Price Formation in Organized Wholesale Electricity Markets

Docket No. AD14-14-000

Staff Analysis of

Shortage Pricing in RTO and ISO Markets

October 2014

For further information, please contact:

Bob Hellrich-Dawson

Office of Energy Policy and Innovation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6360

bob.hellrich-dawson@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

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

II. Introduction...........................................................................................................................................2

III. Shortage Pricing................................................................................................................................3

A. What is Shortage Pricing...................................................................................................................3

B. How Shortage Pricing Works ...........................................................................................................5

IV. Elements of Shortage Pricing Programs ...........................................................................................8

A. Administrative Shortage Prices.........................................................................................................8

B. Defining Reserve Zones..................................................................................................................15

C. Operator Actions.............................................................................................................................17

D. Schedule Coordination Across Seams ............................................................................................21

V. Experience with Shortage Events .......................................................................................................23

A. CAISO.............................................................................................................................................24

B. ISO-NE ...........................................................................................................................................25

C. PJM .................................................................................................................................................31

D. NYISO ............................................................................................................................................34

E. MISO...............................................................................................................................................35

VI. Concluding Remarks.......................................................................................................................38
1

I. 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 (Commission). It focuses on shortage pricing in the RTOs and 

ISOs and the tariff provisions governing what defines a shortage and when shortage 

pricing is invoked, the interaction of shortage pricing for different energy and operating 

reserve products, and the RTOs’ and ISOs’ experiences with reserve deficiencies and 

shortage pricing.

Locational marginal prices for energy and ancillary services ideally would reflect the true 

marginal cost of production, taking into account all physical system constraints, and fully 

compensate all resources for the variable cost of providing service.1

 If demand were 

fully price responsive and shortage pricing rules accurately reflected the value of 

avoiding involuntary load curtailments, short-run energy prices would provide both an 

accurate price signal for short-term supply and demand behavior and facilitate long-term 

entry and exit. To that end, Commission-jurisdictional RTO and ISO markets are built on 

a foundation that encourages resources to offer at a price consistent with marginal cost.

2

When the system operator is unable to meet system needs, it applies administrative 

pricing rules to ensure that costs, including the costs associated with the failure to meet 

minimum operating reserve requirements, are reflected in market prices. Ideally, these

prices would reflect the valuation consumers place on avoiding an involuntary load

curtailment. Under such conditions, prices should rise, inducing performance of existing 

supply resources and encouraging load to reduce consumption so that the system operator 

would not need to administratively curtail load to maintain reliability. A failure to 

properly reflect in market prices the value of reliability to consumers and operator actions 

taken to ensure reliability can lead to inefficient prices in the energy and ancillary 

services markets leading to inefficient system utilization, and muted investment signals. 

Reducing such inefficiencies may lead to more reliable and more economic electric 

service to consumers.

Understanding the mechanisms of shortage pricing and the RTOs’ and ISOs’ experiences 

with shortages and shortage pricing may help to shed light on markets, operations and the 

efficiency of existing market rules related to shortage pricing. Commission staff’s

preliminary observations suggest the following.

 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 Commission staff is issuing a staff report on market power mitigation rules contemporaneous with this 

paper.
2

 RTOs and ISOs all tend to define a shortage in the same way, but shortage 

pricing triggers differ.

 Shortage events are rare, sometimes not occurring at all in a year. But the 

frequency at which these events occur varies by RTO or ISO.

 Oftentimes, shortage events only last for a matter of a few 5-minute dispatch 

intervals.

 Because shortage events are rare and short-lived, potential revenue to be 

earned from shortage pricing could be minimal.

 Some operator actions taken to avert a shortage are not reflected in marketclearing prices.

 Because of the lag between price signals and import and export scheduling, it 

can be difficult for market participants to efficiently schedule exports and 

imports to respond to shortage conditions, sometimes leading to inefficient 

behavior.

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

understanding of the drivers and market impacts of shortage events and shortage pricing. 

The conference scheduled for October 28, 2014, will provide an opportunity for the 

Commission staff to learn the views of market participants, RTOs and ISOs, and market 

monitors.

II. Introduction

In an effort to better understand how shortage, or scarcity, pricing3 works in the 

organized RTO and ISO markets, this paper outlines the tariff rules and operating 

procedures of the RTOs and ISOs, describes how shortages or emergencies are defined 

and what impact this may have on prices for energy and operating reserves. Commission 

staff reviewed the tariffs and recent experiences for the wholesale markets of 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).

4

 This paper is organized around two main topics: the goals of 

shortage pricing and the key design considerations that impact shortage pricing.

 3 In general, this report is focused on pricing rules when an RTO or ISO experiences (or nears) a deficiency 

in one of the ancillary service products or involuntarily curtails load. The terms “shortage pricing” and “scarcity 

pricing” are often, though not always, used synonymously to refer to these pricing events. In the case where an 

RTO or ISO uses these terms to mean different things, we note that and use the terms as defined for that RTO or 

ISO.

4 While the details of SPP’s shortage pricing tariff provisions are provided in Appendix 6, further analysis 

of SPP’s experiences is not included in this report because its day-ahead market was not launched until 2014.
3

This paper does not attempt to assess whether existing shortage pricing rules are 

“correct” or are otherwise ripe for change. Rather, the analysis presented here is intended 

to facilitate discussions concerning the matter of shortage pricing as it affects price 

formation in the RTO and ISO energy and ancillary services markets.

In Section III, Commission staff describe the goals of shortage pricing and explain how 

shortage pricing affects price formation and why such a pricing method is needed. In 

Section IV, Commission staff present some of the important design decisions that go into 

establishing and implementing shortage pricing. To better illustrate these design choices 

and their impacts, actual RTO and ISO shortage pricing events over recent years are 

discussed in Section V. In order to empirically assess actual events, data were taken from 

the RTOs’ and ISOs’ publicly available websites, Ventyx data reporting,5 and RTO and 

ISO data submissions pursuant to Order No. 760.6

 Section VI offers concluding remarks 

and identifies issues for future discussion. A detailed description of each RTO’s and 

ISO’s definition of a shortage and what triggers shortage pricing, and the actions that can 

or must be taken to avert a shortage are found in the appendices.

III. Shortage Pricing

A. What is Shortage Pricing

An RTO or ISO procures, on behalf of its market participants, energy and operating 

reserves in daily and hourly wholesale markets.7

 It must procure sufficient resources to 

meet the expected load at any given moment in time and sufficient operating reserves to 

provide for the flexibility needed to maintain reliability from moment-to-moment and to 

meet unexpected challenges. A resource bidding into the wholesale market may offer to 

supply energy and/or one or more operating reserve products. The RTO or ISO will 

 5 Ventyx, Velocity Suite On-line, available at https://velocitysuite.ventyx.com.

6 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). In Order No. 760, the Commission stated that it may make publicly available staff white papers, 

among other things, that contain analyses derived from data that the Commission uses. Id. P 35.

7 “Operating reserves” is the term used in this paper to refer to the ancillary services procured in the 

wholesale market. All RTOs and ISOs use slightly different names for these products and/or define the reserve 

products in slightly different ways. Typically, operating reserves includes: (a) Regulating Reserve, used to account 

for very short-term deviations between supply and demand (e.g. 4 to 6 seconds); (b) Spinning, or Synchronous 

Reserve, which is capacity held in reserve and synchronized to the grid and able to respond within a relatively short 

amount of time (e.g., within 10 minutes), to be used in case of a contingency, such as the loss of a generator; and, (c) 

Non-Spinning Reserve, capacity that is not synchronized to the grid and which can take longer to respond (e.g., 

within 10-30 minutes) in case of a contingency. Collectively, these and other ancillary services help maintain 

system frequency, maintain a close balance between the supply and demand of electricity, and ensure continuous 

delivery of energy when unexpected events remove a resource from the grid.
4

evaluate all bids to find the most efficient mix of resources to meet all of the system’s 

needs and set market prices for each product. These market prices are co-optimized so 

that the lowest system costs are incurred overall; such that the market price for energy 

and each operating reserve product are interrelated.8

 Many of the supply resources 

available to the system operator may be dispatched in real time to provide some 

combination of energy and operating reserve products simultaneously.

When energy and operating reserves necessary to maintain reliability are in short supply, 

one would expect to see higher prices. This is for several reasons. First, the variable cost 

of the most expensive resource available and needed to serve load during periods of 

system stress is likely to be much higher than the variable cost of the last unit needed in 

more moderate system conditions. Second, various studies suggest that consumers place 

a very high value on avoiding involuntary curtailments.9

 However, price formation under 

tight market conditions is not a straightforward process. The vast majority of demand is 

not price responsive and thus provides no price signal regarding its willingness to stop 

consuming. In addition, operators appropriately take some out-of-market actions to avoid 

shortage conditions. Shortage pricing is the method RTOs and ISOs employ to more 

accurately price energy and operating reserves when market conditions are tight.

These more accurate prices are intended to achieve two primary goals. The first goal is 

to send a short-term price signal to incent performance of existing resources and help to 

maintain reliability. In the short term, these prices should be high enough to induce 

existing resources (including imports) to be available to the market to the maximum 

extent possible and signal consumers to reduce demand. Therefore, shortage pricing 

ought to reflect consumers’ valuation of energy.

The second goal of shortage pricing is to facilitate long-term economic entry through the 

construction of new supply resources and exit of resources that are no longer economic. 

This is especially important in RTOs or ISOs where there is no centralized capacity 

 8 Typically, a resource will be eligible for an opportunity cost payment when it provides an ancillary 

service that prevents it from providing and being paid the market price for energy. This is done so that the resource 

will be revenue neutral towards the system operator’s decision as to which service the resource will provide. 

Otherwise, a resource may not be willing to provide a service, such as Spinning Reserves, that would earn less than 

if that resource had sold energy into the wholesale market.

9 See London Economics International, Inc., Estimating the Value of Lost Load (June 17, 2013), available 

at

http://www.ercot.com/content/gridinfo/resource/2014/mktanalysis/ERCOT_ValueofLostLoad_LiteratureReviewand

Macroeconomic.pdf); Eimear Leahy and Richard S.J. Tol, An Estimate of the Value of Lost Load for Ireland (Oct. 

2010), available at

http://www.researchgate.net/publication/227355786_An_estimate_of_the_value_of_lost_load_for_Ireland/links/091

2f50d1950cdb606000000; Adriaan van der Welle and Bob van der Zwaan, An Overview of Selected Studies on the 

Value of Lost Load (Nov. 15, 2007), available at http://

www.transust.org/workplan/papers/wp2_task_5_lost_load.pdf.
5

market or other mechanism to ensure resource adequacy, but it is also important in 

regions with a capacity market or other mechanism to ensure resource adequacy. When 

shortage prices accurately reflect consumers’ valuation of energy, operating reserves, and 

planning reserves, the resulting long-run participation (entry and exit) will be 

economically efficient because revenues (including shortage pricing) will just cover a 

resource’s long-run revenue requirements.10 To the extent stakeholders want a higher 

level of resource adequacy than an energy-only market can produce, a capacity market 

construct can be added to the energy market with appropriate shortage pricing to induce 

the necessary new entry.11 

While every RTO and ISO tends to broadly define a shortage in the same way, which is 

the inability to meet the minimum requirements for operating reserves and/or energy, 

there are many more technical differences in how each RTO and ISO implements 

shortage pricing. This paper explores some of the different market design approaches.

B. How Shortage Pricing Works12

At a high level, shortage pricing is part of the system of marginal cost pricing. Under 

efficient pricing, prices reflect the marginal costs of delivering the product to the 

customer. When the supply of capacity exceeds demand for energy and operating 

reserves, the marginal cost of energy reflects the marginal out-of-pocket costs of the 

marginal generator – primarily fuel costs. The marginal cost of providing operating 

reserves is principally opportunity costs – the net revenue that the resource could have 

received by selling energy instead of providing reserves. However, when the amount of 

physically available supply of capacity is less than that needed (at the price desired) to 

meet energy demand and operating reserve requirements, additional energy demand can 

be met only by reducing the amount of operating reserves. The marginal cost of energy 

then includes the opportunity cost associated with reducing operating reserves.13 Ideally, 

during shortages, the price of operating reserves would reflect this opportunity cost, and 

the price of energy would reflect this opportunity cost in addition to the marginal out-ofpocket cost of producing energy. 

 10 See The Brattle Group and Astrape Consulting, Resource Adequacy Requirements: Reliability and 

Economic Implications at 74 (Sept. 2013), available at http://www.ferc.gov/legal/staff-reports/2014/02-07-14-

consultant-report.pdf.

11 Id. at 83-84. 

12 The following discussion does not describe any specific shortage pricing program and is not meant to 

reflect how a shortage pricing program should be designed. Instead, this section is intended to generally introduce 

some of the design elements that are typically addressed when implementing such a program. 

13 That is, by reducing operating reserves, the probability increases that load will be involuntarily curtailed 

if a contingency occurs. The resulting associated expected cost is the probability of an involuntary load curtailment 

multiplied by the value of the lost load.
6

Shortage pricing is implemented through a series of design elements, discussed more 

fully in Section IV, that ideally reflect the goals of shortage pricing, the philosophical 

foundation for shortage pricing and the operational realities of employing shortage 

pricing regimes.

Shortage Triggers - Physical Shortage vs. Price-cap Induced Shortage 

In practice, shortage pricing is triggered under two general scenarios. The first occurs 

when the system operator simply does not have enough resources available to meet 

energy and operating reserve requirements. In this case, attempting to find a least-cost 

dispatch of resources subject to a simple constraint that requires an exact amount of 

energy and operating reserves to be procured would result in an unsolvable problem. 

Under the second scenario, the RTO or ISO establishes a price above which it will choose 

to be deficient of operating reserves rather than procure resources that may be available 

to meet the minimum requirement, but cost more than the established price. This 

construct establishes a trade-off between reliability and cost. Under either scenario, 

prices are established through the use of administratively-determined prices or “penalty 

factors,” rather than actual resource supply offers.14 

Depending on the penalty prices and physical supply offers, these penalty factors may 

result in market-clearing prices either increasing to a shortage price higher than the last 

available offer or being capped at the penalty factor. When supply is physically short, the 

result is an administratively-determined shortage price that is higher than the most 

expensive supply offer cleared in the wholesale market. This shortage price reflects the 

cost of the system not being able to meet energy and minimum operating reserve 

requirements. However, when supply is available but more expensive than the penalty 

price, prices are set at the penalty price rather than at the more expensive resources’ 

offers. In this instance, the shortage price caps the maximum price the system will pay to 

meet energy and reserve requirements and chooses to operate with fewer operating 

reserves than to rely on resources more costly than the shortage price.

Conceptually, the penalty factor can be thought of as a “pseudo” or “virtual” resource 

that is offering supply of energy and operating reserves at a specific price.15 The system 

operator “commits” this pseudo resource for the remaining amount of the reserve 

requirement (though it is not physically present, of course).

Cumulative Effect of Shortages of Multiple Services

 14 Similar penalty factors can also apply when there are transmission constraints that impact redispatch. 

These penalties impact market prices in a similar fashion but are not addressed in this paper.

15 PJM, Shortage Pricing Refresher Training at 10 (May 23, 2013), available at

http://www.pjm.com/~/media/committees-groups/committees/mrc/20130523-sp/20130523-shortage-pricingrefresher-training.ashx. 
7

Typically, price formation during shortages is more involved than applying a penalty 

factor for failing to meet a single reliability-based operating reserve requirement, and

penalty factors may be additive in order to reflect the degree of the shortage or the 

particular operating reserve requirement not being met. A shortage can impact all 

operating reserves, a combination of operating reserves, or just one operating reserve, or 

a shortage can be a depletion of all operating reserves and an inability to serve energy 

demand. And, in most RTOs and ISOs, a shortage can occur on a region-wide basis or on 

a zonal-basis. Additionally, penalty factors may be additive in instances where both 

system and local requirements exist.

