
0
0
0
0
1
0
0
0
5
4

PSEG
9
14
0
0
1
0
5
0
0
0
15
14

REC
0
0
0
0
0
0
0
0
0
0
0
0

Total
48
110
2
16
1
2
28
16
8
26
87
170

Table 12-35 shows the status of all combustion turbine natural gas projects by MW that entered PJM generation queues from January 1, 1997, through June30, 2021, by zone. Of the 5,981.3 MW of combustion turbine natural gas projects classified as new generation or upgrade currently active, suspended or underconstruction in the PJM generation queue, 1,138.0 MW (19.0 percent) are located in the Dominion Zone.
Table 12-35 Status of all combustion turbine - natural gas queue projects by zone (MW): January 1, 1997 through June 30, 2021
Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

Project Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
Upgrade© 2021 Monitoring Analytics, LLC

ACEC
AEP
APS
360.7
0.0 1,176.0
43.7
227.0
187.7
0.0
0.0
0.0
0.0
0.0
12.0
0.0
0.0
0.0
0.0
0.0
30.0
7.5 1,519.0
0.0
165.5
57.1
4.0
230.0 1,039.1
0.0
0.0
71.0
70.0
598.2 2,558.1 1,176.0
209.2
355.1
303.7

ATSI
0.0
40.0
0.0
5.0
0.0
0.0
0.0
25.0
0.0
518.7
0.0
588.7

BGE COMED
23.0
0.0
0.0
371.0
0.0
0.0
0.0
87.0
0.0
0.0
0.0
350.0
9.0
10.0
0.0
23.0
144.6
0.0
0.0
688.2
176.6
10.0
0.0 1,519.2

DAY DUKE
0.0
0.0
60.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
104.0
0.0
104.0
0.0
0.0
0.0
43.5
0.0
104.0
0.0
207.5
0.0

DUQ
0.0
0.0
219.4
0.0
0.0
0.0
0.0
0.0
0.0
3.5
219.4
3.5

Project MW
DOM
DPL EKPC JCPLC
1,081.0 1,491.0
0.0 520.0
925.7
86.0
0.0 200.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1,069.8
0.0
73.0
2.1
57.0
0.0
0.0
0.0
1,138.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3,288.8 1,491.0
73.0 522.1
982.7
86.0
0.0 200.0

MEC
10.0
34.1
0.0
13.5
0.0
0.0
0.0
0.0
0.0
0.0
10.0
47.6

OVEC
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

PECO
PE
559.0
361.9
42.0
28.0
0.0
0.0
0.0
12.5
0.0
0.0
0.0
0.0
0.5
326.8
0.0
235.0
0.0
481.0
0.0
92.0
559.5 1,169.7
42.0
367.5

PEPCO
5.0
32.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
57.3
5.0
89.3

PPL
PSEG
150.9
925.9
252.3
215.0
0.0
0.0
0.0
0.0
0.0
675.0
0.0
0.0
19.9 1,140.1
0.0
0.0
0.0
0.0
0.0
0.0
170.8 2,741.0
252.3
215.0

REC
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

Total
6,664.4
2,744.5
219.4
130.0
675.0
380.0
4,281.7
670.6
3,032.7
1,544.2
14,873.2
5,469.32021 Quarterly State of the Market Report for PJM: January through June 643

2021 Quarterly State of the Market Report for PJM: January through June

Wind Project Analysis
Table 12-36 shows the status of all wind generation projects, by number of projects that entered PJM generation queues from January 1, 1997, through June30, 2021, by zone. Of the 115 wind projects classified as new generation or upgrade currently active, suspended or under construction in the PJM generation
queue, 43 projects (37.4 percent) are located in the COMED Zone.
Table 12-36 Status of all wind generation queue projects by zone (number of projects): January 1, 1997 through June 30, 2021
Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

Project Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
Upgrade

ACEC
1
0
0
0
0
0
18
2
6
0
25
2

AEP
18
0
1
0
3
0
111
2
18
1
151
3

APS
17
3
1
0
0
0
45
7
5
0
68
10

ATSI
0
0
0
0
0
0
8
0
3
0
11
0

BGE COMED
0
26
0
5
0
0
0
0
0
0
0
0
0
108
0
8
0
33
0
10
0
167
0
23

DAY DUKE
0
0
0
0
0
0
0
0
0
0
0
0
15
0
0
0
0
0
0
0
15
0
0
0

DUQ
0
0
0
0
0
0
0
0
0
0
0
0

Number of Projects
DOM
DPL EKPC JCPLC
3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
21
11
1
2
3
0
0
0
7
8
0
5
0
4
0
1
32
19
1
7
3
4
0
1

MEC
0
0
0
0
0
0
0
0
0
0
0
0

OVEC
0
0
0
0
0
0
0
0
0
0
0
0

PECO
0
0
0
0
0
0
0
0
0
0
0
0

PE
23
5
0
0
0
0
64
6
2
1
89
12

PEPCO
0
0
0
0
0
0
0
0
0
0
0
0

PPL
8
0
0
0
2
0
46
2
2
0
58
2

PSEG
0
0
0
0
0
0
1
0
1
0
2
0

REC
0
0
0
0
0
0
0
0
0
0
0
0

Total
96
13
2
0
6
0
451
30
90
17
645
60

Table 12-37 shows the status of all wind projects by MW that entered PJM generation queues from January 1, 1997, through June 30, 2021, by zone. Of the33,383.1 MW of wind projects classified as new generation or upgrade currently active, suspended or under construction in the PJM generation queue, 8,843.1
MW (26.5 percent) are located in the COMED Zone.
Table 12-37 Status of all wind generation queue projects by zone (MW): January 1, 1997 through June 30, 2021
Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

644

Project Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeSection 12 Planning

ACEC
7.5
0.0
0.0
0.0
0.0
0.0
4,643.6
5.0
3,441.6
0.0
8,092.7
5.0

AEP
APS
ATSI
3,344.6 1,314.6
0.0
0.0
5.0
0.0
200.0
110.0
0.0
0.0
0.0
0.0
272.0
0.0
0.0
0.0
0.0
0.0
23,166.0 3,472.2 1,295.6
370.0
119.4
0.0
3,341.7
457.0
816.1
16.6
0.0
0.0
30,324.3 5,353.8 2,111.7
386.6
124.4
0.0

BGE
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

COMED
DAY
4,088.9
0.0
213.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
25,327.3 2,128.0
755.7
0.0
8,357.3
0.0
485.8
0.0
37,773.5 2,128.0
1,454.7
0.0

DUKE
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

DUQ
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

Project MW
DOM
DPL
EKPC JCPLC
322.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
300.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4,988.4 2,968.8
150.3 1,504.0
114.0
0.0
0.0
0.0
5,116.9 3,206.2
0.0 3,759.2
0.0
917.3
0.0
510.0
10,728.1 6,175.0
150.3 5,263.2
114.0
917.3
0.0
510.0

MEC
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

OVEC
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

PECO
PE
0.0 1,065.0
0.0
20.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0 5,377.0
0.0
243.4
0.0
159.9
0.0
100.3
0.0 6,601.9
0.0
364.2

PEPCO
PPL
PSEG
0.0
226.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
165.3
0.0
0.0
0.0
0.0
0.0 3,375.1
20.0
0.0
6.0
0.0
0.0
349.6 1,300.0
0.0
0.0
0.0
0.0 4,116.5 1,320.0
0.0
6.0
0.0

REC
Total
0.0 10,369.6
0.0
238.7
0.0
310.0
0.0
0.0
0.0
737.6
0.0
0.0
0.0 78,416.2
0.0
1,613.4
0.0 30,305.5
0.0
2,030.1
0.0 120,138.8
0.0
3,882.2© 2021 Monitoring Analytics, LLC

Section 12 Planning

Solar Project Analysis
Table 12-38 shows the status of all solar generation projects by number of projects that entered PJM generation queues from January 1, 1997, through June30, 2021, by zone. Of the 1,408 solar projects classified as new generation or upgrade currently active, suspended or under construction in the PJM generation
queue, 349 projects (24.8 percent) are located in the Dominion Zone.
Table 12-38 Status of all solar generation queue projects by zone (number of projects): January 1, 1997 through June 30, 2021
Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

Project Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
Upgrade

ACEC
9
1
0
0
0
0
183
3
25
3
217
7

AEP
6
1
4
2
3
0
119
4
216
52
348
59

APS
8
3
1
0
9
0
94
3
93
17
205
23

ATSI
0
0
0
0
0
0
25
2
54
16
79
18

BGE COMED
1
1
0
0
0
0
0
0
0
0
0
0
15
42
0
6
5
52
0
6
21
95
0
12

DAY DUKE
1
0
0
0
1
1
0
2
0
1
0
1
21
16
0
0
30
4
11
0
53
22
11
3

DUQ
0
0
0
0
0
0
1
0
4
1
5
1

Number of Projects
DOM
DPL EKPC JCPLC
36
11
0
51
6
9
0
9
16
2
0
2
6
1
0
0
9
0
1
0
0
0
0
2
237
141
14
194
19
1
0
9
267
47
46
25
51
7
1
3
565
201
61
272
82
18
1
23

MEC
0
0
0
0
4
2
24
0
37
7
65
9

OVEC
0
0
0
0
0
0
1
0
1
1
2
1

PECO
1
0
0
0
0
0
9
0
4
0
14
0

PE
1
1
0
0
4
0
67
3
121
14
193
18

PEPCO
1
0
0
0
0
0
21
3
11
0
33
3

PPL
2
3
0
0
0
0
52
0
73
17
127
20

PSEG
44
0
3
4
0
0
93
3
5
0
145
7

REC
0
0
0
0
0
0
0
0
0
0
0
0

Total
173
33
30
15
31
5
1,369
56
1,120
207
2,723
316

Table 12-39 shows the status of all solar projects by MW that entered PJM generation queues from January 1, 1997, through June 30, 2021, by zone. Of the100,137.6 MW of solar projects classified as new generation or upgrade currently active, suspended or under construction in the PJM generation queue, 32,866.6
MW (32.8 percent) are located in the AEP Zone.
Table 12-39 Status of all solar generation queue projects by zone (MW): January 1, 1997 through June 30, 2021
Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

Project Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
Upgrade© 2021 Monitoring Analytics, LLC

ACEC
62.0
0.0
0.0
0.0
0.0
0.0
2,040.0
170.0
805.0
34.6
2,907.0
204.6

AEP
APS
ATSI
94.7
112.3
0.0
20.0
0.0
0.0
320.0
10.0
0.0
150.0
0.0
0.0
30.0
211.8
0.0
0.0
0.0
0.0
7,930.3 2,448.7 1,521.3
126.0
27.9
62.0
28,890.5 4,083.3 4,100.4
3,476.1
399.5
675.7
37,265.5 6,866.0 5,621.7
3,772.1
427.4
737.7

BGE
1.1
0.0
0.0
0.0
0.0
0.0
121.6
0.0
154.9
0.0
277.6
0.0

COMED
DAY
DUKE
9.0
2.5
0.0
0.0
0.0
0.0
0.0
400.0
125.0
0.0
0.0
75.0
0.0
0.0
70.0
0.0
0.0
10.0
2,850.2 1,323.9
689.4
110.0
0.0
0.0
8,085.5 2,747.0
253.9
385.0
225.5
0.0
10,944.7 4,473.4 1,138.3
495.0
225.5
85.0

DUQ
0.0
0.0
0.0
0.0
0.0
0.0
20.0
0.0
50.6
8.3
70.6
8.3

Project MW
DOM
DPL
EKPC JCPLC
MEC
1,633.7
130.4
0.0
393.4
0.0
25.2
0.0
0.0
14.3
0.0
1,338.5
170.0
0.0
6.6
0.0
61.0
0.0
0.0
0.0
0.0
594.9
0.0
95.0
0.0
44.0
0.0
0.0
0.0
18.6
40.0
13,406.0 2,421.9
768.9 1,610.4
819.7
1,058.8
0.0
0.0
23.8
0.0
25,596.7 1,715.2 4,636.4
341.7
750.7
1,715.4
72.0
40.0
8.8
80.0
42,569.7 4,437.5 5,500.3 2,352.0 1,614.4
2,860.4
72.0
40.0
65.5
120.0

OVEC
0.0
0.0
0.0
0.0
0.0
0.0
78.0
0.0
120.0
50.0
198.0
50.0

PECO
PE
3.3
13.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
60.2
0.0
0.0
78.4 2,541.3
0.0
20.0
55.8 3,806.1
0.0
340.5
137.5 6,421.0
0.0
360.5

PEPCO
PPL
2.5
15.0
0.0
10.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
278.0
914.1
3.6
0.0
215.1 2,139.6
0.0
186.1
495.7 3,068.7
3.6
196.1

PSEG
231.9
0.0
17.5
3.8
0.0
0.0
565.6
1.3
39.9
0.0
854.9
5.1

REC
Total
0.0
2,705.2
0.0
69.5
0.0
2,387.6
0.0
289.8
0.0
1,105.9
0.0
68.6
0.0 42,427.6
0.0
1,603.4
0.0 88,588.2
0.0
7,697.5
0.0 137,214.5
0.0
9,728.82021 Quarterly State of the Market Report for PJM: January through June 645

2021 Quarterly State of the Market Report for PJM: January through June

Renewable Hybrid Project Analysis
Table 12-40 shows the status of all renewable hybrid generation projects (solar + storage, solar + wind and wind + storage) by number of projects that entered
PJM generation queues from January 1, 1997, through June 30, 2021, by zone.37 Of the 286 renewable hybrid projects currently active, suspended or underconstruction in the PJM generation queue, 63 projects (22.0 percent) are located in the Dominion Zone.
Table 12-40 Status of all renewable hybrid generation queue projects by zone (number of projects): January 1, 1997 through June 30, 2021
Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

Project Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
Upgrade

ACEC
0
0
0
0
0
0
4
0
0
1
4
1

AEP
0
0
0
1
0
0
10
0
51
6
61
7

APS
0
0
0
0
1
1
4
0
23
2
28
3

ATSI
0
0
0
0
0
0
4
0
9
0
13
0

BGE COMED
0
0
0
0
0
0
0
0
0
0
0
0
0
5
0
0
0
12
0
2
0
17
0
2

DAY DUKE
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
4
1
1
0
4
1
1
0

DUQ
0
0
0
0
0
0
0
0
2
0
2
0

Number of Projects
DOM
DPL EKPC JCPLC
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20
0
8
0
0
0
0
0
54
3
23
5
9
0
3
0
74
3
31
5
9
0
3
0

MEC
0
0
0
0
1
0
0
1
10
1
11
2

OVEC
0
0
0
0
0
0
0
0
0
0
0
0

PECO
0
0
0
0
0
0
0
0
1
0
1
0

PE
0
0
0
0
0
0
1
0
19
3
20
3

PEPCO
0
0
0
0
0
0
0
0
2
0
2
0

PPL
0
0
0
0
1
0
0
0
26
4
27
4

PSEG
1
0
2
0
0
0
8
0
2
0
13
0

REC
0
0
0
0
0
0
0
0
0
0
0
0

Total
1
0
2
1
3
1
64
1
247
32
317
35

Table 12-41 shows the status of all renewable hybrid projects by MW that entered PJM generation queues from January 1, 1997, through June 30, 2021, byzone. Of the 25,993.6 MW of renewable hybrid generation currently active, suspended or under construction in the PJM generation queue, 9,999.2 MW (38.5
percent) are located in the AEP Zone.
Table 12-41 Status of all renewable hybrid generation queue projects by zone (MW): January 1, 1997 through June 30, 2021
Project MW
Project Status
In Service
Under Construction
Suspended
Withdrawn
ActiveTotal Projects

Project
Classification
New Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
UpgradeNew Generation
Upgrade

ACEC
0.0
0.0
0.0
0.0
0.0
0.0
14.5
0.0
0.0
60.0
14.5
60.0

AEP
APS
0.0
0.0
0.0
0.0
0.0
0.0
3.2
0.0
0.0
20.0
0.0
16.3
3,360.8
300.0
0.0
0.0
9,416.0 2,059.3
580.0
0.0
12,776.8 2,379.3
583.2
16.3

ATSI
0.0
0.0
0.0
0.0
0.0
0.0
209.9
0.0
570.9
0.0
780.8
0.0

BGE COMED
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
629.9
0.0
0.0
0.0 2,278.9
0.0
20.0
0.0 2,908.8
0.0
20.0

DAY DUKE
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
169.0
10.0
20.0
0.0
169.0
10.0
20.0
0.0

DUQ
DOM
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0 1,960.0
0.0
0.0
37.5 5,698.7
0.0
94.0
37.5 7,658.7
0.0
94.0

DPL
EKPC JCPLC
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0 1,004.0
0.0
0.0
0.0
0.0
170.0 2,321.3 180.0
0.0
135.0
0.0
170.0 3,325.3 180.0
0.0
135.0
0.0

MEC
0.0
0.0
0.0
0.0
100.0
0.0
0.0
3.7
77.1
0.0
177.1
3.7

OVEC
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

PECO
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
5.0
0.0
5.0
0.0

PE
0.0
0.0
0.0
0.0
0.0
0.0
160.0
0.0
800.2
38.2
960.2
38.2

PEPCO
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
562.5
0.0
562.5
0.0

PPL
0.0
0.0
0.0
0.0
90.0
0.0
0.0
0.0
337.0
100.0
427.0
100.0

PSEG
1.1
0.0
2.6
0.0
0.0
0.0
29.9
0.0
21.2
0.0
54.7
0.0

REC
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

Total
1.1
0.0
2.6
3.2
210.0
16.3
7,669.0
3.7
24,714.4
1,047.2
32,597.0
1,070.4

37 PJM does not currently have a definition of a hybrid resource.

646

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Relationship Between Project Developer and Transmission
Owner
A transmission owner (TO) is an “entity that owns, leases or otherwise
has a possessory interest in facilities used for the transmission of electricenergy in interstate commerce under the tariff.”38 Where the transmission
owner is a vertically integrated company that also owns generation, there
is a potential conflict of interest when the transmission owner evaluates theinterconnection requirements of new generation which is a competitor to thegeneration or transmission of the parent company and when the transmission
owner evaluates the interconnection requirements of new generation which ispart of the same company as the transmission owner. There is also a potential
conflict of interest when the transmission owner evaluates the interconnection
requirements of a nonincumbent transmission developer which is a competitorof the transmission owner. The MMU recommends outsourcing interconnection
studies to an independent party to avoid potential conflicts of interest.

Of the 711,962.4 MW that have entered the queue during the time period ofJanuary 1, 1997, through June 30, 2021, 70,060.1 MW (9.8 percent) havebeen submitted by transmission owners building in their own service territory.
PSEG is the transmission owner with the highest percentage of affiliatesbuilding in their own service territory. Of the 39,053.9 MW that entered thequeue in the PSEG Zone during the time period of January 1, 1997, throughJune 30, 2021, 14,286.2 MW (36.6 percent) have been submitted by PSEG or
one of their affiliated companies.

Table 12-42 shows the relationship between the project developer andtransmission owner for all project MW that have entered the PJM generation
queue from January 1, 1997, through June 30, 2021, by transmission
owner and unit type. A project where the developer is affiliated with thetransmission owner is classified as related. A project where the developer
is not affiliated with the transmission owner is classified as unrelated. For
example, 36.0 MW of combined cycle generation projects that have entered
the PJM generation queue in the DUKE Zone were projects developed by Duke
Energy or subsidiaries of Duke Energy, the transmission owner for the DUKE
Zone. These project MW are classified as related. There have been 667.5 MWof combined cycle projects that have entered the PJM generation queue in the
DUKE Zone by developers not affiliated with Duke Energy. These project MW
are classified as unrelated.

38 See OATT § 1 (Transmission Owner).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 647

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-42 Relationship between project developer and transmission owner for all interconnection queue projects MW by unit type: June 30, 2021
ParentCompany
AEP
AES
DUQ
DOM
DUKE
EKPC
ExelonFirst Energy

OVEC
PPL
PSEG
Con EdTotal

648

Transmission Related to
Owner
Developer
AEP
RelatedUnrelated
DAY
RelatedUnrelated
DUQ
RelatedUnrelated
DOM
RelatedUnrelated
DUKE
RelatedUnrelated
EKPC
RelatedUnrelated
ACEC
RelatedUnrelated
BGE
RelatedUnrelated
COMED
RelatedUnrelated
DPL
RelatedUnrelated
PECO
RelatedUnrelated
PEPCO
RelatedUnrelated
APS
RelatedUnrelated
ATSI
RelatedUnrelated
JCPLC
RelatedUnrelated
MEC
RelatedUnrelatedPE
RelatedUnrelated
OVEC
RelatedUnrelated
PPL
RelatedUnrelated
PSEG
RelatedUnrelated
REC
RelatedUnrelated
RelatedUnrelated

Section 12 Planning

Number of
Projects
51
884
13
98
0
40
155
924
10
37
2
105
5
362
13
74
17
481
8
357
33
88
1
113
4
534
6
187
2
444
0
180
4
484
0
3
22
389
108
243
0
2
454
6029

Battery
CC
16.0
678.0
7,389.0 21,973.5
20.0
0.0
289.9
1,150.0
0.0
0.0
75.0
665.0
480.2 12,338.5
9,436.2
9,244.5
27.3
36.0
365.4
667.5
0.0
821.8
146.3
170.0
0.0
730.0
1,359.0
8,848.4
20.0
250.0
1,104.1
3,012.1
0.0
0.0
3,593.6 16,823.2
1.0
1,365.0
947.5
5,611.6
40.0
6,965.0
25.3 20,355.5
1.0
0.0
320.0 23,325.9
0.0
1,453.0
1,268.7 29,182.8
0.0
1,678.0
1,246.4 13,589.0
0.0
0.0
1,606.0 15,751.4
0.0
0.0
619.9 17,458.9
0.0
534.0
940.2 18,747.9
0.0
0.0
0.0
0.0
0.0
2,261.0804.8 23,928.3
0.0 11,836.1
1,089.5 18,771.9
0.0
0.0
0.0
6.9
605.5 40,946.4
32,626.8 249,284.1

CT Natural
CT Gas CT - Oil Other
0.0
0.0
0.0
2,913.2
7.5
133.3
38.0
0.0
0.0
273.5
0.0
1.9
0.0
0.0
0.0
222.9
40.0
19.2
2,045.7
100.0
0.0
2,225.8
0.5
227.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
73.0
0.0
0.0
0.0
0.0
0.0
807.4
388.0
20.7
10.0
0.0
0.0
166.6
18.0
133.0
0.0
0.0
0.0
1,529.2
42.0
65.2
351.0
0.0
0.0
1,226.0
600.9
42.6
5.0
89.5
0.0
596.5
2.0
15.0
0.0
0.0
0.0
94.3
34.0
9.0
0.0
0.0
0.0
1,479.7
0.0
84.4
0.0
0.0
0.0
588.7
10.5
166.4
0.0
0.0
0.0
722.1
0.0
4.8
0.0
0.0
0.0
57.6 1,204.4
52.1
5.0
0.0
0.0
1,532.2
0.0
214.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
423.1
8.0
234.5
1,818.1
0.0
0.0
1,137.9
600.0
62.5
0.0
0.0
0.0
0.0
0.0
0.0
4,272.8
189.5
0.0
16,069.7 2,955.8 1,486.3

Fuel
Cell
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2.8
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.6
0.0
0.0
0.0
3.0
0.0
0.0
0.0
0.0
0.0
4.9
0.0
0.0
0.0
11.3

Hydro - Hydro RICE Pumped Run of
NaturalStorageRiver Nuclear
Gas
34.0
2.4
214.0
0.0
0.0
453.6
0.0
12.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
194.6 1,879.0
0.0
340.0
0.0 1,944.0
0.0
0.0
35.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
112.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2.0
0.0
0.0
80.4
0.0
0.0
0.4 3,308.1
1.3
0.0
0.0 1,185.0
0.0
0.0
22.7
0.0
35.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
265.0
437.8
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0 1,640.0
32.0
0.0
0.0
0.0
0.0
0.0
638.3
0.0
140.0
0.0
0.0
16.0
0.0
0.0
0.0
0.0
59.7
0.0
20.0
0.0
0.0
30.0
1.6
0.0
0.6
0.0
0.0
0.0
0.0
0.0
0.0
93.0
0.0
0.0
0.0
0.0
0.0
16.0
46.3
0.0
341.8
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
109.0 1,600.0
0.01,200.0
142.6
488.0
19.9
0.0
0.0
381.0
0.0
0.0 1,000.0
0.0
10.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
374.0
396.4 5,858.2
0.0
1,246.0 2,647.0 7,408.1
654.9

MW by Unit TypeRICE Oil
0.0
0.0
0.0
0.0
0.0
0.0
0.0
10.0
0.0
0.0
0.0
0.0
0.0
5.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
17.0
0.0
0.0
0.0
53.8
0.0
0.0
0.0
0.0
0.0
8.0
0.0
8.0
0.0
0.0
0.0
2.4
0.0
0.0
0.0
0.0
0.0
104.2

RICE Other
Solar
0.0
247.7
75.4 40,789.9
0.0
21.5
10.0
4,677.4
0.0
0.0
0.0
78.9
60.0
4,098.4
119.4 41,331.7
0.0
106.4
4.8
1,116.9
0.0
0.0
0.0
5,540.3
0.0
8.3
10.3
3,103.3
8.5
20.0
0.0
257.6
0.0
9.0
67.7 11,430.7
0.0
7.4
84.6
4,502.1
0.0
0.0
3.7
137.5
0.0
0.0
3.5
499.3
0.0
0.0
25.4
7,293.4
0.0
0.0
6.9
6,359.4
0.0
12.0
12.8
2,405.5
0.0
0.0
23.2
1,734.4
0.0
0.0
14.8
6,781.5
0.0
0.0
0.0
248.0
0.0
124.8
44.7
3,140.0
0.0
180.4
13.7
679.6
0.0
0.0
0.0
0.0
68.5
4,835.8
520.9 142,107.5

Solar + Solar +Storage
Wind
180.0
0.0
13,180.0
0.0
0.0
0.0
189.0
0.0
0.0
0.0
37.5
0.0
17.0
0.0
7,735.7
0.0
0.0
0.0
0.0
10.0
0.0
0.0
3,460.3
0.0
0.0
0.0
74.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2,729.8
199.0
0.0
0.0
170.0
0.0
0.0
0.0
5.0
0.0
0.0
0.0
562.5
0.0
0.0
0.0
2,379.3
0.0
0.0
0.0
780.8
0.0
0.0
0.0
180.0
0.0
0.0
0.0
180.8
0.0
0.0
0.0
998.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
437.0
0.0
2.6
0.0
52.2
0.0
0.0
0.0
0.0
0.0
199.6
0.0
33,152.5
209.0

Steam Steam - Natural
Coal
Gas
3,918.0
90.0
10,399.0
0.0
1,347.5
0.0
0.0
0.0
0.0
0.0
2,810.0
0.0
301.0
0.0
20.0
0.0
0.0
0.0
120.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
15.0
5.5
10.0
101.0
0.0
2.5
0.0
0.0
1,926.0
91.0
0.0
0.0
653.0
15.0
7.0
0.0
0.0
0.0
0.0
0.0
0.0
6.0
1,710.0
0.0
4,092.0
0.0
0.0
0.0
0.0
16.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1,860.0
0.0
561.0
590.0
0.0
0.0
0.0
0.0
111.0
0.0
6,896.6
0.0
24.0
44.0
0.0
25.0
0.0
0.0
0.0
0.0
9,288.5
235.0
27,492.6
751.5

Steam SteamWind +- Oil - OtherWind Storage
Total
0.0
0.0
0.0
0.0
5,380.1
0.0
452.0 30,710.9
0.0 128,489.2
0.0
0.0
0.0
0.0
1,427.00.0
0.02,128.0
0.0
8,719.7
0.0
0.0
0.0
0.0
0.0
0.0
20.0
0.0
0.0
6,042.1
0.0
4.0
2,786.0
0.0 24,514.8
0.0
316.3
8,056.1
0.0 78,758.6
0.0
0.0
0.0
0.0
169.7
0.0
0.0
0.0
0.0
2,396.6
0.0
0.0
0.0
0.0
821.8
0.0
0.0
150.3
0.0
9,540.1
0.0
0.0
0.0
0.0
738.3
0.0
10.0
8,097.7
0.0 22,749.6
0.0
0.0
0.0
0.0
499.9
0.0
25.0
0.0
0.0
8,028.7
0.0
0.0
0.0
0.0
1,194.0
0.0
90.0 39,228.1
0.0 77,873.2
0.0
0.0
0.0
0.0
1,724.4
0.0
65.0
7,092.3
0.0 21,010.6
0.0
0.0
0.0
0.0
7,809.3
0.0
0.0
0.0
0.0 21,157.5
0.0
0.0
0.0
0.0
1.0
0.0
0.0
0.0
0.0 26,526.5
0.0
0.0
0.0
0.0
3,163.0
0.0
184.4
5,478.2
16.3 52,316.6
0.0
0.0
0.0
0.0
1,694.00.0
0.0
2,111.7
0.0 24,935.9
0.0
0.0
0.0
0.0
32.0
0.0
30.0
5,773.2
0.0 26,518.6
0.0
0.0
0.0
0.0
0.0
0.0
84.0
0.0
0.0 21,516.3
0.0
0.0
0.0
0.0
2,399.00.0
525.0
6,966.1
0.0 38,286.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
248.0
0.0
0.0
0.0
0.0
4,205.8
0.0
31.0
4,122.5
90.0 42,013.5
0.0
0.0
0.0
0.0 14,286.2
0.0
0.0
1,320.0
0.0 24,767.8
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
6.9
0.0
4.0
2,786.0
0.0 70,060.1
0.0 1,832.7 121,235.0
106.3 641,902.2© 2021 Monitoring Analytics, LLC

Section 12 Planning

Combined Cycle Project Developer andTransmission Owner Relationships
Table 12-43 shows the relationship between the project
developer and transmission owner for all combined cycle
project MW that have entered the PJM generation queue fromJanuary 1, 1997, through June 30, 2021, by transmission ownerand project status. Of the 48,202.1 combined cycle project MWthat have achieved in service or under construction statusduring this time period, 9,294.6 MW (19.3 percent) have beendeveloped by transmission owners building in their own service
territory. EKPC is the transmission owner with the highest
percentage of affiliates building combined cycle projects intheir own service territory. Of the 991.8 MW that entered thequeue in the EKPC Zone during the time period of January 1,
1997, through June 30, 2021, 821.8 MW (82.9 percent) havebeen submitted by EKPC or one of their affiliated companies.

Table 12-43 Relationship between project developer and transmission owner for all
combined cycle project MW in the queue: June 30, 2021
ParentCompany
AEP

Transmission
Owner
AEP

AES

DAY

DUQ

DUQ

DOM

DOM

DUKE

DUKE

EKPC

EKPC

Exelon

ACEC
BGE
COMED
DPL
PECO
PEPCO

First Energy

APS
ATSI
JCPLC
MEC
PE

OVEC

OVEC

PPL

PPL

PSEG

PSEG

Con EdREC

Total© 2021 Monitoring Analytics, LLC

Related to
Developer
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated

Active0.0
2,520.0
0.0
0.0
0.0
0.0
75.0
1,600.0
0.0
0.0
0.0
0.0
0.0
7.6
0.0
0.0
0.0
1,261.7
0.0
451.0
0.0
0.0
0.0
0.0
0.0
3,884.0
0.0
550.0
0.0
0.0
0.0
0.0
0.0
248.0
0.0
0.0
0.0
55.0
0.0
0.0
0.0
0.0
75.0
10,577.3

In Service
678.0
2,738.0
0.0
0.0
0.0
0.0
4,762.5
2,044.1
0.0
533.0
0.0
0.0
0.0
879.0
130.0
10.0
0.0
1,233.6
60.0
361.2
0.0
3,740.5
0.0
1,788.6525.0
1,720.0
0.0
2,943.0
0.0
1,775.8
0.0
2,640.9
0.0
2,042.3
0.0
0.0
600.0
5,862.0
2,488.0
806.4
0.0
0.0
9,243.5
31,118.3

MW by Project Status
Under
Construction Suspended
0.0
0.0
3,495.0
0.0
0.0
0.0
0.0
1,150.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2,350.9
100.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
664.7
1,136.0
0.0
0.0
1,152.0
1,895.0
0.0
0.0
0.0
35.0
0.0
0.0
75.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
51.6
0.0
51.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
51.1
0.0
7,789.2
4,316.0

Withdrawn
0.0
13,220.5
0.0
0.0
0.0
665.0
7,501.05,600.4
36.0
134.5
821.8
170.0
730.0
7,961.8
120.0
3,002.1
0.0
11,877.0
1,305.0
4,799.4
6,965.0
16,615.0
0.0
21,537.3
928.0
21,778.1
1,678.0
7,049.0
0.0
13,940.6
0.0
14,743.0534.0
16,457.6
0.0
0.0
1,661.0
17,959.7
9,297.0
17,965.5
0.0
6.9
31,576.8
195,483.2

Total
678.0
21,973.5
0.0
1,150.00.0
665.0
12,338.5
9,244.5
36.0
667.5
821.8
170.0
730.0
8,848.4
250.0
3,012.1
0.0
16,823.2
1,365.0
5,611.6
6,965.0
20,355.5
0.0
23,325.9
1,453.0
29,182.8
1,678.0
13,589.0
0.0
15,751.4
0.0
17,458.9
534.0
18,747.90.0
0.0
2,261.0
23,928.3
11,836.1
18,771.9
0.0
6.9
40,946.4
249,284.1

2021 Quarterly State of the Market Report for PJM: January through June 649

2021 Quarterly State of the Market Report for PJM: January through June

Combustion Turbine – Natural Gas Project
Developer and Transmission Owner Relationships
Table 12-44 shows the relationship between the project
developer and transmission owner for all CT – natural gas project
MW that have entered the PJM generation queue from January
1, 1997, through June 30, 2021, by transmission owner andproject status. Of the 9,758.3 CT – natural gas project MW thathave achieved in service or under construction status during
this time period, 2,145.0 (22.0 percent) have been developedby Transmission Owners building in their own service territory.
PSEG is the transmission owner with the highest percentage
of affiliates building CT – natural gas projects in their own
service territory. Of the 2,956.0 MW that entered the queuein the PSEG Zone during the time period of January 1, 1997,
through June 30, 2021, 1,818.1 MW (61.5 percent) have been
submitted by PSEG or one of their affiliated companies.

Table 12-44 Relationship between project developer and transmission owner for all CT –natural gas project MW in the queue: June 30, 2021
ParentCompany
AEP

Transmission
Owner
AEP

AES

DAY

DUQ

DUQ

DOM

DOM

DUKE

DUKE

EKPC

EKPC

Exelon

ACEC
BGE
COMED
DPL
PECO
PEPCO

First Energy

APS
ATSI
JCPLC
MEC
PE

OVEC

OVEC

PPL

PPL

PSEG

PSEG

Con Ed

REC

Total

650

Section 12 Planning

Related to
Developer
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated

Active0.0
1,110.1
0.0
43.5
0.0
3.5
1,138.0
0.0
0.0
0.0
0.0
0.0
0.0
230.0
0.0
144.6
0.0
688.2
0.0
0.0
0.0
0.0
0.0
57.3
0.0
70.0
0.0
518.7
0.0
0.0
0.0
0.0
0.0
573.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1,138.0
3,438.9

In Service
0.0
227.0
38.0
22.0
0.0
0.0
824.0
1,182.7
0.0
0.0
0.0
0.0
0.0
404.4
10.0
13.0
0.0
371.0
351.0
1,226.0
5.0
596.0
0.0
37.0
0.0
1,363.7
0.0
40.0
0.0
720.0
0.0
44.1
5.0
384.9
0.0
0.0
0.0
403.2
912.0
228.9
0.0
0.0
2,145.0
7,263.9

MW by Project Status
Under
Construction Suspended
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
219.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
87.0
350.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
12.0
30.0
0.0
0.0
5.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
13.5
0.0
0.0
0.0
12.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
675.0
0.0
0.0
0.0
0.0
0.0
0.0
349.4
1,055.0

Withdrawn
0.0
1,576.1
0.0
208.0
0.0
0.0
83.7
1,043.1
0.0
0.0
0.0
73.0
0.0
173.0
0.0
9.0
0.0
33.0
0.0
0.0
0.0
0.5
0.0
0.0
0.0
4.0
0.0
25.0
0.0
2.1
0.0
0.0
0.0
561.8
0.0
0.0
0.0
19.9
906.1
234.0
0.0
0.0
989.8
3,962.5

Total
0.0
2,913.2
38.0
273.5
0.0
222.9
2,045.7
2,225.8
0.0
0.0
0.0
73.0
0.0
807.4
10.0
166.6
0.0
1,529.2
351.0
1,226.0
5.0
596.5
0.0
94.3
0.0
1,479.7
0.0
588.7
0.0
722.1
0.0
57.6
5.0
1,532.2
0.0
0.0
0.0
423.1
1,818.1
1,137.9
0.0
0.0
4,272.8
16,069.7© 2021 Monitoring Analytics, LLC

Section 12 PlanningWind Project Developer and Transmission Owner
Relationships
Table 12-45 shows the relationship between the project
developer and transmission owner for all wind project MW thathave entered the PJM generation queue from January 1, 1997,
through June 30, 2021, by transmission owner and projectstatus. Of the 10,918.3 wind project MW that have achievedin service or under construction status during this time period,
12.0 MW (0.1 percent) have been developed by transmission
owners building in their own service territory. Dominion is thetransmission owner with the highest percentage of affiliatesbuilding wind projects in their own service territory. Of the
10,842.1 MW that entered the queue in the Dominion Zone
during the time period of January 1, 1997, through June 30,
2021, 2,786.0 MW (25.7 percent) have been submitted by
Dominion or one of their affiliated companies.

Table 12-45 Relationship between project developer and transmission owner for all windproject MW in the queue: June 30, 2021
ParentCompany
AEP

Transmission
Owner
AEP

AES

DAY

DUQ

DUQ

DOM

DOM

DUKE

DUKE

EKPC

EKPC

Exelon

ACEC
BGE
COMED
DPL
PECO
PEPCO

First Energy

APS
ATSI
JCPLC
MEC
PE

OVEC

OVEC

PPL

PPL

PSEG

PSEG

Con EdREC

Total© 2021 Monitoring Analytics, LLC

Related to
Developer
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated

Active0.0
3,358.4
0.0
0.0
0.0
0.0
2,640.0
2,476.9
0.0
0.0
0.0
0.0
0.0
3,441.6
0.0
0.0
0.0
8,843.1
0.0
4,123.5
0.0
0.0
0.0
0.0
0.0
457.0
0.0
816.1
0.0
4,269.2
0.0
0.0
0.0
260.2
0.0
0.0
0.0
349.6
0.0
1,300.0
0.0
0.0
2,640.0
29,695.5

In Service
0.0
3,344.6
0.0
0.0
0.0
0.0
12.0
310.5
0.0
0.0
0.0
0.0
0.0
7.5
0.0
0.0
0.0
4,302.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1,319.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1,085.5
0.0
0.0
0.0
226.5
0.0
0.0
0.0
0.0
12.0
10,596.3

MW by Project Status
Under
Construction Suspended
0.0
0.0
200.0
272.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
300.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
110.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
165.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
310.0
737.6

Withdrawn
0.0
23,536.0
0.0
2,128.0
0.0
0.0
134.0
4,968.4
0.0
0.0
0.0
150.3
0.0
4,648.6
0.0
0.0
0.0
26,082.9
0.0
2,968.8
0.0
0.0
0.0
0.0
0.0
3,591.6
0.0
1,295.6
0.0
1,504.0
0.0
0.0
0.0
5,620.3
0.0
0.0
0.0
3,381.1
0.0
20.0
0.0
0.0
134.0
79,895.6

Total
0.0
30,710.9
0.02,128.0
0.0
0.0
2,786.0
8,056.1
0.0
0.0
0.0
150.3
0.0
8,097.7
0.0
0.0
0.0
39,228.1
0.0
7,092.3
0.0
0.0
0.0
0.0
0.0
5,478.2
0.0
2,111.7
0.0
5,773.2
0.0
0.0
0.0
6,966.1
0.0
0.0
0.0
4,122.5
0.0
1,320.0
0.0
0.0
2,786.0
121,235.0

2021 Quarterly State of the Market Report for PJM: January through June 651

2021 Quarterly State of the Market Report for PJM: January through June

Solar Project Developer and Transmission Owner
Relationships
Table 12-46 shows the relationship between the project
developer and transmission owner for all solar project MWthat have entered the PJM generation queue from January
1, 1997, through June 30, 2021, by transmission owner andproject status. Of the 5,452.1 solar project MW that haveachieved in service or under construction status during thistime period, 1,532.6 MW (28.1 percent) have been developedby transmission owners building in their own service territory.
PSEG is the transmission owner with the highest percentage ofaffiliates building solar projects in their own service territory.
Of the 860.0 MW that entered the queue in the PSEG Zone
during the time period of January 1, 1997, through June 30,
2021, 180.4 MW (21.0 percent) have been submitted by PSEG
or one of their affiliated companies.

