Price Formation in Organized Wholesale Electricity Markets 

Docket No. AD14-14-000 

Staff Analysis of

Operator‐Initiated Commitments

in RTO and ISO Markets

December 2014 

For	further	information,	please	contact:	

Emma	Nicholson	

Office	of	Energy	Policy	and	Innovation	

Federal	Energy	Regulatory	Commission	

888	First	Street,	NE	

Washington,	DC	20426	

(202)	502‐8846	

emma.nicholson@ferc.gov	

This report is a product of the Staff of the Federal Energy Regulatory Commission. 

The opinions and views expressed in this paper represent the preliminary analysis of 

the Commission Staff. This report does not necessarily reflect the views of the 

Commission. 
 

 

 Table of Contents 

Executive Summary ............................................................................................................. 1

I. Introduction ................................................................................................................... 3

II. Tools Used to Schedule Resources ........................................................................... 3

A. Security Constrained Unit Commitment ................................................................ 5

B. Security Constrained Economic Dispatch ............................................................. 8

III. Overview of Resource Scheduling Process ............................................................... 8

A. Day-Ahead Schedule............................................................................................ 10

B. Residual Unit Commitment Schedule .................................................................. 14

C. Real-time Schedule .............................................................................................. 18

IV. Locational Marginal Pricing .................................................................................... 22

A. Locational Marginal Pricing Overview ............................................................... 22

B. Cost Elements included in the LMP Framework ................................................. 25

C. EcoMin Relaxation .............................................................................................. 26

D. Fast-start Pricing Logic in RTOs and ISOs ......................................................... 28

V. Empirical Analysis .................................................................................................. 30

A. Methodology ........................................................................................................ 31

B. Results Overview ................................................................................................. 32

C. Market-specific Results ....................................................................................... 34

VI. Concluding Remarks ............................................................................................... 40
 

 

1 

Executive Summary

This paper is part of an effort to evaluate matters affecting price formation in the energy 

and ancillary services markets operated by Regional Transmission Operators (RTOs) and 

Independent System Operators (ISOs) subject to the jurisdiction of the Federal Energy 

Regulatory Commission (FERC or Commission). It focuses on operator-initiated 

commitments in the RTOs and ISOs and the challenges in internalizing all relevant 

physical and operational constraints in the day-ahead and real-time market processes. 

This paper defines an operator-initiated commitment as a commitment that is not 

associated with a resource clearing the day-ahead or real-time market on the basis of 

economics and that is not a self-schedule. Deeming an action to be “operator-initiated” is 

not intended to confer any judgment that the action is not appropriate or necessary to 

maintain reliability. 

Locational marginal prices (LMPs) for energy and ancillary services ideally would reflect 

the true marginal cost of production, taking into account all physical and operational 

system constraints, and fully compensate all resources for the variable cost of providing 

service.1

 There are a number of challenges accounting for all physical and operational 

constraints. The central challenge stems from the fact that the full alternating current 

representation of the transmission system cannot currently be explicitly included in the 

market software despite the use of state-of-the-art computational tools. Further, some 

operational and reliability considerations can be difficult to incorporate into the dayahead market process. Such considerations include managing the uncertainty related to 

real-time system conditions and resource performance or addressing local environmental 

constraints or secondary reliability concerns. As a result, alternative means are used to 

manage those elements that cannot be explicitly included in the day-ahead market 

process. 

Two additional market design features related to developing prices that better reflect the 

actual operation of the system are what costs to include in the set of variable costs that 

are eligible to set clearing prices and which resources are eligible to set clearing prices. 

Specifically, there is some question whether some of the costs to commit resources are 

appropriately considered variable costs. This is particularly true for fast-start resources 

that can start-up quickly and typically have shorter minimum run times than other 

resources.

2

 A related question is how to ensure that fast-start resources are considered 

when setting price. Because fast-start resources are offline prior to being dispatched and 

then are typically dispatched immediately to their full operating limit, they can appear to 

 1 See Price Formation in Energy and Ancillary Services Markets Operated by Regional Transmission 

Organizations and Independent System Operators, Notice, Docket No. AD14-14-000 (June 19, 2014).

2

 The definition of fast-start resources varies across RTOs and ISOs. 
 

 

2 

be similar to resources committed out-of-market. As a result, RTOs and ISOs have to 

take steps to ensure the price setting algorithm recognizes these resources to allow them 

to be eligible to set the price. 

This paper describes the processes RTOs and ISOs use to commit and dispatch resources 

in day-ahead and real-time, with a focus on how RTOs and ISOs address the market 

design challenges associated with difficult-to-model physical and operational constraints. 

A component of the discussion is how the market design decisions influence price 

formation. The extent of the price formation issues is somewhat dependent on the actual 

amount of capacity RTOs and ISOs are committing that is not reflected in energy and 

ancillary services prices. If RTOs and ISOs only commit a limited number of resources 

outside of the day-ahead or real-time market processes, then the price formation issues 

discussed would be largely theoretical. The paper concludes with an empirical analysis 

that attempts to measure the magnitude of certain types of operator-initiated 

commitments that are not directly reflected in market clearing prices. 

This paper’s preliminary observations include the following: 

 All RTOs and ISOs have identified a class of reliability and operational issues 

that are incorporated into the day-ahead and real-time market processes but 

which are not reflected in day-ahead and real-time energy and ancillary 

services prices. 

 Some RTOs and ISOs have designed reserve products to address reliability and 

operational issues that would otherwise result in unit commitments outside of 

the day-ahead and real-time market processes. 

 The amount of capacity that is committed but not dispatched above a 

resource’s minimum operating level, a rough proxy for capacity that is not 

reflected in price, is moderate in most RTOs and ISOs but can reach fairly high 

levels in some hours. 

 Most RTOs and ISOs have some method to allow fast-start resources to set 

price, though the method used and the resources eligible to set price differ by 

market. 

 Some RTOs and ISOs allow the commitment costs of certain fast-start 

resources to be reflected in energy and ancillary services prices, though the 

costs included differ by market. 

This paper is intended to spur discussion and lead to a more comprehensive 

understanding of operator-initiated actions and price formation. The workshop scheduled 

for December 9, 2014, will provide an opportunity for Commission Staff to learn the 

views of market participants, RTOs, ISOs, and market monitors. 
 

 

3 

I. Introduction 

Energy and ancillary services markets are the primary mechanism that RTOs and ISOs 

use to identify the least-cost commitment and dispatch of system resources while 

respecting all applicable reliability standards. Because some relevant physical and 

operational constraints cannot, for reasons discussed below, be included in the market 

software, RTO and ISO operators also commit resources outside of the market clearing 

process to resolve reliability issues not internalized in the electricity and ancillary 

services markets. The market design choices that RTOs and ISOs make to best address 

the physical and operational constraints that are not included in the market software 

inherently influence price formation in the energy and ancillary service markets. The 

objective of this paper is to provide information and analysis relevant to a discussion of 

the extent to which out-of-market commitments made by RTOs and ISOs affect price 

formation in energy and ancillary services markets. 

A critical first step in understanding the relationship between operator-initiated 

commitment and dispatch decisions and price formation is to develop an understanding of 

the framework under which unit commitment and dispatch decisions are typically made. 

This paper first provides a brief high level description of the primary software tools and 

business practices RTOs and ISOs use to control available generation (and other 

resources, where relevant) reliably and economically. Second, this paper presents an 

overview of the multi-stage process for scheduling and dispatching resources. In the 

process of presenting the overview, this paper highlights key market design decisions and 

how those decisions can influence price formation. Third, this paper reviews the process 

of setting LMP with a focus on the types of costs that are reflected in prices and the 

resources that are eligible to set price. Finally, the paper presents an empirical analysis of 

market data to identify and estimate the magnitude of certain types of operator-initiated 

commitments that are not directly reflected in market clearing prices. 

II. Tools Used to Schedule Resources

A central function of RTOs and ISOs is to develop a schedule to coordinate the operation 

of all system resources. The schedule instructs all resources on the system when to startup, how much electricity to generate while in operation, and when to shut down. The 

market operator follows a sequence of steps to select a least-cost mix of resources to 

reliably meet expected load conditions and to prepare the system to react to changing 

conditions effectively and economically, while respecting the constraints of the 

transmission system and the resources available to supply energy and ancillary services. 

The overarching goal of this process, from an economic viewpoint, is to maximize the 

social welfare while reliably serving load, where social welfare is measured as consumer 
 

 

4 

surplus plus producer surplus.3

 Given the lack of price responsive demand, maximizing 

social welfare is primarily achieved by minimizing total production cost. The 

overarching goal from a reliability perspective is to comply with mandatory reliability 

standards as well as any local or supplemental reliability rules.

System operators use a suite of software tools to achieve these goals. These tools 

recognize that a resource must be committed – or started up – to be included in the 

schedule. Accordingly, developing a schedule typically involves two key decisions: 

1) Unit commitment: the determination of which resources to start-up or shut-down 

and when to do so; and 

2) Unit dispatch: the determination of the generation in megawatts (MW) each 

committed resource should produce in each interval.4

 

Unit commitment decisions are determined through an optimization process called 

security constrained unit commitment (SCUC). Unit dispatch is determined through a 

security constrained economic dispatch (SCED) optimization process. The phrase 

“security constrained” denotes the fact that the unit commitment and economic dispatch 

decisions are made subject to the condition that transmission system constraints are not 

violated and resource supply offer parameters and operating characteristics are honored. 

The two processes are explained in detail below. 

There are a number of challenges to simultaneously maintaining reliability and 

minimizing production costs. First, the full alternating current representation of the 

transmission system cannot be explicitly included in the unit commitment and economic 

dispatch decisions given the current state-of-the-art computational tools.5

 Specifically, 

voltage and stability constraints cannot be included in either the SCUC or SCED 

processes. As a result, alternative means, described below, must be used to avoid 

violating voltage and stability constraints. Second, the unit commitment and economic 

dispatch decisions are made before the uncertainty surrounding system conditions, 

including load, variable energy resource output, and generator performance is resolved. 

Again, alternative means in both day-ahead and real-time processes, described below, 

have been developed to manage this uncertainty. Third, some local reliability and 

operational rules can take the form of state or regional requirements to limit reliance on 

potentially scarce fuel or otherwise recognize environmental limitations.6

 Some of these 

 3

 Consumer surplus captures the fact that some consumers pay a price less than their maximum willingness 

to pay. Producer surplus captures the fact that some producers are paid a price greater than the marginal cost to 

produce electricity. 

4

 Demand-side resources are instructed to reduce load rather than increase generation. 

5

 Commission Staff’s annual Market Software Conference is intended to make progress on computational 

limitations. See http://www.ferc.gov/industries/electric/indus-act/market-planning.asp. 

6

 For example, NYISO implements the New York State Reliability Council’s Local Reliability Rules I-R3 

and I-R5 by specifying minimum oil burn requirements for certain dual-fuel generators in New York City and Long 
 

 

5 

requirements can be included in the SCUC and SCED processes, but others are managed 

outside of these processes. And fourth, some system operators incorporate supplemental 

protocols designed to prepare resources to maintain reliability in the event that a 

secondary contingency occurs quickly after a primary contingency, so-called N-1-1 

contingencies. These N-1-1 contingencies may be managed within or outside the SCUC 

and SCED processes. To the extent any of the above challenges are managed outside of 

the SCUC and SCED processes, it is difficult to ensure the resources selected in fact have 

the lowest production cost among all alternatives. In addition, any action taken to 

manage these issues that is not included in the SCUC and SCED processes will not be 

directly reflected in the energy and ancillary services prices. Un-modeled reliability 

requirements have an indirect effect on energy and ancillary service prices because these 

requirements commit additional units outside of the market construct, effectively adding 

supply, which could reduce clearing prices. 

A. Security Constrained Unit Commitment

The SCUC is a constrained optimization process that recognizes the costs to start and 

operate resources and the physical and operational limitations of resources that govern 

start up time, minimum run time, how frequently they can be started and how long they 

must be idle before being started again. It is these physical or operational limitations in 

particular that make the unit commitment process an essential part of least-cost operation. 