Shortage pricing typically involves price formation during deficiencies for three 

operating reserve products: (a) Regulating Reserve, used to account for very short-term 

deviations between supply and demand (e.g., 4 to 6 seconds); (b) Spinning, or 

Synchronous Reserve, which is capacity held in reserve and synchronized to the grid and 

able to respond within a relatively short amount of time (e.g., within 10 minutes), to be 

used in case of a contingency, such as the loss of a generator; and, (c) Non-Spinning 

Reserve, capacity that is not synchronized to the grid and which can take longer to 

respond (e.g., within 10-30 minutes) in case of a contingency.16 

Because qualification to provide different reserve products requires different operating 

characteristics, resources providing one operating reserve product cannot always provide 

another service. For example, because Regulating Reserve is actively producing energy 

at a moment in time and can respond to an Automatic Generation Control signal within 4 

or 6 seconds, to the extent an ISO or RTO has extra Regulating Reserve, these resources 

can always substitute for Spinning and Non-Spinning Reserve. However, Spinning and 

Non-Spinning Reserves cannot necessarily substitute for Regulating Reserve. To the 

extent an RTO or ISO can choose to be deficient of a reserve service, most choose to 

become deficient of the lowest quality service (e.g., Non-Spinning Reserve) first. To 

illustrate, assume the Regulation Reserve minimum requirement is 10 MW and the 

Spinning Reserve minimum requirement is 20 MW. The entire 10 MW minimum 

requirement for Regulation Reserve must be met by regulation-qualified resources. 

However, the Spinning Reserve requirement can be met by an additional 20 MW of 

resources also able to provide Regulation Reserve. This substitution happens any time 

the next MW of a regulation-qualified resource (beyond the 10 MW minimum) is cheaper 

than the next MW of spin-qualified resource (that is not also regulation-qualified).

The ability to substitute a resource offering a higher quality reserve service to provide a 

lower quality reserve service creates the opportunity cost described above. Thus, the 

shortage price for regulation service, for example, could reflect this substitutability. 

Suppose the penalty factor for being short of Regulation Reserve is $10/MW and the 

 16 All RTOs and ISOs use slightly different names for these products and/or define the reserve products in 

slightly different ways.
8

penalty factor for being short of Spinning Reserve is $5/MW, and the system operator is 

short of meeting both regulation and Spinning Reserve requirements. In this case, an 

additional MW of regulation capacity could be used to meet either the regulation or 

Spinning Reserve requirement. Therefore, the regulation shortage price could reflect this 

substitutability by setting the regulation clearing price equal to the combined penalty 

price of $15/MW and setting the Spinning Reserve clearing price equal to $5/MW. The 

particular order in which an RTO or ISO allows a deficiency to occur will dictate the 

specific way in which the shortage prices are added together. 

Similar to the substitutability of operating reserves, penalty factors may be added to 

reflect the violation of system and local requirements (“nested” requirements). If, for 

example, a market is short of meeting both a system and local requirement for Spinning 

Reserve, the local shortage price may reflect the penalty price of failing to meet both 

requirements because additional capability within the local area could satisfy both the 

local and system requirement. That is, the opportunity cost of being deficient of a reserve 

service within a local area includes the cost of being deficient on a system-wide basis.

In addition to the substitutability of certain operating reserves, the price formation 

process also involves setting an energy price that maintains appropriate incentive to 

provide either energy or operating reserves. Energy prices are set such that any resource 

dispatched to provide energy will be indifferent between providing energy or operating 

reserves. If, for example, the system operator needs to dispatch a resource that is

providing Spinning Reserve to instead provide energy, and as a result the system 

becomes deficient of Spinning Reserves, the price of energy will include the opportunity 

cost of this unit not providing Spinning Reserve.

17 This opportunity cost can be reflected 

in the energy price by adding the penalty price of not meeting the Spinning Reserve

requirement to the marginal cost of the generator. 

IV. Elements of Shortage Pricing Programs

A. Administrative Shortage Prices

The effectiveness of any shortage pricing program in meeting the goals discussed above 

will to some extent depend on the market clearing prices during shortage events. If 

shortage prices are too high, market participants may face charges in excess of the value 

of avoiding an involuntary load curtailment. If shortage prices are too low, the prices 

may fail to elicit an appropriate market response to address the reliability issue at hand or 

 17 It is possible that capacity used to provide energy could not have been used to provide operating reserves 

due to ramp rate requirements. In CAISO, for example, a generator receiving an award for Spinning Reserves must 

be able to ramp to its awarded quantity in 10 minutes.
9

facilitate efficient entry and exit by adequately contributing to fixed-cost recovery.

18 

Each RTO and ISO establishes very different prices during shortage events.

There are generally three ways that RTOs and ISOs establish prices during shortage 

conditions. One is to set the price to which a market-clearing price moves whenever, and 

to whatever degree, the system operator is unable or unwilling to procure the needed

reserve product to meet the requirement. The second is to use a schedule that defines 

how the market-clearing price increases as the shortage worsens, in combination with 

certain administratively-determined parameters. The third is some combination of the 

prior two.

The following discussion identifies some of these differences and in some cases mentions 

how RTOs and ISOs have changed some of the prices used in their shortage pricing 

programs.19 The discussion focuses on both the way prices are set (fixed price vs. prices 

varying by the severity of the shortage) and the general level of the resulting shortage 

prices. This paper does not address whether shortage prices are too low or too high but 

rather highlights the differences in practice to set the stage for further discussions.

ISO-NE, PJM, and SPP use fixed, individual shortage price levels, rather than a schedule 

of prices to establish shortage prices. ISO-NE’s shortage pricing is shown in Table 1, 

PJM’s in Table 2, and SPP’s in Table 3.

20 In ISO-NE for example, if the system operator 

does not meet the requirement for Local Thirty-Minute Operating Reserve, the marketclearing price (MCP) for that product will be set at $250/MW, as defined by the Reserve 

Constraint Penalty Factor. PJM’s and SPP’s rules work in a similar fashion.

 18 As noted above, entry and exit decisions are the result of both energy and operating reserve market 

outcomes, as well as compensation available from capacity markets or other resource adequacy constructs. In the 

context of shortage pricing as an aspect of price formation, the concern is simply whether scarcity pricing is playing 

the appropriate role in conjunction with other energy, operating reserve and resource adequacy compensation. 

19 Although it is not Commission-jurisdictional, a description of Electric Reliability Council of Texas’s 

shortage pricing rules and experiences is included in Appendix 7 for comparison.

20 In each of these tables, the operating reserve products are presented in order from least-valuable to mostvaluable.
10

Table 1. ISO-NE Reserve Constraint Penalty Factors21

Requirement Price/MW

Local Thirty-Minute Operating Reserve $250 

System Thirty-Minute Operating Reserve $500 

System Ten-Minute Non-Spinning Reserve $850 

System Ten-Minute Spinning Reserve $50 

Replacement Reserve22 $250 

Table 2. PJM Shortage Pricing 

Product Shortage Price/Penalty Factor

Non-Synchronous 

Reserve

$550/MWh

Synchronous Reserve23 $550/MWh

Regulation n/a

 21 ISO-NE also has penalty factors for Regulating Reserve. The Regulation Capacity penalty factor 

($/MW) can be set in two ways: (a) if the energy component of the real-time locational marginal price is greater 

than or equal to $100/MWh, the penalty factor is $100/MW plus the energy component of the real-time locational 

marginal price for each megawatt of Regulation Capacity shortfall, and (b) if the energy component of the real-time 

locational marginal price is less than $100/MWh, the penalty factor is the maximum of either zero or $100 plus the 

energy component of the real-time locational marginal price (i.e. the penalty factor cannot be negative) for each 

megawatt of Regulation Capacity shortfall. Regulation mileage penalty factor is $10/MW for each megawatt of 

Regulation Service shortfall; in addition, selection will consider opportunity cost sensitivities associated with large 

changes in the estimated opportunity cost of a Resource due to the shape of the resource’s supply offer price curve. 

See ISO-NE, Market Rule 1, § III.14.5.

22 ISO-NE’s Replacement Reserve requirement is intended to help resolve conditions where additional 

commitments are necessary to protect the system against normal system uncertainties and to avoid the need for 

emergency actions due to events such as load forecast errors, generator contingencies and reductions, and resource 

unavailability. ISO-NE will redispatch the system, but will not take emergency actions, to maintain Replacement 

Reserve. The $250/MWh reserve constraint penalty factor establishes a cap on the re-dispatch cost ISO-NE will 

incur to maintain the Replacement Reserve requirement.

23 PJM’s penalty factor for Synchronous Reserve will increase to $850/MWh in the 2015/2016 delivery 

year.
11

Table 3. SPP System-Wide Shortage Pricing24

Requirement

Market-Clearing Price or Locational 

Marginal Price

Supplemental Reserve

$1100 + Zonal Regulation-Up plus 

Contingency Reserve Shadow Price25

Spinning Reserve

$200 + Supplemental Reserve MCP + Zonal 

Regulation-Up plus Contingency Reserve 

Shadow Price

Regulation-Up Reserve

$600 + Spinning Reserve MCP + Zonal 

Regulation-Up Shadow Price 

Regulation-Down Reserve $600 

Energy

LMP accounts for all Shortage-Priced MCPs 

with a maximum = $50,000. 

Shortage prices in CAISO present an example of both stepped and fixed price methods. 

Table 4 shows the levels to which prices rise when CAISO fails to meet any of its 

minimum requirements for reserves. For CAISO, in the cases of Regulation-Up and 

Spinning Reserve, a flat price is established no matter the degree of shortage. However, 

for Regulation-Down and Non-Spinning Reserve, the market-clearing price depends on 

the degree of shortage and increases as the shortage worsens. 

Table 4. CAISO Shortage Pricing

Reserve Product Shadow Price Impact of Shortage

Non-Spinning Reserve

 Shortage > 210 MW $700

 210 MW > Shortage > 70 MW $600

 70 MW > Shortage $500

Spinning Reserve $100

Regulation-Up $200

Maximum Upward Sum $1000 ($700+$100+$200)

Regulation Down

 Shortage > 84 MW $700

 84 MW> Shortage > 32 MW $600

 32 MW > Shortage $500

 24 SPP’s zonal shortage pricing operates in a similar manner. These details can be found in Appendix 6.

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

In this case, for example, if the minimum requirement for the Regulation-Up plus Contingency Reserves was 

increased by one MW, the shadow price would be the cost of the next MW needed to meet the new constraint level.
12

As is shown in Table 5, MISO presents a case of fixed, individual prices, sloped and 

stepped curves. MISO’s pricing for Spinning and Regulating Reserves is an example of a 

“sloped” schedule. If MISO is unable to meet its system-wide requirement for Spinning 

and Regulating Reserves,26 it will set market clearing price at a minimum of $65/MWh, 

and, as the shortage worsens, the market clearing price rises to a maximum of $98/MWh. 

However, for the same zonal requirement, MISO uses a “stepped” schedule. The market 

clearing price is equal to $65/MWh so long as at least 90 percent of the requirement is 

met. If less than 90 percent is met, the market clearing price increases to $98/MWh. 

MISO uses a fixed price for energy deficiencies; if MISO is unable to meet demand for 

energy (the most severe shortage situation) the locational marginal price (LMP) for 

energy is set at the Value of Lost Load, which MISO currently sets at $3500/MWh. 

 26 MISO, as system operator, procures four products: Energy, Regulating Reserve, Spinning Reserve, and 

Supplemental Reserve. Regulating, Spinning, and Supplemental Reserves are known, cumulatively, as Operating 

Reserve, while Spinning and Supplemental Reserve are referred to collectively as Contingency Reserve. 
13

Table 5. MISO Shortage Pricing

Product Shortage Price

MISO-wide Operating Reserves Min. $200/MWh to Max. VOLL ($3500/MWh) 

minus Regulating Reserve demand curve value, 

depending on level of shortage.

MISO-wide Spinning and Regulating Reserves Min. $65/MWh to Max. $98/MWh depending on 

level of shortage.

MISO-wide Regulating Reserve Max. of (i) Contingency Reserve Offer Cap and 

(ii) Peaker Commitment Cost for one hour.

MISO-wide Energy LMP set to Value of Lost Load ($3500/MWh).

Reserve Zone Operating Reserves Min. $200/MWh to Max. VOLL ($3500/MWh) 

minus maximum Regulating Reserve Demand 

Curve Scarcity Price.

Reserve Zone Spinning and Regulating 

Reserves

$65/MWh if > 90% of requirement. $98/MWh if 

< 90% of requirement.

Reserve Zone Regulating Reserve Max. of (i) Contingency Reserve Offer Cap and 

(ii) Peaker Commitment Cost for one hour.

From the tables above, one can see that shortage prices for the same product are set at 

different levels in different RTOs and ISOs. While these prices, in theory, ought to 

reflect the value that consumers place on reliability, in reality prices oftentimes reflect a 

combination of this, negotiations between different stakeholders, and the experience of 

the system operator, as illustrated by the fact that the RTOs and ISOs change their pricing 

and penalty factors occasionally.

These competing interests likely explain the different price levels for similar products 

seen in the tables above. For instance, Synchronous Reserve in PJM, Spinning Reserve 

in SPP, Ten-Minute Spinning Reserve in ISO-NE, and MISO’s Spinning and Regulating 

Reserves constraint all apply to roughly the same product. In PJM, during a shortage of 

Synchronous Reserve, Synchronous Reserve would be priced at $550/MWh and energy 

would be $550/MWh plus the relevant locational marginal energy price. In SPP, during a 

Spinning Reserve deficiency, Spinning Reserve would be priced at $200/MW, plus the 

clearing price for Supplemental Reserve, plus the zonal Regulation-Up plus Contingency 

Reserve shadow price. In ISO-NE, during a shortage of Ten-Minute Spinning Reserve, 

Ten-Minute Spinning Reserve would be priced at $50/MWh plus the price of Ten-Minute 

Non-Spinning Reserve, plus the price of Thirty-Minute Operating Reserve. And in 

MISO, if there is a deficiency in the Spinning and Regulating Reserves requirement, the 

market-clearing price for Spinning Reserve will be set at a level dependent upon the 

degree of shortage (between $65/MWh and $98/MWh) plus the price of Supplemental 

Reserve (derived from the Operating Reserve requirement). Depending on the levels of 

the prices for the other products, these price levels may be quite different. 
14

Since ISO-NE implemented its ancillary services market design in October 2006, it has 

raised the Reserve Constraint Penalty Factors (i.e., the shortage prices associate with 

deficiencies for specific reserve products) for both the Local Thirty-Minute Operating 

Reserve requirement and the System Thirty-Minute Operating Reserve requirement. The 

Reserve Constraint Penalty Factor for the Local Thirty-Minute Operating Reserve 

requirement was raised from $50/MWh to $250/MWh on January 1, 2010 and from 

$100/MWh to $500/MWh on June 1, 2012 for System Thirty-Minute Operating Reserve. 