Table 12-46 Relationship between project developer and transmission owner for all solar
project MW in the queue: June 30, 2021
ParentCompany
AEP

Transmission
Owner
AEP

AES

DAY

DUQ

DUQ

DOM

DOM

DUKE

DUKE

EKPC

EKPC

Exelon

ACEC
BGE
COMED
DPL
PECO
PEPCO

First Energy

APS
ATSI
JCPLC
MEC
PE

OVEC

OVEC

PPL

PPL

PSEG

PSEG

Con Ed

REC

Total

652

Section 12 Planning

Related to
Developer
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated

Active48.0
32,318.6
0.0
2,972.5
0.0
58.9
2,504.5
24,807.6
50.0
203.9
0.0
4,676.4
0.0
839.6
0.0
154.9
0.0
8,470.5
0.0
1,787.2
0.0
55.8
0.0
215.1
0.0
4,482.8
0.0
4,776.0
0.0
350.5
0.0
830.7
0.0
4,146.6
0.0
170.0
124.8
2,201.0
0.0
39.9
0.0
0.0
2,727.2
93,558.5

In Service
34.7
80.0
0.0
2.5
0.0
0.0
726.4
932.5
0.0
0.0
0.0
0.0
0.0
62.0
0.0
1.1
9.0
0.0
7.4
123.0
0.0
3.3
0.0
2.5
0.0
112.3
0.0
0.0
0.0
407.7
0.0
0.0
0.0
13.5
0.0
0.0
0.0
25.0
134.3
97.6
0.0
0.0
911.8
1,862.9

MW by Project Status
Under
Construction Suspended
0.0
10.0
470.0
20.0
0.0
0.0
400.0
0.0
0.0
0.0
0.0
0.0
615.6
0.0
783.9
594.9
0.0
0.0
200.0
80.0
0.0
0.0
0.0
95.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
170.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
10.0
211.8
0.0
0.0
0.0
0.0
0.0
0.0
6.6
18.6
0.0
0.0
0.0
84.0
0.0
0.0
0.0
60.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
5.2
0.0
16.1
0.0
0.0
0.0
0.0
0.0
620.8
10.0
2,056.6
1,164.5

Withdrawn
155.0
7,901.3
21.5
1,302.4
0.0
20.0
251.9
14,212.9
56.4
633.0
0.0
768.9
8.3
2,201.8
20.0
101.6
0.0
2,960.2
0.0
2,421.9
0.0
78.4
0.0
281.6
0.0
2,476.6
0.0
1,583.3
12.0
1,622.2
0.0
819.7
0.0
2,561.3
0.0
78.0
0.0
914.1
40.9
526.0
0.0
0.0
566.0
43,465.0

Total
247.7
40,789.9
21.5
4,677.4
0.0
78.9
4,098.4
41,331.7
106.4
1,116.9
0.0
5,540.3
8.3
3,103.3
20.0
257.6
9.0
11,430.7
7.4
4,502.1
0.0
137.5
0.0
499.3
0.0
7,293.4
0.0
6,359.4
12.0
2,405.5
0.0
1,734.4
0.0
6,781.5
0.0
248.0
124.8
3,140.0
180.4
679.6
0.0
0.0
4,835.8
142,107.5© 2021 Monitoring Analytics, LLC

Section 12 Planning

Renewable Hybrid Project Developer andTransmission Owner Relationships
Table 12-47 shows the relationship between the project
developer and transmission owner for all renewable hybrid
project MW that have entered the PJM generation queue fromJanuary 1, 1997, through June 30, 2021, by transmission ownerand project status. Of the 6.8 renewable hybrid project MW thathave achieved in service or under construction status during
this time period, 2.6 MW (37.9 percent) have been developedby transmission owners building in their own service territory.
PSEG is the transmission owner with the highest percentage ofaffiliates building hybrid projects in their own service territory.
Of the 54.7 MW that entered the queue in the PSEG Zone
during the time period of January 1, 1997, through June 30,
2021, 2.6 MW (4.7 percent) have been submitted by PSEG or
one of their affiliated companies.

Table 12-47 Relationship between project developer and transmission owner for all hybrid
project MW in the queue: June 30, 2021
ParentCompany
AEP

Transmission
Owner
AEP

AES

DAY

DUQ

DUQ

DOM

DOM

DUKE

DUKE

EKPC

EKPC

Exelon

ACEC
BGE
COMED
DPL
PECO
PEPCO

First Energy

APS
ATSI
JCPLC
MEC
PE

OVEC

OVEC

PPL

PPL

PSEG

PSEG

Con EdREC

Total© 2021 Monitoring Analytics, LLC

Related to
Developer
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated
RelatedUnrelated

Active180.0
9,816.0
0.0
189.0
0.0
37.5
17.0
5,775.7
0.0
10.0
0.0
2,456.3
0.0
60.0
0.0
0.0
0.0
2,298.9
0.0
170.0
0.0
5.0
0.0
562.5
0.0
2,059.3
0.0
570.9
0.0
180.0
0.0
77.1
0.0
838.4
0.0
0.0
0.0
437.0
0.0
21.2
0.0
0.0
197.0
25,564.6

In Service
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1.1
0.0
0.0
0.0
1.1

MW by Project Status
Under
Construction Suspended
0.0
0.0
3.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
100.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
90.0
2.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2.6
0.0
3.2
226.3

Withdrawn
0.0
3,360.8
0.0
0.0
0.0
0.0
0.0
1,960.0
0.0
0.0
0.0
1,004.0
0.0
14.5
0.0
0.0
0.0
629.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
300.0
0.0
209.9
0.0
0.0
0.0
3.7
0.0
160.0
0.0
0.0
0.0
0.0
0.0
29.9
0.0
0.0
0.0
7,672.7

Total
180.0
13,180.0
0.0
189.0
0.0
37.5
17.0
7,735.7
0.0
10.0
0.0
3,460.3
0.0
74.5
0.0
0.0
0.0
2,928.8
0.0
170.0
0.0
5.0
0.0
562.5
0.0
2,395.6
0.0
780.8
0.0
180.0
0.0
180.8
0.0
998.4
0.0
0.0
0.0
527.0
2.6
52.2
0.0
0.0
199.6
33,467.82021 Quarterly State of the Market Report for PJM: January through June 653

2021 Quarterly State of the Market Report for PJM: January through June

Regional Transmission Expansion Plan (RTEP)39
The PJM RTEP process is designed to identify needed transmission system
additions and improvements to continue to provide reliable service throughout
the RTO. The objective of the RTEP process is to provide PJM with an optimal
set of solutions necessary to solve reliability issues, operational performanceissues and transmission constraints.
The RTEP process initially considered only factors such as load growth andthe generation interconnection requests in its development of the 15 year
plan. Currently, the RTEP process includes a broader range of inputs including
the effects of public policy, market efficiency, interregional coordination andthe effects of aging infrastructure.

RTEP Process
The PJM RTEP process is a 24 month planning process that identifies
reliability issues for the next 15 year period. This 24 month planning processincludes a process to build power flow models that represent the expected
future system topology, studies to identify issues, stakeholder input and PJM
Board of Manager approvals. The 24 month planning process is made up
of overlapping 18 month planning cycles to identify and develop shorter
lead time transmission upgrades and one 24 month planning cycle to provide
sufficient time for the identification and development of longer lead timetransmission upgrades that may be required to satisfy planning criteria.

Market Efficiency Process
PJM’s Regional Transmission Expansion Plan (RTEP) process includes amarket efficiency analysis. The stated purpose of the market efficiency
analysis is: to determine which reliability based enhancements have economic
benefit if accelerated; to identify new transmission enhancements that resultin economic benefits; and to identify economic benefits associated withmodification to existing RTEP reliability based enhancements that whenmodified would relieve one or more economic constraints. PJM identifies the
economic benefit of proposed transmission projects based on production cost
39 The material in this section is based in part on the PJM Manual 14B: PJM Region Transmission Planning Process. See PJM. “PJM Manual
14B: PJM Region Transmission Planning Process,” Rev. 49 (June 23, 2021).

654

Section 12 Planning

analyses.40 PJM presents the RTEP market efficiency enhancements to the PJM
Board, along with stakeholder input, for Board approval.
To be recommended to the PJM Board of Managers for approval, the relative
benefits and costs of the economic based enhancement or expansion of the
proposed project must reduce congestion on one or more constraints by atleast one dollar, meet a benefit/cost ratio threshold of at least 1.25:1 and havean independent cost review, performed by PJM, if expected costs are over $50
million. PJM provides the review of a project with a projected cost of over
$50 million using its own staff or outside consultants that are hired to assist
in the review. PJM presents its findings to the TEAC where PJM’s findings
are reviewed by the stakeholders. While stakeholders can comment on thefindings, PJM makes the final decision about what costs will be used for the
purpose of calculating the Benefit/Cost ratio for the project. The benefit/cost
ratio is the ratio of the present value of the total annual benefit for 15 years
to the present value of the total annual cost for the first 15 years of the life of
the enhancement or expansion.
The market efficiency process is comprised of a 12 month cycle and a 24month cycle, both of which begin and end on the calendar year. The 12 month
cycle is used for analysis of modifications and accelerations to approved
RTEP projects only. The 24 month cycle is used for analysis of new economictransmission projects for years five through 15. This long-term proposal
window takes place concurrently with the long-term proposal window forreliability projects.
PJM’s first market efficiency analysis was performed in 2013, prior to Order
1000. The 2013 window was open from August 12, 2013, through September
26, 2013. This window accepted proposals to address historical congestion
on 25 identified flowgates. PJM received 17 proposals from six entities. One
project was approved by the PJM Board.
The first market efficiency cycle conducted under Order 1000 was performed
during the 2014/2015 RTEP long term window. The 2014/2015 long term
40 See PJM. “PJM Regional Transmission Expansion Plan: 2019,” (February 29, 2020) <https://www.‌pjm.com/-/media/library/reportsnotices/2019-rtep/2019-rtep-book-1.ashx>.

© 2021 Monitoring Analytics, LLC

Section 12 Planningwindow was open from November 1, 2014, through February 28, 2015. Thiswindow accepted proposals to address historical congestion on 12 identified
flowgates. PJM received 93 proposals from 19 entities. Thirteen projects wereapproved by the PJM Board.
The second market efficiency cycle was performed during the 2016/2017
RTEP long term window. The 2016/2017 long term window was open from
November 1, 2016, through February 28, 2017. This window accepted proposals
to address historical congestion on four identified flowgates. PJM received 96
proposals from 20 entities. Four projects were approved by the PJM Board.
PJM also held an addendum 2016/2017 long term window. This 2016/2017
1A long term window was open from September 14, 2017, through September
28, 2017. This window accepted proposals to address historical congestion on
one identified flowgate. PJM received three proposals from two entities. One
project was approved by the PJM Board.
The fourth market efficiency cycle was performed for the 2018/2019 RTEP longterm window. The 2018/2019 long term window was open from November 2,
2018, through March 15, 2019. This window accepted proposals to address
historical congestion on one internal and three interregional flowgates. PJM
received 33 proposals from 10 entities. One project was approved by the PJM
Board to address the historical congestion on the internal flowgate, and one
project was approved by the PJM Board to address the historical congestion
on one of the interregional flowgates.41
The fifth market efficiency cycle is currently in the second year of the twoyear cycle. The 2020/2021 RTEP long term window was open from November
11, 2020, through May 11, 2021. This window accepted proposals to address
historical congestion on four internal flowgates. PJM received 24 proposals
from 7 entities. The proposals are undergoing reliability and market efficiency
analysis as well as cost and constructability analysis. Final project selections
are scheduled to occur in the fourth quarter of 2021.
41 No proposals effectively resolved the congestion on two of the three identified interregional market efficiency flowgates. One proposal
received provisional approval by the PJM Board, pending approval by the MISO Board.

© 2021 Monitoring Analytics, LLC

The Benefit/Cost Evaluation
For an RTEP project to be recommended to the PJM Board of Managers forapproval as a market efficiency project, the relative benefits and costs of theeconomic based enhancement or expansion must meet a benefit/cost ratio
threshold of at least 1.25:1.
The total benefit of a project is calculated as the sum of the net present valueof calculated energy market benefits and calculated reliability pricing model(RPM) benefits for a 15 year period, starting with the projected in service dateof the project. PJM measures benefits as reductions in estimated load charges
and production costs in the energy market and reductions in estimated load
capacity payments and in system capacity costs in the capacity market, butdoes not weight increases and decreases in benefits equally. The method for
calculating energy market benefits and reliability pricing model benefits
depends on whether the project is regional or subregional. A regional projectis any project rated at or above 230 kV. A subregional project is any project
rated at less than 230 kv.
The energy market benefit analysis uses an energy market simulation tool that
produces an hourly least-cost, security constrained market solution, including
total operational costs, hourly LMPs, bus specific injections and bus specificwithdrawals for each modeled year with and without the proposed RTEP
project. Using the output from the model, PJM calculates changes in energy
production costs and load energy payments.
The definition of the energy benefit analysis depends on whether the projectis regional or subregional. For a regional project, the energy benefit for eachmodeled year is equal to 50 percent of the change in system wide total systemenergy production costs with and without the project plus 50 percent of thechange in zonal load payments with and without the project, including only
those zones where the project reduced the load payments. For subregional
projects, the calculation of benefits for each modeled year ignores any impact
on system wide energy production costs and is instead based only the change
in zonal load energy payments with and without the project, but including
only those zones where the project reduced the load energy payments.

2021 Quarterly State of the Market Report for PJM: January through June 655

2021 Quarterly State of the Market Report for PJM: January through June

In both the regional and subregional analysis, changes in zonal load energy
payments are netted against changes in the estimated value of any Auction
Revenue Rights (ARR) that sink in that zone for purposes of determining
whether a zone benefits from a proposed RTEP project. Estimated ARR credits
are calculated for each simulated year using the most recent planning year’s
actual ARR MW combined with FTR prices assumed to be equal to the market
simulation’s CLMP differences between ARR source and sink points. The valueof the ARR rights with and without the RTEP project is evaluated based onchanges in modeled CLMPs on the latest allocation of ARR rights. ARR MW
allocations are not adjusted to reflect any potential changes in ARR allocations
which may be allowed by the RTEP upgrade and the value of the ARRs are
assumed to match the forecasted CLMP differences on the ARR paths.
The Reliability Pricing Model (RPM) Benefit analysis is conducted using the
RPM solution software, with and without the proposed RTEP project, using a
set of estimated capacity offers.
The definition of the benefit in the RPM benefit analysis depends on whether
the project is regional or subregional. For a regional project, the RPM benefit
for each modeled year is equal to 50 percent of the change in system wide
total system capacity payments with and without the project plus 50 percentof the change in zonal capacity payments with and without the project,including only those zones where the project reduced the capacity payments.
For subregional projects, the reliability pricing model benefits for eachmodeled year ignores any impact on system wide total capacity payments
and is equal to the change in zonal capacity payments with and without the
project, including only those zones where the project reduced the capacity
payments.
The difference in the benefits calculation used in the regional and subregional
cost benefit threshold tests is related to how the direct costs of the transmission
projects are allocated for approved regional and subregional projects. The
costs of an approved regional project are allocated so that 50 percent of thetotal costs are allocated on a system wide load ratio share basis and theremaining 50 percent of the total costs are allocated to zones with projected

656

Section 12 Planningenergy market benefits and reliability pricing model benefits in proportion
to those projected positive benefits. The costs of an approved subregional
project are allocated so that the total costs of the project is allocated to zones
with projected energy market benefits and reliability pricing model benefits inproportion to those projected positive benefits.
There are significant issues with PJM’s benefit/cost analysis. The current rules
governing benefit/cost analysis of competing transmission projects do notaccurately measure the relative costs and benefits of transmission projects.
The current rules do not account for the fact that the benefits of projects
are uncertain and highly sensitive to the modeling assumptions used. The
current rules explicitly ignore the increased zonal load costs that a project
may create. The current rules do not account for the fact that the project costs
are nonbinding estimates, are not subject to cost caps and may significantly
exceed the estimated costs. These flaws have contributed to PJM approving
market efficiency projects with forecasted benefits that do not exceed theforecasted costs.
The recent introduction of storage as transmission assets (SATA) raises a numberof additional concerns about PJM’s benefit/cost analysis. PJM’s benefit/cost
analysis uses a 15 year forecast for purposes of evaluating benefits and costsof traditional transmission assets with an expected useful life of 50 years or
more. Using the same 15 year horizon does not make sense for SATA resources
with an expected useful life of 10 years or less, depending on use. Using a
15 year benefit horizon will exaggerate the forecasted benefit stream relative
to the stream of benefits that could be produced over the expected usefullife relative to traditional transmission assets. Further, the rules for how toaccount for the actual, and forecasted, revenues and charges for operating the
SATA to provide transmission load relief have not been established. Without
clear rules on how to allocate operational revenues and costs it is impossible
to develop forecasted benefits and/or costs of a SATA project.
The broader issue is that the market efficiency project approach explicitly
allows transmission projects to compete against future generation projects, but
without allowing the generation projects to compete. Projecting speculative© 2021 Monitoring Analytics, LLC

Section 12 Planningtransmission related benefits for 15 years based on the existing generation
fleet and existing patterns of congestion eliminates the potential for new
generation to respond to market signals. The market efficiency process
allows assets built under the cost of service regulatory paradigm to displace
generation assets built under the competitive market paradigm. The MMU
recommends that the market efficiency process be eliminated.

The Transource Project
The Transource Project (Project 9A) is an example of a PJM approved market
efficiency project that passed PJM’s 1.25 benefit/cost threshold test despite
having benefits, if accurately calculated, that were less than forecasted costs.
This project also illustrates the risks of ignoring potential cost increases
given that the costs included in the benefit/cost calculation are nonbinding
estimates. The Transource Project was proposed in PJM’s 2014/2015 RTEP
long term window. PJM’s 2014/2015 RTEP long term window was the firstmarket efficiency cycle under Order 1000. The 2014/2015 long term window
was open from November 1, 2014, through February 28, 2015. This window
accepted proposals to address historical congestion on 12 identified flowgates.
The AP South Interface was one of the 12 identified flow gates listed in the
2014/15 RTEP Long Term Proposal Window Problem Statement.
A total of 41 market efficiency projects were proposed to address congestion
on the AP South Transmission Interface. Transource Energy LLC, together with
Dominion High Voltage, submitted a proposal referenced by PJM as Project
9A (or IEC or the Transource project) to address AP South related congestion.
Project 9A was considered a subregional project based on its voltage level,
meaning that changes in forecasted system costs were not considered for
purposes of estimating the benefit/cost ratios. Instead, only reductions inzonal load costs were considered as a benefit of the project. Any increases inzonal load costs were ignored in the analysis.
The initial study had a benefit to cost ratio of 2.48, with a capital cost of$340.6 million. The sum of the positive (energy cost reductions) effects
was $1,188.07 million. The sum of negative effects (energy cost increases)© 2021 Monitoring Analytics, LLC

was $851.67 million. The net actual benefit of the project in the study was
therefore $336.40 million, not the $1,188.07 used in the study. Using the total
benefits (positive and negative) to compare to the net present value of costs,
the benefit to cost ratio was 0.70, not 2.48. The project should have been
rejected on those grounds.
Subsequent studies of the 9A project have reduced its benefit/cost ratio asa result of increased costs, decreased congestion on the AP South Interface
since 2014 and a reduction in peak load forecasts since 2015. The most recent
study produced by PJM in 2019 using simulations for years 2017, 2021, 2024
and 2027 had a benefit cost ratio of 2.10 with a capital cost of $383.63
million. The sum of the positive (energy cost reductions) effects was $855.19
million, a reduction of $322 million (28.0 percent) from the initial study.
The sum of negative effects (energy cost increases) was $827.34 million, areduction of $27.86 million (3.3 percent) from the results of the initial study.
The net actual benefit of the project in the 2019 study was $27.85 million,
not the $1,188.07 from the initial study. Using the total benefits (positive andnegative) to compare to the net present value of costs in the 2019 analysis, thebenefit to cost ratio was 0.07, not 2.10. The project should have been rejectedon those grounds.

PJM MISO Interregional Market Efficiency Process(IMEP)
PJM and MISO developed a process to facilitate the construction ofinterregional projects in response to the Commission’s concerns about
interregional coordination along the PJM-MISO seam. This process, called theInterregional Market Efficiency Process (IMEP), operates on a two year studyschedule and is designed to address forward looking congestion. To qualify
as an IMEP project, the project must be evaluated in a joint study process,qualify as an economic transmission enhancement in both PJM and MISO
transmission expansion models and meet specific IMEP cost benefit criteria.42
The allocation of costs to each RTO for IMEPs will be in proportion to thebenefits received.
42 See “Joint Operating Agreement Between the Midwest Independent Transmission System Operator, Inc. and PJM Interconnection, L.L.C.,”(December 11, 2008) <http://www.pjm.com/directory/merged-tariffs/miso-joa.pdf>.

2021 Quarterly State of the Market Report for PJM: January through June 657

2021 Quarterly State of the Market Report for PJM: January through June

While the IMEP process is a joint effort, PJM and MISO perform their own
analysis of benefits to their own system and each uses a different modelingapproach and a different metric for determining the benefits of a proposed
project. PJM makes use of the benefit/cost analysis used for its own internalmarket efficiency projects which will, by definition, overstate project benefits
by ignoring areas where energy costs are increased. MISO, on the other hand,measures benefits as changes in projected system wide production cost causedby the project. The use of different approaches to measuring benefits is an
issue when studying potential benefits of projects in a joint effort, and whenusing the defined benefits to allocate the costs of IMEP projects to each RTO.
PJM’s approach will over allocate the costs of IMEP projects to PJM members.
PJM and MISO conducted a two year interregional market efficiency project
study in 2018/2019 and included the investigation of forward looking
congestion on three market to market flowgates. Proposals were received
during the 2018/2019 long term window, which was open from November
2, 2018, through March 15, 2019. PJM and MISO received 10 proposals fromseven entities. As a result of this analysis, the RTOs recommended one IMEP
project, the Bosserman to Trail Creek 138 kV Project.43 The approved project
has an in service cost of $24.7 million, and counting only PJM positive zonal
benefits, a total present value of projected benefits of $69.2 million. Ignoring
PJM zones with negative benefits (increased costs to load) the project hasa calculated PJM benefit/cost ratio of 2.63. MISO, using both positive andnegative zonal effects, calculated the projected benefits of the project to be$8.4 million. Based on the proportion of the calculated benefits, PJM is tobe allocated 89.1 percent ($23.4 million) of the project costs and MISO is tobe allocated 10.9 percent ($2.9 million) of the interregional costs. The PJM
board approved the recommended project in December 2019. The MISO board
approved the recommended project in September 2020.
Using a rational measure of benefits and costs, the Bosserman to Trail Creek
138 kV Project should not have been approved. Including the projected
positive and negative benefits of the project to all PJM zones, the projected
total benefits of the project drops from $69.2 million to -$68.1 million dollars.
43 Analysis showed that no projects met the B/C criteria on two of the identified flowgates.

658

Section 12 Planning

PJM analysis shows benefits to only one zone of $69.2 million, with thenegative effect on all other zones of -$137.3 million. The resulting benefit/
cost ratio would be -2.59. Even including the net MISO benefit of $8.4 million,
the total projected benefit of the project would still be a -$59.7 million dollars.
Allocating the costs of the project based on the proportion of total regional
benefit (-$68.1 million to PJM and $8.4 million to MISO) would have allocated100 percent of the cost to MISO, resulting in a benefit/cost ratio of 0.32 to
MISO, and a rejection of the project by MISO.
PJM and MISO are currently in the second year of the two year 2020/2021
IMEP cycle. The RTOs are currently coordinating the development of theirregional models.

PJM MISO Targeted Market Efficiency Process (TMEP)PJM and MISO developed the Targeted Market Efficiency Process (TMEP) to
facilitate the resolution of historic congestion issues that could be addressed
through small, quick implementation projects. The TMEP process operates on
a 12 month study schedule. To qualify as a TMEP project, the project musthave an estimated in service date by the third summer peak season from theyear the project was approved, have an estimated cost of less than $20 million
and must have estimated benefits, based on the projected congestion costrelief over a four year period, that exceed the expected installed capacity costof the proposed project.44 45
The benefit of a proposed TMEP project is calculated as the value of eliminatingcongestion on the affected constraint over a four year period. PJM and MISO
calculate the estimated value of eliminating congestion by calculating the
average congestion for the two prior years prior and multiplying by four.
The allocation of costs to each RTO for an approved TMEP project will be inproportion to the benefits received by that RTO.46 The proportion of benefits is
calculated using the average shadow price of the constraint times the dfax to
44 See “Joint Operating Agreement Between the Midwest Independent Transmission System Operator, Inc. and PJM Interconnection, L.L.C.,”(December 11, 2008) <http://www.pjm.com/directory/merged-tariffs/miso-joa.pdf>.
45 On November 2, 2017, PJM submitted a compliance filing including additional revisions to the MISO-PJM JOA to include stakeholder
feedback in the TMEP project selection process. See PJM Interconnection, L.L.C, Docket No. ER17-718-000, et al. (November 2, 2017).
46 See PJM Interconnection, L.L.C, Docket No. ER17-729-000 (December 30, 2016).

© 2021 Monitoring Analytics, LLC

Section 12 Planningaffected downstream buses times MW of load at the buses, which is effectively
the proportion of congestion paid by the RTO. Within an RTO, the RTO’s shareof the cost of the approved project is allocated to each transmission control
area in proportion to the benefits received by each transmission control area.
The first Targeted Market Efficiency Process (TMEP) analysis occurred in 2017and included the investigation of historical congestion on an initial set of
50 market to market flowgates. The causes of congestion on these flowgateswere analyzed. If the historical congestion was a result of outages, or if
the congestion was expected to be mitigated by planned upgrades alreadyincluded in the PJM RTEP or MISO MTEP, then the flowgate was eliminatedfrom consideration in the TMEP process. As a result of this analysis, potential
short term upgrades were identified for 13 of the initial 50 flowgates. PJM andMISO conducted a market efficiency and power flow analysis to determine
the potential to eliminate the identified congestion on the 13 flowgates andrecommended five TMEP projects. The five projects address $59.0 million inhistorical congestion, with a calculated TMEP benefit of $99.6 million. The
projects have a total cost of $20.0 million, with a 5.0 average benefit/cost
ratio. PJM and MISO presented the five recommended projects to their boards
in December 2017, and both boards approved all five projects.47
The second Targeted Market Efficiency Process analysis occurred in 2018
and included the investigation of historical congestion on an initial set of
61 market to market flowgates. As a result of this analysis, potential shortterm upgrades were identified for 20 of the initial 61 flowgates. PJM andMISO conducted a market efficiency and power flow analysis to determine
the potential to eliminate the identified congestion on the 20 flowgates andrecommended two TMEP projects. The two projects address $25.0 million inhistorical congestion, with a calculated TMEP benefit of $31.9 million. The
projects have a total cost of $4.5 million, with a 7.1 average benefit/cost ratio.
PJM and MISO presented the two recommended projects to their boards inDecember 2018, and both boards approved the projects.48
47 See PJM. “MISO PJM IPSAC,” (January 12, 2018) <http://www.pjm.com/-/media/committees-groups/‌stakeholder-meetings/
ipsac/20180112/20180112-ipsac-presentation.ashx>.
48 See PJM. “MISO PJM IPSAC,” (January 18, 2019) <https://www.pjm.com/-/media/committees-groups/‌stakeholder-meetings/
ipsac/20190118/20190118-ipsac-presentation.ashx>.

© 2021 Monitoring Analytics, LLC

With only one additional year of historical information, and the fact thatmany of the same constraints were evaluated in the 2018 TMEP process, PJM
and MISO did not conduct a TMEP study in 2019.
As a result of decreases in M2M congestion and the addition of transmission
upgrades already in process that affect the top congested historical M2M
flowgates, PJM and MISO did not conduct a TMEP study in 2020.
The PJM and MISO TMEP process for measuring the projected benefits ofa TMEP transmission projects is flawed. The current rules incorrectly countcongestion as a cost to load without accounting for how the congestion dollars
are or are not returned to the load through the ARRs and FTRs. The benefit of a
TMEP transmission upgrade should be the expected difference in the total costof energy before and after the upgrade to all affected load. This measurement
would include the change in expected LMP of all affected load before andafter the upgrade, times the MW of load, plus the change in congestion dollars
returned to the affected load before and after the upgrade. Congestion revenue
returned to load is not a cost to the load, it is a credit against the overpaymentof load payments relative to generation credits caused by the transmission
constraint. Ignoring the return of congestion from ARRs/FTRs overstates thepotential benefits of eliminating congestion through the TMEP upgrades, andignores the value of smaller upgrades that may not eliminate a constraint, but
may reduce the average cost of energy for load.

Supplemental Transmission Projects
Supplemental projects are asserted to be “transmission expansions or
enhancements that are not required for compliance with PJM criteria and are
not state public policy projects according to the PJM Operating Agreement.
These projects are used as inputs to RTEP models, but are not required forreliability, economic efficiency or operational performance criteria, as
determined by PJM.”49 Attachment M-3 of the PJM OATT defines the processthat Transmission Owners (TO) must follow in adding Supplemental Projects
in their local plan.
49 See PJM. Planning. “Transmission Construction Status,” (Accessed on June 30, 2021) <http://www.‌pjm.com/planning/rtep-upgradesstatus/construct-status.aspx>.

2021 Quarterly State of the Market Report for PJM: January through June 659

2021 Quarterly State of the Market Report for PJM: January through June

While the identification of the criteria violations and solutions are reviewed, andstakeholders have the opportunity to comment, the solution that is submitted
in the Local Plan is the Transmission Owner’s decision. PJM conducts a do noharm analysis to ensure the Supplemental Projects do not negatively affectthe reliability of the system. Supplemental Projects are ultimately included in
PJM’s Regional Transmission Expansion Plan and are allocated 100 percent
to the zone in which the transmission facilities are located. Supplemental
Projects may displace projects that would have otherwise been implemented
through the RTEP process.
Supplemental projects are currently exempt from the Order No. 1000
competitive process.50 Transmission owners have a clear incentive to increase
investments in rate base given that transmission owners are paid for theseprojects on a cost of service basis.
Figure 12-5 shows the latest cost estimate of all baseline and supplemental
projects by expected in service year. FERC Order No. 890 was issued on
February 16, 2007, and implemented in PJM starting in 2008. Order No.
890 required Transmission Providers to participate in a coordinated, open
and transparent planning process. Prior to the implementation of Order No.
890, there were transmission projects planned by transmission owners andincluded in the PJM planning models, that were not included in the totals
shown in Figure 12-5, Table 12-48 and Table 12-49 because PJM did not trackor report such projects. There has been a significant increase in supplemental
projects coincident with the implementation of Order No. 890 starting in 2008
and the competitive planning process introduced by FERC Order No. 1000
starting in 2011.

Figure 12-5 Cost estimate of baseline and supplemental projects by expected
in service year: January 1, 1998 through June 30, 2021
$5,000$4,500$4,000Latest Cost Estimate - Supplemental Projects
Latest Cost Estimate - Baseline Projects$3,500Latest Cost Estimate ($ Million)

The M-3 Process requires TOs to present the criteria, assumptions and models
that they will use to plan and identify Supplemental Projects on a yearly basis.
The criteria identified for Supplemental Projects are very broad and include:
equipment material condition, performance and risk, operational flexibility
and efficiency, infrastructure resilience, customer service or other, as well as
asset management.

$3,000$2,500$2,000$1,500$1,000$500$0In Service Year

Table 12-48 shows the number of supplemental projects by expected inservice year for each transmission zone. The average number of supplemental
projects in each expected in service year increased by 785.0 percent, from
20 for years 1998 through 2007 (pre Order No. 890) to 177 for years 2008
through 2021 (post Order No. 890).

50 FERC accepted tariff provisions that exclude supplemental projects from competition in the RTEP. 162 FERC ¶ 61,129 (2018), reh’gdenied, 164 FERC ¶ 61,217 (2018).

660

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-48 Number of supplemental projects by expected in service year and zone: 1998 through 2040
Year
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
Total

ACEC
0
0
0
0
0
3
5
4
4
1
3
3
0
0
0
5
2
4
6
8
10
3
5
4
2
5
4
3
5
1
0
0
0
0
0
0
0
0
0
0
0
0
0
90

AEP
0
0
0
0
0
0
0
2
2
1
0
1
6
8
5
21
31
15
17
107
143
159
123
194
215
215
122
87
19
26
11
0
0
0
0
0
0
0
0
0
0
0
0
1,530

APS
0
0
0
0
0
0
10
8
5
5
15
6
7
8
6
4
2
2
4
3
3
4
4
3
6
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
106

© 2021 Monitoring Analytics, LLC

ATSI
0
0
0
0
0
0
0
0
0
0
0
0
0
0
4
5
8
9
17
26
13
30
33
37
43
12
8
6
0
3
0
0
0
1
0
0
0
0
0
0
0
0
0
255

BGE COMED
0
0
0
0
0
0
0
0
0
0
0
0
0
9
0
4
0
6
4
5
1
6
1
8
3
4
0
2
1
2
0
11
2
14
1
37
0
26
1
23
1
20
5
14
6
12
4
5
2
8
0
2
0
4
3
0
8
1
1
0
0
0
4
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
48
223

DAY
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
5
9
5
14
5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
40

DUKE
0
0
0
0
0
0
0
0
0
0
0
0
0
0
7
6
5
8
6
3
14
17
12
15
5
7
2
0
1
2
1
0
0
0
0
0
0
0
0
0
0
0
0
111

DUQ
0
0
0
0
0
0
0
0
0
4
1
3
6
5
3
4
6
4
2
8
3
1
2
1
1
1
0
0
0
2
1
0
0
0
0
0
0
0
0
0
0
0
0
58

DOM
0
0
0
0
0
0
0
1
0
0
7
3
3
2
16
13
18
17
13
31
22
33
27
26
17
11
3
20
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
283

DPL
3
2
11
14
10
10
12
14
9
6
3
5
0
0
1
1
3
5
4
11
6
8
2
1
4
6
2
6
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
159

EKPC
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
4
2
5
4
5
6
8
5
4
3
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
49

JCPLC
0
0
0
0
0
0
2
1
1
0
0
0
1
1
2
1
2
2
0
0
0
3
10
12
14
1
5
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
59

MEC
0
0
0
0
0
0
0
0
0
0
1
0
2
0
0
1
0
0
1
3
0
14
18
46
45
14
20
22
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
187

NEET
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1

OVEC
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5

PECO
0
0
0
0
0
0
0
1
0
0
0
5
2
4
1
1
1
1
3
0
2
1
2
6
4
3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
37

PE
0
0
0
0
0
2
0
2
1
2
0
1
0
0
0
0
2
0
2
3
0
15
34
29
50
33
18
18
0
1
0
0
0
0
0
0
1
0
0
0
0
0
0
214

PEPCO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
4
3
1
1
0
1
0
0
3
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
16

PPL
0
0
0
0
0
0
0
0
2
1
3
1
3
6
5
14
9
7
11
22
20
15
16
22
30
17
13
6
14
26
2
2
1
0
0
0
0
0
0
0
0
0
0
268

PSEG
0
0
0
0
0
0
2
2
1
6
1
2
5
4
11
19
16
24
30
43
26
27
22
20
27
26
8
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
332

REC
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0

Total
3
2
11
14
10
15
40
39
31
35
41
39
42
40
64
107
123
144
147
298
288
356
340
447
483
375
219
182
49
62
16
6
1
1
0
0
1
0
0
0
0
0
0
4,071

2021 Quarterly State of the Market Report for PJM: January through June 661

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-49 shows the latest cost estimate of supplemental projects by expected in service year for each transmission zone. The average cost of supplemental
projects in each expected in service year increased by 2,240.8 percent, from $65.0 million for years 1998 through 2007 (pre Order No. 890) to $1,521.5 million
for years 2008 through 2021 (post Order No. 890).
Table 12-49 Latest cost estimate by expected in service year and zone ($ millions): 1998 through 2040
Year
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
Total

662

ACEC
AEP
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$7.42
$0.00
$4.45
$0.00
$4.06
$14.67$4.03$309.70
$0.56
$2.06
$2.36
$0.00
$0.77
$0.90
$0.00
$34.36$0.00$37.60$0.00$46.00$3.15$134.93$8.03$387.00$3.73$237.45$74.54$84.13$66.28$648.74$66.55$817.94$64.30 $1,162.53$59.58$894.93$86.54 $1,430.13$107.70 $1,449.84$88.40 $1,735.27$52.31 $1,099.51$42.89$607.11$95.50$201.10$17.13$377.53$0.00$177.60
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$860.28 $11,891.03

APS
ATSI
BGE COMED
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$10.00
$0.00
$0.00
$0.82
$10.12
$0.00
$0.00
$2.57
$0.94
$0.00
$0.00
$48.93$9.85$0.00$37.61$4.65$12.03
$0.00
$0.45
$7.61
$12.22$0.00$5.00$21.11$12.13$0.00$18.90
$1.38
$9.30
$0.00
$0.00
$1.00
$5.12
$0.35
$2.20
$12.60$1.10$33.68$0.00$59.25$5.97$58.70$21.20$60.37$3.80$21.90$2.00 $376.00$18.40 $182.70$0.00 $308.15$8.60 $164.45$0.09 $145.97$14.60$42.12$4.08$80.94$11.97 $190.40$76.55$90.19$0.30 $112.78$62.58$78.09$2.70 $235.28$25.40 $139.90$7.48 $280.84 $265.40 $101.00$0.00 $141.06$0.00$21.00$0.00 $107.50$0.00 $212.40$60.00 $199.70 $144.10
$0.00
$0.00
$0.00 $336.00$67.00$0.00 $389.30 $118.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00 $231.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$80.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$216.63 $2,240.76 $1,350.56 $1,840.93

Section 12 Planning

DAY
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.30
$13.66$34.90$23.05$54.15$61.60
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$187.66

DUKE
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$26.06$9.93$2.43$14.12$15.13$64.31$69.80$98.77$70.66$164.81$47.30$54.92$17.64$0.00$4.70$32.57$17.90
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$711.05

DUQ
DOM
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.02
$0.00
$0.00
$31.75$0.00$7.00$14.01$19.60$2.12$34.45$14.98$16.72$85.67$11.60 $165.74$79.10$25.03$14.90$88.61$4.53 $113.53$26.95$40.68$3.62 $104.25$3.13 $162.94$0.30$90.14$7.20 $256.78$18.10$61.37$45.00 $212.68$0.00$72.90$0.00$44.57$0.00 $267.77
$0.00
$0.00
$160.00$0.00$30.40
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$514.35 $1,823.79

DPL
$1.67
$0.77
$32.94
$6.79
$7.00
$8.77
$7.33
$10.99$11.62
$9.72
$2.27
$7.36
$0.00
$0.00
$0.99
$0.99
$5.96
$13.06$26.60$92.29$68.94$33.55$39.50$0.20$46.00$58.90$34.80$71.83
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$600.84

EKPC
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.38
$1.56
$0.25
$2.21
$10.87$23.67$25.61$29.40$11.18$29.59$30.55
$0.00
$0.00
$0.00
$22.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$187.27

JCPLC
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$6.00
$0.00
$0.00
$0.00
$0.03
$1.16
$6.61
$0.05
$5.60
$0.30
$0.00
$0.00
$0.00
$0.90
$2.60
$39.00$48.50$6.80$38.50$0.00$16.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$172.05

MEC
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$4.58
$0.00
$0.00
$4.10
$0.00
$0.00
$2.37
$14.70$0.00$62.30$23.70$186.40$113.66$80.80$147.90$134.70
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$775.21

NEET
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$51.90
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$51.90

OVEC
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$4.40
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$4.40

PECO
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.50
$0.00
$0.00
$0.00
$48.10$31.80$113.30$12.60$22.50$13.30$33.80$86.40$0.00$47.60$2.00$1.60$36.10$89.30$201.80
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$740.70

PE
PEPCO
PPL
PSEG
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$9.60
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$1.50
$0.00
$4.63
$18.80
$0.00
$0.00
$0.34
$2.28
$0.00
$0.00
$1.60
$0.00
$2.73
$0.00
$0.16
$17.60
$0.00
$0.00
$1.86
$17.72$0.00$0.00$11.87$34.60$0.00$0.00$19.66 $223.01
$0.00
$2.40
$76.70 $503.72
$1.30
$0.00
$33.47 $309.71$0.00$42.50$50.17 $743.91
$0.40
$7.80
$58.76 $744.18$8.30$12.00 $264.34 $988.92$0.00 $156.00 $197.34 $631.25$75.80$0.00 $298.00 $356.41$74.50 $102.70 $211.79 $1,861.58$90.79$0.00 $216.03 $483.14$151.50$0.00 $380.05 $774.85$40.70 $737.50 $262.84 $787.30$44.50$38.50 $237.10 $265.95$46.60$0.00 $127.00 $186.50$0.00$0.00 $387.05$0.00$138.00$0.00 $582.41
$0.00
$0.00
$0.00
$51.00
$0.00
$0.00
$0.00
$96.60
$0.00
$0.00
$0.00
$91.90
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$200.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$886.22 $1,099.40 $3,662.67 $8,951.43

REC
Total
$0.00
$1.67
$0.00
$0.77
$0.00
$32.94
$0.00
$6.79
$0.00
$7.00
$0.00
$25.79$0.00$22.60$0.00$42.93$0.00$406.15$0.00$98.82$0.00$47.33$0.00$137.67$0.00$172.19$0.00$311.22$0.00$532.54$0.00$956.63$0.00 $1,016.93$0.00 $1,662.36$0.00 $1,677.44$0.00 $2,589.07$0.00 $2,374.10$0.00 $2,638.08$0.00 $3,900.14$0.00 $3,284.59$0.00 $4,155.33$0.00 $4,425.83$0.00 $2,433.33$0.00 $1,888.20$0.00 $1,107.35$0.00 $1,814.94$0.00$298.90$0.00$327.60$0.00$91.90$0.00$80.00
$0.00
$0.00
$0.00
$0.00
$0.00
$200.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00 $38,769.13© 2021 Monitoring Analytics, LLC

Section 12 Planning

The MMU recommends, to increase the role of competition, that the exemptionof supplemental from the Order No. 1000 competitive process be terminated.