RTO and ISO operators use resource self-schedules, resource supply offers, reliability 

requirements, and transmission system constraints to determine a schedule that indicates 

which resources will be online during an operating day, when they will be online, and 

how much electricity they should produce. The RTOs and ISOs inform individual 

resources of their resource-specific schedule through dispatch but do not publicly share 

the system-wide schedule. Resources are expected to follow their dispatch instructions 

(or price signals) and limit any deviations to a small amount. 

Table 1 summarizes some of the components contained in most resource supply offers. 

While this list is not exhaustive, it gives a sense of the operational constraints that RTO 

and ISO operators must honor when they determine schedules for resources. 

 

 Island. See New York State Reliability Council, New York State Reliability Council Rules, at I-R3, I-R5 (Apr. 10, 

2014), available at http://www.nysrc.org/pdf/Reliability%20Rules%20Manuals/RR %20Manual%2033%20April% 

2010%202014%20Final%20v.2.pdf. 
 

 

6 

 

Table 1 Typical Resource Supply Offer Parameters 

Physical Parameters (units) Financial Parameters (units) 

• self-schedule quantity if applicable (MW) • start-up cost ($/start-up) 

• start-up time (hours) • no-load cost ($/hour while operating) 

• minimum run time (hours) • incremental energy cost 

• economic minimum output level (MW) ($/MWh at various MW levels) 

• economic maximum output level (MW) • costs to provide Ancillary Services 

• ramp rate up (MW/minute) • shut-down cost ($/shut-down) 

• ramp rate down (MW/minute) 

• maximum run-time (hours) 

• shut-down time (hours) 

• minimum downtime (hours) 

The resource supply offer parameters in Table 1 are also affected by environmental 

regulations. For example, a given resource may be limited to a specific number of starts 

per year. The objective of the SCUC process is to minimize the total production cost to 

supply load and operating reserves subject to the limits of the transmission system 

(transmission security constraints), reliability needs, and resource supply offer 

parameters. The production cost component consists of two subcomponents: 

commitment costs and incremental energy costs. Commitment costs are the costs to start 

up a resource and operate it at its economic minimum level (EcoMin)7

 for its minimum 

run-time.8

 Incremental energy costs may include the variable costs (typically based on 

fuel and variable operation and maintenance costs) of producing electricity and the 

opportunity costs of foregoing other opportunities at levels above a resource’s EcoMin, 

often referred to as an individual resource’s energy supply curve. 

Inputs to the SCUC algorithm include the transmission network parameters, resource 

supply offers (including operating parameters) and a requirements forecast. 

Transmission network parameters are used by the SCUC to form a mathematical 

representation of the transmission system, often referred to as the network model. The 

network model ensures that injections (supply resources) and withdrawals (load) are 

physically feasible (i.e., do not violate any physical constraints) given the transmission 

equipment that makes up the power system and the configuration of that equipment 

(network topology). The network model includes a set of transmission power flow limits 

that typically bind on the system. Other transmission power flow limits that do not 

regularly bind are excluded from the network model to reduce the complexity of the 

optimization problem. 

 7

 The EcoMin may be, but is not necessarily, equal to the resource’s minimum physical operating level. 

8

 For example, a resource with a $30,000 start-up cost, a $200/hour no-load cost, a 40 MW EcoMin, a 

$30/MWh incremental energy cost at its EcoMin, and a 5 hour minimum run time would have a $37,000 

commitment cost ($30,000 + $200/hour x 5 hours + 40MW x $30/MWh x 5 hours =$37,000). 
 

 

7 

As noted above, the network model also typically excludes certain local reliability limits 

that either do not typically bind or cannot be readily modeled, such as reactive power and 

voltage limits. Some of the local reliability limits that require more complex 

mathematics to model explicitly may be included in the network model implicitly as 

proxy transmission flow limits that simulate the underlying limit. A key question for 

system operators is when to develop such proxy constraints. The answer is often driven 

by whether there is a predictable relationship between the underlying system constraint 

and flows on a transmission facility and whether the energy and ancillary services prices 

that result from such a proxy constraint would be reasonable charges and compensation 

relative to what would result from explicitly modeling the constraint.9

 Table 2 presents a 

list of typical transmission parameters that are included in the network model. 

Table 2 Typical Transmission Parameters 

Electrical Parameters Configuration Parameters 

• line or equipment impedance • base system configuration 

• allowable ranges/settings for equipment • line outages 

• line or equipment flow limits (can be 

expressed in MW, MVA or Amps) 

• equipment outages 

As discussed in more detail below, the SCUC process is performed several times for each 

operating day, including during the day-ahead market, between day-ahead and real-time 

(referred to as residual unit commitment) and in real-time. A system requirements 

forecast is necessary to perform a SCUC. System requirements include load, operating 

reserves, and losses. The types of loads included in the requirements forecast depends on 

the type of schedule that is developed. The system requirements in the day-ahead 

schedule are based on the MW of load cleared, including net virtual demand, in the dayahead market plus the ancillary services requirements associated with that load. The 

system requirements used in the residual unit commitment (RUC) are represented by the 

best available forecast of what the system load will be on the operating day at the time 

the process is performed plus associated ancillary services requirements. The means by 

which uncertainty is managed is discussed below. The real-time SCUC processes are 

based on continuously updated load and reserve forecasts. 

The SCUC considers the commitment costs of the resources, along with all of the other 

relevant information, and selects the optimal set of resources to commit in addition to 

units that have elected to commit themselves through self-schedules.10 The total costs 

incurred by the market include the value of market-priced resources, commitment costs 

of those resources, and the costs associated with operator-initiated commitments. 

 9

 For example, if reactive power could be explicitly modeled in SCUC and SCED, the models could 

produce prices for (real) power, reactive power and ancillary services, generators could be scheduled, dispatched 

and paid for those services, and loads would pay for those services. 

10 Self-scheduled resources have commitment costs of zero because when resources commit themselves, 

they agree to assume the risk of recovering their own start-up and no-load costs. 
 

 

8 

B. Security Constrained Economic Dispatch

Like the SCUC, the SCED process is a constrained optimization problem. The SCED 

process determines how much electricity each committed resource in the schedule should 

generate, or hold in reserve as ancillary services.11 The SCED process uses much of the 

same information that is used in the SCUC, except that commitment cost data is not 

typically used. Energy and ancillary services dispatch levels are typically co-optimized 

in the SCED, meaning that the process simultaneously determines the optimal amounts of 

each.12 The SCED also calculates energy and ancillary services prices for the relevant 

market interval (hourly for the day-ahead market; and every five minutes for the real-time 

market). LMPs are calculated as the cost of serving the next increment of load at each 

location, and vary due to binding transmission constraints and losses. A similar 

calculation is made to price ancillary services. When calculated in this way, the ancillary 

services prices include the foregone profits that could have been earned from energy 

market sales, which represent a resource’s opportunity cost of providing ancillary 

services. 

III. Overview of Resource Scheduling Process 

The schedule that is ultimately used to dispatch resources in real-time is developed 

through a multi-stage process, using the SCUC and SCED processes. RTOs and ISOs 

typically divide the resource scheduling process into three discrete steps that occur in the 

following order: day-ahead market, RUC, and real-time unit commitment and dispatch. 

Each of these processes uses the SCUC and SCED tools, to a degree, based on current 

offers, system information, and forecasts of system conditions. The timing of this 

sequence is summarized in Figure 1. 

Figure 1 

 Sequence of Resource Schedule Development

 Day-ahead RUC Real-time 

Time Performed -day before 

operating day 

-day before opearating 

day and during 

operating day 

-during operating day 

Scheduling Interval -hourly -hourly -5 minutes 

Each step in this sequence is more fully described in sections III.A through III.C. Each 

of the RTOs and ISOs has similar designs that include these three generic processes, 

 11 Some RTOs and ISOs allow eligible offline units (i.e., units that have not been committed by the SCUC) 

to be considered in the SCED. 

12 All RTOs and ISOs co-optimize energy and ancillary reserves in real-time. With the exception of ISONE (See ISO-NE Manual 11, Market Operations, § 5.2.9.1(2).) all of the RTOs and ISOs co-optimize energy and 

ancillary services in the day-ahead market. 
 

 

9 

although the timing, terminology, and details of each process vary. Resources can be 

included in the schedule in one of three ways: through a market clearing process on the 

basis of economics; through a self-schedule by the resource itself;13 or through an 

operator-initiated commitment. This paper defines an operator-initiated commitment as a 

commitment that is not associated with a resource clearing the day-ahead or real-time 

market on the basis of economics and that is not a self-schedule. Deeming an action to be 

“operator initiated” is not intended to confer any judgment that the action is not 

appropriate or necessary to maintain reliability. Rather, such actions are highlighted 

because they are not directly reflected in energy and ancillary services prices. Operatorinitiated commitments can be made through automated out-of-market processes such as 

the RUC, or they can be made manually. For example, the RUC constitutes operatorinitiated commitment because, although least-cost optimization is considered when 

decisions are made on operator-committed resources, the resources selected during the 

RUC are not included in the process used to set market clearing prices. Operators can 

also manually commit resources outside of the SCUC and SCED processes, as the driver 

of the decision is often a concern that is difficult to include in the SCUC or SCED 

processes, as discussed above. The following section first provides a high-level overview 

of the sequence of resource schedule development before discussing the steps in more 

detail and notes key differences across RTOs and ISOs. 

The day-ahead schedule consists of unit commitment and dispatch instructions for every 

hour in the operating day based on the outcome of the day-ahead market clearing 

process.

14 The day-ahead schedule consists of economic commitments, resource selfschedules, and operator-initiated commitments (if any). RTOs and ISOs amend the dayahead schedule through a RUC that ensures that the day-ahead schedule contains enough 

generation to satisfy forecasted load and reserves. The RUC also addresses any 

reliability issues that are not sufficiently resolved in the day-ahead schedule. The realtime schedule further amends the RUC based on actual system conditions, the real-time 

market clearing process, self-schedules, and any operator-initiated commitments. The 

real-time schedule forms the basis of real-time commitment and dispatch instructions. 

The RTOs and ISOs also have tariff provisions that permit operators to initiate changes to 

the schedule that are outside of either the day-ahead or real-time market process when 

 13 A self-scheduled resource submits its intended operating schedule as part of the day-ahead market 

process; it is included in the SCUC and SCED as a resource with zero commitment costs and zero incremental 

energy costs at its self-scheduled quantity. Updates to a self-schedule may also be submitted in real-time and are 

processed in a similar manner. A resource owner’s decision to self-schedule is based on that entity’s view of its own 

economic best interest. The decision to self-schedule takes the commitment decision out of the SCUC process, 

which may have efficiency implications if that resource is not among the set of least cost resources. 

14 The first step in developing a schedule is actually to determine which long-start resources will be needed 

on the operating day. Long-start resources need to be started prior to the day-ahead scheduling process because they 

have extended start-up times (e.g., 24 hours) and thus need to be notified earlier than units with shorter start-up 

times. 
 

 

10 

necessary to maintain system reliability or address issues not fully accounted for in the 

day-ahead, RUC, or real-time scheduling processes. Operators may manually commit 

resources to address concerns such as capacity shortages, generation or transmission 

contingencies, transmission facility overloads, or abnormal voltages. Operators may also 

manually commit resources for purposes such as avoiding load shedding, assisting 

neighboring areas, or mitigating other reliability issues. 

A. Day-Ahead Schedule 

All FERC-jurisdictional RTOs and ISOs have both a day-ahead and a real-time market. 