Prior to the increase in the System Thirty-Minute Operating Reserve Reserve Constraint 

Penalty Factor, there were a significant number of instances when ISO-NE was deficient 

of operating reserves even though there were sufficient physical resources available to 

meet the requirement. Those resources were deemed uneconomic because they could not 

provide reserves at a cost below $100/MWh.27 Previous to this increase, ISO-NE would 

have failed to meet the operating reserves requirement in those instances when the 

$100/MWh cap was a binding constraint.28 ISO-NE’s External Market Monitor 

calculated that after ISO-NE raised this Reserve Constraint Penalty Factor to $500/MWh, 

System Thirty-Minute Operating Reserve clearing prices exceeded $100/MWh in 0.8 

percent of the intervals during the rest of 2012, averaging roughly $174/MWh in these 

intervals. This increase in System Thirty-Minute Operating Reserve clearing prices 

illustrates the degree to which reserve prices may have been capped as a result of 

shortage pricing rules. The External Market Monitor also noted that reserve prices rose 

in the second half of 2012 to reflect the additional value of reserves as ISO-NE 

implemented additional changes in its reserves markets, including procuring and pricing 

Replacement Reserves and procuring additional Ten-Minute (and Total Operating) 

Reserve above the North American Electric Reliability Corporation minimum 

requirement.29 

In August 2010, MISO instituted a new modeling method that reduced the frequency with 

which the Spinning Reserve requirement was relaxed. Prior to this change, prices varied 

widely and the MISO Independent Market Monitor reported that many of the largest 

shortages resulted in the lowest prices, with the largest shortage (630 MW) priced at just 

$14/MW. After the modeling change, prices were regularly more consistent with 

MISO’s administrative shortage prices and showed, according to the MISO Independent 

 27 Between January 2010 and May 2012, ISO-NE was short of total Operating Reserves an average of 17.7 

hours annually. ISO-NE estimated through simulations that it would have only been short of total Operating 

Reserves an average of 3.5 hours annually if the Reserve Constraint Penalty Factor had been $500/MWh rather than 

$100/MWh. See ISO-NE, Memorandum from Market Development, to NEPOOL Market Participants, Operating 

Reserve Deficiency Information – Historical Data – Updated at 3 (May 16, 2014), available at http://www.isone.com/markets/othrmkts_data/fcm/doc/opr_reserve_deficiency_info_hist_data_updated_5_21_2014.zip.

28 Potomac Economics, 2012 Assessment of The ISO-New England Electricity Markets at 31, Figure 9, 

(May 2013), available at http://www.iso-ne.com/staticassets/documents/markets/mktmonmit/rpts/ind_mkt_advsr/isone_2012_emm_rprt_final.pdf.

29 Id. at 32.
15

Market Monitor, that the improved modeling method had resulted in reduced price

suppression.

30 

On May 1, 2012, MISO implemented a new two-step demand curve for Spinning 

Reserve. Shortage quantities of less than 10 percent of the reserve requirement are priced 

at $65/MWh, while those exceeding 10 percent are priced at $98/MWh. According to the 

Independent Market Monitor, this resulted in more efficient pricing, because MISO no 

longer relaxed the Spinning Reserve requirement to set prices during shortage as often. 

Prior to this, MISO would relax the Spinning Reserve requirement rather than pay a 

higher penalty price for being short of the reserve requirement.

B. Defining Reserve Zones

The RTOs and ISOs all include sub-zones inside their overall footprints for which there 

are minimum reserve requirements as well. Shortage pricing can also be triggered in just 

a reserve zone and these can sometimes be additive, depending upon where a shortage 

occurs. For example, in NYISO, if a shortage occurs in the New York Control Area, the 

shortage price is set as indicated in the New York Control Area column, shown in Table 

6. Similarly, if the shortage occurs in just the East of Central East area or just the Long 

Island area, the market clearing price is set as indicated in the East of Central East

column or the Long Island column, respectively. However, prices in each subzone will 

also reflect the shortage price in larger zones. For example, prices in the East of Central 

East area, which is nested within the New York Control Area zone, will also reflect 

shortage prices in the New York Control Area.

31 In addition, the values are additive for 

products that can substitute for each other. For example, if the New York Control Area is 

short of both Thirty-Minute and Ten-Minute Reserve, that would result in shortage prices 

in the New York Control Area for Ten-Minute Reserve of at least $500/MWh (short 200 

MW or less of Thirty-Minute Reserve) and up to $650 (short more than 400 MW of 

Thirty-Minute Reserve).

 30 Potomac Economics, 2010 State of the Market Report for the Midwest ISO at 58 (June 2011), available 

at http://www.iso-ne.com/staticassets/documents/markets/mktmonmit/rpts/ind_mkt_advsr/isone_2010_immu_rpt_drft_final_june_11.pdf.

31 For example, if there is a shortage of Ten-Minute Reserves in Long Island and East of Central East, but 

not the New York Control Area, Ten-Minute Reserves will be priced at $525/MWh in Long Island and $500/MWh 

in East of Central East. If there is a shortage of Ten-Minute Reserves in the New York Control Area and East of 

Central East but not Long Island, Ten-Minute Reserves will be priced at $450/MWh in the New York Control Area 

and $950/MWh in East of Central East (which includes Long Island). If there is a shortage of Ten-Minute Reserves 

in the New York Control Area and Long Island but not East of Central East, then Ten-Minute Reserves will be 

priced at $450/MWh in the New York Control Area (and New York City since it is nested in the New York Control 

Area) and $475/MWh in Long Island. Finally, if there is a shortage of Ten-Minute Reserves in the New York 

Control Area, East of Central East, and Long Island, then Ten-Minute Reserves will be priced at $450 in the New 

York Control Area, $950/MWh in New York City (East of Central East excluding Long Island) and $975/MWh in 

Long Island.
16

Table 6. NYISO Shortage Pricing ($/MWh)

Service Shortfall

New 

York 

Control 

Area

East of Central 

East (New 

York City or 

Long Island) 

Long 

Island

only

Regulation 0 to 25 80 n/a n/a

> 25 to 80 180 n/a n/a

> 80 400 n/a n/a

Thirty-Minute 0 to 200 50 25 25

> 200 to 400 100 25 25

> 400 200 25 25

Total Ten-Minute > 0 450 500 25

Total Spinning > 0 500 25 25

PJM’s experience on September 10, 2013 provides an interesting example of the 

challenges of establishing prices that reflect shortage on a local rather than system-wide 

level.32 On September 10, 2013, PJM was forced to involuntarily shed 16 MW during 

hours ending 16 and 17 in the ATSI transmission zone. During this event, the energy 

price for the ATSI zone during hour ending 17:00 through 20:00 was at or near its highest 

level ($1800/MWh) to reflect the fact that demand response resources were marginal 

(demand response offer cap was $1800/MWh) during those hours. While this is 

considered a shortage pricing event, the nature of the pricing is somewhat unique. The 

ATSI zone is not defined as a reserve zone for the purposes of identifying local reserve 

deficiencies. Thus, despite the fact that PJM shed load in the ATSI transmission zone, it 

did not set prices based on any reserve deficiency. Rather, prices were set because PJM 

invoked the ATSI Interface, a closed loop interface developed on July 17, 2013, to set 

energy prices any time emergency load management is issued in the ATSI zone.

33 This 

pricing technique appears to have resulted in prices that reflect the shortage event, but 

without accounting for reserve deficiencies on a local basis. 

 32 See PJM, Technical Analysis of Operational Events and Market Impacts During the September 2013 

Heat Wave at 24-30 (Dec. 23, 2013), available at http://www.pjm.com/~/media/documents/reports/20131223-

technical-analysis-of-operational-events-and-market-impacts-during-the-september-2013-heat-wave.ashx 

(discussing the event); id. at 76 (explaining PJM’s ATSI Zone Interface activation, a situation where emergency 

mandatory load management is issued in the ATSI transmission zone).

33 See PJM, ATSI Interface, available at http://www.pjm.com/~/media/etools/oasis/system-information/atsiinterface-definition-update.ashx.
17

C. Operator Actions34

One of the most important differences between the RTOs and ISOs is what actually 

triggers shortage pricing. If an event is triggered too late, the market may be late to 

respond to the system’s needs. Or, if operator actions taken to avoid a shortage35 are not 

priced, prices may fail to appropriately signal tight market conditions. Every RTO and 

ISO has steps the system operator can and must take in order to avert a shortage.36 

However, if a goal of shortage pricing is to reflect in prices the cost of a shortage, it also 

may be important to price certain operator actions taken to avert a shortage. 

The actions system operators take to avert a shortage, such as importing emergency 

energy or instituting a voltage drop, trigger shortage pricing in some RTOs and ISOs but 

not others. While NYISO and PJM invoke shortage pricing in response to certain 

operator actions, CAISO implements shortage pricing in a market run prior to an actual 

shortage occurring.37 NYISO activates shortage pricing when Emergency Demand 

Response is dispatched. PJM considers a voltage drop to be an emergency action that 

triggers shortage pricing.38 Different still, many of MISO’s shortage events are triggered 

by ramping constraints that limit the system operator’s ability to meet reserve 

requirements. That is, MISO has sufficient capacity to meet its reserve requirements, but 

has insufficient ramp capability to meet load and thus must dip into its reserve capacity to 

serve load. On the other hand, SPP specifically forbids ramping constraints from 

triggering shortage pricing, thus masking whether the RTO is short of operating reserves 

 34 Any discussion in this paper of issues related to demand response resources is intended only to reflect the 

manner by which these resources have participated in wholesale electricity markets in the past and is not a statement 

about how such resources may participate in the future.

35 An operator emergency action, taken to avoid a shortage, could be in response to such things as actual 

load being higher than forecasted or the unexpected loss of a supply resource.

36 For instance, if MISO anticipates a shortage, it can commit generation resources up to the emergency 

limits, commit emergency-only generation and demand response resources, curtail fixed demand bids and fixed 

export schedules. If these actions are not sufficient to relieve the shortage, MISO must then call an Emergency 

Energy Alert 1, or if needed Emergency Energy Alert 2. Declaring Emergency Energy Alert 2 then provides MISO 

with further steps it may take to mitigate any shortage, including directing LSEs to curtail Load Modifying 

Resources (a type of demand response resource), dispatching emergency demand response based on submitted 

offers, purchasing emergency energy, issuing a public appeal to reduce demand, and implementing a voltage 

reduction. See MISO, Market Capacity Emergency Procedures RTO-EOP-002-r17 (effective June 1, 2014), 

available at https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=177019.

37 For example, CAISO procures and prices operating reserves on a 15- minute basis in the Fifteen-Minute 

Market, a market run starts 37.5 minutes before the operating 15-minute interval (e.g., 11:22 for Operating Reserves 

awarded from 12:00-12:15). If at 11:22, CAISO forecasts a shortage of operating reserves, it will implement 

shortage pricing in the Fifteen-Minute Market, 37.5 minutes before the actual shortage is predicted to occur.

38 PJM, Manual 11 Energy and Ancillary Services Market Operations, at 33 available at

http://www.pjm.com/~/media/documents/manuals/m11.ashx.
18

or short of ramping capability. These differences across RTOs and ISOs, combined with 

system and meteorological events, lead to different experiences with shortage events and 

shortage pricing in the RTOs and ISOs.39 

Finally, the conditions that lead to shortage pricing may depend on other actions an RTO 

or ISO takes to prepare for tight system conditions. For instance, some RTOs and ISOs 

procure extra reserves to provide flexibility to respond to uncertain system conditions 

(e.g., under-forecast load, generation resource performance issues). In PJM, the dayahead market procures a minimum of a certain percentage of the daily peak load in the 

form of Day-Ahead Scheduling Reserves. In 2013, the Day-Ahead Scheduling Reserves

minimum was set at 6.91 percent. Day-Ahead Scheduling Reserves represented 

approximately 6800 MW of capacity and can respond in thirty minutes.

40 However, only 

the primary reserve requirement, the sum of the Ten-Minute Spinning Reserve

requirement and the Ten-Minute Non-Synchronous Reserve requirement, is considered 

required reserves in PJM. This primary reserve represents about 2000 MWs. Therefore, 

shortage pricing in PJM only begins when approximately 70 percent of all the reserves in 

PJM are exhausted. The primary concern with procuring “extra” reserves is to ensure 

that doing so is reflected in the energy and ancillary services prices outside of shortage 

events.

41 Nevertheless, it is also important to appreciate how the decision to procure 

extra reserves impacts shortage pricing rules. To the extent extra reserves are procured 

out of a desire to avoid an involuntary load curtailment, one can question whether 

becoming deficient in such reserves should also trigger shortage pricing.

The following section explores some examples of how operator actions affect prices 

during tight system conditions.

In ISO-NE, operator actions related to the dispatch of demand response resources have

resulted in instances of relatively low prices during tight system conditions. Under ISONE’s currently-effective tariff, demand response is classified as a “non-dispatchable”

resource and is therefore not eligible to set prices; rather, demand response resources are 

dispatched manually by the system operator during certain shortage or near-shortage

events. However, the External Market Monitor notes that “[t]he activation of demand 

response in real-time can inefficiently depress real-time prices substantially below the 

marginal cost of the foregone consumption by the demand response resources, 

 39 A more complete discussion of existing shortage pricing programs is included in the Appendices. 

40 Monitoring Analytics, State of the Market for PJM, at 316 (Mar. 13, 2013), available at

http://www.monitoringanalytics.com/reports/pjm_state_of_the_market/2013/2013-som-pjm-volume1.pdf.

41 A subsequent workshop will include discussion of this concern.
19

particularly during shortages or near-shortage conditions.”42 For example, on both July 

22, 2011 and December 19, 2011, ISO-NE activated Real-Time Demand Response 

Resources to address operating reserve shortages and in both instances the Demand 

Response Resources were effectively on the margin during at least some of the 

shortage,43 yet prices fell during these intervals – from over $450 in hour ending 16:00 on 

July 22, 2011 to just over $175 in hour ending 17:00; and from over $275 in hour ending 

8:00 to $32 in hour ending 9:00 on December 19, 2011.44 

Similarly, NYISO has experienced instances when operator actions and the dispatch of 

demand response resources have resulted in relatively low prices during tight system 

conditions. While demand response resources in NYISO have had a relatively small 

impact on annual average energy prices, they had a substantial affect in the hours when 

they were deployed and depressed real-time prices to levels well below their cost to the 

system – typically $500/MWh to curtail their load.45 As detailed in Table 7 below, 

NYISO deployed demand response resources in 2012 on two occasions to meet systemwide needs, and on four occasions to meet needs in Southeastern New York. In NYISO, 

shortage pricing is only triggered when emergency demand response is dispatched and

the quantity of demand response exceeds the capacity of other resources available but not 

committed to address the reserve deficiency. This only occurred once in 2012, on July 

28. 

Table 7 shows the events when the quantity of dispatched demand response was less than 

the quantity of other available capacity that was available but not committed to address 

the reserve deficiency. Prices during those (non-shortage pricing) events were below 

$130/MWh on all but two occasions. Of these two events, even for the higher-priced 

occasion when system needs exceeded the amount of demand response called, prices 

were at $409/MWh; this is below the typical cost ($500/MWh) of deploying demand 

response resources.46 In response, NYISO’s External Market Monitor recommended

 42 Potomac Economics, 2012 Assessment of The ISO-New England Electricity Markets at 79 (May 2013), 

available at http://www.iso-ne.com/staticassets/documents/markets/mktmonmit/rpts/ind_mkt_advsr/isone_2012_emm_rprt_final.pdf.

43 That is, the MW amount of Demand Response Resources exceeded the MW shortage in Operating 

Reserves – with Demand Response, there was no shortage of Operating Reserves and without Demand Response 

there would have been a shortage.

44 Potomac Economics, 2011 Assessment of The ISO-New England Electricity Markets at 72-73 (June 

2012), available at http://www.iso-ne.com/staticassets/documents/markets/mktmonmit/rpts/ind_mkt_advsr/emm_mrkt_rprt.pdf.

45 Potomac Economics, 2012 State of the Market Report for the New York ISO Markets at 68-71 (Apr. 

2013), available at

http://www.nyiso.com/public/webdocs/markets_operations/documents/Studies_and_Reports/Reports/Market_Monit

oring_Unit_Reports/2012/NYISO2012StateofMarketReport.pdf.

46 Id.
20

modifications of the market rules so demand response resources that have been deployed 

are eligible to set price in the real-time pricing methodology.47 

Table 7. NYISO Real-time Prices and Available Capacity During Reliability

Demand Response Deployments, 2012

Reported

DR (MW)

Available Capacity (MW) Avg.