End of Life Transmission Projects
An end of life transmission project is a project submitted for the purposeof replacing existing infrastructure that is at, or is approaching, the end ofits useful life. Under the current process, end of life transmission projects
are not subject to the RTEP open window process and have become a formof supplemental project that is exempt from competition under the existing
rules.51

local Transmission Owner is the Designated Entity.54 Some supplemental
projects are in this category.

• Substation Equipment. Due to identification of the limiting element(s) as

substation equipment, such projects are excluded from competition. As
a result, the local Transmission Owner is the Designated Entity.55 Some
supplemental projects are in this category.

Competitive Planning Process Exclusions

While the PJM Operating Agreement defines who will be the DesignatedEntity for projects that are excluded from the competitive planning process,neither the PJM Operating Agreement nor the various commission orders ontransmission competition prohibit PJM from permitting competition to provide
financing for such projects. The MMU recommends that rules be implemented
to permit competition to provide financing for transmission projects. This
competition could reduce the cost of capital for transmission projects andsignificantly reduce total costs to customers. In addition, the criteria for andneed for all exclusions from the competitive process should be reviewed. There
does not appear to be any market reason to exclude transmission projects
from competition for any of these exclusion categories.

There are several project types that are currently exempt from the competitiveplanning process. These project types include:

Comparative Cost Framework

The MMU recommends, to increase the role of competition, that the exemptionof end of life projects from the Order No. 1000 competitive process beterminated and that end of life transmission projects be included in the RTEP
process and should be subject to a transparent, robust and clearly definedmechanism to permit competition to build such projects.

• Immediate Need Exclusion. Due to the immediate need of the violation(3 years or less), the timing required for an RTEP proposal window isdefined to be infeasible and such projects are excluded from competition.
As a result, the local Transmission Owner is the Designated Entity.52 On
October 17, 2019, the Commission issued an Order Instituting Section 206
Proceedings to determine if RTOs have implemented the exemption in amanner consistent with the Commission’s directives under Order 1000.53
Some supplemental projects are in this category.

• Below 200kV. Due to the lower voltage level of the identified violation(s),the driver(s) for this project are excluded from competition. As a result, the51 In recent decisions addressing competing proposals on end of life projects, the Commission accepted a transmission owner proposal
excluding end of life projects from competition in the RTEP process, 172 FERC ¶ 61,136 (2020), reh’g denied, 173 FERC ¶ 61,225 (2020),
and rejected a proposal from PJM stakeholders that would have included end of life projects in competition in the RTEP process, 173
FERC ¶ 61,242 (2020).
52 See OA Schedule 6 § 1.5.8(m).
53 169 FERC ¶ 61,054 (2019).

© 2021 Monitoring Analytics, LLC

The MMU recommended that rules be implemented to require that project
cost caps on new transmission projects be part of the evaluation of competing
projects. On May 24, 2018, the PJM Markets and Reliability Committee (MRC)
approved a motion that required PJM, with input from the MMU, to develop
a comparative cost framework to evaluate the quality and effectiveness ofbinding cost containment proposals versus proposals without cost containment
provisions. On March 20, 2020, the Commission approved PJM’s filing toamend the PJM Operating Agreement to incorporate this requirement.56
The 2020 RTEP Window 1 was the first open window that received cost
capping proposals to be evaluated under the comparative cost framework. The
analysis performed under the new process was insufficient and did not follow
54 See OA Schedule 6 § 1.5.8(n).
55 See OA Schedule 6 § 1.5.8(p).
56 170 FERC ¶ 61,243 (2020).

2021 Quarterly State of the Market Report for PJM: January through June 663

2021 Quarterly State of the Market Report for PJM: January through June

the process defined in the PJM manual.57 The existing proposal templates do
not provide enough information to adequately perform a financial analysis.
The MMU recommends that PJM modify the project proposal templates toinclude data necessary to perform a detailed project lifetime financial analysis.
The required data includes, but is not limited to: capital expenditure; capital
structure; return on equity; cost of debt; tax assumptions; ongoing capital
expenditures; ongoing maintenance; and expected life.

Middle Creek energy storage project did not perform a transmission function,
and was ineligible to recover its costs through formula rates.60

Storage As A Transmission Asset (SATA)

The Transmission Expansion Advisory Committee (TEAC) regularly reviews
internal and external proposals to improve transmission reliability throughout
PJM. These proposals, which include reliability baseline, network, market
efficiency and targeted market efficiency projects, as well as scope changes
and project cancellations, but exclude supplemental and end of life projects,
are periodically presented to the PJM Board of Managers for authorization.61

The PJM Planning Committee is currently considering whether storage devices
should be included in the RTEP process as transmission assets.58
Transmission and generation have, and have always had, a symbiotic
relationship in the provision of wholesale power. Transmission needs
generation to function and generation needs transmission to function.
Transmission can substitute for generation at the margin and generation can
substitute for transmission at the margin. This relationship has always beena relatively unexamined area in the design of competitive wholesale power
markets. For example, there is little if any explicit consideration of the impactof transmission planning on competitive generation investment in RTO/ISO
market rules. Improvement is needed in these areas. Introducing confusion
about what assets are classified as generation and what assets are classified
as transmission frustrates potential reform and undermines the competitivemarkets.
On July 22, 2020, through the supplemental planning process, American
Electric Power Service Corporation (AEP) filed, on behalf of Kentucky
Power Company (Kentucky Power), a Petition for Declaratory Order seeking
confirmation that its Middle Creek energy storage project is eligible for costof-service recovery through AEP’s formula rates.59 AEP’s Middle Creek energy
storage project was a proposed battery storage device that would dischargeenergy to serve retail load at the Middle Creek substation in the event of atransmission outage. On December 21, 2020, the Commission ruled that the
57 See PJM. “PJM Manual 14F: Competitive Planning Process,” Rev. 6 (June 23, 2021).
58 See PJM. “Storage As A Transmission Asset: Problem / Opportunity Statement,” <https://pjm.com/-/media/committees-groups/
committees/pc/2020/20200605-special/20200605-item-02a-storage-as-a-transmission-asset-problem-statement-clean.ashx>.
59 See AEP, Docket No. EL20-58 (July 22, 2020).

664

Section 12 Planning

Storage devices like batteries that are defined to be part of PJM markets should
not be treated as transmission assets. The MMU recommends that storage
resources not be includable as transmission assets for any reason.

Board Authorized Transmission Upgrades

An RTEP project can be approved by the PJM Board if the project ensurescompliance with NERC, regional and local transmission owner planning
criteria or to address market efficiency congestion relief. These projects are
considered Baseline Projects. PJM Board approved RTEP projects that arenecessary to allow new generation to interconnect reliably are considered
Network Projects.
In the first six months of 2021, the PJM Board approved a net change of$680.6 million in transmission upgrades. As of June 30, 2021, the PJM Board
had approved $38.5 billion in transmission system enhancements since1999. On February 22, 2021, the PJM Board authorized an additional $349.8
million in transmission upgrades and additions. On April 23, 2021, the PJM
Board authorized an additional $330.7 million in transmission upgrades andadditions.

Qualifying Transmission Upgrades (QTU)
A Qualifying Transmission Upgrade (QTU) is an upgrade to the transmission
system that increases the Capacity Emergency Transfer Limit (CETL) into an
LDA and can be offered into capacity auctions as capacity. Once a QTU is in
60 173 FERC ¶ 61,264 (2020).
61 Supplemental Projects, including the end of life subset of supplemental projects, do not require PJM Board of Managers authorization.

© 2021 Monitoring Analytics, LLC

Section 12 Planning

service, the upgrade is eligible to continue to offer the approved incremental
import capability into future RPM Auctions.

regional cost allocation, including the 0.01 distribution cutoff factor, is justand reasonable.

If a QTU that was cleared in a Base Residual Auction (BRA) or Incremental
Auction (IA) is not completed by the start of the Delivery Year, the submitting
party is required to provide replacement capacity. Once a QTU is in service,
the upgrade is eligible to continue to offer the approved incremental import
capability into future RPM Auctions. As of June 30, 2021, no QTUs havecleared a BRA or IA.

It is clear that the allocation issues are difficult. Nonetheless, the allocation
methods affect the efficiency of the markets and the incentives for merchanttransmission owners to compete to build new transmission. The MMU
recommends a comprehensive review of the ways in which the solution based
dfax is implemented. The goal for such a process would be to ensure that themost rational and efficient approach to implementing the solution based dfax
method is used in PJM. Such an approach should allocate costs consistent
with benefits and appropriately calibrate the incentives for investment in newtransmission capability. No replacement approach should be approved until
all potential alternatives, including the status quo, are thoroughly reviewed.

Cost Allocation
In response to complaints against PJM RTEP Baseline Upgrade Filings in2014 that included cost allocations for $1.5 billion in baseline transmission
enhancements and expansions, on November 24, 2015, FERC issued an orderdirecting investigation of “whether there is a definable category of reliability
projects within PJM for which the solution-based DFAX cost allocation
method may not be just and reasonable, such as projects addressing reliability
violations that are not related to flow on the planned transmission facility,
and whether an alternative just and reasonable ex ante cost allocation method
could be established for any such category of projects.”62 FERC convened
a technical conference on January 12, 2016, to address the complaints in
multiple proceedings and to address these two core issues.63
The issues identified in the complaints and at the technical conference included:
whether the solutions based allocation method is appropriate for upgrades not
related to transmission overload issues; whether the solutions based allocation
method correctly identifies all the beneficiaries of the upgrades; whether it isreasonable to allocate a level of costs to a merchant transmission project that
could force bankruptcy; and whether the significant shifts in allocation that
result from use of the 0.01 distribution factor cutoff are appropriate.
On February 20, 2020, the Commission issued an Order denying rehearing
requests.64 The Commission found that PJM’s solution based dfax method for
62 153 FERC ¶ 61,245 at P 35 (2015).
63 See Docket Nos. EL15-18-000 (ConEd), EL15-67-000 (Linden), and EL15-95-000 (Artificial Island).
64 170 FERC ¶ 61,122 (2020).

© 2021 Monitoring Analytics, LLC

As an example, the use of the arbitrary 0.01 distribution factor cutoff canresult in large and inappropriate shifts in cost allocation. If the intent of theuse of the 0.01 cutoff is to help eliminate small, arbitrary cost allocations togeographically distant areas, this could be achieved by adding a threshold fora minimum usage impact on the line. The MMU recommends considerationof changing the minimum distribution factor in the allocation from 0.01 to
0.00 and adding a threshold minimum impact on the load on the line basedon a complete analysis of the intent of the allocation and the impacts of theallocation.

Transmission Line Ratings
Transmission line ratings, and more broadly transmission facility ratings, arethe metric for the ability of transmission lines to transmit power from one
point to another. Transmission line ratings have significant and frequently
underappreciated impacts on competitive wholesale power markets like PJM.
These include direct impacts on energy and capacity prices, the frequency
and level of congestion in the day-ahead and real-time energy market, dayahead nodal price differences and the associated value of FTRs, locational
price differences in the capacity market, the need to invest in additionaltransmission capacity, the need to invest in additional generation capacity,

2021 Quarterly State of the Market Report for PJM: January through June 665

2021 Quarterly State of the Market Report for PJM: January through June

the location of new power plants, and the interconnection costs for new power
plants. The impact of transmission facility ratings on markets is a function
both of the line ratings directly and the use of those ratings by the RTO/ISO.
Congestion payments by load result when lower cost generation is notavailable to meet all the load in an area as a result of limits on the transmission
system. When higher cost local generation is needed to meet part of the local
load because of transmission limits, 100 percent of the local load pays thehigher price while only the local generation receives the higher price. The
difference between what the load pays and generators receive is congestion.
Since 2008, congestion costs in PJM have ranged from $0.5 billion to $2.05
billion per year. Congestion costs were significantly higher during extreme
winter weather conditions such as January 2014, when the congestion costs
in PJM were $825.1 million for one month.65

limit and prices were set by transmission penalty factors. In 2019, the average
shadow price of transmission constraints when the line limit was violated wasnearly 15 times higher than when transmission constraint was binding at its
limit.67
Capacity market prices separate locally when transmission capability into
Locational Deliverable Areas (LDA) is not adequate to meet the LDA capacity
requirement with the lowest cost capacity. The available transmission capability
into LDAs is defined as the Capacity Emergency Transfer Limit (CETL). Higher
cost LDAs are the equivalent in the capacity market of congestion in theenergy market. Load in the higher cost LDAs pay more for capacity than thosein lower cost LDAs. For example, the clearing price for the BGE LDA in the2021/2022 Base Residual Auction was $200.30 per MW-day. The clearing
price for the EMAAC LDA was $165.73 per MW-day.68

LMP may, at times, be set by transmission penalty factors. When a transmission
constraint is binding and there are no generation alternatives to resolve theconstraint, system operators may allow the transmission limit to be violated.
When this occurs, the shadow price of the constraint is set by transmission
penalty factors. The shadow price directly affects the LMP. Transmission
penalty factors are administratively determined and can be thought of as aform of locational scarcity pricing. Transmission penalty factors were fully
implemented in PJM pricing effective February 1, 2019.

Transmission line ratings for a given transmission facility vary by the
duration of the power flow, by ambient temperatures, by wind speed andby other conditions. Transmission lines can operate with higher loads for
shorter periods of time. This is significant when a contingency is expectedto last for only a short period. The transmission line rating can mean the
difference between substantial congestion costs and no congestion costs.
The transmission line rating can mean the difference between a transmission
penalty factor and no penalty factor.

Transmission line ratings can result in short term, significant increases inprices as a result of the application of transmission penalty factors. For
example, violation of a transmission constraint, meaning that the flow exceeds
the line limit, could result in a $2,000 per MWh price. As the power flows
approach their rated limits, PJM dispatchers may reduce the limits.66 Violationof these reduced line ratings results in penalty factors setting prices. In 2019,
there were 152,675 transmission constraint intervals in the real-time market
with a non-zero shadow price. For nearly five percent of these transmission
constraints, the line limit was violated, meaning the flow exceeded the facility

In PJM, transmission owners use a range of ratings by duration.69 PJM
requires transmission owners to provide thermal ratings under normal
operating conditions, long term emergency operating conditions, short term
emergency operating conditions and the extreme load dump conditions. But
there is no requirement that the ratings differ for these operating conditions.
PJM typically uses normal line ratings for precontingency (base case)constraints and long term emergency line ratings (four hours) for contingency
constraints. PJM requires transmission owners to provide temperature basedline ratings separately for night and day times. The temperature ranges

65 See the 2018 State of the Market Report for PJM, Volume II, Section 11: Congestion and Marginal Losses.
66 See “Transmission Constraint Control Logic and Penalty Factors,” presented at May 10, 2018 meeting of the Markets Implementation
Committee Special Session Transmission Constraint Penalty Factors at p14. <https://www.pjm.com/-/media/committees-groups/
committees/mic/20180510-special/‌20180510-item-03-transmission-constraint-penalty-factor-education.ashx>.

67 See the 2019 State of the Market Report for PJM, Volume II, Section 3: Energy Market.
68 See the “Analysis of the 2021/2022 RPM Base Residual Auction,” <https://www.monitoringanalytics.com/reports/Reports/2018/IMM_
Analysis_of_the_20212022_RPM_BRA_Revised_20180824.pdf> (August 24, 2018).
69 See “PJM Manual 3: Transmission Operations,” Rev. 59 (May 27, 2021) § 2.1.1, at p 28.

666

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planningfrom 32 degree Fahrenheit or below to 95 degree Fahrenheit or above innine degree increments. But there is no requirement that the ratings differ
for these operating condition temperatures. In PJM, transmission owners are
responsible for developing their own methods to compute line ratings subject
to a range of NERC guidelines and requirements. PJM does not review orverify the accuracy of transmission owners’ methods to compute line ratings.
In PJM, transmission owners have substantial discretion in the approach toline ratings.70

The MMU recommends that PJM routinely review all transmission facility
ratings and any changes to those ratings to ensure that the normal, emergency
and load dump ratings used in modeling the transmission system are accurate
and reflect standard ratings practice.72 All line rating changes and the detailed
reasons for those changes should be public and fully transparent.

Given the significant impact of transmission line ratings on all aspectsof wholesale power markets, ensuring and improving the accuracy andtransparency of line ratings is essential. Line ratings should incorporate
ambient temperature conditions, wind speed and other relevant operating
conditions. PJM real-time prices are calculated every five minutes forthousands of nodes. PJM prices are extremely sensitive to transmission line
ratings. For consistency with the dynamic nature of wholesale power markets,line ratings should be updated in real time to reflect real time conditions andto help ensure that real-time prices are based on actual current line ratings.
The ongoing analysis of dynamic line ratings is a promising area that shouldbe pursued.

A transmission facility is designated as reportable by PJM if a change in its
status can affect a transmission constraint on any Monitored Transmission
Facility or could impede free flowing ties within the PJM RTO and/or adjacentareas.73 When a reportable transmission facility needs to be taken out ofservice, the transmission owner is required to submit an outage request as
early as possible.74 The specific timeline is shown in Table 12-51.75

The MMU recommends that all PJM transmission owners use the same
methods to define line ratings, subject to NERC standards and guidelines,
subject to review by NERC and approval by FERC. The same facilities
should have the same basic ratings under the same operating conditions
regardless of the transmission owner. Transmission owner discretion should
be minimized or eliminated. The line rating methods should be based on thebasic engineering facts of the transmission system components and reflect the
impact of actual operating conditions on the ratings of transmission facilities,
including ambient temperatures and wind speed when relevant.71 The line
rating methods should be public and fully transparent.

The outage data for the FTR market are for outages scheduled to occur in the
2019/2020 planning period and the 2020/2021 planning period, regardlessof when they were initially submitted.76 The outage data for the day-aheadmarket are for outages scheduled to occur from January 2015 through June
2021.

70 PJM presentation to the Planning Committee (PC) (May 3, 2018) “Transmission Owner Ratings Development and Reporting in PJM”(“There are no requirements for PJM to approve or verify a TO’s ratings or do any kind of consistency check.”) at 24.
71 See “Transmission Owner Ratings Development and Reporting in PJM,” presented at May 3, 2018 meeting of the Planning Committee.
<https://www.pjm.com/-/media/committees-groups/committees/pc/‌20180503/20180503-item-13-to-ratings-process-and-reporting.
ashx>.

© 2021 Monitoring Analytics, LLC

Transmission Facility Outages
Scheduling Transmission Facility Outage Requests

Transmission outages have significant impacts on PJM markets, including
impacts on FTR auctions, on congestion, and on expected market outcomes inthe day-ahead and real-time markets. The efficient functioning of the markets
depends on clear, enforceable rules governing transmission outages.

Transmission outages are categorized by duration: greater than 30 calendar
days; less than or equal to 30 calendar days; greater than five calendar days;
less than or equal to five calendar days.77 Table 12-50 shows that 78.0 percent
of requested outages were planned for less than or equal to five days and 7.6
72 See the 2018 State of the Market Report for PJM, Volume II, Section 2: Recommendations.
73 If a transmission facility is not modeled in the PJM EMS or the facility is not expected to significantly impact PJM system security orcongestion management, it is not reportable. See PJM, “Manual 3: Transmission Operations,” Rev. 59 (May 27, 2021).
74 See PJM, “Manual 3: Transmission Operations,” Rev. 59 (May 27, 2021).
75 See PJM, “Manual 3: Transmission Operations,” Rev. 59 (May 27, 2021).
76 The hotline tickets, EMS tripping tickets or test outage tickets were excluded. The analysis includes only the transmission outage tickets
submitted by PJM companies which are currently active.
77 Id. at 70.

2021 Quarterly State of the Market Report for PJM: January through June 667

2021 Quarterly State of the Market Report for PJM: January through June

percent of requested outages were planned for greater than 30 days in the2020/2021 planning period. Table 12-50 also shows that 77.8 percent of therequested outages were planned for less than or equal to five days and 7.8
percent of requested outages were planned for greater than 30 days in the
2019/2020 planning period.
Table 12-50 Transmission facility outage request summary by planned
duration: June 2019 through May 2021
2019/2020
Planned Duration(Days)<=5>5 & <=30
>30
Total

Outage Requests
16,6093,077
1,676
21,362

Percent of Total
77.8%
14.4%
7.8%
100.0%

Table 12-51 Transmission facility outage request received status definition
Planned Duration(Calendar Days)<=5> 5 & <=30

2020/2021
Outage Requests
16,125
2,969
1,577
20,671

Percent of Total
78.0%
14.4%
7.6%
100.0%

After receiving a transmission facility outage request from a TO, PJM assigns
a received status to the request based on its submission date and outage
planned duration. The received status can be On Time or Late, as defined inTable 12-51.78
The purpose of the rules defined in Table 12-51 is to require the TOs to submit
transmission facility outages prior to the Financial Transmission Right (FTR)
auctions so that market participants have complete information about market
conditions on which to base their FTR bids and PJM can accurately model
market conditions.79>30

Request Submitted
Before the first of the month one month prior to the starting month of theoutageAfter or on the first of the month one month prior to the starting month ofthe outage
Before the first of the month six months prior to the starting month of theoutageAfter or on the first of the month six months prior to the starting month ofthe outage
The earlier of 1) February 1, 2) the first of the month six months prior to thestarting month of the outage
After or on the earlier of 1) February 1, 2) the first of the month six months
prior to the starting month of the outage

Received
StatusOn TimeLate
On TimeLate
On Time
Late

Table 12-52 shows a summary of requests by received status. In the 2020/2021
planning period, 41.4 percent of outage requests received were late. In the
2019/2020 planning period, 44.4 percent of outage requests received werelate.
Table 12-52 Transmission facility outage requests by received status: June2019 through May 2021
2019/2020
Planned Duration(Days)<=5>5 & <=30
>30
Total

On Time
9,570
1,640
663
11,873

Late
7,039
1,437
1,013
9,489

Total
16,6093,077
1,676
21,362

2020/2021
Percent
Late
42.4%
46.7%
60.4%
44.4%

On Time
9,912
1,578
632
12,122

Late
6,213
1,391
945
8,549

Total
16,125
2,969
1,577
20,671

Percent
Late
38.5%
46.9%
59.9%
41.4%

Once received, PJM processes outage requests in priority order: emergency
transmission outage request; transmission outage request submitted on time;
and transmission outage request submitted late. Transmission outage requests
that are submitted late may be approved if the outage does not affect thereliability of PJM or cause congestion in the system.80

78 See PJM, “Manual 3: Transmission Operations,” Rev. 59 (May 27, 2021).
79 See “Report of PJM Interconnection, L.L.C. on Transmission Oversight Procedures,” Docket No. EL01-122-000 (November 2, 2001).

668

Section 12 Planning

80 See PJM, “Manual 3: Transmission Operations,” Rev. 59 (May 27, 2021). The following language was removed from Manual 3 Rev. 50: PJM
retains the right to deny all jobs submitted after 8 a.m. three days prior to the requested start date unless the request is an emergency
job or an exception request (i.e. a generator tripped and the Transmission Owner is taking advantage of a situation that was not available
before the unit trip).

© 2021 Monitoring Analytics, LLC

Section 12 Planning

Outages with emergency status will be approved even if submitted late after PJM determines that the outage does not result in Emergency Procedures. PJM
cancels or withholds approval of any outage that results in Emergency Procedures.81 Table 12-53 is a summary of outage requests by emergency status. Of all
outage requests scheduled to occur in the 2020/2021 planning period, 12.2 percent were for emergency outages. Of all outage requests scheduled to occur in the
2019/2020 planning period, 12.2 percent were for emergency outages.
Table 12-53 Transmission facility outage requests by emergency: June 2019 through May 2021
Planned Duration(Days)<=5>5 & <=30
>30
Total

Emergency
1,952
402
262
2,616

2019/2020
Non
Emergency
Total
14,657
16,609
2,675
3,077
1,414
1,676
18,746
21,362

Percent
Emergency
11.8%
13.1%
15.6%
12.2%

Emergency
1,821
451
251
2,523

2020/2021
Non
Emergency
Total
14,304
16,125
2,518
2,969
1,326
1,577
18,14820,671

Percent
Emergency
11.3%
15.2%
15.9%
12.2%

PJM will approve all transmission outage requests that are submitted on time and do not jeopardize the reliability of the PJM system. PJM will approve alltransmission outage requests that are submitted late and are not expected to cause congestion on the PJM system and do not jeopardize the reliability of the
PJM system. Each outage is studied and if it is expected to cause a constraint to exceed a limit, PJM will flag the outage ticket as “congestion expected.”82
After PJM determines that a late request may cause congestion, PJM informs the transmission owner of solutions available to eliminate the congestion. For
example, if a generator planned or maintenance outage request is contributing to the congestion, PJM can request that the generation owner defer the outage.
If no solutions are available, PJM may require the transmission owner to reschedule or cancel the outage.
Table 12-54 is a summary of outage requests by congestion status. Of all outage requests submitted to occur in the 2020/2021 planning period, 6.3 percent
were expected to cause congestion. Of all the outage requests that were expected to cause congestion, 1.6 percent (21 out of 1,296) were denied by PJM in
the 2020/2021 planning period and 19.4 percent (251 out of 1,296) were cancelled (Table 12-56). Of all outage requests submitted to occur in the 2019/2020
planning period, 6.5 percent were expected to cause congestion. Of all the outage requests that were expected to cause congestion, 2.1 percent (29 out of 1,399)
were denied by PJM in the 2019/2020 planning period and 21.7 percent (304 out of 1,399) were cancelled (Table 12-56).
Table 12-54 Transmission facility outage requests by congestion: June 2019 through May 2021
Planned Duration(Days)<=5>5 & <=30
>30
Total

Congestion
Expected
976
267
156
1,399

2019/2020
No
Congestion
Expected
Total
15,633 16,609
2,810
3,077
1,520
1,676
19,963 21,362

Percent
Congestion
Expected
5.9%
8.7%
9.3%
6.5%

Congestion
Expected
945
246
105
1,296

2020/2021
No
Congestion
Expected
Total
15,180 16,125
2,723
2,969
1,472
1,577
19,375 20,671

Percent
Congestion
Expected
5.9%
8.3%
6.7%
6.3%

81 PJM, “Manual 3: Transmission Operations,” Rev. 59 (May 27, 2021).
82 PJM added this definition to Manual 38 in February 2017. PJM, “Manual 38: Operations Planning,” Rev. 14 (Jan. 27, 2021).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 669

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-55 shows the outage requests summary by received status, congestion status and emergency status. In the 2020/2021 planning period, 29.3 percent
of requests were submitted late and were nonemergency while 1.0 percent of requests (203 out of 20,671) were late, nonemergency, and expected to cause
congestion. In the 2019/2020 planning period, 32.3 percent of request were submitted late and were nonemergency while 1.1 percent of requests (238 out of
21,362) were late, nonemergency, and expected to cause congestion.
Table 12-55 Transmission facility outage requests by received status, emergency and congestion: June 2019 through May 2021
Received
StatusLate
On TimeEmergency
Non Emergency
Emergency
Non Emergency

Total

Congestion
Expected
68
238
4
1,089
1,399

2019/2020
No
Congestion
Expected
Total
2,517
2,585
6,666
6,904
27
31
10,753
11,842
19,96321,362

Percent of
Total
12.1%
32.3%
0.1%
55.4%
100.0%

Congestion
Expected
71
203
2
1,020
1,296

2020/2021
No
Congestion
Expected
Total
2,415
2,486
5,860
6,063
35
37
11,06512,085
19,375
20,671

Percent of
Total
12.0%
29.3%
0.2%
58.5%
100.0%

Once PJM processes an outage request, the outage request is labelled as Submitted, Received, Denied, Approved, Cancelled by Company, PJM Admin Closure,
Revised, Active or Complete according to the processed stage of a request.83 Table 12-56 shows the detailed process status for outage requests only for the outage
requests that are expected to cause congestion. Status Submitted and status Received are in the In Process category and status Cancelled by Company and status
PJM Admin Closure are in the Cancelled category in Table 12-56. Table 12-56 shows that of all the outage requests that were expected to cause congestion, 1.6
percent (21 out of 1,296) were denied by PJM in the 2020/2021 planning period, 72.0 percent were complete and 19.4 percent (251 out of 1,296) were cancelled.
Of all the outage requests that were expected to cause congestion, 2.1 percent (29 out of 1,399) were denied by PJM in the 2019/2020 planning period, 70.0
percent were complete and 21.7 percent (304 out of 1,399) were cancelled.
Table 12-56 Transmission facility outage requests by processed status: June 2019 through May 2021
2019/2020
Received
StatusLate
On Time
Total

Emergency
Non Emergency
Emergency
Non Emergency

Cancelled
6
37
1
260
304

Complete
61
185
3
730
979

In Process
0
7
0
77
84

Denied1
8
0
2029

2020/2021
Congestion
Expected
68
238
4
1,089
1,399

Percent
Complete
89.7%
77.7%
75.0%
67.0%
70.0%

Cancelled
5
33
0
213
251

Complete
63
147
2
721
933

In Process
2
10
0
69
81

Denied
1
10
0
10
21

Congestion
Expected
71
203
2
1,020
1,296

Percent
Complete
88.7%
72.4%
100.0%
70.7%
72.0%

There are clear rules defined for assigning On Time or Late status for submitted outage requests in both the PJM tariff and PJM manuals.84 However, the On
Time or Late status only affects the priority that PJM assigns for processing the outage request. Table 12-56 shows that in the 2019/2020 planning period, 238
nonemergency outage requests were submitted late and expected to cause congestion. The expected impact on congestion is the basis for PJM’s treatment of
83 See PJM Markets & Operations, PJM Tools “Outage Information,” <http://www.pjm.com/‌markets-and-operations/etools/oasis/system-information/outage-info.aspx> (2019).
84 OA Schedule 1 § 1.9.2.

670

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planninglate outage requests. But there is no rule or clear definition of this congestion
analysis in the PJM manuals. The MMU recommends that PJM draft a clear
definition of the congestion analysis required for transmission outage requests
to include in Manual 3 after appropriate review.

A transmission outage ticket with duration of five days or less with an On
Time status can retain its On Time status if the outage is rescheduled within
the original scheduled month.85 This rule allows a TO to reschedule within thesame month with very little notice.

Rescheduling Transmission Facility Outage Requests

A transmission outage ticket with a duration exceeding five days with an
On Time status can retain its On Time status if the outage is rescheduled toa future month, and the revision is submitted by the first of the month prior
to the revised month in which the outage will occur.86 This rescheduling ruleis much less strict than the rule that applies to the first submission of outage
requests with similar duration. When first submitted, the outage request witha duration exceeding five days needs to be submitted before the first of themonth six months prior to the month in which the outage was expected tooccur. The rescheduling rule allows TOs to avoid the timing requirements
associated with outages exceeding five days.

A TO can reschedule or cancel an outage after initial submission. Table
12-57 is a summary of all the outage requests planned for the 2019/2020
planning period and the 2020/2021 planning period which were approved
and then cancelled or rescheduled by TOs at least once. If an outage request
was submitted, approved and subsequently rescheduled at least once, theoutage request will be counted as Approved and Rescheduled. If an outage
request was submitted, approved and subsequently cancelled at least once, theoutage request will be counted as Approved and Cancelled. In the 2020/2021
planning period, 29.4 percent of transmission outage requests were approved
by PJM and then rescheduled by the TOs, and 11.9 percent of the transmission
outages were approved by PJM and subsequently cancelled by the TOs. In
the 2019/2020 planning period, 31.9 percent of transmission outage requests
were approved by PJM and then rescheduled by the TO, and 11.4 percent of
the transmission outages were approved by PJM and subsequently cancelledby the TO.

The MMU recommends that PJM reevaluate all transmission outage tickets as
On Time or Late as if they were new requests when an outage is rescheduled
and apply the standard rules for late submissions to any such outages.

Table 12-57 Rescheduled and cancelled transmission outage requests: June2019 through May 2021
PlannedDuration (Days)<=5>5 & <=30
>30
Total

Outage Approved andRequests Rescheduled
16,609
3,889
3,077
1,833
1,676
1,103
21,362
6,825

2019/2020
Percent
Percent
Approved and Approved and Approved andRescheduled
Cancelled
Cancelled
23.4%
2,171
13.1%
59.6%
190
6.2%
65.8%
81
4.8%
31.9%
2,442
11.4%

Outage Approved andRequests Rescheduled
16,125
3,458
2,969
1,631
1,577
982
20,671
6,071

2020/2021
Percent
Percent
Approved and Approved and Approved andRescheduled
Cancelled
Cancelled
21.4%
2,192
13.6%
54.9%
191
6.4%
62.3%
78
4.9%
29.4%
2,461
11.9%

If a requested outage is determined to be late and TO reschedules the outage,
the outage will be revaluated by PJM again as On Time or Late.
85 PJM, “Manual 3: Transmission Operations,” Rev. 59 (May 27, 2021).
86 Id.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 671

2021 Quarterly State of the Market Report for PJM: January through JuneLong Duration Transmission Facility Outage Requests
PJM rules (Table 12-51) define a transmission outage request as On Time or
Late based on the planned outage duration and the time of submission. The rulehas stricter submission requirements for transmission outage requests planned
for longer than 30 days. In order to avoid the stricter submission requirement,
some transmission owners divided the duration of outage requests longer
than 30 days into shorter segments for the same equipment and submitted
one request for each segment. The MMU recommends that PJM not permit
transmission owners to divide long duration outages into smaller segments toavoid complying with the requirements for long duration outages.
More than one outage request can be submitted for the same transmission
equipment. In order to accurately present the results, Table 12-58 shows
equipment outages by the equipment instead of by outage request.
Table 12-58 shows that there were 12,754 transmission equipment planned
outages in the 2020/2021 planning period, of which 1,618 or 12.7 percent
were longer than 30 days, and of which 239 or 1.9 percent were scheduled
longer than 30 days when the duration of all the outage requests are combined
for the same equipment.
Table 12-58 Transmission equipment outages: June 2019 through May 2021
PlannedDuration (Days)> 30

Divided into
Shorter Periods
No
Yes

<= 30
Total

2019/2020
2020/2021
Count ofCount of
Equipment with
Equipment with
Planned Outages Percent of Total Planned Outages Percent of Total
1,474
11.2%
1,379
10.8%
229
1.7%
239
1.9%
11,42787.0%
11,13687.3%
13,130100.0%
12,754100.0%

Table 12-59 shows the details of long duration (> 30 days) outages whencombining the duration of the outage requests for the same equipment.87 The
actual duration of scheduled outages would be longer than 30 days if theduration of the outage requests was appropriately combined for the sameequipment. An effective duration was calculated for each piece of equipment
by subtracting the start date of the earliest outage request from the end date of
the latest outage request of the equipment. In the 2020/2021 planning period,
within effective duration greater than a month and shorter than two months,
there were 23 outages with a combined duration longer than 30 days.
Table 12-59 Transmission equipment outages by effective duration: June2019 through May 2021
Effective Duration of
Outage<=31>31 & <=62
>62 & <=93
>93
Total

2019/2020
Count of Equipment with
Planned Outages
3
27
21
178
229

Percent of
Total
1.3%
11.8%
9.2%
77.7%
100.0%

2020/2021
Count of Equipment with
Planned Outages
2
23
18
196
239

Percent of
Total
0.8%
9.6%
7.5%
82.0%
100.0%

Transmission Facility Outage Analysis for the FTR
MarketTransmission facility outages affect the price and quantity outcomes of FTR
Auctions. The purpose of the rules governing outage reporting is to ensurethat outages are known with enough lead time prior to FTR Auctions so thatmarket participants can understand market conditions and PJM can accurately
model market conditions.
There are Long Term, Annual and Monthly Balance of Planning Period
auctions in the FTR Market. For each type of auction, PJM includes a set ofoutages to be modeled.

Annual FTR Market
The Annual FTR Market includes the Annual ARR Allocation and the Annual
FTR Auction. When determining transmission outages to be modeled in thesimultaneous feasibility test used in the Annual FTR Market, PJM considers all
outages with planned duration longer than or equal to two weeks as an initial

87 A transmission facility is modeled as equipment in the EMS model. Equipment has three identifiers: location (B1), voltage level (B2) andequipment name (B3). The types of equipment include, for example, lines, transformers, and capacitors. There can be multiple outage
requests associated with the same equipment.