The day-ahead market is a daily forward market that takes place the day prior to the 

operating day to which it applies. The day-ahead market process balances supply offers 

(both physical and virtual) against demand bids (both physical and virtual).15 The dayahead schedule is based on the load and ancillary services requirements that cleared the 

day-ahead market, including virtual supply and demand bids.16 

Generally speaking, the day-ahead market clearing process employs a SCUC and SCED 

to dispatch energy and ancillary services in order to minimize total production costs 

subject to constraints in the network model and supply offers. The day-ahead SCUC and 

SCED optimization is dynamic in that it minimizes total production costs over the entire 

operating day. The day-ahead market process produces, for each hour of the relevant 

operating day, financially-binding schedules for all resources and loads that cleared the 

market and calculates energy and ancillary service clearing prices. For resources, this 

means that they are financially obligated to provide the quantity of MW that the resource 

cleared in the day-ahead schedule. For example, if a resource clears 100 MW through the 

day-ahead market in hour-ending 6:00, then it must either physically provide 100 MW 

during that hour at that location, purchase 100 MW from the real-time market during that 

hour at that location, or do some combination thereof.17 In addition to units that are 

scheduled through the day-ahead market, the day-ahead schedule includes self-scheduled 

resources and any resources previously committed through the long-start process.18 

One common day-ahead market feature across all RTOs and ISOs is that demand bids 

and resource supply offers are due at a clearly stated time on the day before the operating 

 15 Virtual supply and demand offers are financial positions taken in the day-ahead market that settle based 

on the difference between day-ahead and real-time clearing prices. 

16 The day-ahead schedule is also likely to include resource commitments made through the RTO or ISO’s 

long-start commitment process. The long-start commitment process is necessary to commit resources with extended 

start-up times (e.g., 36 hours) that cannot be accommodated during the normal day-ahead market process. 

17 In some markets, some resources have capacity obligations and would be expected to deliver scheduled 

energy except in the event of an unexpected outage. 

18 The process that makes long-lead time commitments also involves economic considerations but it is 

separate from the formal centralized day-ahead or real-time markets. 
 

 

11 

day in question. Once the bids are submitted, the RTOs and ISOs run the day-ahead 

SCUC and SCED processes to determine the day-ahead schedule. The RTOs and ISOs 

post the day-ahead prices and issue day-ahead schedules to individual resources at a fixed 

time that varies by RTO and ISO. Table 3 provides a summary of key features of the 

day-ahead market process in the California Independent System Operator Corporation 

(CAISO), ISO New England Inc. (ISO-NE), Midcontinent Independent System Operator, 

Inc. (MISO), New York Independent System Operator, Inc. (NYISO), PJM 

Interconnection, L.L.C. (PJM), and Southwest Power Pool, Inc. (SPP). Column two of 

Table 3 lists the times that day-ahead bids are due and column three lists the time by 

which schedules and prices are posted. 

Table 3 Day-Ahead Market Details

Bids due 

Schedules and 

prices posted1

Out-of-market commitments that may be 

included in the day-ahead schedule

CAISO 10:00 am 1:00 pm Minimum Online Constraints 

ISO-NE 10:00 am 1:30 pm Special Constraint Resources and Local Second 

Contingency Protection Resources 

MISO 11:00 am 3:00 pm System Support Resources, and Voltage and 

Reliability commitments 

NYISO 5:00 am 11:00 am Day-Ahead Reliability Units and Local Reliability 

Rule Units.2

PJM 12:00 pm 4:00 pm Reliability commitments 

SPP 11:00 am 4:00 pm Manual commitments to resolve transmission 

security and local reliability constraints 1 Times are given in local time for each RTO and ISO. CAISO is Pacific; ISO-NE, MISO, PJM, and NYISO are Eastern; 

and SPP is Central.

2

 NYISO is unique because its day-ahead market clearing process is combined with a RUC in a single process with 

several stages.

Resources that are selected by the day-ahead market process on the basis of economics 

are said to have “cleared” the day-ahead market. However, the day-ahead schedule also 

includes self-schedules and operator-initiated resource commitments. 

All RTOs and ISOs have identified a class of known reliability issues for which units are 

committed and included in the day-ahead schedule, but which do not involve a shadow 

price.19 Such reliability commitments are among the first resources included in the dayahead schedule. Self-schedules are included next and economic commitments are made 

over and above the reliability commitments and self-schedules to satisfy the energy and 

ancillary services associated with day-ahead cleared load. While it is possible for 

resources initially included in the day-ahead schedule for reliability reasons to be 

economic absent the reliability constraint, these resources are not initially included in the 

day-ahead schedule on the basis of economics or with the expectation that they will 

 19 A “shadow price” is the incremental cost of meeting a constraint if the constraint is relaxed by one unit. 

In this case, the shadow price, which is not currently calculated, would be the cost savings that would result if the 

reliability constraint included in the day-ahead market was relaxed by one MW. 
 

 

12 

establish the clearing price. Further, certain reliability resources are only scheduled to 

operate at the resource’s minimum operating level, which typically disqualifies them 

from setting the clearing price.20 

Resources committed in the day-ahead market for this class of reliability concerns are 

unlikely to set clearing prices, but they affect clearing prices because they displace 

resources that would otherwise be committed through the economic process. Such 

commitments are typically made on the basis of engineering studies and operational 

experience and are more likely to require make-whole (uplift) payments than 

economically-committed resources. 

The final column of Table 3 provides a summary of the types of operator-initiated 

commitments included in the day-ahead market by each RTO and ISO. For example, 

CAISO’s day-ahead schedule includes Minimum Online Constraints, which are 

commitment constraints that require that certain units be committed to address regional 

reliability standards.21 A key function of Minimum Online Constraints is to address 

North American Electric Reliability Corporation and Western Electricity Coordinating 

Council reliability standards that require CAISO to return flows on critical transmission 

paths to their system operating limit within the thirty minutes following a contingency.22 

NYISO includes commitments in its day-ahead schedule that are not committed on the 

basis of economics but rather are typically requested by New York transmission owners 

to address local reliability issues (Day-Ahead Reliability Units23) or to address local 

reliability issues in New York City and Long Island (Local Reliability Rules24). 

PJM’s day-ahead schedule includes operator-initiated reliability commitments to address 

blackstart, reactive support, voltage support, and interface control needs.25 ISO-NE’s 

day-ahead schedule may include Special Constraint Resources, which are committed at 

 20 See infra section IV.A for more details about which resources are eligible to set the clearing price under 

the LMP framework. 

21 CAISO, Technical Bulletin 2010-01-02 Minimum Online Commitment Constraint (Jan. 2010) available 

at http://www.caiso.com/Documents/TechnicalBulletin-MinimumOnlineCommitmentConstraint.pdf. 

22 CAISO, Contingency Modeling Enhancements Second Revised Straw Proposal at 4 (Mar. 13, 2014), 

available at http://www.caiso.com/Documents/SecondRevisedStrawProposalContingencyModelingEnhancements.pdf. 

23 NYISO, Manual 11, Day-Ahead Scheduling Manual, § 4.2.6, which defines DARU units as “[t]hose 

units that the NYISO commits solely for reliability reasons at the request of a Transmission Owner or for statewide 

reliability needs as initiated by NYISO.” 

24 NYISO Manual 12, Transmission and Dispatching Operations Manual, § 2.1.6. 

25 PJM Interconnection, Impact of Reliability Units Being Included in the Day-Ahead Market at 1 (Apr. 

2013), available at http://www.pjm.com/~/media/committees-groups/committees/mic/20130405-da/20130405-item04-impact-of-reliability-unit-committment-in-day-ahead-whitepaper.ashx. 
 

 

13 

the request of transmission owners or distribution providers in order to maintain local 

reliability.26 ISO-NE also includes expected local second contingency protection 

requirements for the real-time market within its day-ahead schedule.27 ISO-NE protects 

against second contingencies by committing Local Second Contingency Protection 

Resources through minimum commitment constraints within the day-ahead market at five 

interfaces.28 ISO-NE explained that including Local Second Contingency Protection 

Resources commitments in the day-ahead market as minimum commitment constraints 

reduced the need to commit Local Second Contingency Protection Resources in its RUC 

(referred to as a Reserve Adequacy Analysis in ISO-NE). ISO-NE expressed an interest 

in reducing Reserve Adequacy Analysis commitments because the Reserve Adequacy 

Analysis may commit more capacity than is necessary in real-time.29 

MISO includes certain commitments necessary for voltage and local reliability.30 MISO 

transmission owners may also request that System Support Resources be committed in 

the day-ahead or real-time markets. System Support Resources are generation resources 

or synchronous condenser units that are required to maintain the reliability of the 

transmission system.31 SPP allows operators to initiate commitments to address 

reliability issues.32

The rationale for including operator-initiated commitments in the day-ahead-schedule is 

that doing so would result in a day-ahead schedule that more closely resembles the realtime schedule. Including reliability commitments in the day-ahead schedule, as opposed 

to RUC, would likely achieve a more optimal solution because the commitment 

algorithms internalize such commitments and make additional commitments in a manner 

that minimizes total production costs. In addition, the value of including these 

constraints in the day-ahead schedule is that the operator avoids committing and 

dispatching a resource that will not ultimately be needed in real-time and therefore avoids 

any related uplift payments to such resources. Further, greater consistency between the 

 26 ISO-NE, Transmission, Markets and Services Tariff, Market Rule 1, § III.6.2.1. 

27 ISO-NE, Transmittal Letter, Docket No.ER14-584-000, at 5 (filed Dec. 9, 2013). 

28 The five interfaces are: New England West-East, New Hampshire-Maine; Rhode Island; Connecticut; 

and Boston. See ISO-NE, NCPC LSCPR Cost Allocation at 7-8 (Oct. 8, 2013), available at http://www.isone.com/committees/comm_wkgrps/mrkts_comm/mrkts/mtrls/2013/oct892013/ a07_iso_presentation_10_09_13.ppt. 

29 ISO-NE, Transmittal Letter, Docket No. ER14-854-000, at 4; ISO-NE, Testimony of Christopher A. 

Parent, Docket No. ER14-584-000, at 4-5 (Dec. 9, 2013). 

30 Potomac Economics, 2013 Assessment of the ISO New England Electricity Markets at 35 (June 2014), 

available at http://www.iso-ne.com/staticassets/documents/markets/mktmonmit/rpts/ind_mkt_advsr 

/isone_2013_emm_report_final_6_25_2014.pdf. 

31 MISO, Electric Tariff, Module C, § 38.2.7. 

32 SPP Market Protocols, § 4.3.1.2(1)(b). 
 

 

14 

day-ahead and real-time schedules improves price convergence between the day-ahead 

and real-time markets, although arguably both the day-ahead and real-time energy prices 

do not reflect the marginal cost of managing all system constraints. 

A key market design question is when to include a reliability constraint in the day-ahead 

process and when to leave a reliability issue for the RUC. RTOs and ISOs often include 

reliability-related commitments in the day-ahead schedule to avoid RUC commitments 

and the potential associated market distortions. An ISO-NE study on a specific reliability 

concern illustrates some of the trade-offs. ISO-NE performed an analysis in December 

2013 to examine the effects of including Local Second Contingency Protection Resources 

minimum commitment constraints in the day-ahead and real-time markets prior to its 

implementation. This constraint was included in the day-ahead market for unit 

commitment purposes, but did not involve an explicit shadow price. Based on 

simulations for the period between July 20, 2013, and November 30, 2013, ISO-NE staff 

found that including the minimum commitment constraints in the market models reduced 

the median day-ahead price from $35.96/MWh to $33.91/MWh. Compared to day-ahead 

prices without them, including the minimum commitment constraints reduced the dayahead price in 91 percent of the hours in the study period.33 The study also found that 

including the constraints in the day-ahead market reduced real-time surplus capacity in 

97% of hours, with a median reduction of 297 MW.34 Finally, the study found that with 

fewer surplus MWs in real-time, real-time prices would have likely been higher and 

reflected more reserve shortages.35 

This study illustrates some of the trade-offs in deciding to move a reliability constraint 

from the RUC to the day-ahead market process. For instance, doing so can make the dayahead commitment more consistent with the need in real-time. However, not allowing 

reliability constraints to be reflected in the day-ahead energy prices can actually reduce 

prices relative to what they would be without these constraints. This raises questions 

such as when a reliability constraint should be included in the day-ahead model rather 

than in RUC. Additionally, when reliability constraints are included in the day-ahead 

model, whether they should be reflected in day-ahead energy prices. 