LBMP

($/MWh)

Average Minimum

New York Control 

Area Activation

May 29

June 21

1081

1877

1402 1214

3172 2635

$99

$128

SE New York

Activation

June 20

June 21

June 22

July 18

669

650

677

676

2132 1974

1979 1414

3371 2055

1307 172

$111

$235

$101

$409

In summer 2013, NYISO implemented an Enhanced Scarcity Pricing Rule that was 

designed to ensure that real-time prices better reflect real-time shortages. NYISO 

deployed demand response on five days in 2013: July 15 through July 19. NYISO’s 

External Market Monitor found the new shortage pricing rule was applied in the vast 

majority of intervals when demand response was actually needed (234 of 266 intervals),48

although the External Market Monitor also noted that shortage pricing is only applied to 

internal locations, resulting in large differences between real-time prices at internal and

external interfaces. The External Market Monitor noted that, when market participants 

expect a shortage event the next day, this can lead to incentives for participants to import 

day-ahead and buy back at non-shortage real-time prices.49 This strategy, which can lead 

to additional export demand during likely shortage events, would not be profitable if 

shortage pricing were applied to external interface ties.

 47 Id. at 85.

48 Potomac Economics, 2013 State of the Market Report for the New York ISO Markets at A-137 to A-140 

(May 2014), available at

http://www.nyiso.com/public/webdocs/markets_operations/documents/Studies_and_Reports/Reports/Market_Monit

oring_Unit_Reports/2013/2013%20State%20of%20the%20Market%20Report.pdf.

49 Id. at 67-68.
21

In sum, while it may be neither possible nor practical to price all operator actions in RTO 

and ISO markets, pricing some of the more common actions used to avert system 

shortages may in some instances result in more appropriate price formation during tight 

system conditions. Furthermore, the order of operator actions may also be important. 

For example, MISO’s Independent Market Monitor recommended in its 2012 State of the 

Market report that MISO re-order its emergency procedures so that demand response 

resources are used more efficiently. Because demand response in MISO could only be 

called on after other, more costly, steps were taken to avoid a shortage, prices were not 

sending efficient signals.50 As discussed above, operator actions can significantly impact 

price formation, and while such impacts may be of limited duration, these actions are 

often taken during tight conditions when appropriate price signals are paramount.

D. Schedule Coordination Across Seams

When one RTO or ISO declares a shortage or invokes shortage pricing, resources in 

neighboring RTOs and ISOs can see those price signals and respond. With the right 

timing of these events and the coordination of scheduling rules, imports from neighboring 

regions can help an RTO or ISO avoid a shortage and maintain reliability, while sending 

an efficient price signal to those resources that respond.

As discussed above, in summer 2013, NYISO implemented an Enhanced Scarcity Pricing 

Rule that was designed to ensure real-time prices better reflect real-time shortages. The 

NYISO External Market Monitor has noted that shortage pricing is only applied to 

internal locations, resulting in large differences between real-time prices at internal 

versus external interfaces leading to incentives for participants to import day-ahead and 

buy back at non-shortage real-time prices.51

The events of July 6, 2012 in MISO present a good example of where poor timing can 

lead to unintended consequences as importers attempt to react to high prices in a 

neighboring RTO or ISO. Prices were high on that date due to an operating reserve 

shortage caused by a combination of a 1.7 GW increase in load, the loss of a nearly-600 

MW unit, and a 1.5 GW drop in imports from PJM. MISO’s Independent Market 

Monitor identified the lack of coordinated interchange with PJM as the primary cause of 

a number of the high-price intervals.52 In this case, net imports declined because prices 

 50 Potomac Economics, 2012 State of the Market Report for the MISO Electricity Markets at 9 (June 2013), 

available at https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=155430.

51 Potomac Economics, 2013 State of the Market Report for the New York ISO Markets at 67-68 (May 

2014), available at

http://www.nyiso.com/public/webdocs/markets_operations/documents/Studies_and_Reports/Reports/Market_Monit

oring_Unit_Reports/2013/2013%20State%20of%20the%20Market%20Report.pdf.

52 Potomac Economics, 2012 State of the Market Report for the MISO Electricity Markets at ii (June 2013), 

available at https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=155430.
22

were approximately $100/MWh higher in PJM at the time. MISO remained in a shortage 

for another 30 minutes until imports from PJM responded to the new higher MISO 

interface price (at this point approximately 20 times higher than PJM). Because imports

from PJM lagged the event by 30 minutes, the event was actually ending by the time the 

imports arrived, and the full effect of the imports was not felt until 2 pm, resulting in an 

overreaction to the shortage. By 2:10 pm interface prices shifted in response to 

overreaction, net imports had declined, and PJM prices were higher than in MISO while 

load was still increasing in MISO, leading to a second shortage.53

The effect of July 17, 2013, illustrated in Figure 1 below, provides a similar example. On 

this day MISO issued a Maximum Generation Emergency Alert from 14:00 to 19:00 due 

to higher than normal temperatures during the week of July 15th that led to higher load. 

MISO issued the Maximum Generation Alert because its projected peak-hour capacity 

surplus (the amount above the requirement) was expected to be less than 1 percent of its 

reserve requirements.54 Prices rose sharply between 12:30 and 13:30 due to rapid load 

growth and a shift of approximately 600 MW in net-scheduled interchange towards PJM. 

As a result, MISO prices rose and net-scheduled interchange shifted toward MISO by 

roughly 1400 MW from 13:15 to 14:15 pm and net imports on other interfaces (i.e. with 

other systems) began to grow. Prices then moved and remained relatively low when load 

dropped after 13:30, wind output picked up, and MISO resource commitments increased. 

This is seen in Figure 1 by the sharp drop in prices after hour ending 14:00, when realtime LMP dropped from approximately $90 to near $50.55

 53 Id. at 7-8.

54 David B. Patton, Monthly Market Metrics Report July 2013 at 11 (Aug. 21, 2013), available at 

https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=157847.

55 Todd Ramey, Vice President, System Operations & Market Services, MISO, MISO Gas-Electric 

Coordination Update at 4-6 (Oct. 17, 2013), available at http://www.ferc.gov/CalendarFiles/20131017102239-

MISO-MEETING.pdf.
23

Figure 1. MISO Maximum Generation Emergency Alert, July 17, 2013.

While trade between RTOs and ISOs can lead to more efficient market outcomes, 

coordinating import/export transactions with emergency actions, such as those 

highlighted above, remains a challenge. The inability to coordinate can lead to inefficient 

flows between markets and can also lead to uplift payments, as resources committed to 

address a shortage event may be unneeded when higher than expected imports arrive 

from a neighboring region. This raises the question of whether any change to either 

shortage pricing rules or inter-ISO energy market coordination protocols could enhance 

the ability of neighboring regions to help alleviate shortage events.

V. Experience with Shortage Events

Discussed below are the RTOs’ and ISOs’ most recent experiences with shortages. Most 

RTOs and ISOs experience very few shortage events at all, and as a result, seldom see 

shortage pricing. When shortage pricing is invoked, oftentimes prices move as expected: 

prices increase when shortages occur, and decrease when the shortage ends. However, 

the duration of shortage pricing events appears to be very short. In addition, the effects 

of un-priced operator actions and inefficient imports leave open the question of whether 
24

the recent experiences with shortage pricing are achieving the goals discussed in Section 

III. That is, can infrequent, short duration shortage prices provide a signal for short-term 

performance and create incentives for efficient entry and exit? 

A. CAISO

CAISO implemented shortage pricing on December 14, 2010 and since then has had only 

thirty-two 15-minute intervals of shortage pricing. As detailed in Table 8, twenty-eight

of these intervals with ancillary service shortage pricing occurred in 2011, resulting in a 

direct cost of only $60,000.56

Table 8. CAISO 2011 Shortage Pricing Events

Month Ancillary Service

Shortage

Intervals

Average MW 

Shortfall Ancillary Service Region

April Spin 1 7.1 SP 26

May Spin 3 11.5 SP 26/SP 26 Exp

June Regulation-Up 8 19.9 SP 26 Exp

July Regulation-Up 2 0.9 CAISO

July Spin 2 13.8 CAISO

July Non-Spin 9 112.7 CAISO

November Spin 1 12.3 SP 26

November Regulation-Up 2 10 SP 26

In 2012, there was only one 15-minute interval in which the ancillary service 

requirements were not met in either the hour-ahead or real-time markets. This was due to 

a 15 MW deficiency of Spinning Reserve and resulted in an incremental cost to the 

market of just $391.57 In 2013, there were three 15-minute intervals in which the 

Regulation Down requirement could not be met in one reserve zone in either the hour-

 56 CAISO Department of Market Monitoring, 2011 Annual Report on Market Issues and Performance (Apr.

2012), available at http://www.caiso.com/Documents/2011AnnualReport-MarketIssues-Performance.pdf.

57 CAISO Department of Market Monitoring, 2012 Annual Report on Market Issues and Performance at 

115 (Apr. 2013), available at http://www.caiso.com/Documents/2012AnnualReport-MarketIssue-Performance.pdf. 
25

ahead or real-time markets. Because no incremental capacity was procured during these 

intervals, the incremental cost of this event to the market was $0.58 

B. ISO-NE

Like CAISO, ISO-NE does not witness shortage events frequently. ISO-NE uses a 

protocol, Operating Procedure No. 4, which establishes criteria and guidelines for actions 

during existing or anticipated capacity deficiencies.59 While there are ten numbered 

actions described in Operating Procedure No. 4 (detailed in the Appendix), ISO-NE does 

not have to follow a set order; it can take whatever actions it deems necessary for 

reliability. Operating Procedure No. 4 actions include: depleting Thirty-Minute 

Operating Reserve; dispatching real-time demand response resources; requesting 

voluntary load curtailment; purchasing emergency capacity and energy from neighboring 

balancing authorities; implementing a voltage reduction; and, appealing for voluntary 

load curtailment.60 In addition, not every shortage is associated with the triggering of 

Operating Procedure No. 4. Thus, ISO-NE has the discretion to take actions under 

Operating Procedure No. 4 that may or may not trigger shortage pricing. Since June 1, 

2012, ISO-NE implemented Operating Procedure No. 4 on three occasions: January 28, 

2013; July 19, 2013; and December 14, 2013. In addition, ISO-NE had a shortage of 

Ten-Minute Operating Reserve on five occasions – the three Operating Procedure No. 4

events already mentioned, plus November 9, 2013 and January 28, 2014.

Since June 1, 2012, ISO-NE has experienced over 40 instances when system-wide 

Reserve Constraint Penalty Factors have been activated (where Reserve Constraint 

Penalty Factors were binding for Ten-Minute Operating Reserve and/or Total Operating 

Reserve) across 294 five-minute intervals, an average of 12.8 hours per year.61 These are 

 58 CAISO Department of Market Monitoring, 2013 Annual Report on Market Issues and Performance (Apr.

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

CAISO, 2013 Ancillary Service Scarcity Event Report (Mar. 26, 2014) available at

http://www.caiso.com/Documents/2013AncillaryServiceScarcityEventReport.pdf.

59ISO New England Inc., Operating Procedure No. 4 – Action During a Capacity Deficiency (effective 

Aug. 12, 2014), available at http://www.iso-ne.com/rules_proceds/operating/isone/op4/op4_rto_final.pdf

(hereinafter, ISO-NE OP-4 Manual).

60 Id. at 4-7.

61 There are multiple instances where ISO-NE experienced shortages where periods of binding Reserve 

Constraint Penalty Factors were interrupted by a small number of intervals without binding Reserve Constraint 

Penalty Factors, which were counted as multiple instances of Reserve Constraint Penalty Factor activation, even 

though the events were clearly related. See ISO-NE, Operating Reserve Deficiency Information – Historical Data –

Updated,” (May 16, 2014), available at http://www.isone.com/markets/othrmkts_data/fcm/doc/opr_reserve_deficiency_info_hist_data_updated_5_21_2014.zip. 

Therefore, simply looking at the number of instances of RCPF activation may be misleading, and it is more 

instructive to look at the number of intervals of Reserve Constraint Penalty Factor activation. 
26

detailed in Table 9 below. The result in ISO-NE is that shortage pricing is only activated 

during a limited number of hours each year, and reserve prices are $0/MWh for all 

operating reserve products (excluding Regulation) in over 95 percent of hours.62 

Table 9. ISO-NE Shortage Pricing Events, June 2012 – April 2014

Month

Total Number of 

Intervals

Average Total 

MW Shortfall

Ten-Minute

Shortage

Operating 

Procedure 

No. 4

Events

Jul-2012 8 194 No No

Oct-2012 2 9 No No

Nov-2012 2 297 No No

Jan-2013 14 139 Yes Yes

Feb-2013 2 50 No No

Mar-2013 4 109 No No

Jun-2013 14 148 No No

Jul-2013 80 564 Yes Yes

Aug-2013 12 232 No No

Sep-2013 26 87 No No

Oct-2013 28 244 No No

Nov-2013 20 354 Yes No

Dec-2013 37 394 Yes Yes

Jan-2014 15 360 Yes No

Feb-2014 23 327 No No

Mar-2014 6 367 No No

Apr-2014 1 177 No No

Figure 2 illustrates the events of January 28, 2013, when ISO-NE called an Operating 

Procedure No. 4 event. This day followed several severely cold days which culminated 

in tight capacity availability due to fuel limitations. The overnight dispatch of some gasfired generating resources, called on to replace other fuel-limited resources, resulted in 

their operations being reduced due to their now-limited gas supplies. This made these 

 62 Several recent Reserve Constraint Penalty Factor rule changes affect when shortage pricing will be 

invoked. For example, ISO-NE’s External Market Monitor calculated that after ISO-NE raised the Reserve 

Constraint Penalty Factor for total Operating Reserves to $500/MWh on June 1, 2012, Thirty-Minute Reserve 

clearing prices exceeded $100 per MWh in 0.8 percent of the intervals during the rest of 2012, averaging roughly 

$174 per MWh in these intervals, rather than going short of Operating Reserves as ISO-NE would have done 

previously.
27

gas-fired generators unavailable for dispatch during the morning load ramp on January

28. Ten-Minute Operating Reserve and Regulation Reserve therefore could not be 

covered, leading to ISO-NE taking Operating Procedure No. 4 actions to help maintain 

operating reserves.63 Shortly after 17:00 a generator tripped, causing ISO-NE to take 

Operating Procedure No. 4 Actions 1 and 2.64 By 17:45 a generator had been dispatched 

to prevent any worsening of the shortage. 65 These actions resulted in Ten-Minute

Spinning Reserve market-clearing price hitting a high of $526.84/MWh. In turn, LMP 

peaked at $780.89/MWh.66

This event illustrates how when the system operator is unable to meet one reserve 

requirement, here Thirty-Minute Operating Reserve, the price for that constraint increases 

and increases the prices for other products, Ten-Minute Spinning Reserve and energy in 

this example, as can be seen in Figure 2 below. In hour 17:00 when the system operator 

could no longer meet that requirement, the shadow price on that constraint jumped from 

$0 to near $300.67 

 63 ISO-NE, Winter Operations Summary: January – February 2013 at 9 (Feb. 27, 2013), available at

http://www.isone.com/committees/comm_wkgrps/strategic_planning_discussion/materials/winter_operations_summary_2013_feb_

%2027_draft_for_discussion.pdf. 

64 ISO-NE informs all resources that a capacity shortage exists, begins to utilize Thirty-Minute Reserve, 

and implements a power caution for Operating Procedure No. 4 Action 1. ISO-NE dispatches real time demand

resources in the amount and location required for Operating Procedure No. 4 Action 2.

65 ISO-NE Internal Market Monitor, 2013 First Quarter Quarterly Market Report at 14 (May 20, 2013), 

available at http://www.iso-ne.com/markets/mkt_anlys_rpts/qtrly_mktops_rpts/2013/qmrq1_2013.pdf. 

66 Id. at 13. 

67 ISO-NE was deficient of Regulating Reserves prior to being deficient of operating reserves. Though 

ISO-NE also has penalty factors for Regulating Reserve deficiencies, it is not apparent what price impact was seen 

in hours 17:00 and 18:00. Given that no Regulating Reserve deficiency was seen in hour 18:00, it is assumed that 

the increase in price that hour was unrelated.
28

Figure 2. ISO-NE Operating Procedure No. 4 Event, January 28, 2013.

On July 19, 2013 the ISO-NE system was deficient in reserves over the peak hours and 

ISO-NE declared Operating Procedure No. 4. In addition to high electric load, there were 

4,724 MW of generator outages and reductions over the peak hour of the day that 

contributed to the need to implement Operating Procedure No. 4.