672

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

list. Then PJM may exercise significant discretion in selecting outages to be modeled in the final model. PJM posts the final FTR outage list to the FTR web page
usually at least one week before the auction bidding opening day.88
In the 2020/2021 planning period, 321 outage requests were included in the annual FTR market outage list and 20,350 outage requests were not included.89 In
the 2019/2020 planning period, 289 outage requests were included in the annual FTR market outage list and 21,073 outage requests were not included. Table
12-60, Table 12-61, Table 12-62 and Table 12-63 show the summary information on the modeled outage requests and Table 12-64 and Table 12-65 show thesummary information on outages that were not included in the Annual FTR Market.
Table 12-60 shows that 27.4 percent of the outage requests modeled in the Annual FTR Market for the 2020/2021 planning period had a planned duration ofless than two weeks and that 16.5 percent of the outage requests (53 out of 321) modeled in the Annual FTR Market for the planning period were submitted
late according to outage submission rules. It also shows that 15.2 percent of the outage requests modeled in the Annual FTR Market for the 2019/2020 planning
period had a planned duration of less than two weeks and that 17.0 percent of the outage requests (49 out of 289) modeled in the Annual FTR Market for theplanning period were submitted late according to outage submission rules.
Table 12-60 Annual FTR market modeled transmission facility outage requests by received status: June 2019 through May 2021
2019/2020
Planned Duration<2 weeks>=2 weeks & <2 months>=2 months
Total

On
Time
35
84
121
240

Late
9
10
30
49

Total
44
94
151
289

2020/2021
Percent of
Total
15.2%
32.5%
52.2%
100.0%

On
Time
76
88
104
268

Late
12
13
28
53

Total
88
101
132
321

Percent of
Total
27.4%
31.5%
41.1%
100.0%

Table 12-61 shows the annual FTR market modeled outage requests summary by emergency status and received status. Two of the annual FTR market modeled
outages expected to occur in the 2020/2021 planning period were emergency outages. Two of the modeled outages expected to occur in the 2019/2020 planning
period were emergency outages.
Table 12-61 Annual FTR market modeled transmission facility outage requests by emergency: June 2019 through May 2021
Received
StatusOn Time

Late

Planned Duration<2 weeks>=2 weeks & <2 months>=2 months
Total<2 weeks>=2 weeks & <2 months>=2 months
Total

Emergency
0
0
0
0
0
0
2
2

2019/2020
Non
Percent Non
Emergency
Total Emergency
35
35
100.0%
84
84
100.0%
121
121
100.0%
240
240
100.0%
99100.0%
10
10100.0%
28
30
93.3%
47
49
95.9%

Emergency
0
0
0
0
2
0
0
2

2020/2021
Non
Percent Non
Emergency
Total Emergency
76
76
100.0%
88
88
100.0%
104
104
100.0%
268
268
100.0%
10
12
83.3%
13
13
100.0%
28
28
100.0%
51
53
96.2%

88 PJM Financial Transmission Rights, “Annual ARR Allocation and FTR Auction Transmission Outage Modeling,” <https://www.pjm.com/-/media/markets-ops/ftr/annual-ftr-auction/2018-2019/2018-2019-annual-outage-modeling.ashx?la=en> (April 5, 2018). There is no documentation on
the deadline for when modeling outages should be posted on the PJM website.
89 PJM’s treatment of transmission outages in the FTR models is discussed in the 2020 State of the Market Report for PJM: Section 13: FTRs and ARRs: Supply and Demand.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 673

2021 Quarterly State of the Market Report for PJM: January through JunePJM determines expected congestion for both On Time and Late outage requests. A Late outage request may be denied or cancelled if it is expected to cause
congestion. Table 12-62 shows a summary of requests by expected congestion and received status. Of all the annual FTR market modeled outages expected tooccur in the 2020/2021 planning period and submitted late, 9.4 (5 out of 53) was expected to cause congestion. Overall, of all the annual FTR market modeled
outages expected to occur in the 2019/2020 planning period and submitted late, 10.2 percent (5 out of 49) were expected to cause congestion.
Table 12-62 Annual FTR market modeled transmission facility outage requests by congestion: June 2019 through May 2021
Received
StatusOn TimeLate

674

Planned Duration<2 weeks>=2 weeks & <2 months>=2 months
Total<2 weeks>=2 weeks & <2 months>=2 months
Total

Section 12 Planning

Congestion
Expected
11
24
23
58
2
2
1
5

2019/2020
No
Congestion
Expected
Total
24
35
60
84
98
121
182
240
7
9
8
10
29
30
44
49

Percent
Congestion
Expected
31.4%
28.6%
19.0%
24.2%
22.2%
20.0%
3.3%
10.2%

Congestion
Expected
17
19
17
53
2
1
2
5

2020/2021
No
Congestion
Expected
Total
59
76
69
88
87
104
215
268
10
12
12
13
26
28
48
53

Percent
Congestion
Expected
22.4%
21.6%
16.3%
19.8%
16.7%
7.7%
7.1%
9.4%

© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-63 shows that 25.7 percent of outage requests modeled in the annual FTR market for the 2020/2021 planning period and with a duration of two weeks
or longer but shorter than two months were cancelled after the FTR auction was open, compared to 28.7 percent for the 2019/2020 planning period. Table 12-63
also shows that 17.4 percent of outages requests modeled in the Annual FTR Market for the 2020/2021 planning period and with a duration of two months or
longer were cancelled, compared to 22.5 percent for the 2019/2020 planning period.
Table 12-63 Annual FTR market modeled transmission facility outage requests by processed status: June 2019 through May 2021
Planned Duration<2 weeks>=2 weeks & <2 months>=2 months

Processed
StatusIn Progress
Approved
Cancelled
ActiveCompletedTotal
In Progress
Approved
Cancelled
ActiveCompletedTotal
In Progress
Approved
Cancelled
ActiveCompleted
Total

Total Cancelled
Grand Total

2019/2020
OutageRequests
7
0
7
0
30
44
15
0
27
0
52
94
24
0
34
4
89
151
68
289

Percent
15.9%
0.0%
15.9%
0.0%
68.2%
100.0%
16.0%
0.0%
28.7%
0.0%
55.3%
100.0%
15.9%
0.0%
22.5%
2.6%
58.9%
100.0%
23.5%

2020/2021
OutageRequests
5
0
27
0
56
88
7
1
26
0
67
101
14
0
23
6
89
132
76
321

Percent
5.7%
0.0%
30.7%
0.0%
63.6%
100.0%
6.9%
1.0%
25.7%
0.0%
66.3%
100.0%
10.6%
0.0%
17.4%
4.5%
67.4%
100.0%
23.7%

More outage requests were not modeled in the Annual FTR Market than were modeled in the Annual FTR Market. In the 2020/2021 planning period, 321 outage
requests were modeled and 20,350 outage requests were not modeled in the Annual FTR Market. In the 2019/2020 planning period, 289 outage requests weremodeled and 21,073 outage requests were not modeled in the Annual FTR Market.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 675

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-64 shows that 8.2 percent of outage requests not modeled in the Annual FTR Auction with duration longer than or equal to two months, labeled On
Time according to the rules, were submitted or rescheduled after the Annual FTR Auction bidding opening date for the 2020/2021 planning period compared to
15.8 percent in the 2019/2020 planning period.
Table 12-64 Transmission facility outage requests not modeled in Annual FTR Auction: June 2019 through May 2021
2019/2020

Planned Duration<2 weeks>=2 weeks & <2 months>=2 months
Total

Before Bidding
Opening Date
1,684
618
187
2,489

On TimeAfter Bidding
Opening Date
8,696
413
35
9,144

Percent After
83.8%
40.1%
15.8%
78.6%

Before Bidding
Opening Date
238
150
221
609

2020/2021
Late
After Bidding
Opening Date
7,660
823
348
8,831

Percent After
97.0%
84.6%
61.2%
93.5%

Before Bidding
Opening Date
2,002
711
214
2,927

On TimeAfter Bidding
Opening Date
8,605
303
19
8,927

Percent After
81.1%
29.9%
8.2%
75.3%

Before Bidding
Opening Date
226
142
193
561

Late
After Bidding
Opening Date
6,795
820
320
7,935

Percent After
96.8%
85.2%
62.4%
93.4%

Table 12-65 shows that 91.9 percent of late outage requests that were not modeled in the Annual FTR Auction with duration longer than or equal to two months
and submitted after the Annual FTR Auction bidding opening date, and were active or completed in the 2020/2021 planning period. It also shows that 91.1
percent of late outage requests which were not modeled in the Annual FTR Auction with duration longer than or equal to two months and submitted after the
Annual FTR Auction bidding opening date were active or completed in the 2019/2020 planning period.
Table 12-65 Late transmission facility outage requests: June 2019 through May 2021
Planned Duration<2 weeks>=2 weeks & <2 months>=2 months
Total

2019/2020
Completed Or
Active Outages
Total
6,600
7,660
710
823
317
348
7,627
8,831

Percent
Complete
86.2%
86.3%
91.1%
86.4%

2020/2021
Completed Or
Active Outages
Total
5,886
6,795
716
820
294
320
6,896
7,935

Percent
Complete
86.6%
87.3%
91.9%
86.9%

Although the definition of late outages was developed in order to prevent outages for the planning period being submitted after the opening of bidding in the
Annual FTR Auction, the rules have not functioned effectively because the rule has no direct connection to the date on which bidding opens for the Annual
FTR Auction. By requiring all long-duration transmission outages to be submitted before February 1, PJM outage submission rules only prevent long-durationtransmission outages from being submitted late. The rule does not address the situation in which long-duration transmission outages are submitted on time,
but are rescheduled so that they are late. There is no rule to address the situation in which short-duration outages (duration <= 5 days) are submitted on time,
but are changed to long-duration transmission outages after the outages are approved and active. The Annual FTR Auction model may consider transmission
outages planned for longer than two weeks but less than two months. Those outages not only include long duration outages but also include outages shorter
than 30 days. In those cases, PJM outage submission rules failed to prevent those transmission outages from being submitted late. The MMU recommends that
PJM modify the rules to eliminate the approval of outage requests submitted or rescheduled after the opening of bidding in the Annual FTR Auction.

676

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Monthly FTR Market
When determining transmission outages to be modeled in the Monthly Balance of Planning Period FTR Auction, PJM considers all outages with planned
duration longer than five days and may consider outages with planned durations less than or equal to five days. PJM exercises significant discretion in selecting
outages to be modeled. PJM posts an FTR outage list to the FTR webpage usually at least one week before the auction bidding opening day.90 Table 12-66 andTable 12-67 show the summary information on outage requests modeled in the Monthly Balance of Planning Period FTR Auction and Table 12-68 and Table
12-69 show the summary information on outage requests not modeled in the Monthly Balance of Planning Period FTR Auction.
Table 12-66 shows that on average, 29.7 percent of the outage requests modeled in the Monthly Balance of Planning Period FTR Auction were submitted lateaccording to outage submission rules in the 2020/2021 planning period. On average, 32.4 percent of the outage requests modeled in the Monthly Balance ofPlanning Period FTR Auction were submitted late according to outage submission rules in the 2019/2020 planning period.
Table 12-66 Monthly Balance of Planning Period FTR Auction modeled transmission facility outage requests by received status: June 2019 through May 2021
2019/2020
Month
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Average

On Time
162
92
131
379
533
431
311
189
223
428
461
391
311

Late
115
96
86
147
183
163
146
86
93
141
181
167
134

2020/2021
Total
277
188
217
526
716
594
457
275
316
569
642
558
445

Percent
Late
41.5%
51.1%
39.6%
27.9%
25.6%
27.4%
31.9%
31.3%
29.4%
24.8%
28.2%
29.9%
32.4%

On Time
215
96
118
468
596
486
324
224
211
429
477
412
338

Late
101
71
81
140
176
185
130
64
116
142
174
180
130

Total
316
167
199
608
772
671
454
288
327
571
651
592
468

Percent
Late
32.0%
42.5%
40.7%
23.0%
22.8%
27.6%
28.6%
22.2%
35.5%
24.9%
26.7%
30.4%
29.7%

90 PJM Financial Transmission Rights, “2015/2016 Monthly FTR Auction Transmission Outage Modeling,” <http://www.pjm.com/-/media/markets-ops/ftr/ftr-allocation/monthly-ftr-auctions/2015-2016-monthly-transmission-outages-that-may-cause-infeasibilities.ashx?la=en> (December 9,2015).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 677

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-67 shows that on average, 17.1 percent of outage requests modeled in the Monthly Balance of Planning Period FTR Auction were cancelled in the2020/2021 planning period. On average, 19.7 percent of outage requests modeled in the Monthly Balance of Planning Period FTR Auction were cancelled in the
2019/2020 planning period.
Table 12-67 Monthly Balance of Planning Period FTR Auction modeled transmission facility outage requests by processed status: June 2019 through May 2021
Planning Year
2019/2020

2020/2021

678

Month
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Average
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Average

In
Process
17
13
14
58
65
30
27
21
37
55
54
26
35
27
9
22
65
67
52
31
39
36
73
53
38
43

Section 12 Planning

Denied
2
4
5
2
2
1
4
0
0
0
0
2
2
5
16
2
0
4
1
1
1
0
0
0
2
3

Approved
2
0
0
25
13
11
8
9
8
13
12
10
9
7
4
4
19
17
42
7
6
11
11
7
12
12

Cancelled Revised
47
0
45
0
37
0
93
0
131
1
120
0
86
1
52
0
51
0
130
0
148
0
111
1
88
0
48
1
22
0
26
0
114
0
161
2
151
0
97
0
46
0
52
0
92
0
111
0
92
0
84
0

Active
82
72
79
178
200
173
74
95
111
160
177
126
127
75
73
71
195
208
160
75
79
115
175
215
122
130

Complete
127
54
82
170
304
259
257
98
109
211
251
282
184
153
43
74
215
313
265
243
117
113
220
265
326
196

Total
277
188
217
526
716
594
457
275
316
569
642
558
445
316
167
199
608
772
671
454
288
327
571
651
592
468

Percent
Cancelled
17.0%
23.9%
17.1%
17.7%
18.3%
20.2%
18.8%
18.9%
16.1%
22.8%
23.1%
19.9%
19.7%
15.2%
13.2%
13.1%
18.8%
20.9%
22.5%
21.4%
16.0%
15.9%
16.1%
17.1%
15.5%
17.1%

© 2021 Monitoring Analytics, LLC

Section 12 Planning

Table 12-68 shows that on average, 9.1 percent of outage requests not modeled in the Monthly Balance of Planning Period FTR Auction, labeled On Timeaccording to the rules, were submitted after the monthly FTR auction bidding opening dates in the 2020/2021 planning period, compared to 9.1 percent in the
2019/2020 planning period. On average, 65.5 percent of outage requests not modeled in the Monthly Balance of Planning Period FTR Auction, labeled Lateaccording to the rules, were submitted after the Monthly Balance of Planning Period FTR Auction bidding opening dates in the 2020/2021 planning period,
compared to 66.1 percent in the 2019/2020 planning period.
Table 12-68 Transmission facility outage requests not modeled in Monthly Balance of Planning Period FTR Auction: June 2019 through May 2021
2019/2020

Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Average

Before Bidding
Opening Date
673
391
357
894
1,110
1,000
737
580
645
1,317
1,501
1,266
873

On TimeAfter Bidding
Opening Date
86
64
44
124
120
63
63
37
51
99
179
88
85

© 2021 Monitoring Analytics, LLC

Percent After
11.3%
14.1%
11.0%
12.2%
9.8%
5.9%
7.9%
6.0%
7.3%
7.0%
10.7%
6.5%
9.1%

Before Bidding
Opening Date
347
268
300
318
388
457
328
292
280
333
448
484
354

2020/2021
Late
After Bidding
Opening Date
694
729
640
661
929
659
636
572
603
702
693
702
685

Percent After
66.7%
73.1%
68.1%
67.5%
70.5%
59.1%
66.0%
66.2%
68.3%
67.8%
60.7%
59.2%
66.1%

Before Bidding
Opening Date
798
430
438
1,062
1,192
964
738
605
588
1,356
1,387
1,205
897

On TimeAfter Bidding
Opening Date
105
90
74
86
70
71
68
74
52
71
101
92
80

Percent After
11.6%
17.3%
14.5%
7.5%
5.5%
6.9%
8.4%
10.9%
8.1%
5.0%
6.8%
7.1%
9.1%

Before Bidding
Opening Date
332
271
262
273
363
354
390
276
276
308
387
362
321

Late
After Bidding
Opening Date
791
605
617
640
616
580
587
456
574
624
641
600
611

Percent After
70.4%
69.1%
70.2%
70.1%
62.9%
62.1%
60.1%
62.3%
67.5%
67.0%
62.4%
62.4%
65.5%

2021 Quarterly State of the Market Report for PJM: January through June 679

2021 Quarterly State of the Market Report for PJM: January through June

Table 12-69 shows that on average, 71.3 percent of late outage requests whichwere not modeled in the Monthly Balance of Planning Period FTR Auction,
submitted after the Monthly Balance of Planning Period FTR Auction bidding
opening dates, were approved and complete in the 2020/2021 planning period,
compared to 71.8 percent in the 2019/2020 planning period.
Table 12-69 Late transmission facility outage requests: June 2019 throughMay 2021
2019/2020

Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
AverageCompleted
Outages
528
489
500
455
616
472
469
441
475
461
480
518
492

Total
694
729
640
661
929
659
636
572
603
702
693
702
685

2020/2021
Percent
Complete
76.1%
67.1%
78.1%
68.8%
66.3%
71.6%
73.7%
77.1%
78.8%
65.7%
69.3%
73.8%
71.8%

Completed
Outages
574
436
447
436
419
392
440
341
390
440
475
437
436

Total
791
605
617
640
616
580
587
456
574
624
641
600
611

Percent
Complete
72.6%
72.1%
72.4%
68.1%
68.0%
67.6%
75.0%
74.8%
67.9%
70.5%
74.1%
72.8%
71.3%

Transmission Facility Outage Analysis in the DayAhead Energy Market

operating day. The list of approved or active outage requests before the dayahead market is closed is available to market participants. The day-aheadmarket model uses outages included in the day-ahead market save cases as
an input. The outages that actually occurred during the operating day are
the outages that affect the real-time market. If the three sets of outages are
the same, there is no potential impact on markets. If the three sets of outages
differ, there is a potential negative impact on markets. For example, if the listof outages before the day-ahead market was closed was different from the listof outages that included in the day-ahead market save cases, the day-aheadmarket participant would have inconsistent outage information as what dayahead market model used.
For example for the operating day of May 5, 2018, Figure 12-6 shows that:
there were 443 approved or active outages seen by market participants before
the day-ahead market was closed; there were 329 outage requests included in
the day-ahead market model; there were 315 outage requests included in bothsets of outage; there were 128 outage requests approved or active before theday-ahead market was closed but not included as inputs in day-ahead market
model; and there were 14 outage requests included in day-ahead market
model but not available to market participants prior to the day-ahead market.
Figure 12-6 Illustration of day-ahead market analysis: May 5, 2018

Transmission facility outages also affect the energy market. Just as with the
FTR market, it is critical that outages that affect the operating day are known
prior to the submission of offers in the day-ahead energy market so thatmarket participants can understand market conditions and PJM can accurately
model market conditions in the day-ahead market. PJM requires transmission
owners to submit changes to outages scheduled for the next two days no later
than 09:30 am.91
There are three relevant time periods for the analysis of the impact oftransmission outages on the energy market: before the day-ahead market isclosed; when the day-ahead market save cases are created; and during the91 PJM, “Manual 3: Transmission Operations,” Rev. 59 (May 27, 2021).

680

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 12 Planning

Figure 12-7 compares the weekly average number of active or approved
outages available to market participants prior to the close of the day-aheadmarket with the outages included as inputs to the day-ahead market by PJM.

Figure 12-8 compares the weekly average number of outages included as
inputs to the day-ahead market by PJM with the outages that actually occurred
during the operating day.

Figure 12-7 Approved or active outage requests: January 2015 through June
2021

Figure 12-8 Day-ahead market model outages: January 2015 through June
2021
800

800
Market Participant View
Day Ahead Market Model
Market Participant and Day Ahead Model
Market Participant View and Not in Day Ahead ModelDay Ahead Market Model and Not in Market Participant View

700

500
400
300
200

500
400
300
200
100

100
0
2015

600

Number of Outage Requests

Number of Outage Requests

600

Day Ahead Market Model
OccurredDay Ahead Market Model and Occurred
Day Ahead Market Model and Not OccurredOccurred and Not in Day Ahead Market Model

700

2016

© 2021 Monitoring Analytics, LLC

2017

2018

2019

2020

2021

0
2015

2016

2017

2018

2019

2020

2021

2021 Quarterly State of the Market Report for PJM: January through June 681

2021 Quarterly State of the Market Report for PJM: January through June

Figure 12-9 compares the weekly average number of active or approved
outages available to market participants prior to the close of the day-aheadmarket with the outages that actually occurred during the operating day.
Figure 12-9 Approved or active outage requests: January 2015 through June
2021
800
Market Participant View
Occurred

700

Market Participant View and OccurredMarket Participant View and Not OccurredOccurred and Not in Market Participant View

600

Number of Outage Requests

500
400
300
200
100
0
2015

2016

2017

2018

2019

2020

2021

Figure 12-7, Figure 12-8, and Figure 12-9 show that on a weekly average basis,
the active or approved outages available to day-ahead market participants, theoutages included as inputs in the day-ahead market model and the outages
that actually occurred in real time are not consistent. The active or approved
outages available to day-ahead market participants are more consistent withthe outages that actually occurred in real time than with the outages includedin the day-ahead market model.

682

Section 12 Planning© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Financial Transmission and Auction
Revenue Rights
In an LMP market, the lowest cost generation is dispatched to meet the load,
but when there are transmission constraints, load pays the high local price forall generation, including the low cost generation serving part of that load. The
low cost generation receives payment only for its low local price and does notreceive the payment made by load for the output of the low cost generation
at the high local price. The result is that load pays the correct local price but
pays too much in total for energy because it is paying more for the low cost
generation than the low cost generation receives. Load pays the difference
between the high local price and the low local price of the low cost generation.
That payment is appropriately not made to the low cost generation which ispaid its LMP. In an LMP market, load pays more than generation receives.
FTRs are the mechanism for returning those excess payments to load. But
the current FTR mechanism in PJM does not and cannot return all the excess
payments to load. The FTR mechanism in PJM needs a significant redesignin order to achieve that objective. The FTR mechanism has become unduly
complicated and has deviated significantly from its original purpose. Returnof all the excess payments to load would result in a perfect hedge againstcongestion. The current FTR mechanism has significantly attenuated the valueof the FTR/ARR design as a hedge against congestion for load.
The FTR mechanism should be a simple accounting method for assigning
congestion rights to load. But PJM has had to add increasingly complex rules
and regularly intervene in the FTR mechanism because the PJM FTR design
has moved further and further from these economic fundamentals. Somemarket participants have profited in various ways from these design flaws
and those market participants now strongly defend the current design.
When the lowest cost generation is remote from load centers, the physicaltransmission system permits that lowest cost generation to be delivered toload, subject to transmission limits. This was true prior to the introduction of
LMP markets and continues to be true in LMP markets. Prior to the introductionof LMP markets, payment for the delivery of low cost generation to load was© 2021 Monitoring Analytics, LLC

based both on intrazonal generation and intrazonal transmission, both undercost of service rates, and on contracts with specific remote generation outside
the local zone and the associated point to point transmission contracts.
In both cases, customers paid for the physical rights associated with thetransmission system used to provide for the delivery of low cost generation
to load. There was no congestion revenue because customers paid only theactual cost of the low cost generation. Most generation was intrazonal andthe transmission system used to deliver the related energy to intrazonal load
was also intrazonal.
After the introduction of LMP markets, financial transmission rights (FTRs)
were introduced, effective April 1, 1999, for the real-time market and June 1,
2000, for the combined day-ahead and balancing (real-time) markets. FTRs
permitted the loads, which pay for the transmission system, to continue toreceive the benefits of access to either local or remote low cost generation
by returning congestion to the load.1 FTRs and the associated congestion
revenues were directly provided to load in recognition of the fact that, as aresult of LMP, load was required to pay more for low cost generation thanis paid to low cost generation. But there was a flaw built in from the very
beginning of the FTR design that had no significant impact initially but which
was ultimately the source of all the issues with the FTR mechanism. That
flaw was the idea that congestion was based on contract paths in a network
system rather than a result of the actual operation of the complex network.
The flaw was especially ironic given that most load was served by intrazonal
generation subject to cost of service regulation rather than contracts withextrazonal generation. That flaw was inconsistent with the most basic logic of
LMP and the resultant fissure has continued to widen. The origin of FTRs was
the recognition that the way to hold load harmless from making the excess
payments created by the LMP system was to return the excess payments toload. The rights to congestion belong to load. If implemented correctly, FTRs
would be the financial equivalent of firm transmission service for load. If
implemented correctly, FTRs would be a perfect hedge against congestion forload. The result of the current FTR mechanism is a significant reduction in thevalue of FTRs as a hedge for load.
1 See 81 FERC ¶ 61,257 at 62,241 (1997).

2021 Quarterly State of the Market Report for PJM: January through June 683

2021 Quarterly State of the Market Report for PJM: January through June

The notion that FTRs exist in order to provide a hedge for generation is afallacy. In an LMP system, the basic incentive structure for generation derives
from the fact that generation is paid the LMP at the generator bus. If generation
were to be guaranteed a price at a distant constrained load bus rather thanat the generation bus, there would be no incentive for generation to locate
where it is needed on the system. In addition, the payment of the price at
the generator bus is fundamental to the logic of locational marginal pricing
which produces local prices equal to the marginal value of generation at every
point. There is no logical or theoretical basis in locational marginal pricing
for the assertion that generation at low price nodes is underpaid and shouldbe paid more from congestion dollars. Generation does not pay congestion.
Some generation receives a price lower than the system marginal price (SMP)and some generation receives a price greater than SMP but that does notmean that generation is paying congestion. It means that generation is being
paid an LMP that is higher or lower than the system load-weighted average
LMP. If a generating unit wants a hedge, it may enter into an arm’s lengthtransaction with a willing counter party as a hedge. That is the way hedges
work in markets. That is not the purpose of FTRs.
In an LMP system, the only way to ensure that load receives the benefits
associated with the use of the transmission system to deliver low cost energy
is to use FTRs, or an equivalent mechanism, to pay back to load the difference
between the total load payments and the total generation revenues. FTRs werethe mechanism selected in PJM to offset the congestion costs that load pays
in an LMP market. Congestion revenues are the source of the funds to pay
FTRs. Congestion revenues are assigned to the load that paid them throughFTRs.2 The only way to ensure that load receives the benefits associated withthe use of the transmission system to deliver low cost energy is to ensure that
all congestion revenues are returned to load or, more precisely, that the rights
to all congestion revenues are assigned to load. In order to do that, congestion
must be defined correctly based on the operation of the network and not on
arbitrary contract paths.

2 See id. at 62, 259–62,260 & n. 123.

684

Section 13 FTRs and ARRs

Effective April 1, 1999, when FTRs were introduced with the LMP market, there
was a real-time market but no day-ahead market, and FTRs returned real-timecongestion revenue to load. Effective June 1, 2000, the day-ahead market
was introduced and FTRs returned total congestion including day-ahead andbalancing (real-time) congestion to load. Congestion, in PJM’s two settlement
market, is the sum of day ahead and balancing congestion. Effective June 1,
2003, PJM replaced the direct allocation of FTRs to load with an allocationof Auction Revenue Rights (ARRs). Under the ARR construct, the load stillowns the rights to congestion revenue, but the ARR construct allows load toeither claim the FTRs directly (through a process called self scheduling), or
to sell the rights to congestion revenue in the FTR auction in exchange for arevenue stream based on the auction clearing prices of the FTRs. Under the
ARR construct, the right to all congestion revenues should belong to load. Allcongestion surplus should be assigned to load. But the actual implementation
produces a very different result.
ARRs were an add on concept, defined based on a misunderstanding of FTRs,
which had its roots in the assignment of congestion to load using contract
paths (generation to load paths) rather than on the calculation of congestion
actually paid. ARRs used assumed contract paths to assign congestion to load.
The use of contract paths for ARRs was a more critical mistake than using
contract paths for FTRs because contract paths did not and do not account for
all congestion. The use of contract paths led to the mistaken conclusion thatsome congestion did not belong to load and could be sold to FTR buyers. The
ARR concept, as it is currently implemented, does not allow the FTR sellers,load, to establish a price at which they are willing to sell, but forces load toaccept whatever prices buyers are willing to pay. The revenue from the sale ofcongestion rights is not even paid in full to ARR holders. Sellers are required
to return some of the cleared auction revenue to FTR buyers when FTR profits
are not adequate. So called surplus revenue is paid to FTR holders to ensure
payment despite the fact that willing FTR buyers paid the revenues in theauction for the rights to an uncertain level of congestion.
The use of generation to load contract paths rather than the direct calculationof congestion led to an increased divergence between the congestion on© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

the generation to load contract paths and total congestion. This divergence
between actual network use and historic contract paths was exacerbated as
new zones were added with their own historic generation to load contract
paths and as significant numbers of generating units retired and new units
were added.3 Rather than understanding that the divergence resulted from thefact that a contract path based approach did not correctly calculate congestion
in a network system, especially as the system grew significantly, the issue wascharacterized as the existence of excess capacity on the transmission system.
But congestion was never about capacity on the transmission system. Prior to
the introduction of ARRs, the so called excess congestion that exceeded thecongestion on the defined contract paths was returned to load, regardless of
its source. There is no such thing as excess congestion. The overlay of ARRs
on the FTR concept did not change the fundamental logic of congestion, but
permitted the introduction of a system in which the divergence was formallycreated between the amount of congestion paid by load and the amount ofcongestion returned to load. Congestion belongs to the load, by definition.
The introduction of ARRs based on a contract path fiction undermined theassignment of all congestion rights to load.
The contract path fiction is also the source of the incorrect definition of the
product that is bought and sold as FTRs, the available supply of the productand the price paid to the buyers of the product. The product is defined as thedifference in congestion prices across specific transmission contract paths. The
difference in congestion prices across contract paths is not congestion and is
not equal to congestion revenues. The quantity of the product made available
for sale in the FTR auctions is defined as system capability, meaning thecapacity of the transmission system to deliver power. But system capability is
not congestion and system capability is not the difference in congestion prices
across transmission contract paths nor the potential for such difference. The
definition of ARRs based on contract paths led to the mistaken idea that sometransmission system capacity was used by ARRs but some was not and thatboth the ARR capability and the excess capability was available for sale as
FTRs. This fundamental confusion in the design of the market is the source of
3 For a comprehensive report on capacity retirements and capacity additions in PJM, see: “2020 PJM Generation Capacity andFunding Sources: 2007/2008 through 2021/2022,” (September 15, 2020) available at <http://www.monitoringanalytics.com/reports/
Reports/2020/‌Constraint_Based_Congestion_Calculations_20200722.pdf>.

© 2021 Monitoring Analytics, LLC

so called revenue shortfalls, of the redesign of the market to exclude balancing
congestion, and of the need for PJM to intervene in the market. PJM has had
to regularly intervene in the market because the market as designed cannot
reach equilibrium based on the economic fundamentals. The product, thequantity of the product and the price of the product are all incorrectly defined.
The ARR/FTR design does not serve as an efficient mechanism for returning
congestion to load, as a result of an FTR design that was flawed from its
introduction and as a result of various distortions added to the design since
its introduction. The distortions include the definition of target allocations
based on day-ahead congestion only, the fact that ARR holders cannot set thesale price for congestion revenue rights, the return of market revenues to FTR
buyers when profit targets are not met, the failure to assign all FTR auction
revenues to ARR holders, the differences between modeled and actual systemcapability, the definition and allocation of surplus, and the numerous crosssubsidies among participants. The fundamental distortion was the assignmentof the rights to congestion revenue based on specific generation to loadtransmission contract paths. This approach retained the contract path based
view of congestion rooted in physical transmission rights and inconsistent
with the role of FTRs in a nodal, network system with locational marginal
pricing.
The cumulative offset by ARRs for the 2011/2012 planning period through thefirst ten months of the 2020/2021 planning period, using the rules effective
for each planning period, was 74.1 percent. Load has been underpaid by $2.4
billion from the 2011/2012 planning period through the 2020/2021 planning
period.
The overall underassignment of congestion to load includes dramaticallydifferent results by zone. Load in some zones receives congestion revenues
well in excess of the congestion they pay while the reverse is true for otherzones.
If the original PJM FTR approach had been designed to return congestion
revenues to load without use of the generation to load contract paths, and2021 Quarterly State of the Market Report for PJM: January through June 685

2021 Quarterly State of the Market Report for PJM: January through June

if the distortions subsequently introduced into the FTR design had not been
added, many of the subsequent issues with the FTR design and complex
redesigns would have been avoided. PJM would not have had to repeatedlyintervene in the functioning of the FTR system in an effort to meet theartificial and incorrectly defined goal of revenue adequacy. The design should
simply have provided for the return of all congestion revenues to load. The
design should have also provided for the ability of load to sell the rights tocongestion revenue. That sale could be organized as an FTR auction withthe product and the price clearly defined. Now is a good time to address
the issues of the FTR design and to return the design to its original purpose.
This would eliminate much of the complexity associated with ARRs and FTRs
and eliminate unnecessary controversy about the appropriate recipients ofcongestion revenues.
The 2021 Quarterly State of the Market Report for PJM: January through June
focuses on the 2020/2021 Monthly Balance of Planning Period FTR Auctions,specifically covering January 1, 2021, through June 30, 2021.
Table 13-1 The FTR/ARR markets results were partially competitive
Market Element
Market Structure
Participant Behavior
Market Performance

Evaluation
Competitive
Partially Competitive
Partially Competitive

Market Design

Flawed• Market structure was evaluated as competitive. The ownership of FTR
obligations is unconcentrated for the individual years of the 2020/2023
Long Term FTR Auction, the 2020/2021 Annual FTR Auction and eachperiod of the Monthly Balance of Planning Period Auctions. The ownershipof FTR options is moderately or highly concentrated for every Monthly FTR
Auction period and moderately concentrated for the 2020/2021 Annual
FTR Auction. Ownership of FTRs is disproportionately (78.3 percent) byfinancial participants. The ownership of ARRs is unconcentrated.

• Market performance was evaluated as partially competitive because of
the flaws in the market design. Sellers, the ARR holders, cannot set a saleprice. Buyers can reclaim some of their purchase price after the market
clears if the product does not meet a profitability target. The market
resulted in a substantial shortfall in congestion payments to load andsignificant and unsupportable disparities among zones in the share ofcongestion returned to load. FTR purchases by financial entities remain
persistently profitable in part as a result of the flaws in the market design.

• Market design was evaluated as flawed because there are significant

and fundamental flaws with the basic ARR/FTR design. The FTR auction
market is not actually a market because the sellers have no independentrole in the process. ARR holders cannot determine the price at which
they are willing to sell rights to congestion revenue. Buyers have theability to reclaim some of the price paid for FTRs after the market clears.
The market design is not an efficient or effective way to ensure that therights to all congestion revenues are assigned to load. The product soldto FTR buyers is incorrectly defined as target allocations rather than ashare of congestion revenue. ARR holders’ rights to congestion revenues
are not correctly defined because the contract path based assignment ofcongestion rights is inadequate and incorrect. Ongoing PJM subjective
intervention in the FTR market that affects market fundamentals is also
an issue and a symptom of the fundamental flaws in the design. The
product, the quantity of the product and the price of the product are allincorrectly defined.

• The fact that load is not able to define its willingness to sell FTRs or

the prices at which it is willing to sell FTRs and the fact that sellers are
required to return some of the cleared auction revenue to FTR buyers
when FTR profits are not adequate, means that the FTR design does not
actually function as a market and is evidence of basic flaws in the market
design.

• Participant behavior was evaluated as partially competitive as a result of

the behavior of GreenHat Energy, LLC. ARR holders who are the sellers of
FTRs are not permitted to participate in the market clearing.

686

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Overview
Auction Revenue Rights
Market Structure• ARR Ownership. In the 2021/2022 planning period ARRs were allocatedto 1,459 individual participants, held by 131 parent companies. ARR
ownership for the 2021/2022 planning period was unconcentrated with
an HHI of 700.

Market Behavior• Self Scheduled FTRs. For the 2021/2022 planning period, 26.1 percent ofeligible ARRs were self scheduled as FTRs.

Market Performance• ARRs as an Offset to Congestion. ARRs have not served as an effective

mechanism to return all congestion revenues to load. For the 2020/2021
planning period, ARRs offset only 46.2 percent of total congestion.
Congestion payments by load in some zones were more than offset andcongestion payments in some zones were less than offset. Load has
been underpaid congestion revenues by $2.4 billion from the 2011/2012
planning period through the 2020/2021 planning period. The cumulative
offset for that period was 73.7 percent of total congestion.

• ARR Payments. For the 2020/2021 planning period, the ARR target

allocations, which are based on the nodal price differences from theAnnual FTR Auction, were $517.1 million, while PJM collected $691.2
million from the combined Long Term, Annual and Monthly Balanceof Planning Period FTR Auctions, making ARRs revenue adequate. For
the 2019/2020 planning period, the ARR target allocations were $752.2
million while PJM collected $982.0 million from the combined Annual
and Monthly Balance of Planning Period FTR Auctions.

• Residual ARRs. Residual ARRs are only available on contract paths

prorated in Stage 1 of the annual ARR allocation, are only effective for© 2021 Monitoring Analytics, LLC

single, whole months and cannot be self scheduled. Residual ARR clearing
prices are based on monthly FTR auction clearing prices. Residual ARRs
with negative target allocations are not allocated to participants. Instead
they are removed and the model is rerun.
In the 2020/2021 planning period, PJM allocated a total of 25,028.0 MW
of residual ARRs with a total target allocation of $11.7 million, downfrom 27,233.2 MW, with a total target allocation of $12.4 million, in the
2019/2020 planning period.

• ARR Reassignment for Retail Load Switching. There were 29,776 MW of

ARRs associated with $426,700 of revenue that were reassigned in the2020/2021 planning period. There were 31,683 MW of ARRs associatedwith $657,300 of revenue that were reassigned for the same time frameof the 2019/2020 planning period.

Financial Transmission Rights
Market Design• Monthly Balance of Planning Period FTR Auctions. The design of theMonthly Balance of Planning Period FTR Auctions was changed effectivewith the 2020/2021 planning period. The new design includes auctions foreach remaining month in the planning period. The prior design included
auctions for the next three individual months plus remaining quarters.

Market Structure• Patterns of Ownership. For the Monthly Balance of Planning Period

Auctions, financial entities purchased 84.5 percent of prevailing flow
and 91.9 percent of counter flow FTRs for January through June, 2021.
Financial entities owned 78.3 percent of all prevailing and counter flow
FTRs, including 71.7 percent of all prevailing flow FTRs and 85.9 percent
of all counter flow FTRs during the period from January through June
2021. Self scheduled FTRs account for 3.0 percent of all FTRs held.

• Market Concentration. For prevailing flow obligation FTRs in the Monthly
Balance of Planning Period Auctions for the 2020/2021 planning period,

2021 Quarterly State of the Market Report for PJM: January through June 687

2021 Quarterly State of the Market Report for PJM: January through June

all market periods were unconcentrated. For counter flow obligation
FTRs for the 2020/2021 planning period, two periods were moderately
concentrated and all others were unconcentrated. All periods were highly
concentrated for FTR options. FTR options in the Annual FTR Auction
were moderately concentrated.

Market Behavior• Sell Offers. In a given auction, market participants can sell FTRs acquired

in preceding auctions or preceding rounds of auctions. In the 2021/2024
Long Term FTR Auction, total participant FTR sell offers were 446,464
MW. In the 2021/2022 Annual FTR Auction, total participant FTR selloffers were 466,575 MW. In the Monthly Balance of Planning Period FTR
Auctions for the 2020/2021 planning period, total participant FTR selloffers were 16,226,420 MW.

• Buy Bids. In the 2021/2024 Long Term FTR auction, total FTR buy bids

were 2,743,836 MW, up 23.9 percent from 2,213,927 MW the previous
long term auction. There were 2,070,424 MW of buy and self scheduledbids in the 2021/2022 Annual FTR Auction, down 12.3 percent from
2,361,145 MW the previous planning period. The total FTR buy bids from
the Monthly Balance of Planning Period FTR Auctions for the 2020/2021
planning were 35,023,755 MW.

• FTR Forfeitures. Total FTR forfeitures were $4.6 million for the 2020/2021

planning period. On May 20, 2021, FERC issued an order ruling the $0.01
definition of an increase in the value of an FTR unjust and unreasonable,
but upheld the other parts of PJM’s forfeiture rule, and required PJM tomodify the rule.

• Credit. There were five collateral defaults in 2021. There were five payment

defaults in 2021 not involving GreenHat Energy, LLC for a total of $1.8
million. GreenHat Energy’s default payments ended with the 2020/2021
planning period. GreenHat Energy accrued total accrued payment defaults
of $162.0 million, including the auction liquidation costs.4 In addition,
PJM added the settlement fee and claimant payee funds to the default

4 See the 2019 Quarterly State of the Market Report for PJM: January through June for a more complete explanation of credit issues that
occurred in 2019.

688

Section 13 FTRs and ARRs

allocation, resulting in allocations of $12.5 million and $5.0 million fora total of $179.5 million.

Market Performance• Quantity. The 2021/2023 Long Term FTR Auction cleared 426,602 MW(15.5 percent) of FTR buy bids, up 54.8 percent from 275,655 (12.5 percent)in the 2020/2023 Long Term FTR Auction. The Long Term FTR Auction
also cleared 77,230 MW (17.3 percent) of FTR sell offers, compared to49,411 (17.4 percent), a 56.3 percent increase.

• In the 2021/2024 Long Term FTR Auction, 426,602 MW (15.5 percent) of

buy bids cleared and 77,230 MW (17.3 percent) of sell offers cleared. In
the Annual FTR Auction for the 2021/2022 planning period 562,293 MW(27.2 percent) of buy and self schedule bids cleared, down 3.7 percent
from 583,629 (24.7 percent) for the previous planning period. In the2020/2021 planning period, Monthly Balance of Planning Period FTR
Auctions cleared 5,686,087 (16.2 percent) of FTR buy bids and 2,770,301
MW (17.1 percent) of FTR sell offers. For the 2019/2020 planning period,
Monthly Balance of Planning Period FTR Auctions cleared 4,124,903(17.8 percent) of FTR buy bids and 1,995,514 MW (21.3 percent) of FTR
sell offers.

• Price. The weighted average buy bid FTR price in the 2021/2024 Long

Term FTR Auction was $0.05 per MW, down from $0.08 per MW for the
2020/2023 planning period. The weighted average buy bid FTR price in
the Annual FTR Auction for the 2021/2022 planning period was $0.56
per MW, up from $0.45 per MW in the 2020/2021 planning period. The
weighted average buy bid cleared FTR price in the Monthly Balance ofPlanning Period FTR Auctions for all periods of the 2020/2021 planning
period was $0.13 per MWh.

• Revenue. The 2021/2024 Long Term FTR Auction generated $93.9 millionof net revenue for all FTRs, up 153.1 percent from $37.1 million from the2020/2023 Long Term FTR Auction. The 2021/2022 Annual FTR Auction
generated $692.4 million in net revenue, up from $577.0 million for the
2020/2021 Annual FTR Auction. The Monthly Balance of Planning Period© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

FTR Auctions resulted in net revenue of $41.4 million in the 2020/2021
planning period, down from $52.9 million for the same time period in the
2019/2020 planning period.

• Revenue Adequacy. FTRs were paid at 98.7 percent of the target allocationlevel for the 2020/2021 planning period, including distribution of thecurrent surplus revenue.