B. Residual Unit Commitment Schedule

After the day-ahead market process takes place, RTOs and ISOs perform a RUC to 

amend the day-ahead schedule by committing additional resources for three main 

 33 ISO-NE, Effects of Minimum Commitment Constraints to the Day-Ahead and Real-Time Markets at 4 

(Dec. 19, 2013), available at http://www.isone.com/committees/comm_wkgrps/mrkts_comm/mrkts/mtrls/2013/nov13142013/a03_iso_presentation_12_19_13.p

pt. 

34 Id. at 5. 

35 Id. at 6. 
 

 

15 

reasons: (1) resource gaps; (2) reliability issues; and (3) to manage uncertainty and the 

potential for real-time operational issues (e.g., ramping). Resource gaps occur when the 

demand cleared in the day-ahead market is below the RTO’s or ISO’s demand forecast 

for the operating day. Day-ahead cleared load may be below the demand forecast for a 

variety of reasons, ranging from weather and load forecast uncertainty to conscious 

decisions by load serving entities to leave a certain portion of their load unhedged and to 

purchase in the real-time market. Net virtual supply positions can also cause resource 

gaps because they offset physical demand cleared in the day-ahead market. 

The RUC also includes commitments to address reliability issues that are not resolved in 

the day-ahead schedule. The day-ahead schedule will have unresolved reliability issues if 

the model that underlies the day-ahead market does not include all relevant reliability 

constraints. Voltage constraints and other local reliability requirements are significant 

drivers of reliability-related RUC commitments. For example, a particular transmission 

area may contain an un-modeled local reactive power constraint that affects a sub-area 

within the greater transmission area. This can occur when a single high cost resource is 

the only resource that can resolve a reactive power issue that is not enforced in the dayahead market. The day-ahead market may not commit this high cost resource 

economically because the local reactive power constraint is not included in the network 

model. Instead, the day-ahead market clearing process will commit and dispatch the least 

expensive resources in the larger area. If the resource needed to meet this local reliability 

requirement does not clear in the day-ahead market, it must be committed to maintain 

reliability so the operator will ensure that it is committed either through an automated 

algorithm or manually. As noted in a previous FERC staff paper, certain resources are 

consistently committed outside of the market to address reliability issues, which results in 

concentrated uplift payments.36 

The RUC typically maintains the commitment and dispatch decisions in the day-ahead 

schedule and either increases the dispatch levels of units already included in the dayahead schedule or makes additional commitments to address resource gaps and reliability 

issues. While exact practices differ by RTO and ISO, the RUC is based on a unit 

commitment process that minimizes the additional residual commitment costs (i.e., startup and no-load costs, without consideration of any variable costs) associated with any 

incremental commitments beyond the day-ahead schedule.37 

To shed further light on how commitments made in the RUC are reflected in prices, it’s 

informative to note that, while CAISO, ISO-NE, MISO, PJM, and SPP complete the 

 36 See Federal Energy Regulatory Commission, Staff Analysis of Uplift in RTO and ISO Markets (Aug. 

2014), available at http://www.ferc.gov/legal/staff-reports/2014/08-13-14-uplift.pdf (containing discussion and 

analysis concerning uplift). 

37 If day-ahead cleared load is higher than the load forecast, the RUC may remove – or decommit – 

resources from the day-ahead schedule. 
 

 

16 

RUC after the day-ahead market clearing process ends, NYISO’s RUC is integrated 

within its multi-step day-ahead market process. This design results in day-ahead prices 

that reflect RUC commitments. The first step of NYISO’s day-ahead market process 

selects resources to satisfy cleared load and reserve requirements, which is similar to the 

other RTOs and ISOs. However, NYISO’s day-ahead market process continues to an 

additional step that commits additional resources (if necessary) to satisfy the load forecast 

and reliability issues, a traditional function of the RUC. Additional passes in NYISO’s 

day-ahead market software incorporate the resources committed in the second pass of the 

day-ahead market (a RUC) to determine the final day-ahead schedule and clearing 

prices.38 As a result, NYISO’s day-ahead schedule and prices reflect commitments made 

in RUC. 

Operators may commit additional resources in RUC to address uncertainty and the 

potential for real-time operational issues (e.g., ramping). For example, operators may 

assess that the uncertainty surrounding either supply-side or demand-side factors warrant 

the commitment of additional resources over and above the resources necessary to satisfy 

the load forecast. For example, operators may determine that a resource included in the 

day-ahead schedule has a high probability of experiencing a forced outage and 

consequently increase the capacity requirement used in the RUC or manually add 

additional commitments to the RUC results. Such adjustments are made at the discretion 

of the operators. 

Some RTOs and ISOs have added a class of RUC commitments to manage this 

uncertainty and potential for real-time operational issues. For instance, MISO’s RUC, 

referred to as a Forward Reliability Assessment Commitment, includes a requirement that 

the system have sufficient Headroom and Floorroom.39 Headdroom constraints may also 

be included in the MISO’s day-ahead market.40 Headroom is an upward ramping 

capacity requirement to accommodate load increases that can be satisfied by either 

unloaded generation or fast-start units. Floorroom, defined similarly, is downward 

ramping capability. MISO defines headroom as the greater of the (1) unloaded capacity 

requirement (which is currently 750 MW); and (2) sixty percent of the hourly change in 

load.41 Similarly, during SPP’s day-ahead market and RUC, operators also ensure that 

 38 NYISO Manual 11, Day-Ahead Scheduling Manual, § 4.3.1; NYISO, NYISO Day-Ahead Market 

Overview at 12-14 (Jun. 28-29, 2010), available at http://www.ferc.gov/CalendarFiles/20110628072825-Jun28-

SesA1-Johnson-NYISO.pdf. 

39 MISO Tariff Module A, § II.1H; MISO Tariff Module A, § II.1F. 

40 MISO, Ramp Capability Product Design for MISO Markets at 12 (Dec. 22, 2013), available at 

https://www.misoenergy.org/Library/Repository/Communication%20Material/Key%20Presentations%20and%20W

hitepapers/Ramp%20Capability%20for%20Load%20Following%20in%20MISO%20Markets%20White%20Paper.p

df. 

41 MISO, FERC Electric Tariff, Module C, § 40.3.3 (10.0.0). See also page 3 of MISO’s November 22, 

2013 written answers in the Technical Conference in Docket No. ER13-2124-000. 
 

 

17 

the system has sufficient upward ramping capacity (referred to as head-room 

requirements) and downward ramp capacity (referred to as floor-room requirements).42 

The Commission recently approved MISO’s proposed ramp capability product, which 

will procure some of the capability MISO currently includes in its Headroom and 

Floorroom requirements in the day-ahead and real-time markets.43 MISO plans to 

procure Up Ramp and Down Ramp capability through the market by adding a constraint 

to both the day-ahead and real-time market models that specifies the desired ramp 

capability necessary to address short-term variations in net load.44

Some RTOs and ISOs have taken steps to replace certain RUC commitments with reserve 

products to better reflect the costs of such commitments in the day-ahead and real-time 

clearing prices for ancillary services. For example, in an effort to improve day-ahead and 

real-time price formation, in 2013 ISO-NE included in its day-ahead market a cooptimized replacement reserve product to procure in the market-clearing process 

resources that had previously been procured as operator-initiated RUC commitments. 

ISO-NE’s replacement reserve requirement is 160 MW in the summer and 180 MW in 

the winter.45 As such, the replacement reserve requirements are reflected in ISO-NE’s 

forward reserves market, day-ahead energy market and real-time energy market. 

PJM’s Market Service Committee recently approved a similar approach that instructs 

operators to increase the hourly day-ahead scheduling reserve obligation in the day-ahead 

market during hot and cold weather alerts and maximum generation alerts.46 PJM 

explained that the motivation for this proposal was to better reflect the costs of the 

reserves in clearing prices.47 Another key market design question is when a commitment 

that has traditionally been part of the RUC can be converted into a reserve product. 

The objective of the RUC in all of the RTOs and ISOs is to minimize the incremental 

residual commitment costs of any additional capacity that is committed, based on 

resource energy offers submitted into the day-ahead or during the RUC-rebid period. 

CAISO’s RUC is unique because CAISO allows resources to submit a capacity bid, 

 42 SPP OATT, attach. AE, § 5.1.1(11); SPP OATT, attach. AE, § 5.2.1(17). 

43 Midcontinent Indep. Sys. Operator, Inc., 149 FERC ¶ 61,095, at P 5 (2014). 

44 Id. P 6. Net load is physical load minus generation from variable resources. 

45 ISO New England, Inc., Transmittal Letter, Docket No. ER13-1736-000, at 10 (filed June 10, 2013). 

46 PJM, Energy and Reserve Pricing & Interchange Volatility Final Proposal Report at 2 (Oct. 30, 2014), 

available at http://www.pjm.com/~/media/committees-groups/committees/mrc/20141030/20141030-item-04-erpivfinal-proposal-report.ashx.

47 Id. Rather than a fixed amount, the additional reserves would be based on demand as adjusted by a 

“seasonal conditional demand factor” – based on actual demand during the peak hours for the top 10 peak load days 

in the same season the prior year. 
 

 

18 

referred to as a RUC Availability bid, for any capacity not committed as part of the dayahead market.48 When a resource submits a RUC Availability bid, it is offering to submit 

a supply offer for a specific MW quantity of supply to the real-time market during a 

specific hour (or hours). If a resource’s RUC Availability bid is accepted, it must offer a 

MW quantity equal to its RUC award in to the real-time energy market during the hour of 

its award. The RUC Availability bids do not specify the $/MWh level that the resource 

will offer into the real-time market - they only specify that a real-time offer will be 

made.49 CAISO uses the RUC Availability bids to select resources to minimize 

incremental commitment costs.50 In doing so, CAISO calculates a RUC price that is 

separate from the day-ahead energy and ancillary service clearing prices. 51 The RUC 

awards are similar to a capacity payment as they serve to guarantee that the resource will 

offer capacity equal to its RUC award in to the real-time market. CAISO’s internal 

market monitor found that most of its RUC awards do not create additional generation in 

real-time.52 The costs associated with CAISO’s RUC are treated similar to uplift and 

collected through a side payment that is allocated across two tiers.53 

C. Real-time Schedule 

The day-ahead schedule, as amended by the RUC, forms the basis of real-time 

operations. The real-time schedule gives resources instructions to deviate from their dayahead schedule as required by real-time conditions. Throughout real-time, the RTO and 

ISO system operators maintain the balance between supply and demand for energy and 

reserves by issuing dispatch instructions that either commit resources, decommit 

resources, or instruct resources that are currently operating to ramp up or down.54 Real-

 48 CAISO eTariff, § 31.5.1.1. 

49 CAISO Department of Market Monitoring, 2013 Annual Report on Market Issues & Performance at 102 

(Apr. 2014), available at http://www.caiso.com/Documents/2013AnnualReport-MarketIssue-Performance.pdf. 

50 See CAISO eTariff, § 31.5. 

51 See id., § 31.5.1.4. 

52 CAISO Department of Market Monitoring, 2013 Annual Report on Market Issues & Performance at 101 

(Apr. 2014), available at http://www.caiso.com/Documents/2013AnnualReport-MarketIssue-Performance.pdf. 

53 Resource Adequacy resources in CAISO must submit zero cost RUC Availability bids (i.e., $0/MW). 

RUC costs are driven by RUC Availability Payments and any uplift associated with the RUC awards. Day-Ahead 

RUC Tier 1 costs are allocated to virtual suppliers if in aggregate, the day-ahead cleared net virtual supply amount is 

positive. Any remaining RUC costs are allocated pro rata to metered load through a Day-Ahead RUC Tier 2 

allocation. California ISO, Settlement & Billing Internal Configuration Guide: CG CC06806 Day-Ahead Residual 

Unit Commitment (RUC) Tier 1 Allocation 3 (Sept. 2014 ), available at

http://bpmcm.caiso.com/BPM%20Document%20Library/Settlements%20and%20Billing/Configuration%20Guides/

Cost%20Recovery/BPM%20-

%20CG%20CC%206806%20Day%20Ahead%20Residual%20Unit%20Commitment%20(RUC)%20Tier%201%20

Allocation_5.7.doc. 