68 High loads on July 19 

coupled with generator unavailability resulted in tight capacity conditions. The system 

did not have sufficient reserves or capacity available to meet the reserve requirements by 

noon causing ISO-NE to declare Operating Procedure No. 4. Figure 3 below shows the 

times at which the various actions of Operating Procedure No. 4 were declared along 

with the actual operating reserves and reserve requirements throughout the Operating 

Procedure No. 4 event. Action 1 of Operating Procedure No. 4 was system wide, while 

actions 2, 3, and 569 excluded the Maine load zone due to transmission export 

 68 As the summer seasonal claimed capability is normalized to 90 degrees F, some reductions are 

attributable to ambient air temperatures, since the temperature at the time of the peak on July 19 was 95 degrees F. 

Other outages and reductions are attributable to de-rated capacity due to mechanical failures. 

69 ISO-NE requests voluntary load curtailment of market participants’ facilities in the New England New 

England Reliability Coordination Area/Balancing Area Authority for OP-4 Action 3. ISO-NE arranges to purchase 

available emergency capacity and energy, or energy only, (if capacity backing is not available) from market 

participants or neighboring New England Reliability Coordination Areas/Balancing Area Authorities for Operating 

Procedure No. 4 Action 5.
29

constraints.70 Of particular interest here is that it appears that, even when certain reserve 

product requirements were not being met, prices, nonetheless, were flat or dropping. For 

instance, at 12:00 and 13:00 when the first two OP-4 actions were taken, procurement of 

Ten-Minute Non-Spinning Reserve and Thirty-Minute Operating Reserve were still 

deficient. While the price for Thirty-Minute Operating Reserve peaked at its limit of 

$500/MWh, the price of Ten-Minute Non-Spinning Reserve seems to have stayed flat, 

also at $500/MWh, rather than increase. Operating Procedure No. 4 actions were also 

taken at 14:20 and 15:00. At this point and lasting until after 18:00, the requirement for 

Thirty-Minute Operating Reserve was still not met, yet its price dropped. It is not clear 

why prices moved like this over the course of the day; but it does raise the question of 

what impact these Operating Procedure No. 4 actions have on market-clearing prices and 

whether out-of-market actions, in general, can have a price suppressing effect.

Figure 3. ISO-NE OP-4 Event, July 19, 2013.

 70 ISO-NE Internal Market Monitor, 2013 Third Quarter, Quarterly Markets Report (Nov. 13, 2013), 

available at http://www.iso-ne.com/staticassets/documents/markets/mkt_anlys_rpts/qtrly_mktops_rpts/2013/q3_2013_qmr_final.pdf.
30

December 14, 2013 appears to show a slightly different relationship between reserve 

deficiencies and prices. On this date, the actual load and the forecast load were very 

close, but during hour ending 17:00, the actual load started to diverge above the forecast 

value. At 17:00, significant imports into New England were curtailed, which, combined 

with the heavier than expected load, resulted in Operating Procedure No. 4 Action 1 

being declared at 17:00, as shown in Figure 4. Prior to entering Operating Procedure No. 

4, 21 MW in the Winter Demand Response Reliability Program were dispatched. At 

17:07, ISO-NE declared Operating Procedure No. 4 Action 2 and dispatched 248 MW of 

Real-time Demand Response. ISO-NE declared Operating Procedure No. 4 Action 5 at 

17:40 and scheduled 300 MW of Control Area to Control Area emergency capacity from 

17:42 to 18:30. The preliminary integrated peak demand for hour-ending 18:00 on 

Saturday was 20,182 MW, 632 MW above the forecast 19,550 MW value.71 In this 

instance, prices appear to move as one would expect, with increases in prices seemingly 

correlated to worsening deficiencies, and lessening deficiencies coupled with prices 

dropping. Taken with the events of July 19, 2013, it is unclear if one can draw definite 

conclusions regarding what effect out-of-market actions have on market-clearing prices.

 71 ISO-NE, Memorandum to NEPOOL Market Committee and NEPOOL Reliability Committee, 

Implementation of ISO New England Operating Procedure #4 on Saturday, December 14, 2013 (Dec. 18, 2013), 

available at http://www.isone.com/sys_ops/op4_action_archiv/2013/implementation_of_iso_new_england_operatiing_procedure_4_on_saturda

y_december_14_2013.pdf.
31

Figure 4. ISO-NE OP-4 Event, December 14, 2013

C. PJM

PJM invokes shortage pricing in two situations: when reserves fail to meet requirements,

and when PJM institutes a voltage reduction. Like other RTOs and ISOs, shortage 

pricing is rare in PJM in part because PJM’s use of Day Ahead Scheduling Reserves, as 

discussed earlier, means that PJM only uses shortage pricing when it has exhausted 

approximately 70 percent of all reserves. In fact, PJM did not have any reserve shortage 

events or shortage pricing during 2010, 2011, or 2012.

The shortage events PJM experienced in 2013 illustrate some of the complexities 

associated both with incorporating the use of demand response into prices and in defining 

local reserve zones. In 2013, PJM did not have any reserve shortage events, though

shortage pricing was in effect in certain zones on three different days due to emergency 

operations. First, PJM experienced a shortage of Non-Synchronous Reserve in the ATSI 

region that led to LMP in excess of $1000/MWh and shortage pricing for several hours 

on July 18. As discussed in more detail above, this occurred again on September 10 and 

also led to load shedding in the AEP zone. Finally, on September 11, 2013, PJM 

experienced a shortage of Non-Synchronous Reserve and took several actions to ensure 

reliability. PJM deployed long-lead-time demand response in the AEP and ATSI and 
32

other zones, and issued a voltage reduction warning in the AEP and ATSI zones. As on 

September 10, demand response set the market-clearing LMP at its limit of $1800/MWh

in the ATSI zone.

72 The impacts of these events on pricing in PJM are shown in the 

figures that follow.

Figure 5. PJM ATSI Zone Shortage, July 18, 2013.

 72 See PJM Interconnection, Technical Analysis of Operational Events and Market Impacts During the 

September 2013 Heat Wave at 76 (Dec. 23, 2013), available at

http://www.pjm.com/~/media/documents/reports/20131223-technical-analysis-of-operational-events-and-marketimpacts-during-the-september-2013-heat-wave.ashx. See also Monitoring Analytics, LLC, State of the Market for 

PJM at 117 (Mar. 13, 2013), available at

http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2013/2013-som-pjm-volume1.pdf. LMPs 

in PJM in excess of $1000 per MWh reflect shortage pricing because bids in PJM cannot exceed $1000 per MWh. 
33

Figure 6. PJM ATSI Zone Load Shed, September 10, 2013.
34

Figure 7. PJM ATSI and AEP Zones Load Shed, September 11, 2013.

D. NYISO

NYISO presents yet a slightly different example. Like PJM, it invokes shortage pricing 

when it is unable to meet its reserve requirements or when a specific operator action is 

taken: dispatch of Emergency Demand Response. However, while there were not a 

significant number of intervals73 with shortage events in 2013, these events had a 

substantial impact on NYISO’s energy prices, accounting for 7 to 8 percent of average 

Locational Based Marginal Price in 2013. Table 10 below, taken from NYISO’s 2013 

State of the Market report, shows the number of shortage events and how they affected 

annual average energy prices in NYISO.74 Transmission shortage constraints are

included in the table because they are addressed, priced, and affect the system in a way 

 73 There are more than 105,000 5-minute dispatch intervals in a year (8760 hours multiplied by 12 5-minute 

intervals per hour).

74 Potomac Economics, 2013 State of the Market Report for the New York ISO Markets at 66 (May 2014), 

available at

http://www.nyiso.com/public/webdocs/markets_operations/documents/Studies_and_Reports/Reports/Market_Monit

oring_Unit_Reports/2013/2013%20State%20of%20the%20Market%20Report.pdf.
35

that is quite similar to shortages of energy or operating reserves.75 Transmission 

constraints are priced based on redispatch costs, subject to an administrative price cap.

Table 10. NYISO Real-time Shortages and Price Impacts, 2013

Shortage Avg Shortage

Frequency Price

(# of Intervals) ($/MWh)

Impact on Zone Prices ($/MWh)

West Capital Hudson NYC LI

Operating Reserve Shortages

Ten-Minute East

Regulation

Other New York Control Area

Requirements

246 $445

1349 $165

87 $306

$1.04 $1.04 $1.04 $1.04

$1.46 $1.46 $1.46 $1.46 $1.46

$0.25 $0.25 $0.25 $0.25 $0.25

Transmission Shortages

Dunwoodie - Shore Road

E. Garden City - Valley Stream

Leeds-Pleasant Valley

Other Facilities

110 $974

297 $3,310

53 $2,664

363 $2,721

$1.02

$0.54

$0.03 $0.41 $0.49 $0.49

$1.01 $0.33 $0.29 $0.58 $0.57

Scarcity Pricing During DR Activation

New York Control Area

Southeast New York

124

148

 $0.39 $0.33 $0.27 $0.23 $0.24

 $0.47 $0.43 $0.44

Total $3.12 $3.44 $4.20 $4.49 $6.05

Potential Net Revenue ($/kW-year): $27 $30 $37 $39 $53

E. MISO

Though MISO only invokes shortage pricing when it is unable to meet its reserve 

requirements, it represents the relative opposite case in terms of the frequency of shortage 

pricing events. MISO experiences shortages relatively more times per year than the other 

RTOs and ISOs; however, there are still nominally few events and the events are shortlived and appear to have little effect on settlement prices. Table 1176 below shows the 

percentage of intervals during which MISO experienced a shortage of any kind from 

 75 NYISO’s external market monitor found many intervals when gas turbines were not dispatched to relieve 

a constraint even though their marginal cost was lower than the Transmission Shortage Cost of $4,000 per MWh and 

therefore supports the implementation of a graduated transmission demand curve that would better reflect the 

severity and value of transmission shortages. Id. at 66-67.

76 Data for Table 11 was compiled from 2009-2012 Independent Market Monitor’s State of the Market 

reports and Quarterly Reports for 2013. See, e.g., Potomac Economics, 2009 State of the Market Report for the 

Midwest ISO at 52, Figure 30, 54, available at

https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=17882.
36

2009 through summer 2013.77 As can be seen in the table, MISO saw few actual 

instances of shortages in absolute terms even though shortages were more frequent than

in the other RTOs and ISOs.

MISO’s Independent Market Monitor attributed the experience of 2009 to a combination 

of mild weather and a sizable capacity surplus.78 In addition, MISO reduced its 

Regulating Reserve minimum requirement in mid-2009. In 2010, MISO also saw 

infrequent shortages, again explained by the relative surplus of available capacity on the 

system, according to MISO’s Independent Market Monitor. However, MISO’s 

experiences in 2010 illustrate a common occurrence. There were 449 5-minute 

intervals79 where the system marginal price exceeded $175/MWh. On average these 

price spikes lasted only 1.6 intervals, or 9 minutes. The longest lasted eight intervals, or 

40 minutes.

 77 Data for MISO begins in January 2009 when its separate balancing areas were consolidated into one and 

MISO commenced its ancillary services market. Data for 2013 and 2014 are not yet available.

78 Potomac Economics, 2009 State of the Market Report for the Midwest ISO at 9, available at

https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=17882.

79 Because the State of the Market reports do not provide more detailed data, it is impossible to determine if 

these shortage events occurred consecutively or independently. For instance, if some of the 778 5-minute intervals 

in 2009 during which there was a Regulation shortage occurred consecutively (e.g., twelve in a row over the course 

of a settlement hour), it would have a larger impact on prices than if a shortage occurs during only one 5-minute 

interval of a settlement period. See id. at Figure 30. This figure shows both market clearing prices and percentage 

of intervals with shortages. 
37

Table 11. MISO Percent of 5-Minute Intervals With Shortage Pricesa

Year Regulation Spinning Res. Non-Spin Res.

2009 < 1% 1.4% > 0.0%

2010 < 0.2% 1.1% > 0.0%

2011 < 0.5% < 1.1%b > 0.0%

2012 < 0.5% < 1% < 0.5%

2013c < 0.2% < 1.6% > 0.0%

Notes:

a. The exact percentage of intervals with shortage pricing is not always reported. However, rough 

approximations can be made based on published tables and graphs.

b. The specific percentage of Spinning Reserve shortage intervals for 2011 was not reported by the 

Independent Market Monitor. However, it was reported to be lower than the rate in 2010.

c. January through August 2013 only.

In 2011, MISO saw much the same shortage activity as in 2010, with most shortages due 

to system ramping demand.80 High priced events (system marginal price greater than 

$175/MWh) lasted, on average, only 1.8 intervals.81 In 2012, MISO experienced 

unusually warm weather, leading to more expensive periods of shortages during the 

summer. This included all-time peaks in July and shortage prices for operating reserves 

between $1000/MWh and $2400/MWh. As can be seen in Table 11, the percentage of 5-

minute intervals with shortage pricing did not change; however, the actual prices 

reflected in market clearing prices did increase significantly. Finally, through August 

2013, MISO saw fewer shortages than 2012, attributable to lower load, according to the 

Independent Market Monitor, with these shortages resulting in smaller increases in the 

market clearing prices for Regulation, Spinning, and Supplemental Reserves. For 

instance, shortages of Regulation dropped from 55 in the summer of 2012, to only 37 in 

the summer of 2013. As a result, these shortages added only $0.52 to the price of 

Regulation in 2013, while they added $2.75 in the previous summer.82

Figure 8 below shows the events of April 1, 2013. On this day, MISO experienced an 

operating reserve shortage starting at interval 19:30 and lasting through interval 19:55

(i.e., hour ending 20:00 in Figure 8). Because of this shortage, the marginal energy 

component of LMP rose to $936, the market-wide Regulation market clearing price was 

$850, market-wide Spinning Reserve market clearing price was $783, and the marketwide Supplemental Reserve market clearing price was $720. The operating reserve 

 80 Potomac Economics, 2011 State of the Market Report for the MISO Electricity Markets at A-52 (June 

2012), available at https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=132800.

81 Id. A-45.

82 Potomac Economics, IMM Quarterly Report: Summer 2013 June-August at 7-8 (Sept. 2013), available 

at https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=160510.
38

deficiency worsened over the course of the hour, with the system operator eventually 

clearing less than 70 percent of the operating reserve requirement. Therefore, at 19:55 all 

LMPs and market clearing prices were increased by approximately $450. Even though 

this shortage occurred over only six intervals, it impacted the entire hour’s settlement 

values.83 The shortage event ended after the 19:55 interval and LMPs and marketclearing prices dropped immediately after, as seen in Figure 8.

Figure 8. MISO Operating Reserve Shortage Event, April 1, 2013.

VI. Concluding Remarks

Based on a review of the existing RTO and ISO shortage pricing rules and the impacts 

that actual shortage events have had over the last several years, Commission staff observe

that, while RTOs and ISOs all tend to define a shortage in the same way, the shortage 

pricing triggers differ across markets as do the energy and ancillary service prices that 

 83 MISO’s Operating Reserve requirements can change from hour-to-hour and were unavailable to staff at 

the time of writing. Thus it is not possible to determine directly from Figure 8 which Operating Reserve product(s) 

was deficient.
39

result from shortage events. Further, shortage pricing may only be reflected in the actual 

dispatch interval in which it occurs. For instance, if a shortage occurs only over the 

course of one or two 5-minute dispatch intervals, only the hourly price for those intervals 

will reflect the shortage event. To the extent settlements are based on hourly rather than 

5-minute or 15-minute prices, this may mute the intended price signal. In addition,

shortage events are rare in most RTOs and ISOs, sometimes not occurring at all over the 

course of a year. Given this, it is an open question whether there is a need to reduce the 

settlement interval to enhance the price signal associated with shortage pricing.