• Profitability. FTR profitability is the difference between the revenue

received directly from holding an FTR plus any revenue from the saleof an FTR, and the cost of the FTR. In the 2020/2021 planning period,
physical entities made $79.9 million in profits on FTRs purchased directly(not self scheduled), up from $92.5 million in losses in the 2019/2020
planning period and financial entities made $280.6 million in profits, up
from $21.1 million in losses in the 2019/2020 planning period.

Markets Timeline
Any PJM member can participate in the Long Term FTR Auction, the Annual
FTR Auction and the Monthly Balance of Planning Period FTR Auctions.
Table 13-2 shows the date of first availability and final closing date for all
annual ARR and FTR products.
Table 13-2 Annual FTR product dates
Auction2021/2024 Long Term
2019/2020 ARR
2019/2020 Annual

Initial Open Date
6/2/2020
3/2/2020
4/7/2020

Final Close Date
3/2021
4/3/2020
5/4/2020

Recommendations
Market Design• The MMU recommends that the current ARR/FTR design be replacedwith defined congestion revenue rights (CRRs). A CRR is the right toactual congestion that is paid by physical load at a specific bus, zone oraggregate. (Priority: High. First reported 2015. Status: Not adopted.)© 2021 Monitoring Analytics, LLC

ARR• The MMU recommends that the ARR/FTR design be modified to ensurethat the rights to all congestion revenues are assigned to load. (Priority:
High. First reported 2015. Status: Not adopted.)• The MMU recommends that all historical generation to load paths beeliminated as a basis for assigning ARRs. The MMU recommends thatthe current design be replaced with a design in which the rights to actual
congestion paid are assigned directly to the load that paid that congestion
by node. (Priority: High. First reported 2015. Status: Partially adopted.)• The MMU recommends that, under the current FTR design, the rights to allcongestion revenue be allocated as ARRs prior to sale as FTRs. Reductions
for outages and increased system capability should be reserved for ARRs
rather than sold in the Long Term FTR Auction. (Priority: High. First
reported 2017. Status: Not adopted.)• The MMU recommends that IARRs be eliminated from PJM’s tariff, butthat if IARRs are not eliminated, IARRs should be subject to the sameproration rules that apply to all other ARR rights. (Priority: Low. First
reported 2018. Status: Not adopted.)

FTR• The MMU recommends that FTR funding be based on total congestion,

including day-ahead and balancing congestion. (Priority: High. First
reported 2017. Status: Not adopted.)• The MMU recommends that PJM enforce the FTR auction bid limits at theparent company level starting immediately. (Priority: High. First reported
2020. Status: Adopted 2021.)• The MMU recommends a requirement that the details of all bilateral FTR

transactions be reported to PJM. (Priority: High. First reported 2020.
Status: Not adopted.)• The MMU recommends that PJM continue to evaluate the bilateralindemnification rules and any asymmetries they may create. (Priority:
Low. First reported 2018. Status: Not adopted.)

2021 Quarterly State of the Market Report for PJM: January through June 689

2021 Quarterly State of the Market Report for PJM: January through June

• The MMU recommends that PJM reduce FTR sales on paths withpersistent overallocation of FTRs, including a clear definition of persistentoverallocation and how the reduction will be applied. (Priority: High. First
reported 2013. Status: Partially adopted, 2014/2015 planning period.)• MMU recommends that PJM eliminate generation to generation paths
and all other paths that do not represent the delivery of power to load.
(Priority: High. First reported 2018. Status: Not adopted.)• The MMU recommends that the Long Term FTR product be eliminated. If
the Long Term FTR product is not eliminated, the Long Term FTR Market
should be modified so that the supply of prevailing flow FTRs in the Long
Term FTR Market is based solely on counter flow offers in the Long Term
FTR Market. (Priority: High. First reported 2017. Status: Not adopted.)• The MMU recommends that PJM improve transmission outage modelingin the FTR auction models, including the use of probabilistic outage
modeling. (Priority: Low. First reported 2013. Status: Not adopted.)• The MMU recommends that the forfeiture amount from the FTR forfeiturerule be based on the correct hourly cost of an FTR, rather than a simple
daily price divided by 24. (Priority: High. First reported 2018. Status:
Adopted 2019.)

Surplus•

The MMU recommends that all FTR auction revenue be distributed to ARR
holders monthly, regardless of FTR funding levels. (Priority: High. First
reported 2015. Status: Not adopted.)• The MMU recommends that, under the current FTR design, all congestion

revenue in excess of FTR target allocations be distributed to ARR holders
on a monthly basis. (Priority: High. First reported 2018. Status: Not
adopted.)• The MMU recommends that FTR auction revenues not be used by PJM tobuy counter flow FTRs for the purpose of improving FTR payout ratios.5(Priority: High. First reported 2015. Status: Not adopted.)

FTR Subsidies• The MMU recommends that PJM eliminate portfolio netting to eliminate

cross subsidies among FTR market participants. (Priority: High. First
reported 2012. Status: Not adopted. Rejected by FERC.)• The MMU recommends that PJM eliminate subsidies to counter flow

FTRs by applying the payout ratio to counter flow FTRs in the same way
the payout ratio is applied to prevailing flow FTRs. (Priority: High. First
reported 2012. Status: Not adopted.)• The MMU recommends that PJM eliminate geographic cross subsidies.
(Priority: High. First reported 2013. Status: Not adopted.)• The MMU recommends that PJM examine the mechanism by which selfscheduled FTRs are allocated when load switching among LSEs occurs
throughout the planning period. (Priority: Low. First reported 2011.
Status: Not adopted.)

FTR Liquidation• The MMU recommends that the FTR portfolio of a defaulted member becanceled rather than liquidated or allowed to settle as a default cost on
the membership. (Priority: High. First reported 2018. Status: Not adopted.)Conclusion
Solutions
The annual ARR allocation should be designed to ensure that the rights to allcongestion revenues are assigned to load, without requiring contract path orpoint to point physical or financial transmission rights that are inconsistent
with the network based delivery of power and the actual way congestionis generated in security constrained LMP markets. When there are bindingtransmission constraints and locational price differences, load pays morefor energy than generation is paid to produce that energy. The difference iscongestion. As a result, congestion belongs to load and should be returned
to load.

5 See “PJM Manual 6: Financial Transmission Rights,” Rev. 26 (Jan. 27, 2021).

690

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

The current contract path based design should be replaced with a designin which the rights to actual congestion paid are assigned directly to theload that paid that congestion by node. The assigned right is to the actual
difference between load payments, both day-ahead and balancing, andrevenues paid to the generation used to serve that load. The load can retain
the right to the congestion revenues or sell the rights through auctions. The
correct assignment of congestion revenues to load is fully consistent withretaining FTR auctions for the sale by load of their congestion revenue rights.

IssuesIf the original PJM FTR approach had been designed to return congestion
revenues to load without use of the generation to load contract paths, and if
the distortions subsequently introduced into the FTR design not been added,
many of the subsequent issues with the FTR design and complex redesigns
would have been avoided. PJM would not have had to repeatedly intervenein the functioning of the FTR system in an effort to meet the artificial andincorrectly defined goal of revenue adequacy.
PJM has persistently and subjectively intervened in the FTR market in order toaffect the payments to FTR holders. These interventions are not appropriate.
For example, in the 2014/2015, 2015/2016 and 2016/2017 planning periods,
PJM significantly reduced the allocation of ARR capacity, and FTRs, in orderto guarantee full FTR funding. PJM reduced system capability in the FTR
auction model by including more outages, reducing line limits and including
additional constraints. PJM’s modeling changes resulted in significant
reductions in Stage 1B and Stage 2 ARR allocations, a corresponding reductionin the available quantity of FTRs, a reduction in congestion revenues assigned
to ARRs, and an associated surplus of congestion revenue relative to FTR
target allocations. This also resulted in a significant redistribution of ARRs
among ARR holders based on differences in allocations between Stage 1A andStage 1B ARRs. Starting in the 2017/2018 planning period, with the allocationof balancing congestion and M2M payments to load rather than FTRs, PJM
increased system capability allocated to Stage 1B and Stage 2 ARRs, but
continued to conservatively select outages to manage FTR funding levels.

© 2021 Monitoring Analytics, LLC

PJM has intervened aggressively in the FTR market since its inception inorder to meet various subjective objectives including so called revenue
adequacy. PJM should not intervene in the FTR market to subjectively manage
FTR funding. PJM should fix the FTR/ARR design and then should let themarket work to return congestion to load and to let FTR values reflect actual
congestion.
Load should never be required to subsidize payments to FTR holders, regardlessof the reason.6 The FERC order of September 15, 2016, introduced a subsidy to
FTR holders at the expense of ARR holders.7 The order requires PJM to ignore
balancing congestion when calculating total congestion dollars available tofund FTRs. As a result, balancing congestion and M2M payments are assigned
to load, rather than to FTR holders, as of the 2017/2018 planning period. When
combined with the direct assignment of both surplus day-ahead congestionand surplus FTR auction revenues to FTR holders, the Commission’s ordershifted substantial revenue from load to the holders of FTRs and further
reduced the offset to congestion payments by load. This approach ignoresthe fact that load pays both day-ahead and balancing congestion, and thatcongestion is defined, in an accounting sense, to equal the sum of day-ahead
and balancing congestion. Eliminating balancing congestion from the FTR
revenue calculation requires load to pay twice for congestion. Load pays total
congestion and pays negative balancing congestion again. The fundamental
reasons that there has been a significant and persistent difference between dayahead and balancing congestion include inadequate transmission modeling in
the FTR auction and the role of UTCs in taking advantage of these modelingdifferences and creating negative balancing congestion. There is no reason to
impose these costs on load.
These changes were made in order to increase the payout to holders of FTRs
who are not loads. Increasing the payout to FTR holders at the expense of
the load is not a supportable market objective. PJM should implement an
FTR design that calculates and assigns congestion rights to load rather thancontinuing to modify the current, fundamentally flawed, design.
6 Such subsidies have been suggested repeatedly. See FERC Dockets Nos. EL13-47-000 and EL12-19-000.
7 See 156 FERC ¶ 61,180 (2016), reh’g denied, 156 FERC ¶ 61,093 (2017).

2021 Quarterly State of the Market Report for PJM: January through June 691

2021 Quarterly State of the Market Report for PJM: January through June

Load was made significantly worse off as a result of the changes made to the
FTR/ARR process by PJM based on the FERC order of September 15, 2016.
ARR revenues were significantly reduced for the 2017/2018 FTR Auction,
the first auction under the new rules. ARRs and self scheduled FTRs offset
only 49.5 percent of total congestion costs for the 2017/2018 planning period
rather than the 58.0 percent offset that would have occurred under the priorrules, a difference of $101.4 million.
A subsequent rule change was implemented that modified the allocation of
surplus auction revenue to load. Beginning with the 2018/2019 planning
period, surplus day-ahead congestion and surplus FTR auction revenue areassigned to FTR holders only up total target allocations, and then distributed
to ARR holders.8 ARR holders will only be allocated this surplus after full
funding of FTRs is accomplished. While this rule change increased the level ofcongestion revenues returned to load, the rules do not recognize ARR holders’rights to all congestion revenue. With this rule in effect for the 2020/2021
planning period, ARRs and FTRs offset 46.2 percent of total congestion.
The complex process related to what is termed the overallocation of Stage 1A
ARRs are entirely an artificial result of reliance on the contract path model in
the assignment of FTRs. For example, there is a reason that transmission is not
built to address the Stage 1A overallocation issue. The Stage 1A overallocation
issue is a fiction based on the use of outdated and irrelevant generation toload contract paths to assign Stage 1A rights that have nothing to do withactual power flows.

Proposed Design
To address the issues with the current contract path based ARR/FTR market
design, the MMU recommends that the current design be replaced with adesign in which the rights to actual congestion paid are assigned directly
to the load that paid that congestion by node. The assigned right would be
the actual difference between load payments, both day-ahead and balancing,and revenues paid to the generation used to serve that load. The load could
retain the right to the network congestion or sell the right through auctions.
8 163 FERC ¶61,165 (2018).

692

Section 13 FTRs and ARRs

The correct assignment of congestion revenues to load is fully consistent
with retaining FTR auctions for the sale by ARR holders of their congestion
revenue rights.
With a network assignment of actual congestion, there would be no crosssubsidies among rights holders and no over or under allocation of rights relative
to actual network market solutions. There would be no revenue shortfalls ascongestion payments equal congestion collected. The risk of default would
be isolated to the buyer and seller of the right, and any default would not besocialized to other right holders. In the case of a defaulting buyer, the rights tothe congestion revenues would revert to the load. There would be no risk of a
network right flipping in value from positive to negative, because congestionis always the positive difference between what load pays for energy, andgeneration is paid for energy as a result of transmission constraints.
The MMU proposal requires the calculation of constraint specific congestion
and the calculation of that specific constraint’s congestion related charges
to each physical load bus downstream of that constraint. Under the MMU
proposal, the constraint specific congestion calculated by hour, from both
the day-ahead and balancing market would be paid directly to the physicalload as a credit against the associated load serving entity’s (LSE) energy bill.
This right to the congestion is defined as the congestion revenue right (CRR)
that belongs to the physical load at a defined bus, zone or aggregate. The LSE
could choose to sell all or a portion of the CRR through auctions.
A CRR is the right to actual, realized network related congestion that is paidby physical load at a specific bus, zone or aggregate. Under the MMU proposala bus, zone or aggregate specific CRR could be sold as a defined share of theactual congestion. For example, an LSE could sell 50 percent of its congestion
revenue right for the planning period to a third party. The third party buyer
would then be entitled to 50 percent of the congestion that will be credited
to that specific bus, zone or aggregate for the planning period. The remaining
50 percent of the congestion credit for the specified bus, zone or aggregate
would be paid to the LSE along with auction clearing price for the 50 percent
of CRR that was sold to the third party. Depending on actual congestion, an© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

LSE selling its congestion revenue rights could be better or worse off than if
it retained its rights.
Under the MMU proposal, the LSE would be able to set reservation prices in
the auction for the sale of portions or all of its CRR. Third parties would havean opportunity to bid for the offered portions of the CRR, and the market forthe congestion revenue associated with the specified bus, zone or aggregate
would clear at a price. If the reservation price of an identified portion of theoffered CRR was not met at the clearing price, that portion of the offered CRR
would remain with the load. Auctions could be annual and/or monthly.
Under the MMU proposal, point to point rights (FTRs) could exist as a separate,
self-funded hedging product based on simultaneously feasible prevailing andcounter flows in a PJM managed network based auction. The only supply andthe only source of revenues in the point to point market for prevailing flow
FTRs would be counter flow offers and direct payments for specific rights.

Auction Revenue Rights
Auction Revenue Rights (ARRs) are the mechanism used to assign congestion
rights to load, using an archaic contract path based approach, and sell thoserights to FTR buyers in various auctions. ARR values are based on nodal
price differences established by cleared FTR bids in the Annual FTR Auction.
ARR sellers have no opportunity to define a price at which they are willingto sell and must accept the prices as defined by FTR buyers. ARR revenues
are a function of FTR auction participants’ expectations of congestion, risk,
competition and available supply. But some auction revenues may be returned
to FTR buyers, despite the fact that FTR buyers willingly paid a definedprice for FTRs. PJM has significant discretion over the level of supply madeavailable to FTR buyers. The appropriate goals of that discretion should besignificantly limited and defined clearly in the tariff.
ARRs are available only as obligations (not options) and only as a 24 hour
product. ARRs are available to the nearest 0.1 MW. The ARR target allocation
is equal to the product of the ARR MW and the price difference between the

ARR sink and source from the Annual FTR Auction.9 ARR target allocations
are a set value at the time of the Annual FTR Auction. It is logically possible
for ARRs to be revenue inadequate if the money collected from the FTR
auction is not enough to pay the entirety of ARR target allocations for theplanning period. This is extremely unlikely and can only happen if there is amodeling difference between the system model used for ARRs and the systemmodel used for FTRs and the FTR MW are reduced. An ARR’s target allocation,or value, which is established from the Annual FTR Auction, can be a benefit
or liability depending on the price difference between sink and source.
The goal of the ARR/FTR design should be to provide an efficient mechanism
to ensure that load receives the rights to all congestion revenues. In the current
design, all auction revenues should be paid to ARR holders.
The quantity of the product made available as ARRs or for sale in the
FTR auctions is defined as system capability, meaning the capacity of thetransmission system to deliver power. But system capability is not congestionand system capability is not the difference in congestion prices acrosstransmission contract paths nor the potential for such difference. The conceptof system capability is not relevant to assigning the rights to congestion
revenues to load. The use, or misuse, of the concept of system capability inassigning ARRs is derived entirely from the contract path approach used in
the PJM design. The definition of ARRs based on contract paths led to themistaken idea that some transmission system capacity was used by ARRs
but some was not and that both the ARR capability and the excess capability
was available for sale as FTRs. In the current approach, system capability
available to ARR holders is limited by the system capability made available
in PJM’s annual FTR transmission system market model. PJM’s annual FTR
transmission market model represents annual, expected system capability,
modified by PJM to achieve PJM’s goal of guaranteeing revenue equal totarget allocations for FTRs, and subject to the requirement that all Stage1A
ARR requests must be allocated. Stage 1A ARR right requests are guaranteed
and system capability necessary to accommodate the rights must be included
in PJM’s annual FTR transmission system market model.
9 These nodal prices are a function of the market participants’ annual FTR bids and binding transmission constraints.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 693

2021 Quarterly State of the Market Report for PJM: January through June

Market Design
ARRs have been available to network service and firm, point to pointtransmission service customers since June 1, 2003, when the annual ARR
allocation was first implemented for the 2003/2004 planning period. The
initial allocation covered the Mid-Atlantic Region and the APS Control Zone.
For the 2006/2007 planning period, the choice of ARRs or direct allocation
FTRs was available to eligible market participants in the AEP, DAY, DUQ andDOM Control Zones. For the 2007/2008 and subsequent planning periods
through the present, all eligible market participants were allocated ARRs.
Each March, PJM allocates annual ARRs to eligible customers in a three stage
process: Stage 1A, Stage 1B and Stage 2B. Stage 1A ARRs are assigned basedon historic contract paths and Stage 1A ARRs must be preserved for at leastten planning periods regardless of system or regulatory changes.10
In Stage 1A, LSEs can obtain ARRs, based on their lowest daily peak load in
the prior twelve month period, and based on generation to load contract paths
that reflect generation resources that had historically served load, or their
qualified replacements if the resource has retired and PJM has replaced it. The
historical reference year is the year in which PJM markets were implemented,
which is 1999 for the original zones, or the year in which a zone joined
PJM. Firm, point to point transmission service customers can obtain Stage 1A
ARRs, up to 50 percent of the MW of firm, point to point transmission service
provided between the receipt and delivery points for the historical reference
year, subject to a cap of lowest daily peak load in the prior year. Network
service customers can obtain Stage 1A ARRs based on the MW of firm service
provided during the reference year, subject to a cap of lowest daily peak loadin the prior year. Stage 1A ARRs cannot be prorated. If Stage 1A ARRs arefound to be infeasible, transmission system upgrades must be undertaken to
maintain feasibility.11
In Stage 1B, network transmission service customers can obtain ARRs basedon their share of zonal peak load, based on generation to load contract paths,
up to the difference between their share of zonal peak load and Stage 1A
10 See “PJM Manual 6: Financial Transmission Rights,” Rev. 26(Jan 27, 2021 at 23.
11 See “PJM Manual 6: Financial Transmission Rights,” Rev 26 (Jan. 27, 2021).

694

Section 13 FTRs and ARRs

allocations. Firm, point to point transmission service customers can obtain
ARRs based on the MW of long-term, firm, point to point service provided
between the receipt and delivery points for the historical reference year.
In Stage 2, network transmission service customers can obtain ARRs fromany hub, control zone, generator bus or interface pricing point to any part oftheir aggregate load in the control zone or load aggregation zone up to their
total peak network load in that zone. Firm, point to point transmission service
customers can obtain ARRs consistent with their transmission service as inStage 1A and Stage 1B.
When ARR holders self schedule FTRs, the ARR holders choose to be paid basedon variable target allocations rather than the fixed ARR value determined in
the annual FTR auction. ARR holders can self schedule ARRs as FTRs during
the Annual FTR Auction.12 ARRs can be traded between LSEs prior to the firstround of the Annual FTR Auction.
Effective for the 2015/2016 planning period, when residual zonal pricing wasintroduced, ARRs default to sinking at the load settlement point if different
than the zone, but the ARR holder may elect to sink their ARR at the zone
instead.13
In 2016, FERC ordered PJM to remove retired resources from the generation
to load contract paths used to allocate Stage 1A ARRs.14 PJM replaced retired
units with operating generators, termed qualified replacement resources(QRRs).15 Existing Stage 1A resources retain their current allocations, while
ARR allocations to QRRs that replace retired Stage 1A resources are prorated
based on the feasibility of these ARRs after existing resources are allocated.
As a result of this proration, ARRs for QRRs have lower priority than ARRs
from generators that existed in 1998.
Generation to load paths, even from active generators, are based on acontract path model rather than a network model. Generation to load contract
12 OATT Attachment K 7.1.1.(b).
13 See “PJM Manual 6: Financial Transmission Rights,” Rev. 26 (Jan 27, 2021) at 35.
14 156 FERC ¶ 61,180 (2016).
15 See FERC Docket No. EL16-6-003.

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

paths should not be used as a basis for assigning the rights to congestion
revenue. Contract paths are not an accurate representation of the reasons thatcongestion revenues are paid or of how load is served in a network and will,by definition, not accurately measure the exposure of load to congestion.

Market Structure
ARRs are allocated on an annual basis. For the 2021/2022 planning period
there were 1,459 individual participants, held by 131 parent companies.
The ownership of ARRs was unconcentrated, with an HHI of 851, for the
2020/2021 planning period.

Market Performance

Table 13-4 Share of ARRs that source in/out of load zone: 2021/2022
planning period

VolumeTable 13-3 shows the MW of ARR allocations for each round of the 2020/2021
and 2021/2022 planning periods.
Table 13-3 Annual ARR allocation volume: 2020/2021 and 2021/2022
planning periods
Planning
Period2020/2021

2021/2022

Stage
1A
1B
2

Total
1A
1B
2

Round
0
1
2
3
4
Total
0
1
2
3
4
Total

Total

© 2021 Monitoring Analytics, LLC

RequestedCount
30,444
16,832
5,760
4,634
3,233
13,62760,90327,726
18,633
8,105
8,946
6,335
23,38669,745

Table 13-4 shows the share of ARR MW, by stage, for ARRs with paths thatsource inside or outside the zone where the load is located, for the 2021/2022
planning period. Table 13-4 shows that 83.2 percent of the ARR MW arebased on generation inside the zone where the ARR load is located and 16.8
percent of the ARR MW are based on generation outside the zone where the
ARR load is located. This illustrates one of the fundamental issues with thepath based approach which originated in a cost of service design where mostload was served by, or assumed to be served by, generation in the same zone
as load. In fact, in the PJM market, which operates as an integrated network,a significant proportion of congestion is based on constraints that are not in
the same zone as load. The path based approach cannot reflect the actual
congestion paid by load.

Requested
Volume(MW)
76,36030,82022,061
21,69021,27965,030172,210
66,11836,067
19,307
19,23819,26757,812
159,997

ClearedVolume(MW)
76,34021,916
2,593
3,832
4,001
10,426108,682
66,11825,476
2,875
3,679
4,586
11,140102,734

ClearedVolume100.0%
71.1%
11.8%
17.7%
18.8%
16.0%
63.1%
100.0%
70.6%
14.9%
19.1%
23.8%
19.3%
64.2%

Uncleared
Volume
(MW)
20
8,904
19,46817,85817,27854,60463,5280
10,591
16,432
15,55914,681
46,67257,263

Uncleared
Volume
0.0%
28.9%
88.2%
82.3%
81.2%
84.0%
36.9%
0.0%
29.4%
85.1%
80.9%
76.2%
80.7%
35.8%

ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
EXT
JCPLC
MEC
PE
PECO
PEPCO
PPL
PSEG
REC
Total

Stage 1A
Out of Zone
19.7%
9.0%
7.8%
16.6%
39.8%
0.0%
62.1%
0.3%
23.1%
28.9%
52.7%
28.2%
50.0%
1.6%
29.1%
16.8%
2.5%
20.8%
0.0%
18.8%
0.0%
12.3%

In Zone
27.2%
56.9%
52.8%
50.6%
30.3%
74.6%
5.3%
61.1%
49.5%
30.7%
0.0%
50.5%
0.0%
71.4%
55.8%
62.6%
58.2%
24.5%
69.0%
34.1%
0.0%
52.0%

Stage 1B
Out of Zone
7.6%
1.4%
2.6%
1.9%
0.4%
0.0%
1.6%
0.0%
2.6%
0.1%
19.7%
0.3%
49.6%
0.1%
1.2%
0.1%
7.5%
0.6%
0.0%
5.8%
0.0%
2.1%

In Zone
40.5%
27.4%
35.5%
14.8%
11.7%
15.9%
5.7%
37.6%
9.3%
24.8%
2.0%
0.0%
0.0%
1.2%
8.8%
16.7%
29.0%
0.8%
20.4%
18.1%
0.0%
22.7%

Stage 2Out of Zone
0.4%
0.0%
0.1%
2.7%
4.6%
0.0%
8.5%
0.0%
6.1%
0.6%
10.2%
21.0%
0.4%
17.2%
0.0%
0.0%
0.3%
0.9%
1.3%
10.2%
100.0%
2.3%

In Zone
4.6%
5.2%
1.2%
13.4%
13.3%
9.4%
16.8%
0.9%
9.5%
14.8%
15.4%
0.0%
0.0%
8.6%
5.0%
3.8%
2.5%
52.3%
9.3%
13.0%
0.0%
8.5%

2021 Quarterly State of the Market Report for PJM: January through June 695

2021 Quarterly State of the Market Report for PJM: January through June

Stage 1A Infeasibility
Stage 1A ARRs are allocated for a year, but guaranteed for 10 years, withthe ability for a participant to opt out of any planning period within the
10 years. PJM conducts a simultaneous feasibility analysis to determine thetransmission upgrades required to ensure that the long term ARRs can remain
feasible. The rules provide that if a simultaneous feasibility test violation
occurs in any year, PJM will identify or accelerate any transmission upgrades
to resolve the violation and these upgrades will be recommended for inclusionin the PJM RTEP process. But such transmission upgrades must pass PJM’s
RTEP process.
PJM’s transmission planning process (RTEP) does not identify a need for
new transmission associated with Stage 1A overallocations because there is,in fact, no need for new transmission associated with Stage 1A ARRs. The
Stage 1A overallocation issue is a fiction based on the use of outdated andirrelevant generation to load contract paths to assign Stage 1A rights thathave nothing to do with actual power flows. This continues to be true evenwith the replacement of retired generating units.
For the 2019/2020 planning period, Stage 1A of the Annual ARR Allocation
was infeasible, resulting in an over allocation of ARRs on the affected facilities.
As a result, modeled system capability, in excess of actual system capability,
was provided to the Stage 1A ARRs and added to the FTR auction. According
to Section 7.4.2 (i) of the OATT, the capability limits of the binding constraints
rendering these ARRs infeasible must be increased in the model and theseincreased limits must be used in subsequent ARR and FTR allocations andauctions for the entire planning period, except in the case of extraordinary
circumstances. Stage1A related over allocations have to be made up elsewhere
in PJM’s FTR market model, in the form of reduced system capability, in orderfor PJM to achieve its goal of fully funding FTRs.
Table 13-5 shows the MW quantity and count of overloaded facilities and thereasons for the modeled overload. In order to eliminate the infeasibilities forthe requested Stage 1A ARR allocations, PJM was required to raise the modeledcapacity limits on 67 facility/contingency pairs, 53 of which were internal to696

Section 13 FTRs and ARRs

PJM, a total of 7,704.16 There were no overloaded facilities associated withMISO due to transmission outages.
Table 13-5 Stage 1A overloaded facility reasons and MW
ReasonNetwork Load
Network Load
Transmission OutageType
M2M Flowgate
Pseudo Tie Flowgate
Internal PJM

MW
1,767
56
5,881

Count
21
1
53

Figure 13-1 shows the predicted and estimated impact of Stage 1A infeasibilities
on funding for the 2012/2013 through 2020/2021 planning periods, as wellas the predicted impact on funding for the 2021/2022 planning period. The
predicted funding is based on the infeasible ARR MW and the nodal priceof the source and sink in the Annual FTR Auction. The estimated fundingis calculated assuming every infeasible ARR MW is self scheduled, and uses
the hourly congestion LMP values of the applicable day-ahead hours. In the
2016/2017 planning period, Stage 1A ARR infeasibilities accounted for $293.5
million in estimated over allocation. Predicted funding impacts are lower inthe 2017/2018, 2018/2019 and 2019/2020 planning periods from the previous
two planning periods, likely as a result of PJM relaxing model constraints.
PJM’s newly implemented Qualified Replacement Resource rules may slightly
reduce revenue inadequacy from Stage 1A ARRs, but do not eliminate theactual issues with historical Stage 1A resources.

16 PJM 2021/2022 Stage 1A Over allocation notice, PJM FTRs, <http://www.pjm.com/-/media/markets-ops/ftr/annual-arr-allocation/20212022/2021-2022-stage-1a-over-allocation-notice.ashx?la=en> (July 6, 2021).

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Figure 13-1 Stage 1A Infeasibility funding impact

Table 13-6 Qualified Replacement Resource results: 2021/2022

$350

Zone
AEP/DAY
ATSI
ComEd
DEOK
Dominion
DLCO
EKPC
Midatlantic
OVEC
Total

Predicted
Estimated$300

Funding Impact (Millions)

$250

$200

Replacement (All)7,568.0
3,736.0
4,593.5
1,729.2
5,676.8
211.7
229.3
15,530.7
459.2
39,734.4

Replacement (Rate-based)
1,838.3
50.4
4.5
57.6
4,824.0
0.0
0.0
375.9
1,854.0
9,004.7

ARR Reassignment for Retail Load Switching

$150

$100

$50

$-

Historical Retired
10,045.9
5,614.3
5,954.8
2,630.0
4,210.6
834.0
198.1
19,830.2
0.049,317.9

12/13

13/14

14/15

15/16

16/17

17/18

18/19

19/20

20/21

21/22

Table 13-6 shows the MW of retired generation sources for Stage 1A ARRs,
the QRR MW assigned by PJM for all resources and the replacement MW thatwere considered rate based. A rate based unit is a replacement generator thatis owned by the ARR holder, or subject to firm energy and capacity supply
contracts. PJM created the synthetic zone Midatlantic for the QRR assignment
although it is not clear why.

PJM rules provide that when load switches between LSEs during the planning
period, an LSE gaining load in the same control zone is allocated a proportional
share of positively valued ARRs and residual ARRs within the control zone
based on the shifted load.17 ARRs are reassigned to the nearest 0.001 MW andmay be reassigned multiple times over a planning period. The reassignmentof positively valued ARRs supports competition by ensuring that the offset tocongestion follows load, thereby removing a barrier to competition among
LSEs and, by ensuring that only ARRs with a positive value are reassigned,
preventing an LSE from assigning poor ARR choices to other LSEs. However,when ARRs are self scheduled as FTRs, the self scheduled FTRs do not follow
load that shifts while the ARRs do follow load that shifts, and this may resultin lower value of the ARRs for the receiving LSE compared to the total value
held by the original ARR holder.
There were 31,683 MW of ARRs associated with $657,300 of revenue thatwere reassigned for the 2019/2020 planning period. There were 29,776 MW
of ARRs associated with $426,700 of revenue that were reassigned in the2020/2021 planning period.
Table 13-7 summarizes ARR MW and associated revenue reassigned for
network load in each control zone where changes occurred between June2019 and May 2021.
17 See “PJM Manual 6: Financial Transmission Rights,” Rev. 26 (Jan. 27, 2021).

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 697

2021 Quarterly State of the Market Report for PJM: January through June

Table 13-7 ARRs and ARR revenue automatically reassigned for network loadchanges by control zone: June 2019 through May 2021

Control Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DUQ
DOM
DPL
EKPC
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
Total

ARRs Reassigned(MW-day)
2019/2020
2020/2021(12 months)(12 months)
373
417
5,435
2,613
1,383
1,386
2,865
3,012
2,252
2,419
2,583
2,588
765
687
839
827
1,622
1,526
632
431
702
736
0
0
1,032
927
540
608
0
0
3,196
3,605
570
603
1,947
2,176
3,538
3,358
1,340
1,506
69
352
31,68329,776

ARR Revenue Reassigned[Dollars (Thousands) per MW-day]
2019/2020
2020/2021(12 months)(12 months)
$4.8
$2.9
$151.0
$25.2
$39.4
$20.8
$42.6
$25.5
$103.9$151.1
$27.1
$16.8
$9.3
$5.1
$58.3
$26.2
$5.8
$6.7
$6.2
$4.4
$52.2
$21.7
$0.0
$0.0
$4.8
$4.3
$5.6
$2.9
$0.0
$0.0
$24.8
$24.7
$15.7
$7.3
$35.4
$27.3
$38.3
$38.5
$31.8
$15.3
$0.2
$0.1
$657.3$426.7

Revenue
ARRs are allocated to qualifying customers rather than sold, so ARR revenue(target allocation) is different from the revenue that results from the FTR
auctions which generally exceeds the sum of the ARR target allocations.
Figure 13-2 shows the revenue per ARR MW held for each month of the
2010/2011 planning period through the 2019/2020 planning period. The
revenue per ARR MW held do not include target allocation related payouts forself scheduled FTRs, but do include Residual ARRs starting in August 2012.

FTR prices increased in the 2014/2015 Annual FTR Auction in part as a resultof reduced supply caused by PJM’s assumption of more outages in the model
relative to prior years. The decrease in system capability caused by PJM’smore conservative modeling of the FTR market model reduced Stage 1B andStage 2 ARR allocations. The increased FTR prices resulted in an increase inrevenue per ARR MW, but fewer ARR MW. For the 2014/2015 planning period,
the total dollars per MW of ARR allocation was $11,279, while the previous
planning period resulted in revenue per MW of $6,692, a 68.5 percent increase
in revenue per allocated ARR MW. Some of the ARR MW lost from proration
were provided in the Residual ARR process, but the residual allocations are
not comparable to the ARRs awarded in the annual process because residual
ARR allocations change each month and cannot be self scheduled as FTRs.
For the 2015/2016 and 2016/2017 planning periods, the revenue per MW of
ARR allocation was $10,641.54 and $10,411. During these planning periods
PJM chose more restrictive modeling criteria, which did not release the full
capacity of the FTR model to account for revenue inadequacies. Beginningin the 2017/2018 planning period, when balancing congestion was removed
from FTR funding, PJM reinstated less restrictive modeling criteria, andthe revenue per MW of ARR decreased. For the 2017/2018 and 2018/2019
planning periods the revenue per MW of ARR was $5,168 and $6,841.
The revenue per MW value of ARRs for the 2020/2021 planning period
decreased 29.6 percent from the previous planning period (Figure 13-2).
Load pays balancing congestion costs, not included in Figure 13-2, which
reduce the revenue received by ARR holders. There is no support for theassertion made by proponents of shifting balancing congestion solely to loadthat higher ARR values would result (Figure 13-2).

PJM has had to repeatedly intervene in the functioning of the FTR system in aneffort to meet the artificial and incorrectly defined goal of revenue adequacy.

698

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Figure 13-2 Revenue per ARR MW paid to ARR holders compared tocongestion and FTR target allocations: 2010/2011 through 2020/2021$2,000$1,600$250,000,000$/ARR MWFTR Target Allocation
Congestion$200,000,000$1,400

Revenue/ARR MW$1,200$150,000,000$1,000$800$100,000,000

$600

$400

Monthly Average FTR Target Allocation$1,8002021/2022 planning period. While 12.3 percent of all ARR MW are Stage 1A
ARRs with sources outside the zone where load is located, those ARRs provide
32.7 percent of the total ARR revenues.

$50,000,000

This illustrates one of the fundamental issues with the path based approach
which originated in a cost of service design where most load was served by, or
assumed to be served by, generation in the same zone as load. In fact, in the
PJM market, which operates as an integrated network, a significant proportionof congestion is based on constraints that are not in the same zone as load.
The path based approach does not and cannot reflect the actual congestion
paid by load. The use of the path based approach is the fundamental sourceof the under assignment of congestion revenue rights to load in the ARR/FTR
model.
Table 13-8 Share of ARR revenue that sources in/out of load zone: 2021/2022
planning period

$200

$0

$0

ARR holders have limited options to pick source points for their ARRs. The
holders of Stage 1A rights are limited to specific historical sources (or PJM
defined replacement sources when resources retire), which are generally
sources within the same zone as the load. The source of a load zone’s actual
congestion is, in significant part, the result of transmission constraints that
separate that zone from resources external to that zone, not by constraints
that limit access to internal resources.
As a result, the congestion offset revenues per MW of internally sourced
Stage 1A ARR rights are less than the revenue per MW of Stage 1A ARR
rights from externally sourced resources. Table 13-8 shows the share of ARR
revenue, based on the Annual FTR Auction prices, by stage, for ARRs withpaths that source inside or outside the zone where the load is located, for the© 2021 Monitoring Analytics, LLC

ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DOM
DPL
DUKE
DUQ
EKPC
EXT
JCPLC
MEC
PE
PECO
PEPCO
PPL
PSEG
REC
Total

Stage 1A
Out of Zone
44.3%
10.4%
15.0%
94.0%
79.0%
0.0%
88.3%
0.8%
35.3%
75.5%
80.6%
79.0%
50.0%
(0.1%)
39.7%
38.2%
1.9%
88.1%
(0.0%)
34.6%
0.0%
32.7%

In Zone
18.2%
68.4%
61.0%
2.3%
12.8%
92.1%
0.2%
75.5%
52.5%
16.4%
(0.0%)
11.9%
0.0%
7.6%
58.9%
53.5%
75.1%
7.7%
88.5%
46.8%
0.0%
52.0%

Stage 1B
Out of Zone
6.4%
0.8%
1.1%
0.3%
0.5%
0.0%
2.0%
0.0%
1.5%
0.0%
6.9%
0.2%
49.6%
0.1%
1.3%
0.1%
5.0%
1.3%
(0.0%)
2.6%
0.0%
0.9%

In Zone
27.7%
17.9%
22.3%
1.3%
4.7%
3.5%
0.1%
23.2%
8.3%
4.1%
(0.1%)
0.0%
0.0%
0.6%
0.5%
6.2%
16.1%
0.3%
10.3%
2.7%
0.0%
11.1%

Stage 2Out of Zone
0.5%
0.0%
0.0%
2.4%
1.9%
0.0%
9.4%
0.0%
0.4%
0.4%
5.7%
8.9%
0.4%
84.7%
0.1%
0.0%
0.2%
0.2%
0.1%
7.7%
100.0%
1.4%

In Zone
2.9%
2.4%
0.6%
(0.3%)
1.1%
4.4%
0.0%
0.5%
2.0%
3.4%
7.0%
0.0%
0.0%
7.2%
(0.4%)
2.1%
1.7%
2.4%
1.1%
5.7%
0.0%
1.9%

2021 Quarterly State of the Market Report for PJM: January through June 699

2021 Quarterly State of the Market Report for PJM: January through June

Residual ARRs
Introduced August 1, 2012, Residual ARRs are available for eligible ARR
holders when a transmission outage was modeled in the Annual ARR
Allocation, but the transmission facility returns to service during the planning
period. Residual ARRs can only be allocated to participants whose ARRs wereprorated in Stage 1B and only to a maximum of the prorated reduction, so not
all available Residual ARRs are allocated. Residual ARRs are automaticallyassigned to eligible participants the month before the effective date, areeffective for a single month and cannot be self scheduled. Residual ARRtarget allocations are based on the clearing prices from FTR obligations in
the relevant monthly auction, may not exceed zonal network services peakload or firm transmission reservation levels and are only available up to theprorated ARR MW capacity as allocated in the Annual ARR Allocation. For
the following planning period, these Residual ARRs are available as ARRs
in the annual ARR allocation. Residual ARRs are a separate product fromincremental ARRs. Beginning with the June 2017 monthly auction, Residual
ARRs that would have cleared with a negative target allocation are notassigned to participants.18 In prior planning periods, PJM’s modeling of excess
outages in order to manage FTR market outcomes resulted in the allocationof some ARRs that would have been allocated in Stage 1B being allocated as
Residual ARRs on a month to month basis without the option to self schedule.
Table 13-9 shows the Residual ARRs allocated to participants and theassociated target allocations. The available volume is the total additional
capacity available to be allocated as Residual ARRs. The cleared volume is theresidual ARR capacity actually allocated to participants with prorated ARRs
based on the level of prorated ARRs in Stage 1B and the affected paths. In the2020/2021 planning period, PJM allocated a total of 25,028.0 MW of Residual
ARRs with a target allocation of $11.7 million. In the same time period for the
2019/2020 planning period, PJM allocated a total of 25,028.0 MW of residual
ARRs with a target allocation of $12.4 million.