54 To decommit a resource means to instruct it to shut down. 
 

 

19 

time dispatch instructions are developed throughout the operating day – typically every 

five minutes – to optimally commit and/or dispatch resources at least-cost to manage 

real-time conditions and maintain reliability. Operators may perform additional RUCs in 

real-time that are similar to the day-ahead RUC for the hours remaining in the operating 

day with updated inputs that reflect prevailing system conditions. Operators in all of the 

RTOs and ISOs also have additional vehicles to make out-of-market commitments. For 

example, exceptional dispatches55 in CAISO, Out-of-Merit generation56 in NYISO, and 

Balancing Operating Reserves57 in PJM. 

In addition to these standard real-time dispatch operations, some markets also run parallel 

“look-ahead” processes that guide dispatch for the periods beyond the next interval. The 

motivation for a multi-period look-ahead is to overcome the shortcomings of the singleperiod optimization that typically forms the basis of real-time dispatch. Multi-period 

look-ahead processes attempt to make optimal choices over a longer time-span, and can 

often result in commitment and dispatch solutions that are less costly than single-period 

optimizations. A single-period optimization only makes decisions based on the 

immediate future (typically the next five to fifteen minutes). This short-term singleperiod optimization fails to consider changes in system conditions beyond the upcoming 

period. 

For example, suppose that updated load forecasts in real-time are for three hours in the 

future significantly higher than the load assumed in the day-ahead schedule and RUC. 

Two available options that satisfy this future load growth are: (1) commit an expensive 

fast-start resource immediately prior to the load increase; and (2) commit a less expensive 

medium-start58 resource in the next one or two hours. It may be cheaper to commit the 

medium-start resource to serve load that is expected to materialize in the next three hours, 

but a short-term/single-period optimization will not do so because the load increase does 

not happen within the short-term optimization period. In contrast, a multi-period lookahead optimization may realize the benefit of committing the medium-start resource 

instead of the fast-start resource. The look-ahead processes typically involve a rolling 

SCED, SCUC, or both that continuously evaluate system conditions in anticipation of 

future events and future operating periods. The look-ahead processes serve as guides for 

subsequent real-time dispatch instructions. 

Table 4 summarizes the dispatch and look-ahead processes that operators use in real-time 

to assist them in making optimal unit-commitment and dispatch decisions. Note that in 

all RTOs and ISOs, real-time SCEDs, often referred to as real-time dispatch processes, 

 55 CAISO eTariff, § 34.11. 

56 NYISO, Manual 12 Transmission and Dispatching Operations, § 5.7.4. 

57 PJM, Intra-PJM Tariff, OATT, attach. K, § 3.2.3. 

58 Medium-start resources can be started up fairly quickly but not as quickly as fast-start resources. 
 

 

20 

issue dispatch instructions. The period of time included in the forward look-ahead is 

referred to as the “look-ahead horizon” or “forecast period.” Rather than automatically 

following the recommendations of the look-ahead tools, operators also have discretion 

about which resources to ultimately commit and dispatch in real-time. 

The look-ahead process typically creates both actual and advisory dispatch and prices. 

Typically, the first period of the multi-period look-ahead optimization is used to set 

prices and create dispatch instructions, while the remaining periods of the optimization 

are advisory. The last column of Table 4 indicates whether the real-time process 

produces actual dispatch instructions and calculates real-time prices or is used for 

advisory purposes only. 

 
 

 

21 

Table 4 Real-Time and Look-Ahead Commitment and Dispatch Details59

Procedure 

Frequency and Lookahead horizon Advisory or actual 

commitment/dispatch? 

CAISO 

Short-term unit commitment -every hour, with a 4 hour 

look-ahead Actual & Advisory 

Real-time Unit Commitment -every 15 minutes, with a 

60-105 minute look-ahead Actual & Advisory 

Real-time Economic 

Dispatch 

-every 5 minutes, with lookahead of approximately 60 

minutes 

Actual 

ISO-NE Additional RAAs 

-as necessary, with a lookahead for the balance of the 

operating day 

Advisory 

Unit Dispatch Software -every 5 minutes Actual 

MISO 

Intraday RAC 

-as necessary, with a lookahead for the balance of the 

operating day 

Advisory 

Look-ahead Commitment -every 15 minutes, with a 3 

hour look-ahead Advisory 

Real-time SCED -every 5 minutes Actual 

NYISO 

Real-time Commitment 

-every 15 minutes, with a 2 

hour and 30 minute lookahead Actual & Advisory 

Real-time Dispatch -every 5 minutes, with a 60 

minute look-ahead Actual & Advisory 

PJM Intermediate-Term SCED -every 5 minutes, with a 2 hour look ahead Advisory 

Real-time SCED -every 5 minutes Actual 

SPP 

Intra-day RUC 

-as necessary, with a lookahead for the balance of the 

operating day 

Advisory 

Look-ahead SCED 

-every 5 minutes, with a 

look-ahead several periods 

beyond the current interval 

Advisory 

Real-Time Dispatch -every 5 minutes Actual 

 59 Notes on Table 4: See CAISO eTariff § 27.4.1; Id., § 34.3.1-2; Id., § 34.3.1; Id., § 34.5; ; Id., § 34.5.1. 

See ISO-NE, Manual 11, Market Operations, §2.5.1, Id., § 2.5.9.2(1); Potomac Economics, 2013 Assessment of the 

ISO New England Electricity Markets at 88-89 (Jun. 2014), available at http://www.iso-ne.com/staticassets/documents/markets/mktmonmit/rpts/ind_mkt_advsr/isone_2013_emm_report_final_6_25_2014.pdf; See

MISO, Price Formation at MISO Markets at 5 (Apr. 22, 2014), available at 

http://www.caiso.com/Documents/6_MidwestISO_MarketOverview.pdf; MISO FERC Electric Tariff Module C, § 

40.1.A.3(a); Id., § 40.2. See NYISO Market Administration Tariff, § 4.4.1.1.; Id., § 4.4.2.1. See PJM, IT SCED 

Overview at 1-2, available at http://www.pjm.com/~/media/markets-ops/energy/real-time/it-sced-forecasted-lmps/itsced-overview.ashx; PJM, Commitment Decision Making at 15-16 (Aug. 20, 2013), available at

http://www.pjm.com/~/media/committees-groups/task-forces/emustf/20130820/20130820-bor-commitmenteducation.ashx. See SPP OATT, attch. AE, § 1.1.I; Id., § 6.1; Id., § 6.2.2. 
 

 

22 

IV. Locational Marginal Pricing 

LMP is central to price formation in RTOs and ISOs.60 Two key issues associated with 

LMP, operator-initiated actions and the SCUC and SCED processes, are highlighted. 

The first issue is what types of costs are included in the LMP. The second issue is which 

resources are eligible to set the price. Energy prices may be distorted to the extent a 

resource is committed and dispatched to provide energy but is not eligible to set the price. 

The primary challenge is determining whether energy prices should reflect just resource 

incremental energy offers or whether energy prices should also include some or all of a 

resource’s start-up and no-load costs. The issue is connected to the operator-initiated 

actions issues discussed earlier because the decision to include system constraints in the 

RUC, and not the day-ahead or real-time market’s SCUC process, will influence whether 

commitment costs can be reflected in energy prices. 

Section IV.A provides an overview of LMP, section IV.B discusses the issue of what 

costs to include in setting energy and ancillary services prices, section IV.C explains how 

LMP can be amended for fast-start resources, and section IV.D summarizes fast-start 

pricing logic in FERC-jurisdictional RTOs and ISOs. 

A. Locational Marginal Pricing Overview 

The following example provides a highly simplified illustration of how LMP works. 

Consider a system with three units: baseload (Unit A); intermediate (Unit B); and faststart peaking unit (Unit C). Assume for the sake of simplicity that the system has 590 

MW of capacity, resources have no ramp constraints, start-up, or no-load costs, and that 

losses are zero. Table 5 contains the resource supply offers. Based on its first offer 

block, Unit A is willing to supply up to 200 MW at a price of $30/MW. If Unit A 

generates in the 201-230 MW range, it requires a payment of $40/MWh as defined by its 

second offer block. Finally, Unit A requires a payment of $50/MWh if it generates in the 

231-260 MW range. Offer blocks are defined similarly for Units B and C, but both units 

have non-zero EcoMins. For example, Unit B has a 100 MW EcoMin, which means that 

it will only operate at or above 100 MW. Finally, Unit C has a single offer block of 50 

MW because it can only operate (or is only willing to operate) at the 50 MW level. 

 60 All RTOs and ISOs use LMP pricing while NYISO uses Location Based Marginal Pricing (LBMP), 

which, for the purpose of this paper, is very similar to the LMP mechanism. The summary of the basic concepts 

LMP mechanism described here also apply to NYISO’s LBMPs. 
 

 

23 

Table 5 Example of LMP Mechanics 

Unit Block 1 Block 2 Block 3 Total 

 MW range $/MWh MW range $/MWh MW range $/MWh MW 

A 0-200 $30 201-230 $40 231-260 $50 260 

B 100 $70 101-140 $90 141-180 $150 180 

C 50 $200 50 

Figure 2 presents a graphical example of the simple supply stack implied by the offers in 

Table 5 and the LMP prices associated with each level of load. As shown in Figure 2, the 

LMP can at times diverge from the simple supply stack. For example, when load equals 

250 MW, the operator will commit Unit A alone and dispatch it at 250 MW. The LMP 

will be $50/MWh, as determined by Unit A’s third offer block. Therefore, when the 

system load is 250 MW, the price implied by the simple supply stack and the LMP are 

equal to each other. 

However, there can be unexpected outcomes when certain resource types are marginal. 

Specifically, in the graph the LMP tends to match the price implied by the simple supply 

stack only when the most expensive unit in operation is dispatchable. A resource is 

dispatchable when it can increase or decrease its output in accordance with its economic 

supply offer in response to operator instructions. Block-loaded resources, such as Unit C, 

are not dispatchable – instead they are either operating at EcoMin (which equals 

EcoMax) or shut down. The price implied by the simple supply stack and the LMP can 

deviate when load levels require a resource to operate in a non-dispatchable range. 

Continuing with the example, if load increases from 250 MW to 280 MW, Unit B will 

have to be committed. However, Unit B has a 100 MW EcoMin. If Unit A continues to 

generate 250 MW and Unit B generates its 100 MW EcoMin, system generation will 

equal 350 MW, which is in excess of the 280 MW load. Accordingly, in order to 

accommodate Unit B’s 100 MW EcoMin, the operator will have to dispatch Unit A down 

from 250 MW to 180 MW, which is the load minus 100 MW from Unit B (i.e., 280 MW 

– 100 MW).
 

 

24 

Figure 2 

Example of LMP Pricing Mechanism 

Therefore, when load is 280 MW, Unit A generates 180 MW and Unit B generates 100 

MW. The first block of Unit B’s offer is 100 MW for $70/MWh, but when the load is 

280, Unit A is the marginal unit on the system so Unit A’s third offer block of $30/MWh 

will establish the LMP. Unit A is the marginal resource when load is 280 MW because if 

load increases by 1 MW to 281 MW, the least costly resource available to serve that 

increment of load is Unit A at a price of $30/MWh. When load increased from 250 MW 

to 280 MW, the LMP fell from $50/MWh to $30/MWh. Unit B will require an uplift 

payment in this example because the revenue it earns from the LMP-based prices will not 

recover the incremental costs stated in its offer. Unit B’s incremental costs at its 100 

MW EcoMin are $7,000, which are $4,000 more than the $3,000 it will receive in energy 

revenues. 