Some operator actions taken to avert a shortage are not reflected in market-clearing 

prices. In some RTOs and ISOs, for example, calling emergency demand response 

occurs only when prices hit a certain level, yet that strike price is not reflected in LMP in 

any way. In others, those actions do trigger shortage pricing. This raises the question of 

whether operator actions taken to avoid a shortage can or should be reflected in energy 

and ancillary services prices. 

Not all RTOs and ISOs invoke shortage pricing at the same time. Some RTOs and ISOs

invoke shortage pricing prior to an actual shortage event while others only invoke

shortage pricing when an actual shortage occurs. Is it economically efficient (either in 

the short-run or long-run) to invoke shortage pricing prior to an actual reserve 

deficiency? 

Because of the lag between price signals and import and export scheduling, it is difficult 

for market participants to efficiently schedule exports and imports to respond to shortage 

conditions, sometimes leading to inefficient behavior. Can either shortage pricing rules 

or inter-ISO energy market coordination protocols be modified to enhance the ability of 

neighboring regions to help alleviate shortage events? 
40

Appendix 1 California Independent System Operator Corporation (CAISO)

Shortage Definition

CAISO declares a shortage when supply is insufficient to meet any of the minimum 

procurement requirements for energy and Regulation-Up, Spinning Reserve, NonSpinning Reserve or Regulation-Down.

84 Though CAISO must meet the minimum 

requirements established by the Western Electricity Coordinating Council,85 it bases its 

shortage-trigger on its own criteria. CAISO-declared emergencies specifically related to 

deficiencies in Regulation Reserve or operating reserves depend on the severity of the 

deficiency, as described in Table 12 below.

Through the market co-optimization process, CAISO utilizes available resources to 

provide energy and operating reserves in the most efficient manner to clear the energy 

market, manage congestion, and procure required operating reserves. In so doing, 

CAISO honors submitted self-scheduled energy unless it is unable to satisfy 100 percent 

of the operating reserve requirements. In such cases, CAISO curtails all or a portion of a 

submitted self-schedule of energy to allow ancillary service-certified resources to be used 

to meet the operating reserve requirements.86

Shortage Pricing

When CAISO determines that there is or will be an operating reserve deficiency, the 

shortage pricing mechanism will be triggered and the market clearing prices for operating 

reserves will be set by the appropriate value in CAISO’s Scarcity Demand Curves, 

detailed in Table 12 below.

87 At the same time, energy prices may also rise due to the 

impact of shortage pricing, or may be unaffected by the rise in ancillary service prices, 

depending on the ability of the marginal unit to provide energy only or energy and 

operating reserves. If, during an operating reserve deficiency, the CAISO dispatches a 

generator which can provide either energy or operating reserve, to provide one additional 

MW of energy, the price of energy will include the opportunity cost of this unit not being 

 84 CAISO, Tariff, § 27.1.2.3. 

85 The Western Electricity Coordinating Council requires a balancing area authority to maintain 

contingency reserves equal to the greater of (i) the loss of the single greatest contingency or (ii) the sum of three 

percent of hourly integrated load (generation minus station service minus net actual interchange) plus three percent 

of hourly integrated generation (generation minus station power service). See Regional Reliability Standard BAL002-WECC-2 – Contingency Reserve, 145 FERC ¶ 61,141 (2013).

86 CAISO, Tariff, §§ 40.6.1 and 40.6.2

87 CAISO, Tariff, §27.1.2.3. CAISO is required to review the performance of the Scarcity Reserve Demand 

Curves every three years and assess whether changes are necessary. This can be done more frequently if CAISO 

determines more frequent reviews are appropriate. CAISO, Tariff, §27.1.2.
41

available to provide operating reserves, a more valuable product.88 On the other hand, if 

the capacity used to provide the incremental energy could not have been used to fulfill an 

operating reserve requirement, the price of energy will not be directly affected by 

shortage pricing.89 The energy and operating reserve co-optimization models will 

determine the energy LMP and operating reserve market-clearing prices simultaneously.

Table 12. CAISO Shortage Pricing

Reserve Product Reserve Product

Regulation-Up $200

Spinning Reserve $100

Non-Spinning Reserve

 Shortage > 210 MW $700

 210 MW > Shortage > 70 MW $600

 70 MW > Shortage $500

Maximum Upward Sum $1000 ($200+$100+$700)

Regulation-Down

 Shortage > 84 MW $700

 84 MW> Shortage > 32 MW $600

 32 MW > Shortage $500

Non-Spinning Reserve requirement cannot be met, Spinning and Regulating 

Reserve requirements can be met

If CAISO is short of Non-Spinning Reserve, the Non-Spinning Reserve market-clearing 

price will depend on the severity of the shortage. As shown in the table above, if there is 

a shortage less than 70 MW, then the Non-Spinning market-clearing price is set at $500. 

A shortage of between 70 MW and 210 MW would result in a shadow price of $600. 

And a shortage of greater than 210 MW would result in a shadow price of $700. The 

market-clearing prices for Spinning Reserve and Regulation-Up will be calculated as 

normal, accounting for the opportunity cost now associated with Non-Spinning Reserve. 

If the CAISO dispatches a generator in order to provide one additional MW of energy 

during shortage conditions, the price of Energy will include the opportunity cost (i.e. the 

 88 Locational marginal prices are designed to keep the resource indifferent between providing energy and 

ancillary services. In the case where the resource is capable of providing both energy and operating reserves, energy 

prices reflect the opportunity cost of not providing operating reserves.

89 It is possible that capacity used to provide energy could not have been used to provide operating reserves 

due to ramp rate requirements. In CAISO, for example, a generator receiving an award for Spinning Reserves must 

be able to ramp to its awarded quantity in 10 minutes.
42

$500, $600, or $700 shadow price) of the unit if it is capable of but prevented from 

providing Non-Spinning Reserve.

Spinning Reserve requirement cannot be met; Non-Spinning and Regulating 

Reserve requirements can be met

In this case, the shadow price associated with Spinning Reserve, as indicated by the table 

above, is $100. The market-clearing price for Regulation-Up would be established as 

normal, but would reflect the opportunity cost of $100 for not providing Spinning 

Reserve. The market-clearing price for Non-Spinning Reserve is set as normal with no 

shortage pricing impact.90 If CAISO dispatches a generator in order to provide one 

additional MW of energy during shortage conditions, the price of energy will include the 

opportunity cost (i.e., the $100 shadow price) of the unit if it is capable of but prevented 

from providing Regulation-Up.91

Regulation-Up Reserve requirement cannot be met; Non-Spinning and Spinning 

Reserve requirements can be met

Again, as indicated in the table above, the shadow price associated with Regulation-Up 

would be $200 when the operator is unable to meet the Regulation-Up minimum 

requirement. Market-clearing prices for Spinning Reserve and Non-Spinning Reserve

would be unaffected. If the CAISO dispatches a generator in order to provide one 

additional MW of energy during shortage conditions, the price of energy will include the 

opportunity cost (i.e., the $200 shadow price) of the unit if it is capable of but prevented 

from providing Regulation-Up.

 90 In a scenario where a more valuable reserve product is short but a less valuable one is not, the MCP of 

the less valuable product never reflects shortage conditions both because that product is not short and also because 

there is no opportunity cost to a resource providing that product, unlike if the resource were providing a more 

valuable product and there is a shortage of a less valuable product.

91 There are other combinations of shortages that are not described here. In these cases MCPs are additive. 

In the event that there is also a shortage of Non-Spinning Reserve greater 70 MW, between 70 MW and 210 MW, or 

greater than 210 MW, then a shadow price of $500, $600, or $700, respectively, would be added to the MCPs of 

Regulation-Up and Spinning Reserves. 

For example, if there is both a shortage of 60 MW of Non-Spinning Reserve to a shortage of Spinning 

Reserve and Regulation-Up reserve, the shadow price of Non-Spinning Reserve would be $500, and this would then 

be added to the shadow prices of Regulation-Up and Spinning Reserves. Therefore, the Regulation-Up MCP would 

be $800 ($300 + $500) and the Spinning Reserve MCP would be $600 ($100 + $500). A Shadow Price of $1000 for 

Regulation-Up is possible when there is a shortage of Regulation-Up and Spinning Reserve, as well as a NonSpinning Reserve shortage greater than 210 MW. When this occurs the shadow price associated with the shortage 

of each product is summed ($200+$100+$700) to determine the total Shadow Price. For example, the highest 

shadow price associated with Spinning Reserve is $800 ($100+$700).
43

Regulation-Up Reserve and Spinning Reserve requirements cannot be met; NonSpinning Reserve requirement can be met

In this scenario, because Regulation-Up is a more valuable product than Spinning 

Reserve and both are short, the market-clearing price associated with Regulation-up is 

equal to the sum of the $100 shadow price for Spinning Reserve and the $200 shadow 

price for Regulation-Up Reserve, or $300. The market-clearing price for Spinning 

Reserve is equal to $100. If the CAISO dispatches a generator in order to provide one 

additional MW of energy during shortage conditions, the price of Energy will include the 

opportunity cost (i.e., the $300 shadow price) of the unit if it is capable of but prevented 

from providing both Regulation-Up and Spinning Reserve. If the unit is only capable of 

providing Spinning Reserve, only the $100 shadow price will be added to the price on 

Energy.

Regulation-Down Reserve requirement cannot be met; all other reserve 

requirements can be met.

The shadow price associated with Regulation-Down depends on the severity of the 

shortage, as indicated by the table above. There will be no impact on the shadow price of 

energy because, in this case, the system operator needs downward ramping capability 

(i.e., for resources to provide less energy to the system) and therefore there is no 

opportunity cost to the resource for providing one additional unit of energy.
44

Appendix 2 ISO New England Inc. (ISO-NE)

Shortage Definition

ISO-NE defines an operating reserve shortage as a situation in which there is insufficient 

operating reserve available to meet the operating reserve requirements for the system or 

any Reserve Zone at a redispatch cost equal to or less than that specified by the Reserve 

Constraint Penalty Factors.92 An operating reserve shortage is the trigger for a shortage 

event, which is defined as “any period of thirty or more contiguous minutes of systemwide Reserve Constraint Penalty Factor activation, defined as being short of Operating 

Reserves.”93 While the Reserve Constraint Penalty Factor -based administrative shortage 

pricing only applies to real-time prices and operations, ISO-NE has several other tools at 

its disposal to address actual or anticipated operating reserve shortages.

After ISO-NE has run its Day-Ahead market, which clears resources against as-bid load 

and reserve requirements, ISO-NE runs a Reserve Adequacy Analysis which attempts to 

ensure enough resources have been committed during every hour to meet its forecasted 

load plus forecasted reserve requirements for the remaining hours of the current day and 

the next day. If needed, ISO-NE will commit additional resources in the Reserve 

Adequacy Analysis over and above what cleared in the day-ahead market to meet its 

forecasted real-time energy and operating reserve requirements. However, sufficient 

resources may not always be available in the Reserve Adequacy Analysis to meet the

day-ahead forecasted needs. If the sum of day-ahead fixed demand bids and fixed 

external transaction sales cannot be satisfied with the sum of all scheduled external 

transaction purchases, cleared increment offers, and available generation at its economic 

maximum limit, ISO-NE’s software will issue an Emergency Condition warning message 

due to a shortage of economic supply in the day-ahead energy market. In order to 

achieve power balance in that situation, all fixed external transaction sales are considered 

to be dispatchable at $1,000/MWh and ISO-NE will reduce or eliminate scheduled 

energy deliveries associated with any remaining price-sensitive demand bids (including 

external transaction sales) and decrement (virtual) bids, from lowest price to highest until 

power balance is achieved.94

Third, ISO-NE has a set of operating procedures to deal with capacity deficiencies and 

other abnormal system conditions. ISO-NE’s primary operating procedure for addressing 

 92 ISO-NE, Tariff, § III.2.7A.

93 ISO-NE, Tariff, § III.13.7.1.1.1.

94 ISO-NE, Tariff, § III.2.6(b). If those steps are insufficient, ISO-NE will reduce all remaining fixed 

demand bids proportionately (by ratio of load MW) until balance is achieved and will set LMP values equal to the 

highest offer price of all on-line generation, increment offers or external transaction purchases, or the price from the 

previous step, whichever is higher.
45

capacity deficiencies is Operating Procedure No. 4 which establishes criteria and guides 

for actions during existing or anticipated capacity deficiencies. While there are 10 

numbered actions described in Operating Procedure No. 4, ISO-NE does not have to 

follow a set order; it can take whatever actions it feels will best aid reliability. Operating 

Procedure No. 4actions include the following groups of actions: 1) inform all resources 

with a capacity supply obligation to prepare to provide all associated capability and begin 

to allow depletion of Thirty-Minute Operating Reserve; 2) dispatch real-time demand 

response resources; 3) request voluntary load curtailment of market participants’ facilities 

in the New England Reliability Coordination Area/Balancing Area Authority; 4) 

implement a power watch ; 5) arrange to purchase available emergency capacity and 

energy, or energy only, from market participants or neighboring Reliability Coordination 

Areas/Balancing Area Authorities; 6) implement a 10-minute lead time voltage reduction 

of 5 percent of normal operating voltage, dispatch Real-Time Emergency Generation 

Resources in the amount and location required, and alert NYISO that sharing of reserves 

within the Northeast Power Coordinating Council may be required; 7) request that 

generation without a Capacity Supply Obligation voluntarily provide energy for 

reliability purposes; 8) implement a short lead-time (less than 10 minutes) voltage 

reduction of 5 percent of normal operating voltage; 9) request all of the customer 

generation not contractually available to market participants and request voluntary load 

curtailment by large industrial and commercial customers; 10) initiate radio and 

television appeals for voluntary load curtailment; and 11) request that each New England 

state governor reinforce power warning appeals. When the system conditions have 

improved sufficiently, ISO-NE will cancel these actions, though the order of cancellation 

may be different from the order of initiation.95

Shortage Pricing

ISO-NE’s administrative shortage pricing mechanism is triggered whenever there is 

insufficient operating reserve available to meet the operating reserve requirements for the 

system or any reserve zone, or sufficient operating reserve is not available at a redispatch 

cost equal to or less than that specified by the reserve constraint penalty factors. The 

reserve constraint penalty factors thus serve a dual purpose – they allow ISO-NE’s 

software to achieve a feasible solution when there are insufficient reserves from actual 

resources96 and they set a price ceiling limiting the maximum cost incurred to redispatch 

resources to provide reserves.97 Reserve constraint penalty factors may be reflected in 

 95 ISO-NE OP-4 Manual at 4-7.

96 In this case, reserve constraint penalty factors are effectively a “virtual” supply resource supplying 

reserves at the reserve constraint penalty factor price level.

97 In this instance, the “shortage” will be economic, not physical, since additional reserves could have been 

created at a price higher than the reserve constraint penalty factor. This additional redispatch, however, would be 

costly both in dollars and in the amount of time it would take ISO-NE’s software to find a feasible solution to its 

dispatch problem.
46

energy prices. ISO-NE is unusual among the RTOs, as it invokes emergency procedures 

(Operating Procedure No. 4) after it has invoked shortage pricing.

ISO-NE procures several categories of operating reserves to allow it to meet North 

American Electric Reliability Corporation and Northeast Power Coordinating Council 

reliability standards. At a minimum, to ensure reliable operations, ISO-NE must procure 

sufficient resources to meet requirements for: (i) Ten-Minute Reserve, which comprises

Ten-Minute Spinning Reserve and Ten-Minute Non-Spinning Reserve; (ii) Total ThirtyMinute Operating Reserve, which comprises Ten-Minute Spinning Reserve, Ten-Minute 

Non-Spinning Reserve, and Thirty-Minute Operating Reserve; and, (iii) Replacement 

Reserve. ISO-NE has explicit requirements at the system level for Ten-Minute Spinning 

Reserve, Total Ten-Minute Reserve, and Total Thirty-Minute Operating Reserves, in 

addition to local requirements for Total Thirty-Minute Operating Reserve for the 

NEMA/Boston, Southwest Connecticut, and Connecticut zones.