18 See FERC Letter Order, Docket No. ER17-1057 (April 5, 2017).

700

Section 13 FTRs and ARRs

Table 13-9 Residual ARR allocation volume and target allocation: 2014/2015
planning period through 2020/2021 planning period
Planning Period
2014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021

Available Volume(MW)65,095.3
61,807.0
71,000.7
81,040.8
49,646.9
48,286.5
43,484.2

Cleared Volume(MW)
22,532.9
37,042.4
35,034.9
39,597.4
27,335.6
27,233.2
25,028.0

Cleared Volume
34.6%
59.9%
49.3%
48.9%
55.1%
56.4%
57.6%

Target Allocation$8,160,918.27$8,620,353.27$6,986,723.44$17,497,625.78$11,817,002.00$12,369,580.58$11,677,033.36

IARRs
In theory, Incremental Auction Revenue Rights (IARRs) are ARRs made available
by physical transmission system upgrades from customer funded transmission
projects or from merchant transmission or generation interconnection
requests. In order for a transmission project to result in IARRs, the project
must create simultaneously feasible incremental market flow capability in
PJM’s ARR market model, over and above all system capability being usedby existing allocated ARRs and/or would be used by granting any prorated
outstanding ARR requests, in the ARR market model.19
There are three sources of IARRs: IARRs based on a specific transmission
investment; IARRs based on merchant transmission or generationinterconnection projects; and IARRs based on RTEP upgrades. In the case ofa specific transmission investment, the participant elects desired IARR MW
between a specified source and sink and PJM and the affected transmission
owners determine the upgrades necessary to create incremental capability.20
In the other two cases, the participants paying for the upgrades are assigned
IARRs if any are created. There have been 13 successful IARR requests
totaling 2,990.1 MW. One IARR path of 64.5 MW was terminated (June 1,2012), leaving 12 unique source and sink combinations of 2,925.6 MW of
IARRs. Of these 12 unique paths, three paths consisting of 1,200.0 MW werebased on specific transmission investments requests, six paths consisting of
1,047.4 MW were based on merchant transmission requests and three paths
19 See PJM Incremental Auction Revenue Rights Model Development and Analysis, PJM June 12, 2017. <https://www.pjm.com/~/media/
markets-ops/ftr/pjm-iarr-model-development-and-analysis.ashx>.
20 See Attachment EE of the PJM Open Access Transmission Tariff <https://www.pjm.com/directory/merged-tariffs/oatt.pdf>.

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

consisting of 678.6 MW were based on customer funded (RTEP) transmission
projects. The three paths based on specific transmission investments involved
a generation company working with its affiliated transmission company. The
other nine paths were based on projects that would have been built regardlessof the addition of IARRs.

The MMU recommends that IARRs be eliminated from the PJM tariff. If IARRs
are not eliminated, the MMU recommends that IARRs be subject to prorating
like all other ARR rights rather than being exempt from prorating.

The MMU supports increased competition to provide transmission using market
mechanisms. The IARR process is not a viable mechanism for facilitatingcompetitive transmission investments. Maintaining the IARR process impedes
the search for real solutions. PJM’s process for creating and assigning IARRs
is fundamentally flawed and cannot be made consistent with the requirementsof Order No. 681 which established IARRs.21

FTRs are financial instruments that entitle their holders to receive revenue or
require them to pay charges based on locational congestion price differencesin the day-ahead energy market across specific FTR transmission paths. These
day-ahead congestion price differences, multiplied by the FTR position in
MW, are termed the FTR target allocations. The FTR target allocations define
the maximum, but not guaranteed, payout for FTRs. The target allocation of
an FTR reflects the difference in day-ahead congestion prices (CLMPs) rather
than the difference in LMPs, which includes both congestion and marginal
losses. Negative target allocations require the FTR holder to make payments
rather than receive revenues in the FTR market. One of the fundamental flaws
in the FTR design is the mismatch between congestion and the differencesin day-ahead prices between nodes. The difference in day-ahead congestion
prices is not congestion. Target allocations are not congestion.

Order No. 681 requires that long-term firm transmission rights made feasibleby transmission upgrades or expansions be available upon request to theparty that pays for such upgrades or expansions.22 Order No. 681 also requiresthat the rights granted by upgrades/expansions cannot come at the expenseof transmission rights held by others. IARRs are treated as Stage 1A rights,
which are given first and absolute priority in PJM’s annual allocation process.
Granting Stage 1A status to IARRs is preferential treatment of IARR rights
relative to the ARR rights belonging to load. If the annual market model used
to assign existing ARR rights in a given year cannot simultaneously support
all Stage 1A ARR requests, the system model is modified so as to make theStage 1A ARR requests feasible. The result is an over allocation of congestion
rights relative to expected congestion. To avoid having FTR target allocations
exceed expected congestion, PJM reduces the annual supply (market model
system capability) available to non-Stage 1A rights through selective line
outages and line rating reductions. The resulting market model artificially
supports all the Stage 1A ARR requests and artificially reduces the amount ofremaining later tier ARRs from other rights holders. Stage 1A ARRs, including
IARRs, are approved at the expense of other preexisting congestion rights. In
the case of IARRs, this is in violation of Order No. 681.
21 See November 7, 2019 Comments on TranSource, LLC v. PJM, 168 FERC ¶ 61,119 (2019) (“Opinion No. 566”).
22 Long-Term Firm Transmission Rights in Organized Electricity Markets, Order No. 681, 116 FERC ¶61,077 (2006) (“Order No. 681”), order on
reh’g, Order No. 618-A, 117 FERC ¶ 61,201 (2006), order on reh’g, Order No. 681-A, 126 FERC ¶ 61,254 (2009).

© 2021 Monitoring Analytics, LLC

Financial Transmission Rights

Under the current rules, the revenue available to pay FTR holders’ target
allocations in a given month includes day-ahead congestion, payments byholders of negatively valued FTRs, auction revenues greater than ARR target
allocations, and any charges made to day-ahead operating reserves which
occur where there are hours with net negative congestion. Any such revenue
above FTR target allocations from prior months in a planning period are used
to pay any current month shortfalls. Target allocations are a cap on payments
to FTR holders for each planning period. At the end of each planning period,
any surplus revenue above the target allocations is distributed to ARR holders.
FTR funding is not on a path specific basis or on an hour to hour basis andtreats all FTRs the same. For example, if the payout ratio is less than 1.0 at theend of the planning period, the payments to all FTRs are reduced. Payments
are made pro rata based on target allocations. The result is widespread crosssubsidies because assignment of path specific FTRs may exceed system

2021 Quarterly State of the Market Report for PJM: January through June 701

2021 Quarterly State of the Market Report for PJM: January through June

capability and affect the payments to FTRs on other paths. FTR auction
revenues and excess revenues are carried forward from prior months anddistributed back from later months within a planning period. At the end of aplanning period, if some months remain not fully funded, an uplift charge iscollected from any FTR market participants that hold FTRs for the planning
period based on their pro rata share of total net positive FTR target allocations,excluding any charge to FTR holders with a net negative FTR position for theplanning period.
Auction market participants may offer to buy FTRs between any eligible
pricing nodes on the system, as defined by PJM for each auction. For the
Annual FTR Auction and FTRs bought in the monthly auctions, the available
FTR source and sink points include hubs, control zones, aggregates, generator
buses, load buses and interface pricing points. For the Long Term FTR Auction
there is a more restricted set of available hubs, control zones, aggregates,
generator buses and interface pricing points available. PJM does not allow
FTR buy bids to clear with a price of zero unless there is at least one constraint
in the auction which affects the FTR path. FTRs are available to the nearest
0.1 MW.
FTRs are bought from supply defined by PJM. The fact that load is selling
congestion revenue rights is not fully recognized in the FTR design, although
FTR buyers can resell FTRs at a price they agree to accept. Load has no role indefining the price at which PJM sells FTRs on their behalf. PJM’s objective in
the auctions is to maximize auction revenue, given the total set of bid prices
and bid MW, but absent reservation prices from load. The failure to allow
sellers the ability to decide at what price to sell FTRs is a fundamental flaw
in the FTR market. The result is that PJM cannot actually maximize auction
revenue and that the FTR market is not really a market.
Once bought from PJM, FTRs can be bought and sold. Buy bids are bids to buy
FTRs in the auctions. Sell offers are offers to sell existing FTRs in the auctions.
Market participants can buy and sell existing FTRs, outside of the auction
process, through a voluntary bulletin board, termed the PJM bilateral market.

702

Section 13 FTRs and ARRs

FTRs can also be exchanged bilaterally without using the bulletin board.
There is no requirement to report bilateral transactions, or any information
about them, to PJM.

Supply and Demand
Total FTR supply in each auction is limited by the definition of the transmission
system capacity included in the PJM FTR market model as modified, forexample, by PJM assumptions about transmission outages, for which there
are no clear rules. PJM may also limit available transmission capacity throughsubjective judgment exercised without any clear guidelines.
The MMU recommends that the full transmission capacity of the system beallocated as ARRs prior to sale as FTRs.
The FTR auction process does not account for the fact that significant
transmission outages, which have not been provided to PJM by transmission
owners prior to the auction date, will occur during the periods covered by theauctions. Such transmission outages may or may not be planned in advanceor may be emergency outages.23 In addition, it is difficult to model in anannual auction two outages of similar significance and similar durationin different areas which do not overlap in time. The choice of which tomodel will generally have significant distributional consequences; they willaffect different areas very differently. The fact that outages are modeled atsignificantly lower than historical levels results in selling too much FTR
capacity, which creates downward pressure on ARR prices. To address thisissue, the MMU recommends that PJM use probabilistic outage modeling tobetter align the supply of ARRs and FTRs with actual expected transmission
capacity.

Long Term FTR Auctions
In July 2006, FERC approved Order No. 681 mandating the creation of longterm firm transmission rights in transmission organizations with organizedelectricity markets. FERC’s goal was that “load serving entities be able to
23 See the 2019 State of the Market Report for PJM, Volume II, Section 12: Transmission Facility Outages: Transmission Facility Outages
Analysis for the FTR Market.

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

request and obtain transmission rights up to a reasonable amount on a longterm firm basis, instead of being limited to obtaining exclusively annual
rights.”24 Despite that order and inconsistent with the directive in that order,
LSEs are not able to request ARRs nor are LSEs guaranteed rights to therevenue from Long Term FTR Auctions in PJM’s long term FTR auction market
design. Excess system capability in years two and three of the long term FTR
auction is never made available to load in the form of ARRs and is only madeavailable to FTR buyers.

But the revisions do not address the congestion revenue rights sold in years
two and three of the Long Term FTR Auction, which remain unavailable to
ARRs. Capacity awarded in the Long Term FTR Auction is unavailable as
ARRs in years two and three. As a result, the rights to significant congestion
revenues are still assigned to the Long Term FTR Auction without ever having
been made available to ARR holders. That outcome is inconsistent with thebasic logic of ARRs and inconsistent with the stated intent of the market
design which is to return all congestion revenues to load.

PJM conducts the Long Term FTR Auction for the next three consecutive
planning periods. The Long Term FTR Auction consists of five rounds beginningin June of the preceding planning period and continuing through March. FTRs
purchased in prior rounds or Long Term Auctions may be offered for sale insubsequent rounds of the long term, annual or monthly FTR auctions. FTRs
obtained in the Long Term FTR Auctions have terms of one year. FTR products
available in the Long Term Auction include 24 hour, on peak and off peak FTR
obligations, with FTR options unavailable in the Long Term FTR Auctions.

Long Term FTR Auction transmission capacity is determined by removing all
outages and running an offline model of the previous Annual FTR Auction
model with all ARR bids from the prior annual ARR allocation. Any ARR
MW that clear in this offline model are reserved for ARR holders in therelevant planning periods, and are removed from the Long Term FTR Auction
capability. Even this approach does not, and cannot, preserve all possible
capacity for ARR holders in the first year of the Long Term Auction due tochanges in system topology and outage selection between planning periods.
PJM outage assumptions are a key factor in determining the supply of ARRs
and the related supply of FTRs in the Annual FTR Auction.

Beginning with Round 2 of the 2019/2022 Long Term FTR Auction, PJM
implemented revisions to the determination of residual system capability
made available in the Long Term FTR Auctions, and eliminated the YRALL
product, consistent with the MMU’s recommendation. The revisions affect thedetermination of ARR rights reserved for ARR holders. Rather than simply
preserving the ARR cleared capacity from the previous annual allocation, PJM
reruns the simultaneous feasibility test for the ARR/FTR market model, without
outages, using the previous year’s ARR requests, prorated when necessary,and uses the resulting ARRs as the basis for reserving capability for ARR
holders in the Long Term FTR Auction. The ARR requests are greater than thepreviously cleared ARRs. The difference between the requested ARRs and the
ARR/FTR market model’s transmission system capacity, both without outages,
determines the residual capability offered in the Long Term FTR Auction. The
revisions provide ARR holders with more congestion rights in the Long Term
FTR Auction that will carry into the Annual FTR Auction.
24 Order No. 681 at P 17.

© 2021 Monitoring Analytics, LLC

Annual FTR Auctions
Annual FTRs are effective for an entire planning period, June 1 through May
31. Outages expected to last two or more months, as well as any outages of ashorter duration that PJM decides would cause FTR revenue inadequacy if notmodeled, are included in the determination of the simultaneous feasibility for
the Annual FTR Auction.25 While the full list of outages selected is publicly
posted, PJM exercises significant subjective judgment in selecting outages
to accomplish FTR revenue adequacy goals and the process by which theseoutages are selected is not clear, is not defined and is not documented. ARR
holders who wish to self schedule must inform PJM prior to round one of
the annual auction. Any self scheduled ARR requests clear 25 percent of therequested volume in each round of the Annual FTR Auction as price takers.
The Annual FTR Auction consists of four rounds that allow any PJM member
to bid for any FTR or to offer for sale any FTR that they currently hold. FTRs
25 See “PJM Manual 6: Financial Transmission Rights,” Rev. 26 (Jan. 27, 2021).

2021 Quarterly State of the Market Report for PJM: January through June 703

2021 Quarterly State of the Market Report for PJM: January through Junein this auction can be obligations or options for peak, off peak or 24 hour
periods. FTRs purchased in one round of the Annual FTR Auction can be soldin later rounds or in the Monthly Balance of Planning Period FTR Auctions.

Monthly Balance of Planning Period FTR Auctions
Total Monthly FTR Auction capacity is based on the residual capacity available
after the Long Term and Annual FTR auctions are conducted and adjustments
are made to outages to reflect anticipated system conditions for the time
periods auctioned. Outages expected to last five or more days are includedin the determination of the simultaneous feasibility test for the Monthly
Balance of Planning Period FTR Auction. These are single-round monthly
auctions that allow any transmission service customer or PJM member to bid
for any FTR or to offer for sale any FTR that they currently hold. Before the2020/2021 planning period, the first three individual months, and quarterly
periods that had not yet begun, were available for bid or offer. Beginningwith the 2020/2021 planning period, market participants can bid for or offer
monthly FTRs for any of the remaining individual calendar months in theplanning period. FTRs in the auctions include obligations and options and 24
hour, on peak and off peak products.26

Bilateral Market
Market participants can buy and sell existing FTRs, outside of the auction
process, through a voluntary bulletin board, termed the PJM bilateral market.
FTRs can also be exchanged bilaterally without using the bulletin board. Thereis currently no requirement to report bilateral transactions, or any information
about them, to PJM. Bilateral transactions that are not done through PJM caninvolve parties that are not PJM members. PJM has no knowledge of bilateraltransactions, or the terms and risks of bilateral transactions, that are done
outside of PJM’s bilateral market system. Bilateral transactions not reported to
PJM are dependent on the contract established between the parties.
For bilateral trades reported to PJM, the FTR transmission path must remain
the same, FTR obligations must remain obligations, and FTR options mustremain options. However, an individual FTR may be split up into multiple,
26 See “PJM Manual 6: Financial Transmission Rights,” Rev. 26 (Jan. 27, 2021).

704

Section 13 FTRs and ARRs

smaller FTRs, down to increments of 0.1 MW. Bilateral FTRs reported to PJM
can also include more restrictive start and end times, meaning that the start
time cannot be earlier than the original FTR start time and the end timecannot be later than the original FTR end time.

FTR Bid Limits
PJM has the authority to limit participant’s bids to 5,000 to avoid or mitigate
significant system performance problems related to bid/offer volume.27 PJM
has had a cap of 10,000 bids and offers per auction round and per period at
the corporate family level for more than a year, although the rule has not been
enforced. On December 11, 2019, PJM made an informational announcement
to urge participants to respect the rule.28 Some participants continued to
exceed the limit in 2020 through the use of multiple affiliates, although thenumber of such participants was significantly reduced. On October 26, 2020,
the MMU informed stakeholders that it had notified companies that violated
the limits persistently that the companies should comply, and recommended
that PJM enforce the limit.29 On November 5, 2020, PJM proposed to add alanguage in PJM Manual 6 regarding the bid limit.30 The MMU recommends
that PJM enforce the FTR auction bid limits at the corporate family level
starting immediately.

Market Structure
In order to evaluate the ownership of FTRs, the MMU categorizes all
participants owning FTRs in PJM as either physical or financial. Physicalentities include utilities and customers which primarily take physical positions
in PJM markets. Financial entities include banks, trading firms and hedge
funds which primarily take financial positions in PJM markets. International
market participants that primarily take financial positions in PJM markets are
27 Operating Agreement Schedule 1 § 7.3.5(d) allows PJM to limit participant’s bids to 5,000 to avoid or mitigate significant system
performance problems related to bid/offer volume.
28 See “Informational Update: FTR Auction Bid Limits,” PJM Presentation to the Market Implementation Committee (December 11, 2019)<https://www.pjm.com/-/media/committees-groups/committees/mic/20191211/20191211-item-06-ftr-auction-bid-limits.ashx>.
29 See “Market Monitor Report,” IMM Presentation to the Members Committee (October 26, 2020) <https://www.pjm.com/-/media/
committees-groups/committees/mc/2020/20201026-webinar/20201026-item-07-imm-report.ashx>.
30 See “Manual 6, Rev. 26: FTR Auction Bid Limits,” PJM Presentation to the Market Implementation Committee (November 5, 2020)<https://www.pjm.com/-/media/committees-groups/committees/mic/2020/20201105/20201105-item-05a-m6-updates-ftr-bid-limits.
ashx>.

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

generally considered to be financial entities even if they are utilities in theirown countries.
Table 13-10 shows the 2021/2024 Long Term FTR Auction market cleared
FTRs by trade type, organization type and FTR direction. The results showthat financial entities purchased 83.0 percent of prevailing flow buy bid FTRs
and 91.4 percent of counter flow buy bid FTRs with the result that financial
entities purchased 87.1 percent of all long term FTR auction cleared buy bids.
Physical entities purchased 17.0 percent of all cleared long term FTRs in the2021/2024 Long Term FTR Auction, down 4.90 percentage points from theprevious Long Term FTR Auction.
Table 13-10 Long term FTR auction patterns of ownership by FTR direction:
2021/2024
Trade TypeBuy Bids

Sell Offers

Organization Type
PhysicalFinancial
Total
PhysicalFinancial
Total

Prevailing Flow
17.0%
83.0%
100.0%
18.6%
81.4%
100.0%FTR Direction
Counter Flow
8.6%
91.4%
100.0%
25.3%
74.7%
100.0%

All
12.9%
87.1%
100.0%
20.8%
79.2%
100.0%

Table 13-11 shows the HHI for the periods in the 2017/2020 through 2021/2024
Long Term FTR Auctions. The YRALL auction was highly concentrated until
its removal in the 2020/2023 Long Term Auction. The individual annual
auctions are unconcentrated with the exception of years two and three of the
17/20 Auction.

Table 13-12 shows the annual FTR auction cleared FTRs for the 2021/2022
planning period by trade type, organization type and FTR direction. In the
Annual FTR Auction for the 2021/2022 planning period, financial entities
purchased 74.6 percent of prevailing flow FTRs, up 3.4 percentage points, and88.8 percent of counter flow FTRs, up 5.2 percentage points, with the resultsthat financial entities purchased 79.8 percent, up 4.2 percentage points, of allannual FTR auction cleared buy bids for the 2021/2022 planning period.
Table 13-12 Annual FTR Auction patterns of ownership by FTR direction:
2021/2022
FTR Direction
Trade TypeBuy Bids

Organization Type
PhysicalSell Offers

Financial
Total
PhysicalFinancial
Total

Self-Scheduled
FTRs
Yes
No
Total
No

Prevailing Flow
7.5%
17.9%
25.4%
74.6%
100.0%
9.5%
90.5%
100.0%Counter Flow
0.1%
11.1%
11.2%
88.8%
100.0%
6.2%
93.8%
100.0%

All
4.8%
15.4%
20.2%
79.8%
100.0%
8.2%
91.8%
100.0%

Table 13-13 shows the HHI values for cleared buy and self scheduled bids forthe 2016/2017 through 2021/2022 Annual FTR Auctions. Obligation buy bids
are consistently unconcentrated, while Option buy bids are unconcentrated
to moderately concentrated. Cleared self scheduled bids are always highly
concentrated.

Table 13-11 Long term HHIs by auction
Auction
17/20 Long Term Auction
18/21 Long Term Auction
19/22 Long Term Auction
20/23 Long Term Auction
21/24 Long Term Auction© 2021 Monitoring Analytics, LLC

YR1
779
711
492
567
495

YR2
1779
940
647
575
535

YR3
1354
749
768
638
767

YRALL
8533
8654
9954
NA
NA

2021 Quarterly State of the Market Report for PJM: January through June 705

2021 Quarterly State of the Market Report for PJM: January through June

Table 13-13 Annual auction HHIs by auction
Auction
21/22 Annual Auction

20/21 Annual Auction

19/20 Annual Auction

18/19 Annual Auction

17/18 Annual Auction

Offset Type
Obligation
Obligation
OptionObligation
Obligation
OptionObligation
Obligation
OptionObligation
Obligation
OptionObligation
Obligation
OptionTrade Type
Buy
Self Scheduled
Buy
Buy
Self Scheduled
Buy
Buy
Self Scheduled
Buy
Buy
Self Scheduled
Buy
Buy
Self Scheduled
Buy

HHI
420
3291
957
278
2970
1299
251
2661
978
357
2620
1213
303
2794
2099

Table 13-14 presents the monthly balance of planning period FTR auction
cleared FTRs for 2021 by trade type, organization type and FTR direction.
Financial entities purchased 84.5 percent of prevailing flow FTRs, up 1.9
percentage points, and 91.9 percent of counter flow FTRs, up 4.2 percentage
points, from 2020, with the result that financial entities purchased 88.0
percent, up 2.8 percentage points, of all prevailing and counter flow FTR buy
bids in the monthly balance of planning period FTR auction for 2021.
Table 13-14 Monthly Balance of Planning Period FTR Auction patterns ofownership by FTR direction: January through June, 2021
Trade TypeBuy Bids

Sell Offers

Organization Type
PhysicalFinancial
Total
PhysicalFinancial
Total

Prevailing Flow
15.5%
84.5%
100.0%
4.8%
95.2%
100.0%FTR Direction
Counter Flow
8.1%
91.9%
100.0%
3.1%
96.9%
100.0%

Table 13-15 shows the monthly cumulative HHI values for cleared obligation
MW for the 2020/2021 planning period monthly auctions for prevailing flow
FTRs. Cleared prevailing flow bids were unconcentrated in all of the months.31
Table 13-15 Monthly Balance of Planning Period FTR Auction HHIs by period
for prevailing flow FTRs
AuctionJun-20Jul-20Aug-20
Sep-20
Oct-20Nov-20Dec-20Jan-21
Feb-21
Mar-21
Apr-21
May-21

JUN
359

JUL
415
296

AUG
446
369
304

SEP
591
446
398
314

OCT
720
551
458
413
341

Auction Period
NOV
DEC
625
855
518
701
469
623
435
577
404
503
340
456
386

JAN
686
553
506
491
443
422
398
337

FEB
763
546
506
467
432
440
413
379
337

MAR
752
646
590
531
545
549
530
502
450
410

APR
686
594
555
519
536
552
543
513
479
467
425

MAY
768
607
555
506
536
565
562
538
511
498
478
425

Table 13-16 shows the monthly cumulative HHI values for cleared obligation
MW for the 2020/2021 planning period monthly auctions by month forcounter flow FTRs. Cleared counter flow bids were unconcentrated in all but
two of the months, which were moderately concentrated, in the 2020/2021
planning period.

All
12.0%
88.0%
100.0%
4.3%
95.7%
100.0%

31 See 2021 Quarterly State of the Market Report for PJM: January through June, Section 3: Energy Market, Competitive Assessment for
HHI definitions.

706

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Table 13-16 Monthly Balance of Planning Period FTR Auction HHIs by period
for counter flow FTRs
AuctionJun-20Jul-20Aug-20
Sep-20
Oct-20Nov-20Dec-20Jan-21
Feb-21
Mar-21
Apr-21
May-21

JUN
655

JUL
636
514

AUG
806
571
508

SEP
771
658
560
537

OCT
914
745
625
596
546

Auction Period
NOV
DEC
905
1012
753
811
660
708
604
673
567
638
585
608
653

JAN
772
642
603
599
616
604
615
622

FEB
831
673
632
627
646
631
650
617
522

MAR
939
773
728
697
736
746
722
705
640
600

APR
1007
866
776
763
773
812
808
799
747
722
645

MAY
974
855
768
764
786
797
807
798
759
725
704
666

Table 13-17 shows the average daily FTR ownership for all FTRs for the firstsix months of 2021, by FTR direction and self scheduled FTRs.
Table 13-17 Daily FTR held position ownership by FTR direction: 2021
Organization Type
PhysicalPhysical Self Scheduled
Financial
Total

Prevailing Flow
22.8%
5.6%
71.7%
100.0%FTR Direction
Counter Flow
14.1%
0.1%
85.9%
100.0%

availability of auction bids for counter flow FTRs.32 PJM may also remove or
reduce infeasibilities caused by transmission outages by clearing counter flow
bids without being required to clear the corresponding prevailing flow bids.33
The use of both of these procedures is contingent on the conditions that: PJM
actions not affect the revenue adequacy of allocated ARRs; all requested selfscheduled FTRs clear; and net FTR auction revenue is positive.

Long Term FTR Auction
In the 2021/2024 Long Term FTR Auction, 209,914 MW (24.2 percent of bid
volume; 49.2 percent of total FTR volume) of counter flow FTR buy bids
cleared, an increase from 122,311 MW and 19.8 percent of total FTR volume.
In the same auction, prevailing flow FTR buy bids cleared 216,688 MW (11.5
percent of bid volume; 50.8 percent of total FTR volume) a decrease from275,655 MW and a decrease from 11.5 percent of total FTR volume. In the2021/2024 Long Term FTR Auction, 25,046 MW (12.9 percent) of counter flowsell offers and 52,183 MW (20.6 percent) of prevailing flow sell offers cleared.
Table 13-18 Long Term FTR Auction market volume: 2021/2024

All
18.7%
3.0%
78.3%
100.0%

Trade Type FTR Direction
Buy bids
Counter Flow

Prevailing Flow

Market Performance
VolumePJM regularly intervenes in the FTR market based on subjective judgment
which is not based on clear or documented guidelines. Such intervention
in the FTR, or any market, is not appropriate and not consistent with theoperation of competitive markets. In an apparent effort to manage FTR
revenues, PJM may adjust normal transmission limits in the FTR auction
model. If, in PJM’s judgment, the normal transmission limit is not consistent
with revenue adequacy goals and simultaneous feasibility, then transmission
limits are reduced pro rata based on the MW of Stage 1A infeasibility and the© 2021 Monitoring Analytics, LLC

Sell offers

Total
Counter Flow

Prevailing Flow

Total

PeriodTypeYear 1
Year 2
Year 3Total
Year 1
Year 2
Year 3Total
Year 1
Year 2
Year 3Total
Year 1
Year 2
Year 3Total

Bid and
Bid and
Requested
Requested
Count Volume (MW)
130,159
360,617
81,976
270,226
68,822
235,465
280,957
866,309
231,969
835,606
147,762
584,870
112,954457,050492,685
1,877,527
773,6422,743,836
57,301
107,859
28,85260,511
9,919
25,307
96,072
193,677
80,430162,681
32,93069,531
8,509
20,575
121,869
252,786
217,941
446,464

ClearedVolume(MW)
95,59659,25955,058
209,914
109,41261,36245,914
216,688426,602
16,2116,789
2,047
25,04636,711
12,147
3,325
52,183
77,230

ClearedVolume
26.5%
21.9%
23.4%
24.2%
13.1%
10.5%
10.0%
11.5%
15.5%
15.0%
11.2%
8.1%
12.9%
22.6%
17.5%
16.2%
20.6%
17.3%

Uncleared
Volume(MW)
265,021210,967
180,407656,395
726,195
523,508
411,136
1,660,839
2,317,234
91,64853,72323,260168,631
125,969
57,384
17,250200,603369,234

Uncleared
Volume
73.5%
78.1%
76.6%
75.8%
86.9%
89.5%
90.0%
88.5%
84.5%
85.0%
88.8%
91.9%
87.1%
77.4%
82.5%
83.8%
79.4%
82.7%

32 See “PJM Manual 6: Financial Transmission Rights,” Rev. 26 (Jan. 27, 2021).
33 See id.

2021 Quarterly State of the Market Report for PJM: January through June 707

2021 Quarterly State of the Market Report for PJM: January through June

Figure 13-3 shows the percent of FTR MW cleared, and bid and clearedvolume, by direction, for each round of the Long Term FTR Auction from the2015/2018 through the 2021/2024 auctions.
Figure 13-3 Long Term FTR Auction bid and cleared volume by round anddirection
1,600,000

25%Counter Cleared
Prevailing Cleared

1,400,000

Counter Bid

20%

Prevailing Bid

1,200,000

Long Term FTR Product(Including YRALL)
Effective Planning
Period2014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021
2021/2022

YR3
81,66689,41997,837
69,161
87,23280,94754,451
98,829YR286,754
99,32995,63786,323
109,827
118,112125,330
80,998YR1
131,911
123,400
107,182
108,126
176,998
188,438
127,054
205,008

Obligation Volume (MW)Annual (including Long Term Percent
Total Long Term
self scheduled)of Total Cleared
300,330
356,52245.7%
312,148355,68246.7%
300,656
397,25843.1%
263,609493,68334.8%
374,057
549,66940.5%
387,496576,93740.2%
306,835
525,55036.9%
384,835
512,44942.9%

15%800,000
10%

600,000

Percent Cleared

Percent Cleared

1,000,000
FTR MW

Table 13-19 Long Term and Annual Auction total cleared FTR MW

Table 13-20 shows the MW proportion of FTRs by source and sink node typefor cleared buy bids in the 2021/2024 Long Term FTR Auction. Generator to
generator FTRs comprise 62.1 percent of all cleared FTR buy bids.
Table 13-20 Long Term FTR node type matrix: 2021/2024 auction
Sink Type400,000
5%

16/19

20/23

YR3

YR2

YR1

YR3

YR2

YR1

YR3

19/22

YRALL

YR2

YR1

YR3

18/21

YRALL

YR2

YR1

YR3

17/20

YRALL

YR2

YR1

YR3

YRALL

YR2

YR1

YR3

15/18

YRALL

YR2

0

YR1

200,000
0%

Source Type
Aggregate
Generator
HubInterface
Residual Metered Aggregate
Zone

Aggregate
0.9%
6.7%
0.2%
0.0%
0.1%
0.4%

Generator
6.3%
62.1%
0.8%
0.3%
0.8%
2.1%

Hub
0.2%
2.9%
0.9%
0.1%
0.0%
1.9%

Interface
0.1%
1.1%
0.4%
0.0%
0.0%
0.1%

Residual Metered
Aggregate
0.2%
0.4%
0.4%
0.0%
0.0%
1.2%

Zone
0.2%
3.7%
3.3%
0.1%
0.0%
2.1%

21/24

Auction Round

Table 13-19 compares cleared FTR obligations (not options) acquired in theLong Term FTR Auctions to the total cleared FTR obligations from the Annual
FTR Auction, for FTRs in the 2014/2015 through 2021/2022 planning periods.
A three year FTR is distributed to each individual planning period during
its three year effective period. Long term FTRs that are effective in a single
planning period were an average of 41.1 percent of total FTR volume in the
2014/2015 through 2021/2022 planning periods.

708

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Annual FTR Auction
Table 13-21 shows the annual FTR auction market volume for the 2021/2022 planning period. Total FTR buy bids were 2,070,424 MW, down 1.2 percent from2,364,145 MW for the previous planning period. For the 2021/2022 planning period 535,277 MW (26.2 percent) of buy bids cleared, up 2.4 percentage points
from 556,034 MW for the previous planning period. There were 466,575 MW of sell offers with 66,830 MW (14.3 percent) clearing for the 2021/2022 planning
period. The total volume of cleared buy and self scheduled bids was 562,293 MW, down 9.0 percent from 583,629 MW in the previous Annual FTR Auction.
Table 13-21 Annual FTR Auction market volume: 2021/2022
Trade TypeBuy bids

Type
Obligations

Options

Total

Self-scheduled bids

Obligations

Buy and self-scheduled bids

Obligations

Options

Total

Sell offers

Obligations

Options

Total© 2021 Monitoring Analytics, LLC

FTR Direction
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total

Bid and
RequestedCount
145,908
310,514456,42226
30,89530,921
145,934
341,409487,343
54
3,686
3,740
145,962314,200
460,16226
30,89530,921
145,988
345,095
491,083
72,37878,869151,247
1
1,436
1,437
72,37980,305
152,684

Bid and
Requested
Volume (MW)552,109
1,233,197
1,785,307341
257,760
258,101
552,451
1,490,958
2,043,408
221
26,79527,016552,330
1,259,992
1,812,322
341
257,760
258,101
552,671
1,517,752
2,070,424
212,555
240,820453,374
35
13,166
13,201
212,590
253,986
466,575

ClearedVolume(MW)
206,353
279,079
485,433
50
49,794
49,844
206,404
328,874
535,277
221
26,79527,016
206,574
305,874
512,44850
49,794
49,844
206,625355,668
562,293
27,22038,22565,446
0
1,384
1,384
27,22039,61066,830

ClearedVolume
37.4%
22.6%
27.2%
14.8%
19.3%
19.3%
37.4%
22.1%
26.2%
100.0%
100.0%
100.0%
37.4%
24.3%
28.3%
14.8%
19.3%
19.3%
37.4%
23.4%
27.2%
12.8%
15.9%
14.4%
NA
10.5%
10.5%
12.8%
15.6%
14.3%

Uncleared
Volume(MW)345,756
954,118
1,299,874
291
207,966
208,257
346,047
1,162,084
1,508,131
000345,756
954,118
1,299,874
291
207,966
208,257
346,047
1,162,084
1,508,131
185,334
202,594
387,92835
11,782
11,817
185,370
214,376
399,745

Uncleared
Volume
62.6%
77.4%
72.8%
85.2%
80.7%
80.7%
62.6%
77.9%
73.8%
0.0%
0.0%
0.0%
62.6%
75.7%
71.7%
85.2%
80.7%
80.7%
62.6%
76.6%
72.8%
87.2%
84.1%
85.6%
NA
89.5%
89.5%
87.2%
84.4%
85.7%

2021 Quarterly State of the Market Report for PJM: January through June 709

2021 Quarterly State of the Market Report for PJM: January through June

Figure 13-4 shows the percent of FTR MW cleared and bid and cleared volume,by direction, for each round of the Annual FTR Auction from the 2015/2016
planning period through the 2021/2022 planning period.

Figure 13-5 Comparison of self scheduled FTRs: 2009/2010 through2021/2022
120,000

90%
80%

35%
Counter Cleared
Prevailing ClearedCounter Bid
Prevailing Bid
Percent Cleared

70%

80,00030%

Percent Self Scheduled
Maximum Self Scheduled MWMW

800,000

100,000

25%

60,000Self Scheduled MW

60%
50%

FTR MW20%

15%400,000

Percent Cleared

40%

600,000

40,00020,000

30%
20%
10%

10%
0

200,000

Percent Self Scheduled

Figure 13-4 Annual FTR Auction bid and cleared volume by round anddirection
1,000,000

100%

0%

5%

0

1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4
15/16

16/17

17/18

18/19

19/20

0%

20/21

Auction Round

Figure 13-5 shows the proportion of ARRs self scheduled as FTRs for the last
thirteen planning periods. The maximum possible level of self scheduled FTRs
is equal to total ARRs. Eligible participants self scheduled 27,016 MW (26.1
percent) of ARRs as FTRs for the 2021/2022 planning period, compared to
27,016 MW (25.4 percent) in the previous planning period.

710

Section 13 FTRs and ARRs

Table 13-22 shows the MW proportion of FTRs by source and sink node typefor cleared cleared buy and self scheduled bids in the 2021/2022 Annual FTR
Auction.
Generator to generator FTRs comprise 53.7 percent of all cleared FTR buy
and self scheduled bids, up 5.7 percentage points from the previous planning
period. It is not clear why generator to generator FTRs make up such adisproportionate share of total FTRs. Congestion results from load paying
more for generation than generators receive. By definition, congestion is
between generator sources and load sinks. Generator to generator paths do
not represent the delivery of generation to load. FTRs between generators
simply create a speculative opportunity because they can be a low cost or
zero cost FTR in the current design with a significant payoff if there is a pricedifference between the two nodes.

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

The MMU recommends that PJM examine the source and sink nodecombinations available in the FTR market and eliminate generation to
generation paths and all other paths that do not represent the delivery of
power to load.
Table 13-22 Annual auction FTR node type matrix by proportion of MW:
2021/2022
Sink Type
Source Type
Aggregate
Generator
HubInterface
Residual Metered Aggregate
Zone

Aggregate
1.8%
11.1%
0.3%
0.1%
0.1%
0.4%

Generator
5.1%
53.7%
0.8%
0.4%
0.5%
1.4%

Hub
0.2%
4.2%
0.5%
0.0%
0.0%
0.6%

Interface
0.0%
0.7%
0.0%
0.0%
0.0%
0.0%

Residual Metered
Aggregate
0.2%
5.3%
0.3%
0.1%
0.0%
0.5%

Zone
0.4%
8.4%
1.3%
0.1%
0.0%
1.3%

Monthly Balance of Planning Period Auctions
Table 13-23 provides the monthly balance of planning period FTR auction
market volume for the entire 2019/2020 and 2020/2021 planning periods.
There were 29,351,515 MW of FTR obligation buy bids and 12,711,366 MW of
FTR obligation sell offers for all bidding periods in the 2020/2021 planning
period. The monthly balance of planning period FTR auction cleared 5,374,799(18.3 percent) of FTR obligation buy bids and 2,216,261 MW (17.4 percent) of
FTR obligation sell offers.
There were 5,672,240 MW of FTR option buy bids and 3,515,054 MW of FTR
option sell offers for all bidding periods in the Monthly Balance of Planning
Period FTR Auctions for the 2020/2021 planning period. The ownership ofoptions was highly concentrated in all periods. The monthly auctions cleared
311,288 MW (5.5 percent) of FTR option buy bids and 554,040 MW (15.8
percent) of FTR option sell offers.

© 2021 Monitoring Analytics, LLC

Table 13-23 Monthly Balance of Planning Period FTR Auction market volume:2021
Bid and
Bid and Requested
ClearedMonthly
Requested
VolumeVolumeAuctionType
Trade Type
Count
(MW)
(MW)
Jan-21
Obligations Buy bids
381,342 1,836,655
322,062
Sell offers
217,469
811,662
130,359
Options
Buy bids
6,018
442,023
14,751
Sell offers
28,121
237,886
32,306
Feb-21
Obligations Buy bids
376,380 1,790,943
392,484
Sell offers
202,939
761,827
137,133
Options
Buy bids
2,117
200,050
8,830
Sell offers
20,855207,239
30,062Mar-21
Obligations Buy bids
294,408 1,424,569
327,035
Sell offers
150,359
603,193
126,499
Options
Buy bids
1,593
102,266
5,694
Sell offers
14,659155,357
37,104Apr-21
Obligations Buy bids
232,361 1,038,292
235,418
Sell offers
103,242
396,155
88,706
Options
Buy bids
952
95,3174,750
Sell offers
8,212
100,079
33,112
May-21
Obligations Buy bids
143,525
726,081
172,760
Sell offers
45,385
177,164
47,835
Options
Buy bids
476
6,658
1,963
Sell offers
3,048
45,362
21,6202019/2020* Obligations Buy bids
5,926,122 20,396,353 3,975,985
Sell offers
3,436,131 7,709,887 1,586,486
Options
Buy bids
86,428 2,779,104
148,918
Sell offers
179,301 1,656,059
409,0292020/2021** Obligations Buy bids
6,378,593 29,351,515 5,374,799
Sell offers
3,827,330 12,711,366 2,216,261
Options
Buy bids
89,167 5,672,240
311,288
Sell offers
516,603 3,515,054
554,040* Shows 12 months for 2019/2020 ** Shows 12 months for 2020/2021

Uncleared
ClearedVolumeVolume(MW)
17.5% 1,514,593
16.1%
681,304
3.3%
427,27213.6%
205,581
21.9% 1,398,459
18.0%
624,694
4.4%
191,22114.5%
177,176
23.0% 1,097,534
21.0%
476,694
5.6%
96,572
23.9%
118,25322.7%
802,87422.4%
307,449
5.0%
90,56733.1%
66,96723.8%
553,32127.0%
129,329
29.5%
4,695
47.7%
23,742
19.5% 16,420,368
20.6% 6,123,402
5.4% 2,630,186
24.7% 1,247,031
18.3% 23,976,716
17.4% 10,495,105
5.5% 5,360,952
15.8% 2,961,014

Uncleared
Volume
82.5%
83.9%
96.7%
86.4%
78.1%
82.0%
95.6%
85.5%
77.0%
79.0%
94.4%
76.1%
77.3%
77.6%
95.0%
66.9%
76.2%
73.0%
70.5%
52.3%
80.5%
79.4%
94.6%
75.3%
81.7%
82.6%
94.5%
84.2%

Figure 13-6 shows the bid volume from each monthly auction for each periodof the Monthly Balance of Planning Period FTR Auction. The prompt monthis the first month for which FTRs are sold. The bid volume for the non-prompt
months is significantly lower than for the prompt months. On average, thenon-prompt month bid volume is 42.6 percent of the prompt month bid
volume.