In fact, until load exceeds 360 MW, Unit A will be the marginal unit because Unit C is 

not dispatchable between zero and 100 MW and thus cannot be the marginal unit. The 

price established might seem to be counterintuitive because, as shown in this example, 

the LMP can fall when load increases despite the fact that the simple supply stack is 

upward sloping. 

A natural question to ask is why the RTOs and ISOs do not simply set the energy price at 

Unit B’s first offer block of $70/MWh. However, doing so would introduce a 

complication because at a price of $70/MWh, Unit A has an incentive to deviate from its 

180 MW dispatch instruction and generate more electricity because it can generate 260 

MW at a cost well below $70/MWh. Accordingly, RTOs and ISOs must consider 

generator incentives when establishing the LMP. In this example, an LMP of $30/MWh 

is incentive compatible when load is 280 MW because neither Unit A nor Unit B (with its 

uplift payment) has an incentive to deviate from their respective dispatch instructions. 

$0

$30

$60

$90

$120

$150

$180

$210

100120140160180200220240260280300320340360380400420440460480

Simple Supply Stack and LMP ($/MWh)

Quantity Demanded (MW)

Simple Supply Stack LMP
 

 

25 

Thus, while LMP-based prices coupled with uplift can yield seemingly counterintuitive 

results at times, they are intended to reflect the cost of the marginal unit and yield 

incentive compatible prices.61 These examples are highly simplified. Resource 

parameters such as ramp rates, minimum run times, start-up, and no-load costs, not to 

mention reliability requirements, only make the problem more complex and can introduce 

further divergences between the LMP and the price implied by the simple supply stack. 

B. Cost Elements included in the LMP Framework 

The example in section IV.A showed that the classical LMP framework only permits 

incremental energy costs to be included in the LMP. The LMP framework can require 

uplift when there is a divergence between the supply offers and the LMP – even when 

start-up and no-load costs are zero. Uplift is also required when a resource’s energy 

revenue (established under the LMP framework) does not recover its incremental start-up 

and no-load costs. In practice, payments to resources to recover start-up and no-load 

costs are a key component of uplift. Alternatives to the LMP pricing framework, such as 

Convex Hull pricing, attempt to include total production costs – rather than incremental 

energy costs alone – in clearing prices.62 If resources have start-up and no-load costs, 

Convex Hull prices are higher, on average, than LMP prices, but uplift payments are 

lower as a result. 

The motivation of amending LMPs to include start-up and no-load costs is to better 

reflect the costs of serving the next increment of load in clearing prices. Expanding the 

costs included in LMP can be viewed as an expansion of the definition of marginal costs. 

Marginal costs are typically considered to be exclusively short-run variable costs that are 

incurred immediately by resources as they increase output (e.g., fuel, emissions costs, 

etc.). If the timeframe over which marginal costs are defined is expanded to include the 

time it takes to start-up a resource, then the start-up and no-load costs associated with 

committing fast-start resources could be regarded as marginal costs and included in 

clearing prices. As explained in section IV.D below, several RTOs and ISOs have 

already adopted this practice. 

The LMP example in section IV.A can be expanded to include start-up costs and better 

illustrate Convex Hull prices. Suppose that Units A, B, and C have positive start-up costs 

and zero no-load costs. Unit A has a $5,000 start-up cost, Unit B has a $2,000 start-up 

cost, and Unit C has a $1,000 start-up cost. Table 6 demonstrates the effect of including 

the start-up costs in the first block of each Unit’s supply offer. Unit start-up costs can be 

 61 Prices are said to be “incentive compatible” if resources do not have an incentive to deviate from the 

dispatch instructions associated with those prices. 

62 Paul Gribik, William Hogan, and Susan Pope, Market-Clearing Electricity Prices and Energy Uplift at 

17 (Dec. 31, 2007) (working paper), available at

http://www.hks.harvard.edu/fs/whogan/Gribik_Hogan_Pope_Price_Uplift_123107.pdf. 
 

 

26 

amortized over the MW in each unit’s first offer block.63 As shown in Table 6, the 

$/MWh offers in the first block necessarily increase when those blocks reflect both 

incremental energy costs and start-up costs. 

Table 6 Example of including Start-up Costs in Energy Offers

Start-up 

Cost 

Original 

Block 1 Offer 

(no start-up costs) 

Revised 

Block 1 Offer 

(with start-up costs) 

Unit ($/start) ($/MWh) ($/MWh) 

A $5,000 $30 $55 

B $2,000 $70 $90 

C $1,000 $200 $220 

Note: The Original Block 1 offers do not include start-up costs. The Revised Block 1 offers 

include start-up costs amortized over the maximum MW contained in Block 1.

The revised clearing prices that include start-up costs will reduce uplift payments. 

However, they may not entirely eliminate uplift. For example, if Unit A is only 

dispatched at 100 MW and no other units are dispatched, Unit A will not recover all of its 

start-up costs because it is operating at a level below the top level in its first offer block. 

The discussion in the next section will note how LMPs calculated to include start-up 

costs would differ from traditionally calculated LMPs for several scenarios. 

C. EcoMin Relaxation 

System conditions will naturally diverge from the day-ahead schedule given differences 

between actual and forecasted load, as well as forced generator outages and forced line 

outages. In real-time, operators can only rely on sufficiently flexible online capacity and 

fast-start resources to manage these differences. Fast-start resources are units that can 

quickly start-up and ramp to a dispatch instruction - typically within ten minutes.64 In 

most RTOs and ISOs, fast-start resources are gas-fired combustion turbines; however the 

majority of fast-start resources in ISO-NE are pumped storage units.65 

Fast-start units are typically ineligible to establish the day-ahead or real-time clearing 

price because they are block-loaded (i.e., a unit’s EcoMax equals EcoMin) and thus are 

 63 This is one of several ways to amortize the start-up costs. Start-up costs can also be amortized over all 

MWh that the resource produces. 

64 The definition of fast-start resources varies by RTO and ISO. 

65 Potomac Economics, 2013 Assessment of the ISO New England Electricity Markets at 91 (July 2014), 

available at http://www.iso-ne.com/committees/comm_wkgrps/prtcpnts_comm/prtcpnts/mtrls/2014/ 

jun2425262014/ npc_2014062426_isone_2013_emm_report_final.pdf. 
 

 

27 

not dispatchable to serve the next MW of load.66 While certain exceptions exist, only 

resources that are following dispatch instructions and not constrained by their EcoMax, 

EcoMin, or ramp-rate are eligible to set the energy component of the energy price in a 

standard SCED. This presents a problem when fast-start resources are the resource called 

upon to meet system needs in real-time because the majority of fast-start resources are 

either block-loaded or have a relatively small range over which they can be dispatched, 

and so are rarely, if ever, deemed marginal under a classic LMP mechanism. Fast-start 

resources may be indifferent about whether or not they set the LMP because any 

production costs not recovered through energy market revenues are recovered through 

uplift payments. Inframarginal resources, which are resources that have costs below the 

clearing price, are directly affected because their energy revenues are determined by the 

incremental costs of the marginal unit that sets the clearing price. Thus, market rules that 

make certain high-cost resources ineligible to set clearing prices, despite the fact that 

these high-cost resources operate, can decrease the energy market revenues of 

inframarginal units. 

The example in section IV.A can be expanded to show the effect of committing fast-start 

resources that are ineligible to set the LMP. Suppose that load is 460 MW, which means 

that all three units must be committed. The dispatch instructions when load is 460 MW 

are: Unit A: 260 MW; Unit B: 150 MW; Unit C: 50 MW. The LMP is $150/MWh based 

on Unit B’s third offer block. Unit C is operating at its EcoMin, so without some 

modification to the LMP mechanism, it is ineligible to set the price. 

LMPs in RTOs and ISOs are typically developed through SCED processes, which are 

often referred to as pricing runs. If Unit C were to set the clearing price in this example, 

the pricing run must be modified to make the underlying software regard Unit C as a 

dispatchable resource, because only dispatchable resources can be marginal. This can be 

accomplished by “relaxing” Unit C’s EcoMin to a level below 50 MW, thus making it 

eligible to set the clearing price for energy at $200/MWh. The EcoMin relaxation takes 

place in the pricing run. For example, the pricing run could change Unit C’s EcoMin to 0 

MW and Unit C could be “dispatched” at 40 MW within the pricing run. However, the 

dispatch instructions sent to Unit C would honor its 50 MW EcoMin. 

Thus, if Unit C’s EcoMin is relaxed and load is 460 MW, the LMP equals $200/MWh – 

which is based on Unit C’s incremental energy costs. Without EcoMin relaxation, the 

LMP would equal $150/MWh based on Unit B’s third offer block. Further, if Unit C’s 

EcoMin is relaxed and start-up costs are included in each unit’s first offer block, the LMP 

would be $220/MWh (see Table 6). Setting the price based on Unit C’s offer still creates 

incentive capability issues for Unit B unless Unit B receives a make-whole payment to 

keep it indifferent to following its 150 MW dispatch instruction. 

 66 A resource’s EcoMin is the minimum level that it can operate on the basis of economics. A resource’s 

EcoMax is the maximum level that it can operate on the basis of economics. 
 

 

28 

Expanding the types of costs included in LMP beyond incremental energy costs can 

exacerbate the incentive compatibility discussed previously because it creates an even 

greater discrepancy between the pricing run and the actual dispatch instructions sent to 

resources. These discrepancies are tolerated within limits because they result in real-time 

prices that better reflect the costs of serving load, but significant discrepancies can have 

implications for RTOs and ISOs, such as over-generation.67 

D. Fast-start Pricing Logic in RTOs and ISOs 

Most RTOs and ISOs implement some form of EcoMin relaxation for fast-start resources 

to make them eligible to set the real-time clearing price.68 Given that operators cannot 

physically violate the operational parameters of resources, the relaxation takes place in 

the pricing run, which differs from the dispatch instructions that are actually sent to 

operators. RTOs and ISOs relax the EcoMin of eligible fast-start units under certain 

conditions by setting their EcoMin equal to zero or some other value that makes the 

pricing run regard the fast-start resource as dispatchable. Table 7 summarizes how the 

RTOs and ISOs treat fast-start resources in real-time. CAISO, ISO-NE, and NYISO 

relax the EcoMins of eligible fast-start resources to zero in their pricing runs while PJM 

relaxes EcoMins by approximately 10 percent. However, CAISO only relaxes the 

EcoMin of Constrained Output Generators and resources must apply to CAISO if they 

want to be treated as such.69 CAISO currently has very few resources that are treated as 

Constrained Output Generators.70 Once implemented, MISO’s Extended LMP proposal 

will also relax the EcoMin of eligible fast-start resources to zero to make them eligible to 

set clearing prices.71

 67 ISO-NE notes that divergence between prices and dispatch levels can lead to incentive compatibility 

issues and over-generation. See ISO-NE, Real-Time Price Formation Technical Session #6 at 29 (Sept. 22, 2014), 

available at http://www.iso-ne.com/static-assets/documents/2014/09/ price_information_technical_session6.pdf. 

68 Fast-start units can feasibly set the day-ahead LMP through EcoMin relaxation but fast-start commitment 

decisions are not typically made until real-time. 

69 CAISO eTariff, § 27.7.1. 

70 Scott Harvey, Pricing and Price Signals: What is the problem we are trying to solve? at 9-11 (Apr. 22, 

2014), available at http://www.caiso.com/Documents/2_Pricing-PriceSignals.pdf. 

71 The Commission conditionally accepted MISO’s Extended LMP proposal in July 2012. See

Midcontinent Indep. Sys. Operator, Inc., 140 FERC ¶ 61,067 (2012). The initial implementation was scheduled for 

the Fall of 2013 but MISO requested a delay in September 2014. See MISO Transmittal Letter in Docket No. ER14-

2863-000 (Sept. 12, 2014); MISO, Motion to Withdraw Filing, Docket No. ER14-2566-000 (Sept. 12, 2014). 
 

 

29 

Table 7 Treatment of Fast-Start Resources in Real Time 

 Mechanism for allowing 

fast-start resources set the 

clearing price? 