In ISO-NE, reserves are priced in real-time based on the opportunity cost of providing 

reserves. Thus, resources do not explicitly offer reserves at specific prices, rather they 

offer to supply energy and/or reserves, and provide associated offer prices, and ISO-NE 

determines the optimal assignment of resources between supplying energy and reserves 

as well as energy and reserve prices that are consistent with that dispatch. In most 

intervals, reserve prices are zero since there are sufficient reserves available from offline 

capacity capable of providing operating reserves and unloaded online capacity such that 

there is no tradeoff between supplying energy and supplying reserves.

When there is a tradeoff between energy and reserves, the maximum redispatch cost ISONE will incur to create reserves is limited to the reserve constraint penalty factors, 

outlined in Table 13 below. The reserve constraint penalty factors also represent a price 

ceiling as to what ISO-NE will pay for reserves when it is physically short of reserves.

Table 13. ISO-NE Reserve Constraint Penalty Factors

Requirement Price

Local Thirty-Minute Operating Reserve $250 

System Thirty-Minute Operating Reserve $500 

System Ten-Minute Non-Spinning Reserve $850 

System Ten-Minute Spinning Reserve $50 

Replacement Reserve $250 

Replacement Reserve
47

ISO-NE recently implemented a Replacement Reserve requirement of 160 MW in the 

summer and 180 MW in the winter to help resolve conditions where additional 

commitments are necessary to protect the system against normal system uncertainties and 

to avoid the need for emergency actions due to events such as load forecast errors, 

generator contingencies and reductions, and resource unavailability. ISO-NE will 

redispatch the system (but not take emergency actions) to maintain Replacement Reserve, 

the Replacement Reserve price, including the reserve constraint penalty factor.

Local Thirty-Minute Operating Reserve

If ISO-NE is short of Thirty-Minute Operating Reserve in any of the three Reserve 

Zones, the price for Local Thirty-Minute Operating Reserve in that zone will be 

$250/MWh.

System Thirty-Minute Operating Reserve

If ISO-NE is short of Total Thirty-Minute Operating Reserve but not Ten-Minute

Reserve, the price for Thirty-Minute Operating Reserve will be $500/MWh, and the price 

for Ten-Minute Operating Reserve prices will be at least at that level, if not higher. 

Energy prices will also reflect this reserve constraint penalty factor unless the system is 

purely ramp-constrained and there is no tradeoff between supplying energy or reserves.98

System Ten-Minute Non-Spinning Reserve

The reserve constraint penalty factor for Ten-Minute Operating Reserve is either 

$850/MWh or $1,350/MWh depending on whether the system is short of Total ThirtyMinute Operating Reserve or just short of Ten-Minute Non-Spinning Reserve. Since 

ISO-NE has a Total Thirty-Minute Operating Reserve requirement, rather than an explicit 

Thirty-Minute Operating Reserve Requirement, even if ISO-NE is short of Ten-Minute

Operating Reserve, it will still attempt to procure additional Thirty-Minute Operating 

Reserve, if available, to meet its Total Thirty-Minute Operating Reserve Requirement.

System Ten-Minute Spinning Reserve

If ISO-NE is carrying sufficient Total Ten-Minute Reserve and Total Thirty-Minute 

Operating Reserve, but less than its desired amount of Ten-Minute Spinning Reserve,99

ISO-NE will attempt to create additional Ten-Minute Spinning Reserve subject to a price 

ceiling of $50/MWh. When the Ten-Minute Spinning Reserve constraint is binding (e.g. 

 98 For the sake of simplicity, this example ignores the possibility of combinations of local reserve 

deficiencies combined with transmission constraints that can result in different pricing outcomes.

99 ISO-NE typically carries at least half of its Total Ten-Minute Reserve Requirement as Ten-Minute 

Spinning Reserve, though that figure can go as low as twenty five percent depending on system conditions. 
48

there is a positive price for Ten-Minute Spinning Reserve even though ISO-NE is 

meeting its Total Ten-Minute Reserve and Total Thirty-Minute Operating Reserve 

requirements), this additional cost will typically be reflected in the system energy price 

(LMP).

Regulation Reserve Shortage

ISO-NE’s Regulation Capacity penalty factor is more complicated than the reserve 

constraint penalty factors used for other Operating Reserve products. For Regulation 

Capacity, there are two possible pricing impacts ($/MW): (a) if the energy component of 

the real-time locational marginal price is greater than or equal to $100/MWh, the penalty 

factor is $100/MW plus the energy component of the real-time locational marginal price 

for each megawatt of Regulation Capacity shortfall, and (b) if the energy component of 

the real-time locational marginal price is less than $100/MWh, the penalty factor is the 

maximum of either zero or $100 plus the energy component of the real-time locational 

marginal price for each megawatt of Regulation Capacity shortfall. The Regulation 

Mileage penalty factor is $10/MW for each megawatt of Regulation Service shortfall; in 

addition, selection will consider opportunity cost sensitivities associated with large 

changes in the estimated opportunity cost of a Resource due to the shape of the resource’s 

supply offer price curve.

Energy Shortage

The energy offer cap is $1,000/MWh, so in a shortage energy prices should reach that 

level,100 and may also reflect the reserve constraint penalty factors for shortages of 

System Ten-Minute Reserve and System Thirty-Minute Operating Reserve if those 

products are short as well, so (the energy component of) energy prices could reach 

$2,350/MWh during an energy shortage ($1000 + $850 + $500).

 100 The energy component of LMP should reach $1,000/MWh. Losses and congestion energy prices may 

lead to LMP at any location exceeding or falling short of $1,000/MWh.
49

Appendix 3 Midcontinent Independent System Operator, Inc. (MISO)

Shortage Definition

MISO defines a shortage as any time the sum of demand bids, fixed export schedules, 

system losses, and operating reserve requirements in the day-ahead energy and ancillary 

services market cannot be met by the maximum supply level of all available nonemergency resources, import schedules, and virtual supply offers. Shortages can occur 

either on a MISO-wide basis or a zonal basis.101

If MISO anticipates or is experiencing a shortage of operating reserves in the day-ahead 

market, it will commit generation resources up to the emergency limits of market 

participants’ offers to supply, demand response resources type II, and external 

asynchronous resources.102 MISO will also commit generation resources, Demand 

Response Resources Type I, and Demand Response Resources Type II that are 

designated as emergency-only to levels necessary to relieve the shortage in an economic 

manner.103 If operating reserves are depleted and energy demand cannot be met, MISO

will then curtail fixed demand bids and fixed export schedules.

In the real-time market, MISO’s rules governing a shortage are similar to those followed 

in the day-ahead period. In the case of a shortage of operating reserve, MISO will take 

the additional step of curtailing exports schedules in amounts sufficient to relieve the 

shortage in an economic manner.104 If these actions are not sufficient to relieve the 

shortage, MISO must then call an Emergency Energy Alert 1 (EEA1). If MISO deems 

the shortage to be significant, it can declare Emergency Energy Alert 2 (EEA2).

105 

Declaring EEA2 provides MISO with further steps it may take to mitigate any shortage, 

including: (1) directing load serving entities to curtail appropriate amounts of Load 

Modifying Resources (a type of demand response resource); (2) dispatching emergency 

demand response based on submitted offers; (3) purchasing emergency energy; (4) 

 101 MISO’s current seven reserve zones are or incorporate parts of (approximately) Indiana; Illinois, 

Missouri, Iowa, Arkansas, Louisiana, and Mississippi; the lower peninsula of Michigan; Wisconsin and the upper 

peninsula of Michigan; Iowa, Minnesota, and North Dakota; southeast Louisiana; and, Texas.

102 This does not include resources committed to provide Regulation service, which must be kept at a setpoint below their maximum in order to continue to provide Regulation service.

103 MISO, Tariff, Module C Energy and Operating Reserves, at § 39.2.10 (Shortage Conditions in the DayAhead Energy and Operating Reserve Markets).

104 MISO, Tariff, Module C Energy and Operating Reserves, at § 40.2.20 (Capacity Shortage in the RealTime Energy and Operating Reserve Market).

105 Id.
50

issuing a public appeal to reduce demand; and, (5) directing local Balancing Authorities 

to implement a voltage reduction.106

Shortage Pricing

When a shortage of operating reserves occurs, whether MISO-wide or on a zonal basis, 

and none of the steps described above alleviate the problem, MISO’s tariff states that 

energy locational marginal prices and operating reserve market-clearing prices are 

determined using the Security-Constrained Economic Dispatch algorithm which 

incorporates shortage pricing based on Operating Reserve Demand Curves, Regulation 

and Spinning Reserve Demand Curves, and Regulating Reserve Demand Curves.107 

These demand curves apply to three different (worsening) scenarios that can occur alone 

or in combination. MISO defines four products that it, as the system operator, procures: 

locational energy, Regulating Reserve, Spinning Reserve, and Supplemental Reserve.108 

Regulating Reserve may substitute for Spinning Reserve because it is a higher quality 

product, but not vice-versa. Similarly, Spinning Reserve may substitute for Supplemental

Reserve, but not vice-versa. 109 

MISO uses a combination of negatively-sloped demand curves and administrative prices 

to establish the energy LMP and operating reserve market-clearing prices, as summarized 

in Table 14 below. Many of these hinge on MISO’s Value of Lost Load, the estimated 

value that consumers put on losing power, and the probability of losing load if a shortage 

in Operating Reserve is exacerbated by a further contingency. Value of Lost Load in 

MISO is currently set at $3500/MWh.

Operating Reserve Demand Curve (i.e. the combination of all reserve products)

If MISO experiences a region-wide shortage of the Operating Reserve requirement, it

will set the market-clearing price for all operating reserves at a level dependent on the 

degree of shortage.110 The market-clearing price starts at $200/MWh if MISO is able to 

clear 96 percent or more of the requirement. If MISO is able to clear less than 4 percent 

 106 MISO, Market Capacity Emergency Procedures RTO-EOP-002-r17 (effective June 1, 2014), available 

at https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=177019.

107 MISO, Tariff, Module C Energy and Operating Reserves, at § 39.2.10 (Shortage Conditions in the DayAhead Energy and Operating Reserve Markets).

108 MISO, Business Practice Manual 002 Energy and Operating Reserve Markets at 43. 

109 Id. at 46, 190. 

110 Operating Reserve demand curves for zonal shortages are similar, with slight changes in the exact 

numbers.
51

of the requirement, the market-clearing price is set at the Value of Lost Load, or 

$3500/MWh, minus the maximum market-wide Regulating Reserve demand curve price 

for that month. For any amount cleared at least 4 percent but less than 96 percent then 

the market-clearing price is a function of the product of Value of Lost Load and the 

probability that there will be a loss of load due to single forced resource outage of 100 

MW or greater.

When MISO experiences a zonal shortage of the operating reserves requirement, if the 

market operator is able to clear 80 percent or more of the requirement, the marketclearing prices for all operating reserve products is set equal to $200/MWh. If MISO is 

able to clear less than 10 percent of the requirement, the market-clearing price is set equal 

to the Value of Lost Load minus the reserve zone’s maximum Regulating Reserve

Demand Curve Scarcity Price. For any amount cleared at least 10 percent but less than 

80 percent of the requirement, the market-clearing price is set equal to the sum of the 

Energy Offer Price Cap ($1000/MWh) and the Contingency Reserve Offer Price Cap

($100). 

Table 14. MISO Shortage Pricing

Product Shortage Price

MISO-wide Operating Reserve Min. $200/MWh to Max. VOLL ($3500/MWh) 

minus Regulating Reserve demand curve value, 

depending on level of shortage.

MISO-wide Spinning and Regulating Reserves Min. $65/MWh to Max. $98/MWh depending on 

level of shortage.

MISO-wide Regulating Reserve Max. of (i) Contingency Reserve Offer Cap and 

(ii) Peaker Commitment Cost for one hour.

MISO-wide Energy LMP set to Value of Lost Load ($3500/MWh).

Reserve Zone Operating Reserve Min. $200/Mwh to Max. VOLL ($3500/MWh) 

minus maximum Regulating Reserve Demand 

Curve Scarcity Price.

Reserve Zone Spinning and Regulating 

Reserves

$65/MWh if > 90% of requirement. $98/Mwh if 

< 90% of requirement.

Reserve Zone Regulating Reserve Max. of (i) Contingency Reserve Offer Cap and 

(ii) Peaker Commitment Cost for one hour.

Regulating and Spinning Reserves Demand Curve

If MISO experiences a region-wide or zonal shortage of Regulation and Spinning 

Reserves, it will set the market-clearing prices for both Spinning Reserve and Regulating 

Reserve at a level dependent on the degree of shortage. The market-clearing price starts 

at $65/MWh if MISO is able to clear more than 90 percent of the requirement. If MISO
52

is able to clear less than 90 percent of the requirement, the market-clearing price is set at 

$98/MWh.111 There is no impact on the market-clearing price for Supplemental Reserve.

Regulating Reserve shortage

If MISO experiences a region-wide or zonal shortage of Regulating Reserve, the marketclearing price for Regulating Reserve will be set equal to the maximum of either the 

Contingency Reserve Offer Cap or the average cost per MWh of committing and running 

a peaker unit for one hour. MISO defines three different types of Regulating Reserve

shortages: (i) a shortage of Regulating Reserve in the upward direction; (ii) a shortage of 

Regulating Reserve in the downward direction; and (iii) a shortage of resources with 

Regulation Capability. In the first case, a Regulation Up shortage, shortage prices will 

impact energy LMP but not Spinning or Supplemental Reserve market-clearing prices. 

In the case of a Regulation Down shortage, energy LMP will be effected negatively and 

there is no impact on Spinning or Supplemental Reserve market-clearing prices. If there 

is a shortage of regulation-qualified resources, because this is not considered a capacity 

shortage, it only impacts the Regulating Reserve market-clearing price.

Energy Shortage

In the event that operating reserves are depleted and energy demand cannot be met, all 

energy and operating reserves will be priced at the Value of Lost Load, currently set at 

$3500/MWh.112

 111 MISO, Tariff, Schedule 28 (Operating Reserve Demand Curves). Schedule 28 specifies these price 

levels for quantities less than 90 percent and greater than 90 percent (omitting 90 percent exactly).

112 MISO, Tariff, Module C Energy and Operating Reserves at § 39.2.10 (Shortage Conditions in the DayAhead Energy and Operating Reserve Markets).
53

Appendix 4 New York Independent System Operator, Inc. (NYISO)

Shortage Definition

NYISO has a comprehensive set of pricing rules during shortage conditions when NYISO 

has run short of Regulation, Ten-Minute Reserve, Thirty-Minute Reserve, and/or

Spinning Reserve for the entire ISO, or for either of two defined subzones. NYISO also 

has rules and procedures to address and avoid shortages before they occur in real-time. 

NYISO denotes the entire ISO as the New York Control Area; the subzones are East of 

Central East, which includes New York City and Long Island, and Long Island (LI), 

which is a separate subzone within East of Central East.

If NYISO’s Security Constrained Unit Commitment program indicates that NYISO will 

be short of operating reserves in the Day-Ahead market, or if Security Constrained Unit 

Commitment has already been completed and conditions then change such that the

revised day-ahead forecast indicates there will be an operating reserve deficiency, 

NYISO will take the following actions as needed to relieve the deficiency: (i) 

commit/schedule additional generation from the set of unaccepted/uncommitted bids; (ii) 

request additional generation bids from market participants; (iii) count the energy 

associated with external resources with a New York Control Area Installed Capacity 

commitment as well as external energy sales by New York Control Area Installed 

Capacity resources as operating reserves; (iv) inform market participants that their 

generation may be dispatched to Upper Operating Limit Emergency levels the following 

day; and, (v) notify the appropriate market participants to prepare to make Special Case 

Resources and Emergency Demand Response Program resources available for the next 

day. In addition, should these actions be insufficient, NYISO may request that 

Transmission Owners (a) notify interruptible customers to make interruptible load 

available for curtailment for the next day; (b) prepare to initiate procedures to reduce 

voltage by 5 percent if they have Manual Voltage Reduction equipment; (c) contact large 

commercial and industrial customers to voluntarily curtail load; (d) make public appeals; 

and, (e) count load reductions that can be can be implemented within 10 minutes using 

Quick Response Voltage Reduction as NYISO Ten-Minute Reserve.113

If there is still a shortage in real-time, NYISO will attempt to preserve Ten-Minute

Synchronized Reserve by converting Ten- and Thirty-Minute Non-Synchronized 

Reserves to Ten-Minute Synchronized Reserve or energy, activating the use of generating 

resources’ Upper Operating Limit Emergency limits, curtailing exports, counting load 

reduction available from Quick Response Voltage Reduction as Ten-Minute Reserve, and 

purchasing emergency energy from resources outside of NYISO.