2021 Quarterly State of the Market Report for PJM: January through June 711

2021 Quarterly State of the Market Report for PJM: January through June

Figure 13-6 Monthly Balance of Planning Period FTR Auction bid volume (MWper period): June 2020 through May 2021 Auction

Figure 13-7 Monthly Balance of Planning Period FTR Auction cleared volume(MW per period): June 2020 through May 2021 Auction

1,200,000

300,000

1,000,000

June Auction

July Auction

August Auction

September Auction

October Auction

November Auction

December Auction

January Auction

February Auction

March Auction

April Auction

May Auction

250,000

Cleared MW

Bid MW

800,000

600,000

400,000

200,000

-

JUN

JUL

AUG

SEP

OCT

NOV

DEC

JAN

FEB

MAR

APR

MAY

FTR Period

Figure 13-7 shows the cleared volume from each monthly auction for eachperiod of the Monthly Balance of Planning Period FTR Auction. The clearedvolume for non-prompt months is also significantly lower than in prompt
months. On average, the non-prompt month cleared volume is 24.8 percent of
the prompt month cleared volume.

712

Section 13 FTRs and ARRs

30%
June Auction
August Auction
October Auction
December Auction
February Auction
April Auction
Cumulative Cleared

July Auction
September Auction
November Auction
January Auction
March Auction
May Auction

25%

200,000

20%

150,000

15%

100,000

10%

50,000

5%

-

JUN

JUL

AUG

SEP

OCT

NOV DECFTR Period

JAN

FEB

MAR

APR

MAY

0%

Bilateral Market
Table 13-24 provides the PJM registered secondary bilateral FTR market
volume for the 2019/2020 and the 2020/2021 planning periods. Bilateral FTR
transactions registered through PJM do not need to include an accurate priceor the entire volume of the transaction. Bilateral FTR transactions are notrequired to be registered through PJM. As a result, the bilateral data are not areliable basis for evaluating actual bilateral activity in PJM FTRs.

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Planning Period
2019/2020

Type
Obligation

Option2020/2021

Obligation

OptionClass Type
24-Hour
On Peak
Off PeakTotal
24-Hour
On Peak
Off PeakTotal
24-Hour
On Peak
Off PeakTotal
24-Hour
On Peak
Off Peak
Total

Volume (MW)5,032.9
1,996.1
1,661.8
8,690.8
0.0
0.0
0.0
0.0
6,164.0392.0
96.0
6,652.0
0.0
0.0
0.0
0.0

Figure 13-8 Long Term, Annual and Monthly FTR Auction bid and clearedvolume: June 2003 through May 2021
10,000,000
9,000,000

Net Bid Volume
Cleared Volume
Bid Volume

8,000,000
7,000,000

Volume (MW)Table 13-24 Secondary bilateral FTR market volume: 2019/2020 and2020/202134

6,000,000
5,000,000

4,000,000
3,000,000
2,000,000

Figure 13-8 shows the FTR bid, net bid and cleared volume from June 2003
through May 2021 for Long Term, Annual and Monthly Balance of Planning
Period Auctions. Cleared volume includes FTR buy and sell offers that were
accepted. The net bid volume includes the total buy, sell and self scheduledoffers, counting sell offers as a negative volume. The bid volume is the totalof all bid and self scheduled offers, excluding sell offers. The cleared volume
in August 2018 was negative due to the liquidation of the GreenHat FTR
portfolio, which resulted in a large quantity of FTRs selling in the monthly
auction.

1,000,000
0Figure 13-9 shows cleared auction volumes by auction type as a percent of
the total FTR cleared volume by calendar months for June 2004 through May
2021. FTR volumes are included in the calendar month they are effective,
with long term and annual FTR auction volumes spread equally to eachmonth in the relevant planning period. Over the course of each planning
period an increasing number of Monthly Balance of Planning Period FTRs arepurchased, resulting in a greater share of total FTRs. When the Annual FTR
Auction occurs, FTRs purchased in previous Monthly Balance of Planning
Period Auctions, other than the current June auction, are no longer effective,
resulting in a smaller share for monthly and a greater share for annual FTRs.

34 The 2019/2020 planning period covers bilateral FTRs that are effective for any time between June 1, 2019 through May 31, 2020, which
originally had been purchased in a Long Term FTR Auction, Annual FTR Auction or Monthly Balance of Planning Period FTR Auction.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 713

2021 Quarterly State of the Market Report for PJM: January through June

Figure 13-9 Cleared auction volume (MW) as a percent of total FTR clearedvolume by calendar month: June 2004 through May 2021

Table 13-25 Long Term FTR Auction weighted-average cleared prices (Dollars
per MW): 2021/2024

100%
Monthly FTR Auction

90%

Trade TypeBuy bids

FTR Direction
Counter Flow

Annual FTR Auction

80%

Long Term FTR Auction

Prevailing Flow

70%
60%
50%

Sell offers

Total
Counter Flow

40%

Prevailing Flow

30%
20%

Total

10%

0%

Price

Period TypeYear 1
Year 2
Year 3Total
Year 1
Year 2
Year 3Total
Year 1
Year 2
Year 3Total
Year 1
Year 2
Year 3Total

24-Hour($1.11)($0.68)($0.59)($0.88)
$1.14
$1.08
$1.17
$1.13
$0.48
($0.24)($0.29)($0.03)($0.27)
$0.64
$0.46
$0.21
$0.56
$0.35

Class TypeOn Peak
Off Peak($0.31)($0.54)($0.34)($0.56)($0.29)($0.46)($0.31)($0.52)
$0.30
$0.56
$0.29
$0.53
$0.27
$0.44
$0.29
$0.52
($0.02)$0.01($0.25)($0.55)($0.34)($0.58)($0.32)($0.48)($0.28)($0.55)
$0.26
$0.57
$0.24
$0.58
$0.21
$0.39
$0.25
$0.56
$0.08
$0.20

All
($0.48)($0.47)($0.39)($0.45)
$0.52
$0.52
$0.51
$0.52
$0.05
($0.40)($0.45)($0.41)($0.42)
$0.42
$0.42
$0.30
$0.41
$0.14

Table 13-26 shows the weighted-average cleared buy bid prices by trade type,
FTR product, FTR direction and class type for the Annual FTR Auction for the2021/2022 planning period. The weighted-average cleared buy bid price in the2021/2022 Annual FTR Auction was $0.24 per MW, up from $0.18 per MW in
the 2020/2021 planning period.

Table 13-25 shows the cleared, weighted-average prices by trade type, FTR
direction, period type and class type for the 2021/2024 Long Term FTR
Auction. Only FTR obligation products (no options) are available in the Long
Term FTR Auctions. In this auction, weighted average buy bid counter flow
and prevailing flow FTR prices were -$0.45 and $0.52, compared to -$0.49
and $0.51 from the 2020/2023 Long Term FTR Auction. Weighted averagesell bid counter flow and prevailing flow FTR prices were -$0.42 and $0.41,
compared to -$0.32 for counter flow FTRs and $0.45 for prevailing flow FTRs.

714

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Table 13-26 Annual FTR Auction weighted-average cleared prices (Dollars perMW): 2021/2022
Trade TypeBuy bids

Type
Obligations

Options

Self-scheduled bids

Obligations

Buy and self-scheduled bids

Obligations

Options

Sell offers

Obligations

Options

FTR Direction
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total
Counter Flow
Prevailing Flow
Total

24-Hour($0.43)
$1.42
$0.84
$0.00
$0.43
$0.43
($0.07)$0.77$0.77($0.42)
$1.00
$0.80
$0.00
$0.43
$0.43
($1.05)$0.63($0.06)
NA
$0.01
$0.01

Class TypeOn Peak
Off Peak($0.38)($0.22)
$0.64
$0.34
$0.21
$0.09
$0.00
$0.00
$0.28
$0.18
$0.28
$0.18
NA
NA
NA
NA
NA
NA
($0.38)($0.22)
$0.64
$0.34
$0.21
$0.09
$0.00
$0.00
$0.28
$0.18
$0.28
$0.18
($0.65)($0.36)
$0.53
$0.27
$0.05
$0.00
NA
NA
$0.25
$0.11
$0.25
$0.11

All
($0.31)
$0.58
$0.21
$0.00
$0.25
$0.25
($0.07)$0.77$0.77($0.31)
$0.61
$0.26
$0.00
$0.25
$0.25
($0.54)
$0.42
$0.02
NA
$0.15
$0.15

Table 13-27 Cleared volume, revenue and $/MW: 2012/2013 through2021/2022 Annual FTR Auction
2012/20132013/20142014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021
2021/2022

Cleared Buy Bid
Volume371,295
420,489
365,843
378,328
420,198513,263587,775
611,878
556,034
535,277

Percent Cleared
14.5%
12.8%
11.2%
15.4%
16.2%
22.3%
20.4%
21.9%
23.8%
26.2%

Buy Bid Revenue(millions)$627.3$567.6$789.7$948.6$918.0$555.2$635.6$649.0$449.6$519.0

Buy Bid Revenue($/MW)$1,689$1,350$2,159$2,507$2,185$1,082$1,081$1,061$809$970

Figure 13-10 shows the weighted average cleared buy bid price of obligationsin the Monthly Balance of Planning Period FTR Auctions by bidding period
for the 2020/2021 planning period and the average price per MWh for eachof the FTR periods.

Table 13-27 shows the cleared buy bid volume, cleared buy bid revenue
and cleared revenue/cleared MW for the eight latest planning periods. In
the 2014/2015 planning period the $/MW increased significantly from the2013/2014 planning period due to PJM’s decisions to limit capacity throughconservative modeling. In the 2017/2018 Annual FTR Auction, the $/MW
decreased to lower than 2013/2014 levels, due in part to the partial relaxationof PJM’s conservative modeling practices due to the reassignment of balancing
congestion and M2M payments to load and exports. This reduction continued
into the 2019/2020 planning period. The reassignment of balancing congestion
and M2M payments to load did not increase the per MW value of ARRs.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 715

2021 Quarterly State of the Market Report for PJM: January through June

Figure 13-10 Monthly Balance of Planning Period FTR Auction cleared,
weighted-average, buy bid price per period (Dollars per MWh): 2020/2021
planning period
$0.45
June
AugustOctober
DecemberFebruary
April
Average

$0.40

$0.35

July
September
NovemberJanuary
MarchMay

Hourly FTR profits are the sum of the hourly revenues minus the hourly
costs for each FTR. The hourly revenues equal hourly FTR target allocations,adjusted by the payout ratio. The hourly auction costs are the product of the
FTR MW and the auction price divided by the time period of the FTR in hours.
The FTR revenues do not include after the fact adjustments which are verysmall and do not occur in every month.

$/MWh

$0.30
$0.25
$0.20

$0.15
$0.10
$0.05
$0.00

JUN

JUL

AUG

SEP

OCT

NOV
DEC
FTR Period

JAN

FEB

MAR

APR

MAY

Profitability
FTR profitability is the difference between the revenue received directly fromholding an FTR plus any revenue from the sale of an FTR, and the cost of
the FTR. FTR profitability is relevant only to participants purchasing FTRs
and is not relevant to self scheduled FTRs. For a prevailing flow FTR, theFTR revenue is the actual revenue that an FTR holder is paid as the target
allocation plus the auction price from the sale of the FTR, if relevant, andthe FTR cost is the auction price. For a counter flow FTR, the FTR revenue isthe auction price that an FTR holder is paid to take the FTR plus the positive
auction price from the sale of the FTR, if relevant, and the FTR cost is the target
allocation that the FTR holder must pay plus the negative auction price fromthe sale of the FTR, if relevant. Profits include the payment of surplus to FTRs.

716

Bilateral transactions are excluded from the profit calculations because there
are inconsistent reporting requirements and no assurance that reported prices
reflect the actual prices under the PJM rules. ARR holders that self schedule
FTRs receive congestion revenues but do not receive profits from those FTRs
because ARR holders are assigned the rights to congestion revenues which
they choose to take directly as the congestion payments associated with thecorresponding FTRs.

Section 13 FTRs and ARRs

The surplus includes surplus day-ahead congestion revenue and FTR auction
surplus. Revenues from the surplus are included in FTR profits because thesurplus is first allocated to FTR holders to cover any shortfall in paying
FTR target allocations. Beginning with the 2018/2019 planning period, after
covering any shortfall in FTR target allocations within the planning period,
the net surplus at the end of the planning period is distributed to ARR holders.
The fact that FTR profits in each planning period have been positive forfinancial entities as a group, regardless of the payout ratio, raises questions
about the competitiveness of the market. FTR profits for financial entities
were not positive in the 2019/2020 planning period when accounting forGreenHat losses but were positive otherwise. FTR profits for financial entities
without GreenHat losses were positive in every completed planning period
from 2012/2013 through 2020/2021 except the 2016/2017 planning period,
and were positive if summed over the entire period (Table 13-30). It is notclear, in a competitive market, why FTR profits for financial entities remain
persistently profitable. In a competitive market, it would be expected thatprofits would be competed to zero.

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Table 13-28 lists FTR profits, and the congestion returned through self scheduled FTRs, by organization type and FTR direction of the 2020/2021 planning
period. This table includes the auction cost and revenue from both buying and selling FTRs that were effective between June 2020 and May 2021. This includes
FTRs from the 2018/2021, 2019/2022 and 2020/2023 Long Term auctions, the 2020/2021 Annual auction, and the Monthly auctions from June 2020 throughMay 2021. The costs and revenues of the yearly FTR products are prorated based on the time period of the FTRs. Any revenues or costs related to bilateraltransactions are not included in profits. All participants who were assigned ARRs are classified as physical ARR. Some participants that are not eligible for ARRs
are classified as physical because they are physical participants, for example companies that own only generation.
Self scheduled FTRs have zero cost. ARR holders who self scheduled FTRs received $116.8 million in congestion revenues. Revenues from self scheduled FTRs
are a return of congestion to the load that paid the congestion and are not profits.
Table 13-28 FTR profits and revenues by organization type and FTR direction: 2020/2021
Organization Type
Financial
Financial without GreenHat
PhysicalPhysical ARR
Total

Purchased FTRs Profit
Self Scheduled FTRs Revenue Returned
Prevailing FlowCounter Flow
Total Prevailing FlowCounter Flow
Total
$155,176,709$125,409,870$280,586,579$154,797,219$126,108,796$280,906,014$60,989,987($48,492)$60,941,495$30,242,098($11,260,046)$18,982,052$184,184,380($420,719)$183,763,660$246,408,794$114,101,332$360,510,126$184,184,380($420,719)$183,763,660

Table 13-29 lists the monthly FTR profits for the 2019/2020 planning period and the 2020/2021 planning period by organization type. FTR profits include
revenue from FTR sales, but do not include any net end of planning period surplus distribution and do not include any revenue or cost from bilateraltransactions. FTR revenues for self scheduled FTRs are not included. FTR profits for FTRs purchased in auctions by ARR holders are included. In the 2020/2021
planning period, profits for all participants were $360.5 million, up from $113.6 million in losses in the 2019/2020 planning period. The largest month to monthincrease in profits was in April, $81.0 million and the second largest month to month increase in profits was in February, $80.6 million. Among organization
types, financial organizations had the largest increase in profits in the 2020/2021 planning period, $301.7 million. The increase in profits was a result of higher
target allocations and lower auction costs.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 717

2021 Quarterly State of the Market Report for PJM: January through June

Table 13-29 Monthly FTR profits by organization type: 2019/2020 and2020/202135
Month
Jun-19Jul-19Aug-19Sep-19Oct-19
Nov-19Dec-19Jan-20Feb-20Mar-20
Apr-20May-20Financial($7,530,412)$11,073,631($11,192,103)$13,219,100$6,628,121$6,579,914$6,176,313($5,308,687)($14,980,199)($14,165,737)($14,526,206)$2,886,620

Total
Jun-20Jul-20Aug-20
Sep-20
Oct-20Nov-20Dec-20Jan-21
Feb-21
Mar-21
Apr-21
May-21($21,139,644)$13,553,728$35,758,125$26,341,215$23,243,038$9,270,440$7,462,052$26,204,312$14,413,025$26,325,929$31,624,116$33,914,216$32,476,383

Total$280,586,579

Organization Type
Financialwithout GreenHat
Physical($5,175,703)($4,406,629)$13,727,088$1,715,298($7,445,637)($4,515,760)$20,305,030$6,308,310$12,845,824$2,404,277$10,996,869$2,167,865$11,021,397($212,596)($132,954)($10,539,357)($11,873,252)($11,213,649)($12,669,353)($8,006,489)($11,926,918)($11,145,117)$5,478,459($5,416,808)
Summary for Planning Period 2019/2020$25,150,852($42,860,656)$14,169,535$2,968,368$35,699,812$9,137,003$26,180,692$6,690,519$22,978,996$7,356,627$8,813,003$5,358,560$7,789,762($3,735,384)$26,414,749$160,949$14,543,616($606,901)$27,249,807$14,548,075$31,679,111$5,276,933$32,426,080$6,217,364$32,960,851$7,569,383
Summary for Planning Period 2020/2021$280,906,014$60,941,495

PhysicalARR($5,300,686)$2,195,625($2,965,124)$4,870,000$3,916,338$2,038,284($3,696,208)($10,405,137)($10,337,622)($10,777,549)($11,779,700)($7,372,412)

Total($17,237,726)$14,984,553($18,672,988)$24,397,410$12,948,736$10,786,063$2,267,509($26,253,180)($36,531,470)($32,949,775)($37,451,023)($9,902,600)($49,614,191)($105,462)$3,750,023$3,240,451$4,494,466($843,912)($2,396,979)$2,536,264$1,014,141$3,170,577$5,960,090$3,418,465($5,256,074)($113,614,490)$16,416,634$48,645,151$36,272,185$35,094,131$13,785,088$1,329,689$28,901,524$14,820,265$44,044,582$42,861,139$43,550,045$34,789,692$18,982,052$360,510,126

Table 13-30 lists the historical profits by calendar year by organization type
beginning in the 2012/2013 planning period for purchased FTRs. (Profits
do not include congestion revenue to self scheduled FTRs.) Profits include
revenue from the sale of FTRs and exclude bilateral transactions. Profits
include any surplus distribution or uplift payments. The end of planning
period surplus or uplift was distributed to FTR holders prorata based on FTR
positive target allocations through the 2017/2018 planning period. Beginningwith the 2018/2019 planning period, any net end of planning period surplus,
after paying out any shortfall in FTR target allocations within the planning
period, was distributed to ARR holders. Surplus allocated to ARR holders in
the 2018/2019 planning period was $112.3 million, $140.7 million in the
2019/2020 planning period, and $137.1 million in the 2020/2021 planning
period.

35 The GreenHat Default Allocation Assessment by PJM was $46.3 million for the 2019/2020 planning period and $1.8 million for the
2020/2021 planning period, excluding the FTR Waiver Settlement of $17.5 million. The calculated GreenHat losses do not exactly matchthe assessment. The loss calculation is based on GreenHat’s actual portfolio instead of the assessment formula and does not consider
bilateral transactions or GreenHat’s collateral.

718

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Table 13-30 FTR profits by organization type: 2012/2013 through 2020/202136
2012/20132013/20142014/2015$201,825,234$913,502,323$250,551,943($50,304,408) ($145,080,521)$19,453,837
Financial$151,520,826$768,421,802$270,005,781$201,825,234$913,502,323$250,551,785
Financial without GreenHat($50,304,408) ($145,080,521)$19,453,837$151,520,826$768,421,802$270,005,623$68,537,800$297,456,284$82,853,390
Physical($41,626,011)($53,642,077)$5,395,706$26,911,789$243,814,207$88,249,096$26,572,818$366,128,947$112,609,140($25,873,836)($81,279,067)$18,515,990
Physical ARR($45,978,766)($81,765,964)$15,530,158$698,982$284,849,881$131,125,130
Total$179,131,597 $1,297,085,890$489,380,007* Bilateral transactions are included in surplus allocation calculation but are not included in profits calculation
ProfitSurplus
Total
ProfitSurplus
Total
ProfitSurplus
Total
ProfitSurplus
Surplus from Self scheduled FTRs
Total

2015/2016$68,895,867$4,921,078$73,816,945$70,094,918$4,921,078$75,015,995$10,007,327$1,865,146$11,872,473$82,181,795$7,110,576$3,073,711$89,292,371$174,981,788

2016/2017($12,525,947)$8,810,267($3,715,680)($11,821,248)$8,810,267($3,010,981)($4,010,669)$4,181,855$171,186($2,468,152)$12,040,688$6,469,297$9,572,536$6,028,043

2017/2018$239,981,474$90,361,918$330,343,392$240,111,850$90,361,918$330,473,768$57,532,872$34,296,618$91,829,490$66,458,939$47,753,635$42,513,186$114,212,574$536,385,456

2018/2019$113,086,231

2019/2020($21,139,644)

2020/2021$280,586,579$113,086,231$223,376,757($21,139,644)$25,150,852$280,586,579$280,906,014$223,376,757($5,945,233)$25,150,852($42,860,656)$280,906,014$60,941,495($5,945,233)($6,248,557)($42,860,656)($49,614,191)$60,941,495$18,982,052($6,248,557)$100,892,442($49,614,191)($113,614,490)$18,982,052$360,510,126

Table 13-31 shows the profits and losses of the five most and the five least profitable participants by patterns of ownership. Total MWh is the sum of all MWh
by ownership type regardless of profitability. The Top 5 Profit is the sum of the profits of the five most profitable participants by ownership type. The Top 5
Profit/MWh is the Top 5 Profit divided by the sum of the MWh of the top 5 participants by ownership type. The Top 5 Market Share of MWh is the sum of the
MWh of the top 5 participants by ownership type divided by Total MWh. The Top 5 Profit Share Among Profitable Participants is the Top 5 Profit divided by
the sum of the profits of all profitable participants by ownership type. The same logic applies for the statistics related to the Bottom 5 participants. The All row
includes all participants including all ownership types when calculating the share of the profits and losses of the Top 5 and Bottom 5 participants. When allparticipants across ownership types are considered, four of the Top 5 participants and three of the Bottom 5 participants are financial participants. Of all theownership types, the Top 5 physical ARR participants’ share of profits is the highest, 87.3 percent, although the total profits of that group is the lowest. The
profits of physical ARR participants are more concentrated among the top participants in the 2020/2021 planning period than in the 2019/2020 planning period.
There are only a small number of physical ARR participants who directly purchase FTRs. The Bottom 5 financial participants’ share of losses is the highest, 91.9
percent (excluding GreenHat’s losses). Financial participants’ losses are concentrated in a small number of participants.
Table 13-31 Top 5 and bottom 5 FTR profits by ownership type: 2020/2021
Organization Type
Financial
Financial without GreenHat
PhysicalPhysical ARR
All

Total MWh
3,677,603,584
3,652,781,964
479,748,824
422,287,584
4,579,639,992

Top 5Profit$130,859,078$130,859,078$42,693,365$34,766,323$131,739,736

Top 5Profit/MWh
$0.17
$0.17
$0.28
$0.10
$0.16

Top 5
Market Sharein MWh
21.2%
21.3%
31.8%
82.9%
18.2%

Top 5
Profit Share Among
Profitable Participants
33.7%
33.7%
47.1%
87.3%
25.4%

Bottom 5
Loss($98,929,798)($98,929,798)($20,074,516)($15,087,394)($110,776,787)

Bottom 5
Loss/MWh($0.20)($0.20)($0.55)($1.22)($0.28)

Bottom 5
Bottom 5
Market Share
Loss Share Amongin MWh Unprofitable Participants
13.6%
91.6%
13.7%
91.9%
7.5%
67.7%
2.9%
72.5%
8.6%
69.9%

36 Bilateral profits and losses net to zero in market total profits and losses.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 719

2021 Quarterly State of the Market Report for PJM: January through June

Table 13-32 shows the shares of profitable and unprofitable FTR MWh byownership type in the 2020/2021 planning period. All ownership types had
more profitable MWh than unprofitable MWh.

Table 13-33 Long Term FTR Auction Revenue: 2021/2024
Trade TypeBuy bids

FTR Direction
Counter Flow

Table 13-32 MWh share by profitability by ownership type: 2020/2021
Organization Type
Financial
Financial without GreenHat
PhysicalPhysical ARR
Total

Unprofitable
17.2%
16.6%
14.8%
6.7%
15.9%

Profitable
82.8%
83.4%
85.2%
93.3%
84.1%

Prevailing Flow

Sell offers

Revenue

Total
Counter Flow

Prevailing FlowLong Term FTR Auction Revenue
Table 13-33 shows the long term FTR auction revenue data by trade type,
FTR direction, period type and class type. The 2021/2024 Long Term FTR
Auction netted $45.1 million in revenue, $8.0 million more than the previousLong Term FTR Auction. Buyers paid $93.9 million and sellers received $48.9
million, down $1.3 million and $9.2 million over the previous Long Term FTR
Auction.

720

Section 13 FTRs and ARRs

Total
Total

Period TypeYear 1
Year 2
Year 3Total
Year 1
Year 2
Year 3Total
Year 1
Year 2
Year 3Total
Year 1
Year 2
Year 3Total

24-Hour($38,788,118)($13,853,738)($7,936,367)($60,578,224)$68,082,328$47,661,107$46,115,078$161,858,513$101,280,290($87,814)($336,147)($1,195)($425,156)$2,082,120$490,249$107,683$2,680,052$2,254,896$99,025,394

Class TypeOn Peak
Off Peak($106,882,948)($62,872,994)($71,225,157)($40,900,612)($55,169,227)($32,456,552)($233,277,332) ($136,230,158)$130,225,121$65,158,734$69,764,897$32,131,729$43,013,931$21,877,662$243,003,949$119,168,126$9,726,617($17,062,032)($19,668,013)($8,743,571)($8,464,997)($4,901,489)($2,440,230)($1,217,953)($30,573,241)($14,863,013)$45,982,412$19,827,893$15,785,908$6,048,067$2,930,441$1,461,069$64,698,761$27,337,029$34,125,520$12,474,016($24,398,903)($29,536,049)

All($208,544,060)($125,979,508)($95,562,146)($430,085,714)$263,466,184$149,557,733$111,006,672$524,030,589$93,944,874($28,499,399)($13,702,633)($3,659,378)($45,861,409)$67,892,425$22,324,223$4,499,193$94,715,842$48,854,432$45,090,442

Annual FTR Auction Revenue
Table 13-34 shows the Annual FTR Auction revenue by trade type, type, FTR
direction and class type. The Annual FTR Auction for the 2021/2022 planning
period generated $692.4 million, up 20.0 percent from $577.0 million in the2020/2021 planning period, and down 18.0 percent from $844.6 million in
the 2019/2020 planning period. Counter flow FTR holders received $220.8
million, down 12.7 percent from the previous planning period and prevailingflow FTR holders paid $913.2 million, up 10.0 percent from the previous
planning period.

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Table 13-34 Annual FTR auction revenue: 2021/2022
Trade TypeBuy bids

Self-scheduled bids

Buy and self-scheduled bids

Sell offers

Type
FTR Direction
Obligations Counter Flow
Prevailing Flow
Total
Options
Counter Flow
Prevailing Flow
Total
Total
Counter Flow
Prevailing Flow
Total
Obligations Counter Flow
Prevailing Flow
Total
Obligations Counter Flow
Prevailing Flow
Total
Options
Counter Flow
Prevailing Flow
Total
Total
Counter Flow
Prevailing Flow
Total
Obligations Counter Flow
Prevailing Flow
Total
Options
Counter Flow
Prevailing Flow
Total
Total
Counter Flow
Prevailing Flow
Total

Total

24-Hour($24,885,989)$179,956,973$155,070,984$0$11,781,446$11,781,446($24,885,989)$191,738,420$166,852,430($133,780)$181,382,650$181,248,870($25,019,769)$361,339,623$336,319,854$0$11,781,446$11,781,446($25,019,769)$373,121,069$348,101,300($8,873,028)$7,726,333($1,146,694)$0$3,450$3,450($8,873,028)$7,729,783($1,143,244)$349,244,544

Class TypeOn Peak
Off Peak($165,673,155)($95,834,482)$379,016,229$188,556,802$213,343,075$92,722,320$0$0$25,424,679$20,620,200$25,424,679$20,620,200($165,673,155)($95,834,482)$404,440,909$209,177,002$238,767,754$113,342,520
NA
NA
NA
NA
NA
NA
($165,673,155)($95,834,482)$379,016,229$188,556,802$213,343,075$92,722,320$0$0$25,424,679$20,620,200$25,424,679$20,620,200($165,673,155)($95,834,482)$404,440,909$209,177,002$238,767,754$113,342,520($36,096,887)($20,781,645)$43,429,708$21,412,646$7,332,822$631,001$0$0$529,203$429,808$529,203$429,808($36,096,887)($20,781,645)$43,958,912$21,842,455$7,862,025$1,060,809$230,905,729$112,281,710

All($286,393,626)$747,530,005$461,136,378$0$57,826,325$57,826,325($286,393,626)$805,356,330$518,962,704($133,780)$181,382,650$181,248,870($286,527,407)$928,912,655$642,385,248$0$57,826,325$57,826,325($286,527,407)$986,738,980$700,211,573($65,751,560)$72,568,688$6,817,128$0$962,462$962,462($65,751,560)$73,531,150$7,779,590$692,431,983

The total net of all buy and sell offers in the Annual FTR Auction, not including self scheduled FTRs, was $577.0 million for the 2020/2021 planning period and$692.4 million for the 2021/2022 planning period, a 20.0 percent increase in revenue.
FTRs sold in Long Term FTR Auctions are sold at a substantial discount to the same FTR sold in Annual FTR Auctions. Table 13-35 shows the increase in total
auction revenue that would have resulted for the 2014/2015 through 2021/2022 planning periods if long term FTRs were sold at annual auction clearing prices.
This difference provides a good estimate of the value of the transmission capability made available in the Long Term FTR Auction that is not made available to
ARR holders. This capability should be made available to ARR holders in the Annual FTR Auction where it is the most valuable.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 721

2021 Quarterly State of the Market Report for PJM: January through June

Table 13-35 Estimated additional Long Term FTR Auction revenue at Annual
FTR Auction prices
Planning Period
2014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021
2021/2022
Total

YR3
$59,598,642$67,896,588$42,378,048$6,134,076$7,872,604$9,711,188($416,585)$73,050,796$266,225,357

Long Term FTR Product
YR2
YR1$30,284,173$52,030,909$40,975,278$9,936,078$3,854,373$11,055,824($1,841,715)$12,396,817$2,926,457$13,480,353$4,098,887$103,227,004$52,736,819($9,690,808)($3,111,721)$13,856,264$129,922,552$206,292,441

YRALL$926,989$303,082$1,079,901$227,524($111,226)$805,425$1,242,707
NA$4,474,401

Total Difference$142,840,713$119,111,026$58,368,147$16,916,702$24,168,189$117,842,504$43,872,132$83,795,339$606,914,751

Monthly Balance of Planning Period FTR Auction Revenue
Table 13-36 shows monthly balance of planning period FTR auction revenue
by trade type, type and class type for 2021. The Monthly Balance of Planning
Period FTR Auctions for the 2020/2021 planning period netted $41.4 million
in revenue, the difference between buyers paying $245.0 million and sellers
receiving $203.6 million. For the entire 2019/2020 planning period, theMonthly Balance of Planning Period FTR Auctions netted $52.9 million
in revenue with buyers paying $331.1 million and sellers receiving $278.2
million.

Table 13-36 Monthly Balance of Planning Period FTR Auction revenue: 2021
Class Type
24-Hour
On Peak$1,941,358$3,115,732$118,732$1,962,676
Options$7,201$295,920$52,076$1,307,888
Feb-21
Obligations$1,488,611$4,102,215$151,204$3,430,637
Options$6,780$178,510$66,074$845,917
Mar-21
Obligations$875,232$4,248,129($370,674)$2,359,553
Options$19,057$213,699$52,023$1,084,212
Apr-21
Obligations$298,333$3,124,790($41,738)$1,795,035
Options$7,925$94,663$28,839$841,377
May-21
Obligations$752,007$1,524,128($71,677)$1,089,999
Options$0$139,731$593$555,263
2019/2020*
Obligations$133,437,559$129,554,826$7,250,257$132,773,410
Options$567,551$13,430,803$1,210,460$44,320,769
Net Total$125,544,393($34,108,549)
2020/2021**
Obligations Buy bids
$76,746,367$54,636,231
Sell offers$4,698,724.82$52,945,884
Options
Buy bids$208,720$5,410,467
Sell offers$1,051,014$21,345,999
Net Total$71,205,347($14,245,186)* Shows twelve months for 2019/2020 **Shows twelve months for 2020/2021
Monthly
AuctionJan-21Type
Obligations

Trade TypeBuy bids
Sell offers
Buy bids
Sell offers
Buy bids
Sell offers
Buy bids
Sell offers
Buy bids
Sell offers
Buy bids
Sell offers
Buy bids
Sell offers
Buy bids
Sell offers
Buy bids
Sell offers
Buy bids
Sell offers
Buy bids
Sell offers
Buy bids
Sell offers

Off Peak$6,036,272$4,515,876$368,044$1,874,030$8,421,228$6,788,020$273,701$1,324,871$8,919,313$6,212,710$311,568$1,726,196$5,647,597$3,766,861$181,157$1,210,681$3,194,089$2,696,146$217,126$831,306$45,741,569$66,392,916$8,397,321$26,237,313($38,491,339)$100,913,096$94,347,154$7,087,686$29,168,798($15,515,170)

All$11,093,362$6,597,284$671,165$3,233,994$14,012,054$10,369,861$458,991$2,236,862$14,042,674$8,201,589$544,324$2,862,432$9,070,720$5,520,159$283,745$2,080,897$5,470,225$3,714,468$356,857$1,387,162$308,733,954$206,416,583$22,395,675$71,768,541$52,944,505$232,295,694$151,991,763$12,706,872$51,565,811$41,444,992

FTR Target Allocations
FTR target allocations were examined separately by source and sinkcontribution. Hourly FTR target allocations were divided into those that were
benefits and liabilities and summed by sink and by source. Figure 13-11 shows
the 10 largest positive and negative FTR target allocations, summed by sink,
for the 2020/2021 planning period. The top 10 sinks that produced financial
benefit accounted for 35.6 percent of total positive target allocations with theWestern Hub accounting for 11.1 percent of all positive target allocations. The

722

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

top 10 sinks that created liability accounted for 16.8 percent of total negative
target allocations with PSEG accounting for 4.1 percent of all negative target
allocations.
Figure 13-11 Ten largest positive and negative FTR target allocations summed
by sink: 2020/2021
PSEG
JCPLC
PPL
Western Hub

Largest liability

PECO
PEPCO
MEC
ATSI
White Rock (BGE)

Timber Road (AEP)
PEPCO
PECO
DPL
PSEG

Largest benefit

PPL
Northern Illinois Hub

Figure 13-12 Ten largest positive and negative FTR target allocations summed
by source: 2020/2021
Western Hub
AEP-Dayton Hub
BGE
Otter Point (BGE)
Birchwood (DOM)
Perryman (AP)PPL
North Neck 1 (DOM)
Dominion Residual Aggregate
Brandon Shores (BGE)
Quad Cities 2 (COMED)
Quad Cities 1 (COMED)Rock Springs (DPL)PSEG
Susquenhana 2 (PPL)
Susquenhana 1 (PPL)PPL
Northern Illinois Hub
PECOWestern Hub-$150

Dominion Residual Aggregate

Largest liability

Largest benefit

-$100

-$50

$0

$50

$100

$150

Target allocations (Millions)

AEP-Dayton Hub

BGE
Western Hub
-$100

-$50

$0

$50
$100
Target allocations (Millions)

$150

$200

$250

Figure 13-12 shows the 10 largest positive and negative FTR target allocations,summed by source, for the 2020/2021 planning period. The top 10 sources
with a positive target allocation accounted for 26.4 percent of total positive
target allocations with the Western Hub accounting for 5.2 percent of total
positive target allocations. The top 10 sources with a negative target allocationaccounted for 25.5 percent of all negative target allocations, with the Western
Hub accounting for 11.2 percent of total negative target allocations.

© 2021 Monitoring Analytics, LLC

Surplus Congestion Revenue
Surplus congestion revenue is a misnomer. In fact, there is no such thing as
surplus congestion revenue. The rights to all congestion revenue belong toload. Surplus congestion revenue, as defined in PJM rules, is an artifact of theflawed design of the current approach to FTR/ARRs.
In the current design, surplus congestion revenue should be allocated to ARR
holders because such revenue is part of total congestion revenues. In addition,
FTR Auction revenue results from the prices paid by willing FTR buyers andshould not be returned to FTR buyers for any reason and should be settled
monthly.

2021 Quarterly State of the Market Report for PJM: January through June 723

2021 Quarterly State of the Market Report for PJM: January through June

Surplus day-ahead congestion is defined as the difference between the dayahead congestion collected and FTR target allocations. Surplus FTR auction
revenue is defined as the difference between the sum of monthly FTR auction
revenue from the Long Term, Annual and monthly auctions, and ARR target
allocations. Surplus FTR auction revenue can result from high prices in the
FTR auctions, and from FTR capacity sold in excess of assigned ARR capacity
on specific paths, and FTR capacity sold on paths not available to ARR holders.
Surplus congestion revenue is defined as the sum of the surplus day-aheadcongestion revenue and the surplus FTR auction revenue at the end of eachmonth.37 Beginning with the 2014/2015 planning period, PJM may use surplus
FTR auction revenue to pay for the clearing of counter flow FTRs as part of
the auction clearing process.38 The remaining surplus is first used to ensurethat ARR target allocations in the month are fully funded. Any remaining
surplus is used to pay any shortfall in FTR target allocations for the current
month or prior months in the planning period. Any remaining surplus is used
to pay any shortfall in FTR target allocations for the entire planning period at
the end of the planning period. Any remaining surplus is distributed to ARR
holders.39
If, at the end of the planning period, all the surplus congestion revenue has
been provided to FTR holders and target allocations for the year are notcovered, an uplift charge is assigned to FTR holders to cover the net planning
period deficiency. An individual participant’s uplift charge allocation is theratio of their share of net positive target allocations to the total net positive
target allocations.

of the bar, and from auction surplus, represented by the orange portion of
the bar. The horizontal green lines represent the amount of revenue that FTRs
were paid from the surplus to be made whole for that month. The height ofthe bar below the green line is the portion of auction surplus that went to
FTR holders, and the height of the bar above the green line is the portion thatwould have gone to ARR holders at the end of the planning period, if nothingchanged and this surplus was not provided to FTRs. If a green line is above
the bar that means there was not enough surplus congestion in that month to
make FTRs whole. For example, September 2020 did not have enough surplus
congestion to make FTRs whole. Those FTRs were made whole using surplus
revenue from previous months.
The market rules should recognize that ARR holders have the right to all
surplus congestion revenue, not just the remainder after funding FTRs. The
MMU recommends that all FTR auction revenue be distributed to ARR holders
monthly, regardless of FTR funding levels. The MMU recommends that,
under the current FTR design, all congestion revenue in excess of FTR target
allocations be distributed to ARR holders on a monthly basis. In Figure 1313 the amount represented by each bar would be assigned to ARR holders inevery month. In the 2020/2021 planning period, $137.1 million of surplus
congestion revenue was paid to FTR holders that would have been paid to
ARR holders under the MMU recommendation.