Can costs other than 

incremental energy set 

clearing price? 

Can off-line faststart units set the 

clearing price? 

CAISO Yes - Relax EcoMin to 

zero 

Yes. No-load No 

ISO-NE Yes - Relax EcoMin to 

zero 

Yes. Start-up and noload costs Yes 

MISO 

Yes – Relax EcoMin to 

zero with the 

implementation of 

Extended LMP 

Yes. Start-up and noload costs 

Yes, but MISO is 

currently 

considering 

changes to this 

feature of ELMP 

NYISO Relax EcoMin to zero Yes. Start-up costs Yes 

PJM Yes - Relax EcoMin up to 

10% No No 

SPP No No No 

Another consideration with EcoMin relaxation and price formation is which costs in the 

fast-start resource’s supply offer are eligible to set the LMP.72 Typically, clearing prices 

based on the LMP framework only include incremental energy costs and exclude start-up 

and no-load costs. NYISO has provisions that allow the start-up and incremental energy 

costs of eligible fast-start resources to be included in clearing prices when they are 

marginal.73 ISO-NE permits the start-up, no-load, and incremental energy costs of 

eligible fast-start resources to be included in the clearing price when they are marginal 

from the time the resource is committed and up to the point that it synchronizes with the 

system.74 CAISO permits the incremental energy and no-load costs of Constrained 

Output Generator resources to be included in the LMP75, while PJM’s LMP only includes 

incremental energy costs. MISO’s Extended LMP will also include the start-up, no-load, 

and incremental energy costs of eligible fast-start resources. If start-up and no-load costs 

 72 The LMP equals the sum of incremental energy costs, losses, and congestion. As such, an incremental 

energy offer alone does not set the LMP. For the sake of simplicity, this paper refers to marginal resources that 

establish the energy component of LMPs as resources that set the LMP. 

73 See NYISO Market Administration Tariff, §17.1.1-3; NYISO, Manual 12, Transmission and Dispatching 

Operations Manual, § 5.1.1. 

74 ISO-NE, Real-Time Price Formation Technical Session #6 at 23-25 (Sept. 22, 2014), available at

http://www.iso-ne.com/static-assets/documents/2014/09/price_information_technical_session6.pdf. The start-up 

and no-load costs of fast-start resources in ISO-NE are only included in LMP in the intervals when the resource is 

first committed and while it is ramping up to its dispatch instruction, known as “synchronizing”. Once the fast-start 

resource is online and operating at ISO-NE’s desired dispatch point, only its incremental energy costs are eligible to 

set LMP. 

75 CAISO eTariff, § 27.7.3. 
 

 

30 

are included in the clearing price, they are amortized over the fast-start unit’s minimum 

run-time, which is typically required to be one hour or less. 

Traditional real-time dispatch and pricing runs have another feature that some RTOs and 

ISOs have amended. Typically, the SCED that underlies the pricing run only dispatches 

resources that have already been committed and are thus currently online. NYISO and 

ISO-NE have modified their pricing run to expand the set of resources that can be 

dispatched in the pricing run. Both ISOs allow eligible fast-start units that are off-line to 

set the clearing price during the interval when the resource is starting up. As explained in 

section IV.B, the rationale for allowing off-line fast-start resources to set the clearing 

price is that it will result in prices that better reflect the cost of serving the next increment 

of load, which may involve committing a fast-start resource that is off-line. MISO’s 

original Extended LMP proposal permitted off-line fast-start resources to establish the 

LMP. MISO’s market monitor raised concerns about certain design elements of the 

Extended LMP proposal and MISO is currently developing alternative proposals to 

address those concerns.76

V. Empirical Analysis 

The extent of the price formation issues associated with operator-initiated actions 

discussed above is dependent on the actual amount of capacity ISOs and RTOs are 

committing that are not reflected in energy and ancillary services prices. If ISOs and 

RTOs only commit a limited number of resources outside of the day-ahead or real-time 

market processes, then the issues discussed above would largely be theoretical. This 

section presents an empirical analysis based on data provided pursuant to Order No. 76077

and publicly available data to examine the extent to which out-of-market commitments 

are made in RTOs and ISOs. The data provided pursuant to Order No. 760 does not 

explicitly identify which commitments were initiated by operators, so this analysis takes 

a narrow focus and develops a conservative indicator of resource commitments that were 

potentially operator-initiated. This analysis found that the average MW of capacity 

operating at or close to EcoMin for the duration of its commitment period constituted a 

small portion of load. However, the analysis also found that the MW operating at 

EcoMin is highly variable, and can reach up to 5 percent of average load on some days. 

 76 MISO, Motion to Withdraw Filing, Docket No. ER14-2566-000, at 3, (Sept. 12, 2014). 

77 Enhancement of Electricity Market Surveillance and Analysis through Ongoing Electronic Delivery from 

Regional Transmission Organizations and Independent System Operators, Order No. 760, FERC Stats. & Regs. 

¶31,330 (2012). Paragraph 35 of Order No. 760 states the Commission may make publicly available staff white 

papers, among other things, that contain analyses derived from data that the Commission uses. 
 

 

31 

A. Methodology 

This analysis examines the extent to which resources that were not self-scheduled, and 

committed and operated at a level close to their EcoMin for the duration of their 

commitment period. In the absence of more definitive data, this metric is a reasonable 

estimate of the extent to which resources are committed out-of-market by operators, 

either through an automated process like the RUC or through a manual commitment. As 

explained below, this estimate could be regarded as a lower bound estimate. 

The analysis identified resources committed at or near EcoMin because market-based 

commitments are unlikely to commit resources to remain at EcoMin for their entire 

dispatch periods on a persistent basis. It is more likely that resources that are committed 

at their EcoMin levels and remain at that level for the duration of their commitment are 

committed outside of a market clearing process because, with the exception of fast-start 

resources, resources committed as part of the market process are dispatched at levels 

above their EcoMin. If a resource is inframarginal, then it is optimal to increase its 

dispatch as much as possible because its costs are below those of the marginal unit. 

Unless it is a fast-start resource with a relaxed EcoMin, the marginal unit is unlikely to be 

at EcoMin because, as explained in section IV.A, marginal units must be dispatchable – 

which implies that they are not operating at EcoMin. 

This metric may over- or understate operator-initiated commitments. It may over-state 

operator-initiated commitments to the extent that identified resources were committed at 

their EcoMin by a market optimization process and not through operator actions. For 

example, given EcoMin relaxation, it is possible that some resources committed at 

EcoMin can set the clearing price. However, this measure is more likely to understate 

out-of-market operator-initiated commitments than it is to overstate them. First, this 

measure does not capture instances of operator-initiated commitments that were over 5 

percent above EcoMin. Second, this estimate does not capture operator-committed 

resources that spend a portion of their commitment dispatched close to their EcoMin and 

another portion dispatched above EcoMin.78 Finally, the estimate does not capture 

instances when resources that were initially self-scheduled or committed on the basis of 

economics were asked to remain online by operators. Thus, despite these sources of 

imprecision, this metric is a useful and conservative indicator of the extent to which outof-market operator-initiated commitments are present in the markets examined. 

The analysis examined hourly commitment and dispatch data provided pursuant to Order 

No. 760 in 2013. Each non-self-scheduled commitment observed was classified as either 

an EcoMin commitment or a non-EcoMin commitment, based on whether the resource 

was dispatched close to its EcoMin for the entire duration of its daily commitment. The 

 78 This scenario may occur if a resource is initially committed by an operator-initiated process and 

subsequently dispatched up because, once committed, its energy costs are economic. 
 

 

32 

output (in MWh) from EcoMin commitments were aggregated for each operating day.79 

Next, average (mean), maximum, and standard deviation statistics were computed from 

the daily MW values. Two different thresholds measure whether a resource’s average 

dispatch was “close” to its EcoMin level: average dispatch within 2.5 percent of EcoMin; 

and average dispatch within 5 percent of EcoMin. These thresholds are used to account 

for measurement error and small variations in generator dispatch.80 

B. Results Overview 

Table 8 presents summary statistics for calendar year 2013 in CAISO, ISO-NE, MISO,81

and PJM.82 The average daily MW generated from resources dispatched within 2.5 

percent of EcoMin in 2013 ranges from 77 MW in ISO-NE to 812 MW in PJM. The 

MW estimates in Table 8 are relatively low compared to the average system loads in 

2013, likely due in part to the conservative nature of this analysis. 

Table 8 Summary statistics of MW dispatched EcoMin in 2013 

 MW dispatched within 

2.5% of EcoMin 

MW dispatched within 

5% of EcoMin 

Average hourly 

load in MW 

 Mean Max Mean Max 

CAISO 174 960 269 1,245 26,391 

ISO-NE 77 1,020 133 1,300 14,767 

MISO 200 1,210 378 1,636 58,269 

PJM 812 3,446 1,298 4,254 90,322 

Source: Order No. 760 Database 

One pattern that is readily apparent in Table 8 is the variable nature of MW committed 

and dispatched within either 2.5 or 5 percent of EcoMin. For example, the annual 

average MW dispatched within 5 percent of EcoMin in PJM in 2013 was 1,298 MW, 

compared to a maximum of 4,254 MW. The CAISO, ISO-NE, and MISO statistics 

demonstrate a similar pattern. Figure 3 plots the MW of capacity dispatched within 5 

percent of EcoMin for each day in the 2013 sample for PJM, ISO-NE, MISO, and 

 79 For EcoMin commitment periods that extend beyond single operating days (e.g., from 10 p.m. on Day 1 

to 4 a.m. on Day 2), the MWh output realized in any given hour in that commitment period is included in the MW 

total for both days. 

80 Dispatch levels in some RTOs and ISOs are based on state estimators that estimate various parameters – 

including generator outputs – of the system. Furthermore, resources are permitted to operate within a certain band 

around their dispatch instruction. 

81 The 2013 sample for MISO is restricted to dates prior to December 19, 2013, when the Entergy footprint 

joined MISO. 

82 SPP is excluded from the analysis because its Day-2 market has yet to operate for a full calendar year. 

NYISO is excluded from the analysis because the data submitted pursuant to Order No. 760 do not contain a full 

record of 2013 operations. 
 

 

33 

CAISO, sorted in descending order. These plots show that the nature of the EcoMin 

commitments is fairly similar in each RTO and ISO, with the relatively high MW values 

on a small percentage of days and comparably lower values – sometimes zero MW – on 

other days. 

Figure 3 

2013 Daily Average MW within 5% of EcoMin 

Sorted in Descending Order 

The RTOs and ISOs plotted in Figure 3 are markets of different sizes, load profiles, 

resource mixes, transmission topologies, and reliability rules. As such, it is difficult to 

compare the magnitude of operator actions. Figure 4 presents the plots in Figure 3 

normalized by average annual load.83 As shown in Figure 4, the MW of capacity 

operating within 5 percent of EcoMin constitutes at most 8.8 percent of average annual 

load in ISO-NE, but the MW exceed 5 percent of average annual load on just five days in 

the sample. The daily average capacity operating within 5 percent of EcoMin was at 

most 4.7 percent in both PJM and CAISO. The numbers are slightly lower in MISO, 

with the capacity operating within 5 percent of EcoMin reaching a maximum of 2.8 

percent of total load. 

 

 83 The measurements of MW within 5 percent of EcoMin were normalized by dividing each observation by 

the average annual load. 
 

 

34 

Figure 4 

2013 Daily Average MW within 5% of EcoMin 

as a Percent of Average Annual Load 

C. Market-specific Results

This section presents more detailed EcoMin MW results for each market from Staff’s 

analysis of Order No. 760 data. When possible, additional information about operatorinitiated commitments is presented for each market. 

CAISO 

Table 9 below presents more information about the average amount of MW from 

resources that were committed and held within 2.5 and 5 percent of EcoMin in 2013. The 

average daily MW of energy from resources committed within 5 percent of their EcoMin 

was 269 MW, but the figure was as high as 1,245 MW on a single day. CAISO has tariff 

provisions to allow certain fast-start resources committed at EcoMin, i.e., Constrained 

Output Generators, to set the LMP but Staff understands from discussions with CAISO 

that, currently, CAISO has very few Constrained Output Generators. 

 
 

 

35 

Table 9 CAISO Summary of MW 

Near EcoMin in 2013 

Tolerance range 

above EcoMin Mean Max Std. Dev. 

0-2.5% 174 960 195 

0-5.0% 269 1,245 237 

Source: Order No. 760 Database, Jan. 1-Dec. 31, 2013

According to CAISO’s Department of Market Monitoring, in 2013, the average hourly 

MW of energy committed by CAISO operators under exceptional dispatch orders was 

approximately 50 MW.84 In 2013, 79 percent of energy from exceptional dispatches 

came from “minimum load energy,” or the energy associated with resources operating at 

their EcoMin.85 Total MWh from CAISO’s exceptional dispatch orders constituted 0.26 

percent of total 2013 load.86 The Department of Market Monitoring explained that RUC 

procured an average of 930 MW per hour in 2013. However, only 13 MW, on average, 

came from resources that were committed through RUC, although the maximum hourly 

level of RUC commitments was 450 MW.87 

ISO-NE 

As shown in Table 10, in 2013, ISO-NE had an annual daily average of 133 MW 

generated from resources committed within 5 percent of their EcoMin and 77 MW from 

resources operating within 2.5 percent of EcoMin. ISO-NE has provisions that permit 

certain fast-start resources to set the LMP but the conservative nature of this estimate is 

more like to understate the operator-initiated commitments than it is to understate them. 

Additionally, ISO-NE’s external market monitor found that fast-start resources are 

frequently ineligible to set the LMP because once they are online, they are ineligible to 

set the LMP when they are operating within their minimum run time.88 

 

 84 CAISO, Department of Market Monitoring, 2013 Annual Report on Market Issues & Performance at 

213, Figure 9.1 (Apr. 2014), available at http://www.caiso.com/Documents/2013AnnualReport-MarketIssuePerformance.pdf. 

85 Id. at 212. 

86 Id. 

87 Id. at 102. 

88 Potomac Economics, 2013 Assessment of the ISO New England Electricity Markets at 87-88 (June 2014), 

available at http://www.iso-ne.com/staticassets/documents/markets/mktmonmit/rpts/ind_mkt_advsr/isone_2013_emm_report_final_6_25_2014.pdf 
 

 

36 

Table 10 ISO-NE Summary of MW 

near EcoMin in 2013 

Tolerance range 

above EcoMin Mean Max Std. Dev. 

0-2.5% of EcoMin 77 1,020 147 

0-5.0% of EcoMin 133 1,300 195 

Source: Order No. 760 Database, Jan. 1-Dec. 31, 2013

ISO-NE’s internal market monitor explained that commitments made during its RUC in 

2013 were zero on most days. ISO-NE’s internal market monitor reports that, during the 

peak hour of days with positive RUC commitments, the MW committed in RUC ranged 

from a low of 26 MW in May 2013 to a high of 2,879 MW in February 2013.89 The 

internal market monitor also found that the difference between the day-ahead and realtime LMPs in ISO-NE increased with the amount of capacity that operators committed in 

RUC.90

MISO 

In 2013, an average of 378 MW per day was generated by resources that were operating 

within 5 percent of their respective EcoMins, but this figure reached as high as 1,636 

MW in a single daily. As with other RTOs and ISOs, this wide range shows the 

variability of operator-initiated commitments. 

Table 11 MISO Summary of MW 

near EcoMin in 2013 

Tolerance range 

above EcoMin Mean Max Std. Dev. 

0-2.5% of Ecomin 200 1,210 217 

0-5.0% of EcoMin 378 1,636 330 

Source: Order No. 760 Database, Jan. 1-Dec. 18, 2013

MISO makes information about some operator-initiated commitments available on a realtime basis on its website.91 Below is a summary of commitments eligible for real-time 

make-whole payments (left axis), known as Revenue Sufficiency Guarantee (RSG) 

payments, plotted along with real-time load (right axis) in 2013. Such commitments are 

 89 ISO-NE Internal Market Monitor, 2013 Annual Markets Report at 64-65 (May 6, 2014), available at

http://www.iso-ne.com/static-assets/documents/markets /mkt_anlys_rpts/annl_mkt_rpts/2013/ 

2013_amr_final_050614.pdf. 

90 Id. at 83. 

91 MISO, Real-Time RSG Commitments, available at https://www.misoenergy.org/MarketsOperations/ 

RealTimeMarketData/Pages/Real-TimeRSGCommitments.aspx. 
 

 

37 

referred to as “Real-time RSG commitments.” The bars in Figure 5 represent the 

EcoMax of real-time RSG commitments broken out by commitment reason.92 The 

constraint-related RSG commitments are associated with operators dispatching resources 

to manage real-time constraints while the capacity-related RSG commitments as 

associated with commitments to make up for any gaps between the day-ahead schedule 

and the load forecast. 

Figure 5 

MISO Average EcoMax of Real-Time RSG Commitments 

and Real-Time load in 2013 

The annual average EcoMax of real-time RSG commitments is just under 1,000 MW per 

hour. Note that the real-time RSG commitment levels above are by definition higher than 

the electricity generated by these commitments because the MW value represents the 

average EcoMax of resources, not average dispatch. As evident in Figure 5, the MW 

level of capacity-related RSG commitments varies by hour and closely tracks load. The 

constraint-related RSG commitments are much lower and do not vary by load level, 

which suggests that some resources, albeit a small number, are consistently committed to 

resolve given constraints. The real-time RSG commitments show the same seasonality as 

load. Figure 6 shows the average EcoMax of real-time commitments in June 2013. 

 92 MISO reports the EcoMax of resources, which will overstate the actual MW of real-time RSG 

commitments to the extent that resources are committed at levels below their EcoMax. The 2013 RSG 

commitments summarized at the 5-minute interval can be downloaded at: 

https://www.misoenergy.org/Library/Repository/Market%20Reports/2013_Historical_RT_RSG_Commitment.csv. 
 

 

38 

Figure 6 

MISO Average EcoMax of Real-Time RSG Commitments 

and Real-Time load in June 2013 

It appears from Figure 6 that the capacity-related RSG commitments follow load, which 

was in the 70 GW range during peak hours in June 2013. The correlation coefficient 

between capacity-related commitments and real-time MISO loads in 2013 was 0.944. 

This result is not surprising given that capacity-related RSG commitments are made to 

make up differences between the load cleared in the day-ahead market and forecasted and 

real-time loads. 

PJM 

Table 12 summarizes the MW of electricity per day from resources that were committed 

and dispatched within 2.5 percent and 5 percent of their respective EcoMins in 2013. In 

2013, a daily average of 1,298 MW was committed within 5 percent of its EcoMin, with 

a daily high of 4,254 MW. In 2013, an average of 812 MW per day was committed 

within 2.5 percent of its EcoMin. 

Table 12 PJM Summary of MW 

near EcoMin in 2013 

Tolerance range 

above EcoMin Mean Max Std. Dev. 

0-2.5% of EcoMin 812 3,446 577 

0-5.0% of EcoMin 1,298 4,254 743 

Source: Order No. 760 Database, Jan. 1-Dec. 31, 2013

Some of the MW committed at or near EcoMin are associated with units that do not clear 

the day-ahead market on the basis of economics but that are nonetheless included in the 

day-ahead schedule by operators because they are needed for reliability reasons, such as 
 

 

39 

blackstart, reactive support, voltage support, and interface control.93 In 2013, just under 

1,000 MW of resources were included in the day-ahead schedule despite the fact that they 

did not economically clear the day-ahead market. Many of these resources were 

committed and dispatched at or near EcoMin. 

PJM provides daily summaries of Balancing Operating Reserve on its website.94 

Resources that are committed to provide Balancing Operating Reserve are eligible for 

credits. Balancing Operating Reserve credits are separated into four categories: RA 

Reliability, RA Deviation, RT Reliability, and RT Deviation.95 RA Reliability 

commitments are associated with resources that are committed in PJM’s reliability 

analysis to maintain system reliability. RA Deviations are associated with commitments 

made in RUC to address differences between load cleared in the day-ahead market and 

the load forecast (resource gaps). 

Resources that are instructed to operate in real-time by PJM operators rather than the 

real-time market are eligible for real-time Balancing Operating Reserve credits. If a 

resource’s incremental energy costs are above the LMP at its bus in three or fewer five 

minute real-time intervals then its Balancing Operating Reserve credits are categorized as 

RT Reliability. Real-time Balancing Operating Reserve credits to resources that are 

economic in four or more real-time intervals are categorized as RT Deviation credits. 

Figure 7 summarizes the average hourly MWh of resources that received Balancing 

Operating Reserve credits in 2013. The average hourly MWh associated with reliability 

commitments in the RUC was 18 MWh (RA Reliability) and 266 MWh was committed 

to address resource gaps (RA Deviations). 

 

 93 PJM Interconnection, Impact of Reliability Units Being Included in the Day-Ahead Market at 1 (Apr. 5, 

2013), available at http://www.pjm.com/~/media/committees-groups/committees/mic/20130405-da/20130405-item04-impact-of-reliability-unit-committment-in-day-ahead-whitepaper.ashx.

94 Balancing Operating Reserve Commitments are summarized in the monthly Market Implementation 

Committee’s MIC Market Operations Reports, available on the PJM website. 

95 PJM, Intra-PJM Tariff, OATT, attach. K, § 3.2.3. 
 

 

40 

Figure 7 

Average Hourly PJM Balancing Operating Reserves in 2013 

The majority of resources that received real-time Balancing Operating Reserve credits in 

2013 were economic in at least four real-time intervals (1,742 MWh out of an annual 

average of 2,073 MWh of real-time Balancing Operating Reserve-related MWh). In 

2013 an average of 331 MWh received RT reliability credits per hour, which means that 

these resources’ costs were above the real-time LMP in most real-time intervals. 

VI. Concluding Remarks 

This paper describes the alternative means RTOs and ISOs use to manage the physical 

and operational constraints that cannot be explicitly included in the day-ahead and realtime market processes. The discussion highlights the fact that all RTOs and ISOs have 

identified a class of reliability and operational issues that are incorporated into the dayahead market unit commitment process but which are not directly reflected in day-ahead 

energy and ancillary services prices. Doing so can make the day-ahead commitment 

more consistent with the need in real-time. However, not allowing such reliability and 

operational constraints to be reflected in day-ahead energy prices can actually reduce 

prices relative to what they would be without these constraints. This raises questions 

such as when a reliability constraint should be included in the day-ahead model rather 

than in RUC. Additionally, when included in the day-ahead model, whether the 

reliability constraint should be reflected in day-ahead energy prices. 

In addition, some RTOs and ISOs have designed reserve products to address reliability 

and operational issues that would otherwise result in unit commitments outside of the 

day-ahead or real-time market processes. Another key market design question is when a 
 

 

41 

commitment that has traditionally been part of the RUC can be converted into a reserve 

product. 

The importance of price formation concerns associated with operator-initiated actions are 

difficult to assess because one cannot observe what prices would have been absent the 

action without conducting a costly parallel market solution without the operator actions. 

This paper attempts to understand the degree to which resources are committed and not 

reflected in price by measuring the generation from capacity that was committed but not 

dispatched above 2.5 percent and 5 percent of their minimum operating levels. The 

analysis suggests that this quantity is moderate in most RTOs and ISOs but can reach 

fairly high levels on some days. 

Finally, with regard to whether resources are fully compensated for the variable cost of 

providing service, this paper notes most RTOs and ISOs have some method to allow faststart resources to set the clearing price, though the method used and the resources eligible 

to set price differ by market. In addition, some RTOs and ISOs allow some of a fast-start 

resource’s commitment costs to be reflected in energy and ancillary services prices, 

though the costs included differ by market. The differences across RTOs and ISOs raise 

the question of whether these differences are the result of differences in system needs or 

differences in pricing philosophy.