Figure 13-13 shows the distribution of the monthly surplus congestion revenue
distributed to FTR holders as if it were settled monthly. The figure shows the
portions of total monthly surplus, represented by the total height of the bar,that are from day-ahead congestion surplus, represented by the blue portion
37 Prior to the 2017/2018 planning period, the surplus congestion revenue was not the simple sum of the surplus FTR auction revenue
and surplus day-ahead congestion because there were various cross market charges subtracted from FTR revenue, including M2M andcompeting use charges, which reduced available surplus congestion revenue.
38 See “PJM Manual 6: Financial Transmission Rights,” Rev. 26 (Jan. 27, 2021).
39 On May 31, 2018, a rule change was implemented. Effective for the 2018/2019 planning period, surplus day-ahead congestion charges
and surplus FTR auction revenue that remain at the end of the Planning Period allocated to ARR holders, rather than to FTR holders. 163
FERC ¶ 61,165.

724

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Figure 13-13 Monthly surplus congestion and auction revenue distributed to
FTR holders: June 2017 through June 202140
$30.0

$61.5

$252.1Figure 13-14 Monthly FTR auction surplus: 2011/2012 through 2021/2022

Auction Surplus
Congestion Surplus$25,000,000

Payments to FTRs

$25.0

$20,000,000

$20.0

$15.0

Surplus Revenue

Surplus Congestion Revenue (Millions)and completely to ARR holders. The MMU recommends that all FTR auction
revenue be distributed to ARR holders on a monthly basis.

$10.0$15,000,000$10,000,000$5.0$5,000,000

Jun-17

Dec-17

Jun-18Dec-18Jun-19Dec-19Jun-20Dec-20Jun-21$-Figure 13-14 shows the surplus FTR auction revenue from the 2011/2012
planning period through the 2020/2021 planning period. Each new planning
period introduces a new FTR model, including outages and PJM’s discretionary
adjustments for revenue adequacy. The differences in the assumptions in themarket model can result in large differences in FTR auction surplus and ARR
revenue from one planning period to another.

June
Sep
Dec
Mar
June
Sep
Dec
Mar
June
Sep
Dec
Mar
June
Sep
Dec
Mar
June
Sep
Dec
Mar
June
Sep
Dec
Mar
June
Sep
Dec
Mar
June
Sep
Dec
Mar
June
Sep
Dec
Mar
June
Sep
Dec
Mar
June

$0.0

11/12

12/13

13/14

14/15

15/16

16/17

17/18

18/19

19/20

20/21 21/22

FTR auction revenue is the value that FTR buyers assign to congestion rightsthat belong to ARR holders. There is no logical or market based reason to assign
any part of that auction revenue back to the FTR buyers. It is inconsistent
with the operation of a market that sellers are required to return some ofthe purchase price to buyers if the purchase is less profitable for buyers than
expected. Auction revenue from the sale of FTRs should be distributed directly
40 The bars for December 2018 and January 2019 are truncated.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 725

2021 Quarterly State of the Market Report for PJM: January through June

Table 13-37 shows the surplus FTR auction revenue, surplus day-aheadcongestion revenue and surplus congestion revenue for planning periods
2010/2011 through the 2020/2021 planning period.
Table 13-37 Surplus FTR Auction Revenue: 2010/2011 through 2020/202141
Surplus FTR Auction Revenue
Planning Period(Millions)
2010/2011$29.7
2011/2012$108.92012/2013$66.7
2013/2014$71.7
2014/2015*$29.0
2015/2016$29.6
2016/2017$27.9
2017/2018$27.4
2018/2019$180.8
2019/2020$217.82020/2021$166.1
Total$955.6*Start of counter flow “buy back”

Surplus Day-Ahead
Congestion (Millions($1,218.7)($460.3)($328.5)($715.3)$139.8$56.4$97.1$344.0($68.5)($87.9)($185.1)($2,426.9)

Surplus Congestion Revenue(Millions)($449.3)($192.5)($292.3)($678.7)$139.6$42.5$72.6$371.2$112.3$140.7($14.5)($748.5)

Revenue Adequacy
FTR revenue adequacy, like surplus congestion revenue, is a misnomer. FTR
revenue adequacy, as defined in PJM rules, is an artifact of the flawed designof the current approach to FTR/ARRs.
As defined, FTR revenue adequacy simply compares congestion revenues to
FTR target allocations. (Target allocations are the CLMP differences between
the source and sink of the FTR times the MW of the FTR.) There is no reason
to expect congestion revenues to equal FTR target allocations under the pathbased approach. Revenue adequacy is not a benchmark for how well the
FTR process is working. Target allocations define the maximum payments
to FTRs but target allocations are not congestion. FTR revenue adequacy is
not equivalent to the adequacy of ARRs as an offset for load against total
congestion. A path specific target allocation is not a guarantee of payment.

Actual congestion revenues are unrelated to PJM’s decisions about the FTR
auction model. As a result, the fewer FTRs sold, the higher the probability thatcongestion will exceed the sum of the FTR target allocations. For example,
PJM’s subjective decision to reduce available system capability in FTR auctions
for the 2014/2015 through 2016/2017 planning periods resulted in a highlevel of revenue adequacy. PJM’s decisions have included the arbitrary use ofhigher outage levels and the decision to include additional constraints (closed
loop interfaces) both of which reduced the FTRs made available for sale in FTR
auctions. PJM’s actions have led to a significant reduction in the allocationof Stage 1B and Stage 2 ARRs and therefore a reduction in available FTRs.
While PJM’s arbitrary decision to increase outages in the ARR allocationand in the Annual FTR Auction reduced FTR revenue inadequacy, it did not
address the Stage 1A ARR over allocation issue directly because Stage 1A
ARR allocations cannot be prorated. Instead, PJM’s actions for the 2014/2015
through 2016/2017 planning periods resulted in decreased Stage 1B ARR
allocations, decreased Stage 2 ARR allocations and decreased FTR capability.
The direct assignment of balancing congestion and M2M payments to load
beginning in the 2017/2018 planning period increased the congestion revenue
available to pay FTR holders. In response, PJM reduced the number of outages
taken in the ARR allocation and in the Annual FTR Auction, increasing ARR
allocations and FTR availability.
The current ARR/FTR design does not serve as an efficient way to ensurethat load receives all the congestion revenues or has the ability to receive
the auction revenues associated with all the potential congestion revenues.
There are several reasons for the disconnect between congestion revenues
and ARR/FTR revenues in the current design. The reasons include: the useof generation to load paths rather than a measure of total congestion toassign congestion revenue rights; the failure to provide to ARR holders thefull system capability that is provided to FTR purchasers in the Long Term
FTR Auction; unavoidable modeling differences such as emergency outages;
avoidable modeling differences such as outage modeling decisions; and crosssubsidies among and between FTR participants and ARR holders.

41 Total congestion surplus not equal to the sum of the columns in years prior to the 2017/2018 planning period because other charges
were subtracted from the congestion surplus.

726

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Revenue adequacy for ARRs is, for practical purposes, a meaningless concept.
Revenue adequacy for ARRs means that FTR buyers collectively pay morethan zero for FTRs in FTR auctions, and that those payments were received
by ARR holders. Unsurprisingly, ARRs have been revenue adequate for every
auction to date. ARR revenue adequacy has nothing to do with the adequacyof ARRs as an offset to total congestion. ARRs can be revenue adequate at
the same time that ARRs return only half of congestion to load, or even much
less.
Total net FTR auction revenue for the 2019/2020 planning period, before
accounting for self scheduling, load shifts or residual ARRs, was $982.0
million. The FTR auction revenue pays ARR holders’ credits. For the 2020/2021
planning period, total net FTR auction revenue was $691.2 million.
Table 13-38 presents the PJM FTR revenue detail for the 2019/2020 planning
period and the 2020/2021 planning period. This includes ARR target allocations
from the Annual ARR Allocation and net revenue sources from the Long Term,
Annual and Monthly Balance of Planning Period FTR Auctions.42 In this table,
under the new balancing congestion and M2M payment rules, any negative
congestion is from day-ahead congestion and does not include balancing
congestion. A negative deficiency is a surplus, which will be distributed to
ARR holders at the end of the planning period, while a positive deficiency
is a shortfall, which will be charged as FTR uplift at the end of the planning
period.

Table 13-38 Total annual ARR and FTR revenue detail (Dollars (Millions)):
2019/2020 and 2020/2021
Accounting Element
ARR information
ARR target allocations
ARR credits
FTR auction revenue
Annual FTR Auction net revenue
Long Term FTR Auction net revenue
Monthly Balance of Planning Period FTR Auction net revenue
Surplus auction revenue
ARR Surplus
ARR payout ratio
FTR targets
Positive target allocations
Negative target allocations
FTR target allocations
Adjustments:
Adjustments to FTR target allocations
Total FTR targets
FTR payout ratio
FTR revenues
ARR excess
Congestion
Net Negative Congestion (enter as negative)
Hourly congestion revenue
M2M Payments(credit to PJM minus credit to M2M entity)
Adjustments:
Surplus revenues carried forward into future months
Surplus revenues distributed back to previous months
Other adjustments to FTR revenues
Total FTR revenues
Surplus revenues distributed to other months
Net Negative Congestion charged to DA Operating Reserves
Total FTR congestion credits
Total congestion credits(includes end of year distribution)
Remaining deficiency

2019/2020

2020/2021$752.2$752.2$982.0$844.6$84.5$52.9$517.1$517.1$691.2$577.0$72.7$41.4$217.8100%$166.1100%$904.3($224.3)$680.1$1,397.7($313.0)$1,080.3($7.9)$673.5100%($4.5)$861.898.7%$217.8$166.1$0.0$596.4$0.0$0.0$899.6
$0.0

$0.0
$0.0
$0.0

$9.0
$20.2
$0.0

$0.0
$0.0
$814.2$814.2($140.7)

$29.2
$0.0
$1,094.9$1,094.9$14.5

FTR target allocations are defined based on hourly CLMP differences in the
day-ahead energy market for FTR paths. FTR credits are paid to FTR holders
and, depending on market conditions, can be less than the target allocations
but are capped at target allocations. Table 13-39 lists the FTR revenues, target
allocations, credits, payout ratios, congestion credit deficiencies and excesscongestion charges by month.
42 The final ARR values may change if load shifts.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 727

2021 Quarterly State of the Market Report for PJM: January through June

120%
100%
80%
60%
40%

Jan-21

Jan-20Jan-19Jan-18Jan-17Jan-16

Jan-150%

Jan-1420%

Jan-13

Section 13 FTRs and ARRs

140%

Jan-12

728

160%

Jan-11$1,065.7

With Excess Revenue Distribution

Jan-10Total

Without Excess Revenue Distribution

180%

Jan-09$814.2$74.4$118.3
$95.2
$90.9
$67.5
$55.1
$79.6
$69.0
$104.9$96.3$95.6$118.9200%

Jan-08Total
Jun-20Jul-20Aug-20
Sep-20
Oct-20Nov-20Dec-20Jan-21
Feb-21
Mar-21
Apr-21
May-21Figure 13-15 FTR payout ratio by month, excluding and includingexcess revenue distribution: January 2004 through June 2021

Jan-07FTR
FTR
FTR
Monthly Credits
FTR Target Payout Ratio
Credits
Payout Ratio Surplus/Deficiency
Allocations(original) (with adjustments) (with adjustments) (with adjustments)$39.4
100.0%$52.1
100.0%($13.0)$82.0
100.0%$91.7
100.0%($10.5)$42.8
100.0%$57.1
100.0%($14.7)$73.6
100.0%$83.4
100.0%($9.7)$84.5
100.0%$91.1
100.0%($6.6)$72.3
100.0%$84.6
100.0%($12.3)$74.1
100.0%$80.6
100.0%($6.4)$44.8
100.0%$63.2
100.0%($18.4)$28.2
100.0%$50.0
100.0%($21.8)$38.5
100.0%$51.4
100.0%($12.9)$32.0
100.0%$42.9
100.0%($10.9)$62.7
100.0%$66.2
100.0%($3.5)
Summary for Planning Period 2019/2020$674.9$814.2($140.7)$73.3
100.0%$74.7
100.0%($1.1)$112.3100.0%$118.3100.0%($6.0)$94.4
100.0%$95.2
100.0%($0.8)
$95.2
94.9%
$95.2
100.0%
$0.0
$72.2
93.1%
$72.2
100.0%$0.0$53.4
100.0%$55.1
100.0%($1.7)
$90.5
87.5%
$90.5
100.0%$0.0$67.6
100.0%$69.0
100.0%($1.4)$95.4
100.0%$104.9100.0%($9.6)$107.589.6%$105.598.2%$1.1$109.4
87.4%
$95.6
87.4%
$13.4
$110.3100.0%$118.9100.0%($8.6)
Summary for Planning Period 2020/2021$1,081.5$1,095.3$14.5

Jan-06

PeriodJun-19Jul-19Aug-19Sep-19Oct-19
Nov-19Dec-19Jan-20Feb-20Mar-20
Apr-20May-20FTR
Revenues(with adjustments)
$52.1
$91.7
$57.1
$83.4
$91.1
$84.6
$80.6
$63.2
$50.0
$51.4
$42.9
$66.2

Jan-05

Table 13-39 Monthly FTR accounting summary (Dollars (Millions)):
2019/2020 and 2020/2021

Figure 13-15 shows the original PJM reported FTR payout ratio by month,excluding excess revenue distribution, for January 2004 through June 2021.
The months with payout ratios above 100 percent have congestion revenue
greater than the target allocations and the months with payout ratios under
100 percent have congestion revenue that is less than the target allocations.
Figure 13-15 also shows the payout ratio after distributing surplus congestion
revenue across months within the planning period. The payout ratio forrevenue inadequate months in the current planning period may change if
surplus congestion revenue is collected in the remainder of the planning
period.

Jan-04

The total row in Table 13-39 is not the sum of each of the monthly rows
because the monthly rows may include excess revenues carried forwardfrom prior months and excess revenues distributed back from later months.
September 2020 had revenue shortfalls totaling $4.2 million, but September
FTR target allocations were fully funded using surplus revenue from previous
months. March and April 2021 had revenue shortfalls that could not be madewhole using surplus revenues from previous months, resulting in a revenue
shortfall for the planning period.

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Table 13-40 shows the FTR payout ratio by planning period from the
2003/2004 planning period forward. Planning period 2013/2014 includes
the additional revenue from unallocated congestion charges from Balancing
Operating Reserves. Beginning with the 2018/2019 planning period payments
to FTRs are limited to 100 percent of the target allocations.

Figure 13-16 FTR surplus and day-ahead, balancing and total congestion:2005 through June 2021
$1,000Day-Ahead Congestion$800

Balancing Congestion
Total CongestionFTR Surplus

Table 13-40 Reported FTR payout ratio by planning period

43

FTR Payout Ratio
97.7%
100.0%
90.7%
100.0%
100.0%
100.0%
96.9%
85.0%
80.6%
67.8%
72.8%
116.2%
106.8%
112.6%
138.5%
100.0%
100.0%
98.7%

Figure 13-16 shows the FTR surplus, day-ahead, balancing and total congestion
payments from January 2005 through June 2021.

$600

Dollars (Millions)

Planning Period
2003/2004
2004/2005
2005/2006
2006/2007
2007/2008
2008/20092009/20102010/20112011/20122012/20132013/20142014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021

$400

$200

$0

-$200

-$400

ARRs as an Offset to Congestion for Load
Load pays for the transmission system and pays congestion revenues.
FTRs, and later ARRs, were intended to return congestion revenues to load
to offset an unintended consequence of locational marginal pricing. With
the implementation of the current, path based FTR/ARR design, the purposeof FTRs has been subverted. The inconsistencies between actual network
solutions used to serve load and path based rights available to load cause amisalignment of congestion paid by load and the congestion paid to load, inaggregate and on a specific load basis. These inconsistencies between actual
network use and path based rights cause cross subsidies between ARR holders

43 The actual payout ratios for planning periods 2006/2007, 2007/2008, and 2008/2009 may have exceeded 100 percent.

© 2021 Monitoring Analytics, LLC

2021 Quarterly State of the Market Report for PJM: January through June 729

2021 Quarterly State of the Market Report for PJM: January through Juneand FTR holders and among ARR holders. One result of this misalignment is that individual zones have very different offsets due to the location of their pathbased ARRs compared to their actual congestion costs from actual network use.
Table 13-41 shows the ARR and FTR revenue paid to load, the congestion offset available to load with and without allocating balancing congestion to load andthe congestion offset when surplus congestion revenue is allocated to load. The highlighted offsets are the actual offsets based on the rules that were effective inthat planning period. The pre 2017/2018 offset is calculated as the ARR credits and the FTR credits excluding balancing congestion and M2M payments, divided
by the total day-ahead congestion and the load share of balancing and M2M payments.
The allocation of balancing congestion and M2M payments to load went into effect for the 2017/2018 planning period. If these rules had been in place beginningwith the 2011/2012 planning period, ARR holders would have received a total of $1,351.4 million less in congestion offsets from the 2011/2012 through the2020/2021 planning period. The total overpayment to FTR holders for the 2011/2012 through 2020/2021 planning period would have been $1,534.3 million.
Total ARR and self scheduled FTR revenue offset 46.2 percent of total congestion costs for the 2020/2021 planning period. For the 2019/2020 planning period,
FTR bidders paid more in the auctions than the actual day-ahead target allocations for the same paths. The unexpected reduction in energy prices in 2020 led
to a corresponding unexpected reduction in target allocations and in actual congestion. This resulted in an offset over 100 percent because the resulting total
ARR value was greater than actual congestion costs. FTR prices were lower in the Annual FTR Auction for 2020/2021, reducing the offset for the 2020/2021
planning period.
Table 13-41 ARR and FTR total congestion offset (in millions) for ARR holders: 2011/2012 through 2020/2021
Pre 2017/2018(Without Balancing)

Revenue

Planning
Period2011/20122012/20132013/20142014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021
Total

730

ARR
Credits$512.2$349.5$337.7$482.4$635.3$640.0$427.3$529.1$542.0$373.9$4,829.4

Unadjusted
FTR Credits$310.0$268.4$626.6$348.1$209.2$149.9$212.3$130.1$91.9$179.3$2,525.8

Day Ahead
Congestion$1,025.4$904.7$2,231.3$1,625.9$1,098.7$885.7$1,322.1$832.7$612.1$899.6$11,438.0

Section 13 FTRs and ARRs

Balancing+ M2MCongestion($275.7)($379.9)($360.6)($268.3)($147.6)($104.8)($129.5)($152.6)($169.4)($256.2)($2,244.7)

Total
Congestion$749.7$524.8$1,870.6$1,357.6$951.1$780.8$1,192.6$680.0$442.7$643.4$9,193.4

Surplus
Revenue Pre
2017/2018
Rules($50.6)($94.0)($139.4)
$36.7
$9.2
$15.1
$52.3
($5.8)($1.6)($43.1)($221.2)

Surplus
Revenue
2017/2018
Rules
$35.6
$18.4
($49.0)$111.2
$42.1
$36.5
$80.4
$16.2
$21.6
($0.0)$312.9Post
2017/2018
Rules$113.9$62.1($49.0)$400.6$188.9$179.0$370.7$112.2$157.8($0.0)$1,536.1

Total ARR/FTR Offset$771.6$523.9$824.8$867.2$853.7$805.0$692.0$653.34$632.3$510.14$7,134.1

2017/2018 (With
Balancing)

Current
Percent Revenue
Offset Received
102.9%$582.1
99.8%$256.444.1%$554.663.9%$673.489.8%$739.0103.1%$721.658.0%$590.696.1%$522.7142.8%$486.1
79.3%$297.1
77.6% $5,423.6

Post 2017/2018 (With
Balancing and Surplus)

New
Percent Revenue
Offset Received
77.6%$660.448.9%$300.129.7%$554.649.6%$962.877.7%$885.992.4%$864.049.5%$880.976.9%$618.8109.8%$622.246.2%$297.1
59.0% $6,646.8

New Offset
88.1%
57.2%
29.7%
70.9%
93.1%
110.7%
73.9%
91.0%
140.6%
46.2%
72.3%

Effective Offset

Cumulative
Revenue$771.6$523.9$824.8$867.2$853.7$805.0$590.6$618.8$622.2$297.1$6,774.9

Offset102.9%
99.8%
44.1%
63.9%
89.8%
103.1%
49.5%
91.0%
140.6%
46.2%
73.7%© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

Table 13-41 illustrates the inadequacies of the ARR/FTR design. The goalof the design should be to give the rights to 100 percent of the congestion
revenues to the load.
The cumulative offset, beginning in the 2011/2012 planning period, isthe sum of the revenue received for that planning period and all previous
planning periods divided by the total congestion for that planning period
and all previous planning periods. The cumulative shortfall is the cumulative
difference between the ARR holders’ revenue and the congestion they paid,
for the planning period and prior planning periods.
Table 13-42 also shows the cumulative offset and shortfall, assuming therules implemented in the 2017/2018 planning period. The cumulative offset
percentage has increased since the 2014/2015 planning period except for the
2019/2020 planning period. The cumulative offset would have been 72.3
percent if the 2017/2018 surplus allocation rules had been in place for theentire period.
Table 13-42 ARR and FTR cumulative offset for ARR holders using 2017/2018
surplus allocation: 2011/2012 through 2020/2021
Planning Period
2011/20122012/20132013/20142014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021

Cumulative Offset
88.1%
75.4%
48.2%
55.0%
61.7%
67.8%
68.8%
70.6%
74.3%
72.3%

Cumulative Shortfall (Millions)($89.3)($314.0)($1,630.0)($2,024.8)($2,090.0)($2,006.8)($2,318.5)($2,379.8)($2,200.2)($2,546.6)

Table 13-43 shows the cumulative offset and shortfall using the rules thatwere effective in the given planning period to calculate the ARR/FTR revenue.
The cumulative offset was 73.7 percent based on the rules that were in placefor each planning period. Load has been underpaid by $2.4 billion from the2011/2012 planning period through the 2020/2021 planning period. The© 2021 Monitoring Analytics, LLC

amount of underpayment would have been even greater, $3.8 billion, if the
2017/2018 surplus allocation rules had been in place for the entire period.
Table 13-43 ARR and FTR cumulative offset for ARR holders using effective
surplus allocation rules: 2011/2012 through 2020/2021
Planning Period
2011/20122012/20132013/20142014/2015
2015/20162016/20172017/20182018/20192019/2020
2020/2021

Cumulative Offset
102.9%
101.6%
67.4%
66.3%
70.4%
74.5%
70.5%
72.2%
75.8%
73.7%

Cumulative Shortfall (Millions)
$21.9
$21.0
($1,024.8)($1,515.2)($1,612.6)($1,588.4)($2,190.4)($2,251.7)($2,072.1)($2,418.4)

Zonal ARR Congestion Offset
Zonal ARR congestion offsets vary significantly across zones. There is no
reason that this should be the result. This outcome is a direct result of theflawed definition of congestion and of the method for assigning rights tocongestion to ARR holders. The results show that path based ARR assignmentsin the current path based ARR/FTR design are not aligned with actual network
use by load, and are therefore not aligned with how congestion is actually
paid by load on actual network usage. Due to this misalignment of ARR rights
relative to actual network usage, individual loads cannot claim the congestion
they paid through assigned ARRs. The misalignment of path based ARR rights
produces cross subsidies among ARR holders.
ARRs are allocated to zonal load based on historical generation to loadtransmission contract paths, in many cases based on 1999 contract paths.
ARRs are allocated within zones based on zonal base load (Stage 1A) andzonal peak loads (other stages). ARR revenue is the result of the prices that
result from the sale of FTRs through the FTR auctions. ARR revenue for eachzone is the revenue for the ARRs that sink in each zone.

2021 Quarterly State of the Market Report for PJM: January through June 731

2021 Quarterly State of the Market Report for PJM: January through June

Congestion paid by load in a zone is the total difference between what the zonal load pays in congestion charges net of payments to the generation that serves
the zonal load, including generation in the zone and outside the zone.44
Table 13-44 shows the day-ahead congestion and balancing congestion and M2M charges paid by load in each zone along with the congestion offsets paid toload: FTR auction revenue; self scheduled FTR revenue adjusted by the payout ratio for FTRs if below 100 percent; and the allocation of end of planning period
surplus.45 The offset for the 2020/2021 planning period assigns the current surplus revenue at the end of the quarter to ARR holders. Table 13-44 also shows
payments by load for balancing congestion and M2M payments. The total congestion offset paid to load is the sum of all of those credits and charges.
The zonal offset percentage shown in Table 13-44 is the sum of the congestion related revenues (offset) paid to load in each zone divided by the total congestion
payment made by load in each zone.
Table 13-44 Zonal ARR and FTR total congestion offset (in millions) for ARR holders: 2020/2021 planning period
Zone
ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DUQ
DOM
DPL
EKPC
EXT
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
Total

ARR Credits
$4.4
$40.2
$32.9
$20.4
$58.4
$36.4
$5.9
$24.2
$5.6
$7.7
$28.6
$3.0
$0.5
$6.0
$3.5
$0.0
$15.0
$6.1
$25.9
$24.3
$24.7
$0.2
$373.9Adjusted
FTR Credits
$0.0
$36.4
$14.9
$0.2
$3.6
$11.5
$0.8
$4.9
$0.2
$85.7
$8.1
$0.0
$0.0
$0.0
$0.7
$0.0
$0.2
$4.9
$3.8
$3.4
$0.0
$0.0
$179.3

Balancing+
M2M
Charge($2.7)($38.1)($14.8)($19.5)($9.1)($28.5)($5.3)($8.4)($4.0)($37.9)($6.7)($4.2)($13.8)($6.1)($5.3)($0.3)($10.9)($6.5)($8.3)($11.5)($13.9)($0.6)($256.2)

Surplus
Allocation Total Offset($0.1)$1.7($2.4)$38.4($1.4)$33.0($0.6)$1.1($1.7)$52.8($1.2)$19.4($0.2)$1.5($0.8)$20.8($0.2)$1.8($1.9)$55.5($0.9)$30.1($0.1)($1.1)($0.0)($13.3)($0.2)($0.0)($0.1)($1.1)$0.0($0.3)($0.4)$4.2($0.3)$4.5($0.8)$21.4($0.7)$16.1($0.7)$10.8($0.0)($0.4)($14.5)$297.0Day Ahead
Congestion$8.2$149.0
$60.0
$70.1
$34.0
$106.8
$16.3
$25.8
$10.4
$121.5
$46.9
$12.6
$24.8
$19.0
$21.7
$1.2
$35.8
$22.9
$28.8
$42.3
$38.9
$2.6
$899.6

Balancing
Congestion($2.3)($32.2)($12.5)($16.4)($7.7)($24.2)($4.5)($7.1)($3.4)($32.9)($5.8)($3.6)($13.8)($5.0)($4.6)($0.3)($9.1)($5.7)($6.9)($9.6)($11.9)($0.5)($219.9)

M2M
Payments($0.5)($5.9)($2.3)($3.0)($1.4)($4.4)($0.8)($1.2)($0.9)($0.6)($4.9)($0.6)$0.0($1.1)($0.7)$0.0($1.8)($0.8)($1.3)($1.9)($2.0)($0.1)($36.3)

Total
Congestion$5.5$110.9
$45.2
$50.6
$24.8
$78.3
$11.0
$17.4
$6.2
$87.9
$36.2
$8.4
$11.0
$12.9
$16.5
$0.9
$24.9
$16.4
$20.5
$30.8
$25.0
$2.1
$643.4

Offset
31.2%
34.6%
73.0%
2.1%
212.7%
24.7%
13.4%
119.5%
29.6%
63.1%
83.2%
(13.0%)(120.7%)(0.2%)(6.9%)(28.8%)
17.0%
27.3%
104.5%
52.4%
43.2%(17.0%)
46.2%

44 See “Constraint Based Congestion Calculations,” PJM ARR FTR Market Task Force (July 17, 2020) <https://www.pjm.com/-/media/committees-groups/task-forces/afmtf/2020/20200722/‌20200722-item-03a-constraint-based-congestion-calculations.ashx>.
45 See 2019 State of the Market Report for PJM, Volume II, Section 11: Congestion and Marginal Losses

732

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

The total congestion offset paid to loads in the 2020/2021 planning period was 46.2 percent of congestion costs. The results vary significantly by zone. Loads
in some zones, like BGE, receive substantially more in offsets than their total congestion payments. Loads in other zones, like ATSI, receive substantially less inoffsets than their total congestion payments. The offsets are a function of the assignment of ARRs and the valuation of ARRs in the FTR auctions.

Offset Available from Self Scheduling
It is not possible for load to recover all of the congestion that they pay under the current design in which the rights to congestion revenues are assigned basedon fictitious contract paths. Table 13-45 shows the total congestion offset that would be available to ARR holders via allocated ARRs, by zone, if the ARR holders
self scheduled all their allocated ARRs as FTRs in the 2018/2019 through 2020/2021 planning periods. The results show that the recovery of congestion varies
significantly by zone and that some zones recover more than the congestion they pay and some zones recover less. This is not consistent with a rational FTR/
ARR design based on the fundamentals of the way that congestion costs are actually paid.
Table 13-45 Offset available to load if all ARRs self scheduled: 20182019 through 2020/2021 planning periods

ACEC
AEP
APS
ATSI
BGE
COMED
DAY
DUKE
DUQ
DOM
DPL
EKPC
EXT
JCPLC
MEC
OVEC
PECO
PE
PEPCO
PPL
PSEG
REC
Total

SS FTR
$11.5
$84.9
$37.4
$45.3
$49.0
$51.4
$11.2
$50.4
$7.2
$55.8
$57.7
$0.9
$1.7
$2.6
$5.0
NA
$15.7
$17.5
$19.5
$4.3
$35.6
$0.2
$565.018/19 Planning Period
Bal+M2M
Charges Congestion+M2M($1.9)$10.0($24.2)$105.4($9.0)$44.7($12.5)$52.3($6.1)$20.0($16.7)$96.3($3.3)$12.8($5.3)$23.6($2.5)$7.7($18.4)$66.0($4.0)$59.0($2.3)$9.5($4.8)($4.1)($4.2)$20.3($3.3)$14.6
NANA($7.4)$29.9($4.2)$17.5($5.4)$18.2($7.7)$36.6($8.8)$38.5($0.9)$1.1($152.7)$680.0© 2021 Monitoring Analytics, LLC

Offset
96.2%
57.6%
63.5%
62.8%
215.0%
36.1%
61.8%
191.2%
61.5%
56.7%
91.0%
(14.5%)
76.7%(7.8%)
11.8%
NA
27.7%
76.0%
77.8%
(9.1%)
69.6%(68.7%)
60.6%

SS FTR
$2.6
$62.7
$31.2
$27.9
$53.7
$40.6
$5.6
$30.5
$8.1
$32.8
$27.3
$4.1
$0.9
$2.3
$0.8
NA
$16.8
$11.2
$23.2
$39.2
$21.3
$0.2
$443.019/20 Planning Period
Bal+M2M
Charges Congestion+M2M($2.1)$3.7($28.2)$81.9($10.4)$31.9($13.9)$36.8($6.7)$15.3($19.8)$65.2($3.9)$9.7($6.0)$14.9($3.2)$5.1($16.9)$59.2($8.7)$17.4($2.9)$7.4($2.2)($1.7)($4.6)$9.2($4.2)
$8.7
$0.1
$0.5
($8.2)$13.4($3.8)$10.8($6.1)$13.7($8.5)$20.5($8.9)$18.4($0.3)$0.6($169.4)$442.7

Offset
15.6%
42.1%
65.1%
38.1%
308.0%
31.9%
17.4%
164.2%
95.2%
26.9%
107.3%
16.8%
74.3%(25.5%)(38.5%)
NA
63.8%
69.1%
124.3%
149.9%
67.2%(22.6%)
61.8%

SS FTR
$1.8
$77.3
$42.0
$30.7
$79.7
$69.6
$8.0
$40.9
$8.9
$40.9
$56.4
$6.6
$0.3
$0.9
$8.0
NA
$14.0
$13.5
$37.3
$43.7
$43.2
$1.0
$624.8

20/21 Planning Period
Bal+M2M
Charges Congestion+M2M($2.7)$5.5($38.1)$110.9($14.8)$45.2($19.5)$50.6($9.1)$24.8($28.5)$78.3($5.3)$11.0($8.4)$17.4($4.0)$6.2($37.9)$87.9($6.7)$36.2($4.2)$8.4($13.8)$11.0($6.1)$12.9($5.3)$16.5($0.3)$0.9($10.9)$24.9($6.5)$16.4($8.3)$20.5($11.5)$30.8($13.9)$25.0($0.6)$2.1($256.2)$643.4

Offset(16.4%)
35.3%
60.3%
22.1%
284.2%
52.4%
24.9%
187.2%
79.7%
3.5%
137.4%
29.3%(122.3%)(40.2%)
16.5%
NA
12.4%
42.8%
141.7%
104.5%
117.0%
21.0%
57.3%

2021 Quarterly State of the Market Report for PJM: January through June 733

2021 Quarterly State of the Market Report for PJM: January through June

CreditDefault Portfolio Considerations

There were five collateral defaults in 2021. There were five payment defaults
in 2021 not involving GreenHat Energy, LLC for a total of $1.8 million.
GreenHat Energy’s default payments ended with the 2020/2021 planning
period. GreenHat Energy accrued total accrued payment defaults of $162.0
million, including the auction liquidation costs.46 In addition, PJM added thesettlement fee and claimant payee funds to the default allocation, resulting
in allocations of $12.5 million and $5.0 million for a total of $179.5 million.

Under the method applied to the GreenHat default, when an FTR participant
defaults on their positions, their portfolio remains in the FTR market andwill continue to accrue revenues and/or charges and must be reconciled.
Under this method, PJM leaves the participant’s positions unchanged, lets
the positions settle at day-ahead prices, and charges any net losses to thedefault allocation assessment. This method exposes all members in PJM to an
uncertain charge for the default allocation assessment that will not be known
until those FTRs settle.

GreenHat Settlement Proceedings
On June 5, 2019, FERC issued an order that established a paper hearing
and settlement judge procedures regarding the GreenHat liquidation waiver
request.47 FERC recognized “…there are multiple complexities associated with
implementing the Waiver Order Directive that should be addressed in a paper
hearing…”48 Before the paper hearing began, FERC established a settlement
procedure to “…encourage the parties to make every effort to settle theirdisputes before the paper hearing commences.”49
By delegated order issued December 30, 2019, the Commission approved asettlement agreement between PJM and the interested parties.50 The result of thesettlement was a release of all claims of harm resulting from the July auction
liquidation of GreenHat’s portfolio, the payment of $12.5 million directly to
two participants, and payment of up to $5 million total to participants thatcan show economic harm from PJM’s actions during the July auction.
This settlement, requiring up to $17.5 million in additional payments, will berecovered via the default allocation assessment fund, which is allocated to all
PJM members in proportion to their total net bill.

The MMU recommends a method under which defaulted FTRs would becanceled rather than holding or liquidating them. Canceling the FTRs would
release the FTRs to the FTR market. The market would then decide the valueof the capacity released and the timing of its release. There would be nodiscretion necessary to settle the defaulted position and the losses would becontained within the ARR/FTR market.
Cancellation of a defaulting portfolio does not change congestion. But
cancellation of a defaulting portfolio can affect ARR/FTR funding as a resultof changes in auction revenue, changes in the net target allocations, andpotential simultaneous feasibility violations, while any collateral collectedfrom the defaulted participant is available to offset losses from the cancelled
FTRs. However, PJM can and does address similar issues routinely. PJM has
tools available, such as the counter flow buyback and Stage 1A over allocation
rules, and uses them regularly in the Annual FTR Auction, to improve funding
as well as address feasibility concerns. Cancellation of FTRs would isolate thecosts of the default to those participating in and benefitting from the FTR
market.

46 See the 2019 Quarterly State of the Market Report for PJM: January through June for a more complete explanation of credit issues that
occurred in 2019.
47 On June 21, 2018, GreenHat Energy, LLC was declared in payment default for non-payment of a $1.2 million weekly invoice on June 5,
2018. GreenHat had been declared in default twice earlier in June 2018 for two collateral calls totaling $2.8 million. Daugherty, Suzanne,email sent to the MC, MRC, CS, and MSS email distribution list, “Notification of GreenHat Energy, LLC Payment Default,” (June 22, 2018).
48 See 167 FERC ¶ 61, 2019 at P 27 (2019).
49 See Id. at P 28.
50 See 169 FERC ¶ 61,260 (2019).

734

Section 13 FTRs and ARRs

© 2021 Monitoring Analytics, LLC

Section 13 FTRs and ARRs

FTR Forfeitures
In the Forfeiture Rule Directive, the Commission determined that the Forfeiture
Rule is just and reasonable and “…serves to deter such manipulation” related
to virtual transaction cross product manipulation.51 The Commission identified
four main tenets with which the Forfeiture Rule must comply, including thatit: (i) deter manipulation, (ii) provide transparency allowing participants tomodify their behavior, (iii) base forfeitures on an individual participant’s
actions and (iv) is not punitive.52
The point of the Forfeiture Rule is to avoid an inefficient and costly process
and to establish an objective rule that prevents profiting from virtual trading
on one’s own FTR positions. The Forfeiture Rule operates to remove the
incentive to engage in manipulation; the rule does not involve findings ofmanipulation.53
The FTR forfeiture rule considers the impact of a participant’s net virtualtransaction portfolio on all constraints.54 If a participant’s net virtual portfolio
impacts a constraint by the greater of 0.1 MW or 10 percent or more of theline limit, and that constraint affects an individual FTR’s target allocation by$0.01, metric that the participant’s net virtual portfolio increased the value ofthe FTR, then the FTR is subject to FTR forfeiture.
The FTR Forfeiture Rule does not penalize FTR holders. The FTR forfeiturerule does not affect the profits or losses of virtual activity. The FTR Forfeiture
Rule, if triggered by a participant’s virtual portfolio, results in forfeiting only
FTR profits and only in the specific hours for which the rule is violated. The
profit is calculated as the hourly FTR target allocation minus the FTR’s hourlycost. Even when FTR profits are forfeited, the value that the buyer assigned tocongestion in the FTR auction (the price paid) is not affected. For example, if
a buyer paid $5.00/MWh for congestion and congestion was $5.00/MWh, theforfeiture would be zero. If congestion were $7.00/MWh, the forfeiture would
be $2.00/MWh. Market participants understand the relationship between FTR
51 Forfeiture Rule Directive at P 33.
52 Forfeiture Rule Directive at P 62.
53 See “Protest and Motion for Rejection of the Independent Market Monitor for PJM,” Docket No. EL20-41 (June 1, 2020).
54 A modified FTR forfeiture rule was implemented effective January 19, 2017. See 2019 State of the Market Report for PJM, Volume II,
Section 13: Financial Transmission Rights for the full history.

© 2021 Monitoring Analytics, LLC

and virtual positions in detail and can avoid violating the FTR forfeiture rule
if they choose to do so.
The FTR forfeiture rule has not reduced participation in the PJM FTR market
or participation in virtual activity. There has been an increase in the numberof participants in the FTR market since the implementation of the new FTR
forfeiture rule, and a decrease in the number of participants with forfeitures.
On May 20, 2021, FERC issued an order ruling the $0.01 definition of anincrease in the value of an FTR unjust and unreasonable, but upheld the otherparts of PJM’s forfeiture rule. In this Order, FERC required PJM to modify the
FTR forfeiture rule and submit a compliance filing. As a result, PJM stopped
billing FTR forfeitures using this method on May 20, 2021, and will not
implement a forfeiture rule until FERC accepts a compliance filing.
Figure 13-17 shows the monthly FTR forfeitures under the modified FTR
forfeiture rule from January 19, 2017, through May 20, 2021. As requiredby the FERC order, PJM began retroactively billing FTR forfeitures with theSeptember 2017 bill. In the period from January 2017 through September
2017, participants did not have good information about the level of their
FTR forfeitures, so they could not accurately modify their bidding behavior
to avoid FTR forfeitures. After September 2017, FTR forfeitures decreased
significantly, and stabilized, as participants received information on their FTR
forfeitures.
On June 24, 2019, PJM implemented a new method to properly calculate
the hourly cost of an FTR only for hours in which it is effective.55 Beginningwith the September 2019 bill, PJM began billing using the correct hourly costcalculation. For the 2020/2021 planning period, total FTR forfeitures were
$4.6 million.

55 See “Minor modification to Tariff Language for FTR Forfeiture Rule,” Docket No. ER19-2240 (June 24, 2019).

2021 Quarterly State of the Market Report for PJM: January through June 735

2021 Quarterly State of the Market Report for PJM: January through June

Figure 13-17 Monthly FTR forfeitures for physical and financial participants$1,800,000
Financial$1,600,000

Physical$1,400,000$1,200,000$1,000,000$800,000$600,000$400,000$200,000$-

Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May
2016/2017736

2017/2018

Section 13 FTRs and ARRs

2018/20192019/2020

2020/2021© 2021 Monitoring Analytics, LLC