Shortage Pricing

 113 NYISO, Manual 15 Emergency Operations Manual, at 4-5 to 4-8.
54

Whatever actions the NYISO operator takes to avert an operating reserve deficiency, 

NYISO’s shortage pricing is triggered whenever NYISO runs short of Regulation, TenMinute Reserve, Thirty-Minute Reserve, or Spinning Reserve for the entire ISO or for its 

two defined subzones. NYISO’s administrative shortage prices are shown in Table 15

below.

Table 15. NYISO Shortage Pricing114

Service Shortfall

New 

York 

Control 

Area

East of CE

(New York 

City or Long 

Island) 

Long 

Island

only

Regulation 0 to 25 80 n/a n/a

> 25 to 80 180 n/a n/a

> 80 400 n/a n/a

Thirty-Minute 0 to 200 50 25 25

> 200 to 400 100 25 25

> 400 200 25 25

Total Ten-Minute > 0 450 500 25

Total Spinning > 0 500 25 25

If a shortage occurs in the New York Control Area, the market-clearing price is set as 

indicated in the “New York Control Area” column. For instance, if the New York 

Control Area is more than 400 MW deficient in Thirty-Minute Reserve, the marketclearing price for Thirty-Minute Reserve would be $200/MWh. In addition, the values 

are additive when there is a deficiency of multiple products: if the New York Control 

Area is short of both Thirty-Minute and Ten-Minute Reserve, that would result in a 

market-clearing price for Thirty-Minute Reserve in the New York Control Area of 

$200/MWh (assuming it is deficient more than 400 MW) and the market-clearing price 

for Ten-Minute Reserve would be at least $500/MWh (equal to the shortage price for 

Ten-Minute Reserve plus the shortage price for being deficient less than 200 MW of 

Thirty-Minute Reserve) to a maximum of $650/MWh (equal to the shortage price for 

Ten-Minute Reserve plus the shortage price for being deficient more than 400 MW of 

Thirty-Minute Reserve).

Similarly, if the shortage occurs just in the East of Central East area or just in the Long 

Island area the market-clearing prices are set as indicated in the East of Central East

 114 NYISO, Market Services Tariff, §§ 15.3.7, 15.4.7.
55

column or the “Long Island” column, respectively. Prices in each subzone will also 

reflect administrative price in larger zones. For instance, prices in the East of Central 

East area, which is nested within the New York Control Area zone, will also reflect 

administrative prices in the New York Control Area. Prices in Long Island, which is 

nested in both the East of Central East and the New York Control Area zones, will reflect 

administrative prices in East of Central East and the New York Control Area, as 

applicable to the situation. 

Regulation

Regulation in NYISO is procured region-wide and shortage prices are defined by a 

stepped demand curve: Regulation prices will be $80/MWh if there is a shortfall of 

between 0 and 25 MW, $180/MWh for a shortfall greater than 25 MW up to 80 MW, 

and $400/MWh for a shortage greater than 80 MW.

Thirty-Minute Operating Reserve

Shortages of Thirty-Minute Operating Reserve are also subject to a stepped demand 

curve: $50 for 0 to 200 MW, $100 for greater than 200 MW up to 400 MW and 

$200/MWh if the shortage is greater than 400 MW. If the shortage is in the East of 

Central East zone, prices are $25/MWh higher in every case, and are $50/MWh ($25 plus 

$25) higher if the shortage is in the Long Island zone.

Total Ten-Minute Reserve

Any shortage of Total Ten-Minute Reserve is priced at $450/MWh in the New York 

Control Area (rest of state) zone, an additional $500/MWh if East of Central East is also 

short of Ten-Minute Reserve ($950/MWh) and an additional $25/MWh is Long Island if

short as well ($975/MWh).

Spinning Reserve

Any shortage of Spinning Reserve is priced at $500/MWh in the New York Control Area

(rest of state) zone, an additional $25/MWh if East of Central East is also short of TenMinute Reserves ($525/MWh) and an additional $25/MWh is Long Island if short as well 

($550/MWh).

Energy Shortage

NYISO also fully co-optimizes energy and reserves. The energy offer cap is 

$1,000/MWh, so in a shortage energy prices should reach that level, and may also rise to 

higher price levels to reflect the additional shortage prices for Thirty-Minute Operating 

Reserve, Ten-Minute Operating Reserve, Spinning Reserve, and any locational shortage 
56

price. Thus, a shortage of energy on Long Island could yield energy prices of up to 

$2775/MWh115 if the New York Control Area, East of Central East, and Long Island are 

all also short of Ten-Minute Reserve, Total Operating Reserve, and Total Spinning 

Reserve.

 115 $2775=$1000 (energy) + $250 (Thirty-Minute Reserve system-wide and zonal) + $975 (Ten-Minute 

Reserve system-wide and zonal) + $550 (Spinning system-wide and zonal).
57

Appendix 5 PJM Interconnection, L.L.C. (PJM)

Shortage Definition

PJM defines a reserve shortage as a situation in which the dispatch software is unable to 

obtain the required reserves in a particular reserve region at a price less than the reserve 

shortage penalty factor. Shortage pricing is based on a forecast of a shortage in the realtime commitment period so it is possible that shortage pricing might occur without an 

actual shortage happening. 

If, after real-time commitment, the system operator still anticipates a shortage, the 

options that the dispatcher can use to avert a shortage are limited. The dispatcher can 

issue a warning to units to be aware of the impending shortage and to PJM management 

who can then issue messages to the public to conserve energy. After a shortage begins, 

the dispatcher can invoke the emergency range on generators which can give some more 

capacity. Also, after a shortage begins, the dispatcher can invoke region-wide emergency 

demand response.

Load shedding and voltage drops at the nodal level results in shortage pricing equivalent 

to a Synchronous Reserve shortage at that node.116

Shortage Pricing

PJM invokes shortage pricing whenever the dispatch software cannot meet the primary 

reserve requirement. The primary reserve requirement is the sum of the Synchronous

Reserve requirement and the Non-Synchronous Reserve requirement. An additional 

shortage price is added when the Synchronous Reserve requirement cannot be satisfied. 

These are the only shortage prices in PJM.

As in the other RTOs, the energy LMP and operating reserve market-clearing prices 

would also account for the opportunity cost of missing out on an operating reserve price 

equal to the relevant shortage prices. 

 116 PJM, Manual 11 Energy & Ancillary Services Market Operations. 
58

Table 16. PJM Shortage Pricing

Product Shortage Price/Penalty Factor

Synchronous Reserve $550/MWh

Non-Synchronous 

Reserve

$550/MWh

Regulation n/a

Voltage Drop $2100 = $1000/MWh + Synchronous and NonSynchronous penalties ($1100)

Energy $2100 = $1000/MWh + Synchronous and NonSynchronous penalties ($1100)

Primary Reserve Demand Curve (i.e. Non-Synchronous Reserve and/or 

Synchronous Reserve requirements cannot be met)

The Primary Reserve demand curve accounts for PJM’s ability to meet both its NonSynchronous Reserve and Synchronous Reserve requirements and is a stepped demand 

curve with two vertical jumps. The first step is at a quantity equal to the sum of the NonSynchronous Reserve requirement plus the Synchronous Reserve requirement, where the 

demand curve rises to the Non-Synchronous Reserve penalty factor, currently set at

$550/MWh. The second step is at the Synchronous Reserve requirement (i.e., if this 

point is passed, PJM has procured no Non-Synchronous Reserve and cannot meet the 

Synchronous Reserve requirement either) and the demand curve rises to the sum of the 

Synchronous Reserve penalty factor, also currently $550/MWh, and the Primary Reserve 

penalty factor, or $1100/MWh.

Regulating Reserve Demand

If PJM runs short of ordinary Regulation Reserve, it uses Synchronous Reserve and treats

them as regulation resources to the best of their ability. PJM does not have a Regulation 

Reserve shortage price. Using Synchronous Reserve as Regulation is considered a 

“spinning event” in PJM but these events are not shortage events and typically do not 

result in high Synchronous Reserve prices.

Spinning events in PJM can occur when there is a generator outage, a transmission 

outage, or a shortage of Regulation Reserve. There were 16 spinning events in PJM in 

2013. Most of these events were very brief: eight of these were 10 minutes or less in 

duration. The external market monitor did not say what caused each spinning event but 

did say the longest spinning event, which occurred on September 10, 2013, and lasted 68 

minutes, was caused by a shortage of Regulation Reserve. The Spinning Reserve price 
59

during this event was $0/MWh; therefore, a shortage in Regulation Reserve has no direct 

relationship to the Spinning Reserve price.117

Energy Shortage or Voltage drop

If PJM institutes a voltage drop or is forced to shed load, the penalty factor in the affected 

area will be the same as a Synchronous Reserve shortage and would currently be 

$800/MWh. Emergency demand response, when called upon, leads to the highest 

possible energy price, which is currently set at $2100 per MWh.118

 117 Monitoring Analytics, LLC, State of the Market for PJM at 313 (Mar. 13, 2014), available at

http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2013/2013-som-pjm-volume1.pdf.

118 See, e.g., PJM, Operating Agreement, Sch. 1, § 3.2.3A.001(c).
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Appendix 6 Southwest Power Pool, Inc. (SPP)

Shortage Definition

SPP defines shortage prices as the market-clearing prices and locational market price 

levels when there is insufficient operating reserve available to meet the operating reserve 

requirements.

119 SPP further defines multiple scenarios under which a shortage can 

occur. 

SPP defines its operating reserves as Regulation-Up, Regulation-Down, and Contingency 

Reserve (which includes Spinning Reserve and Supplemental Reserve). SPP uses the 

term operating reserve to refer to these as a group. Finally, SPP also defines Ready 

Reserve, a reserve product seemingly less valuable than spinning reserve, possibly the 

same as Supplemental Reserve.

SPP’s tariff outlines steps that must be taken in order to avert a shortage. Specifically, 

SPP’s tariff specifies that, in order, non-firm fixed exports will be curtailed, and, if 

necessary, resources will be committed to their maximum generating limits and/or 

emergency-only resources will be committed. These steps occur automatically within the 

day-ahead security-constrained unit dispatch. If these steps do not resolve the problem, 

the system operator may manually commit emergency-only designated units.120

Shortage Pricing

SPP applies values derived from various shortage pricing schedules to set marketclearing prices during a shortage of operating reserves, as shown in Table 17. These 

apply in both the day-ahead and real-time markets, and also apply on both a system-wide 

and a reserve zone basis. Shortage pricing values are based on defined offer caps for 

energy and the operating reserve products, depending on the specific shortage. If an 

operating reserve shortage is caused by insufficient ramping ability, SPP does not 

institute shortage pricing.121

 119 SPP, Tariff, attach. AE, §1.1 Definitions S. The tariff provisions described here have only been 

effective since March 1, 2014. Prior to this time SPP was a real-time-only balancing market comprising 16 separate 

Balancing Authority Areas. Each Balancing Authority Area was responsible for maintaining reserves.

120 SPP, Tariff, attach. AE, § 5.1.2(1). It is possible for a resource owner to choose an emergency-only 

dispatch status that allows the system operator to commit the resource only to alleviate an anticipated emergency 

condition or local reliability issue. SPP Tariff, attach. AE, § 4.1(10).

121 See SPP, Tariff, attach. AE, § 8.3.4.2.
61

Table 17. SPP System-Wide Shortage Pricing

Requirement Market-Clearing Price

Supplemental Reserve

$1100 + Zonal Regulation-Up plus 

Contingency Reserve Shadow Price

Spinning Reserve

$200 + Supplemental Reserve MCP + Zonal 

Regulation-Up plus Contingency Reserve 

Shadow Price

Regulation-Up Reserve

$600 + Spinning Reserve MCP + Zonal 

Regulation-Up Shadow Price 

Regulation-Down Reserve $600 

Energy

LMP accounts for all Shortage-Priced MCPs 

with a maximum = $50,000. 

System-wide Contingency Reserve requirement cannot be met; Regulation-Up and 

Regulation-Down Reserve requirements can be met and zonal requirements can be 

met122

In the event that SPP cannot meet its contingency reserve requirement, the marketclearing price for Supplemental Reserve is set equal to the sum of the shortage prices of 

the system-wide Regulation-Up plus Contingency Reserve constraint and the zonal 

Regulation-Up plus Contingency Reserve constraint. The system-wide shortage price for 

the Regulation-Up plus Contingency Reserve constraint is set equal to the Operating 

Reserve Demand Curve, which is defined as the sum of the safety-net energy offer cap 

($1000) plus the Contingency Reserve offer cap ($100), or $1100. The Spinning Reserve

market-clearing price is set equal to the sum of: (i) Supplemental Reserve marketclearing price; (ii) the system-wide Regulation-Up plus Spinning Reserve constraint 

shortage price; and, (iii) the zonal Regulation-Up plus Spinning Reserve constraint

shortage price. While this appears to be a complex calculation, in reality this simply 

means that the value is calculated as normal except that a resource’s opportunity cost for 

providing Spinning Reserve must include the $1100 system-wide shortage price due to 

that shortage. Also, if the Spinning Reserve requirement cannot be met, the value of the 

shortage price on the Regulation-Up plus Spinning Reserve is set to $200.123 Similarly, 

SPP’s Regulation-Up market-clearing price under this scenario would be equal to the sum 

of: (i) Spinning Reserve market-clearing price; (ii) system-wide Regulation-Up 

constraint shortage price; and, (iii) the zonal Regulation-Up constraint shortage price. 

Again, the Regulation-Up market-clearing price would include the opportunity cost of 

 122 SPP defines a shortage of Contingency Reserves (Spinning plus Supplemental Reserves), but does not 

define a shortage specifically of Spinning Reserve while being able to meet its supplemental reserve requirement.

123 SPP, Tariff, attach. AE, Addendum 1 Violation Relaxation Limit Values.
62

providing Regulation-Up (rather than Spinning or Supplemental Reserves) and so the 

$1100 filters through to this market-clearing price as well.

System-wide Contingency Reserve and Regulation-Up Reserve requirements 

cannot be met; Regulation-Down and zonal requirements can be met

If SPP is short of both contingency reserves and Regulation-Up, the Supplemental 

Reserve market-clearing price and Spinning Reserve market-clearing price are calculated 

as described above. The Regulation-Up market-clearing price is calculated slightly 

differently now, however, because this product is also experiencing a shortage. The 

Regulation-Up market-clearing price is equal to the sum of: (i) Spinning Reserve

market-clearing price; (ii) the system-wide Regulation-Up shortage price; and, (iii) the 

zonal Regulation-Up shortage price; the shortage price of system-wide Regulation-Up is 

equal to the sum of the Regulation offer cap ($500) plus the Contingency Reserve offer 

cap ($100), or $600.

System-wide Contingency Reserves requirement cannot be met, and zonal 

minimum requirements cannot be met; all other requirements can be met

This scenario mimics the first one presented for SPP, except that in addition, the system 

operator cannot meet the zonal minimum requirements. In those zones where the 

minimum requirement has not been met, shortage pricing is instituted. For instance, if 

the zonal requirement is not met, then the zonal constraint shortage price is also set to 

$1100 and the Supplemental Reserve market-clearing price in that zone is equal to $2200. 

This price would then filter through (via the opportunity cost calculation) to the marketclearing prices for the other reserve products (except Regulation-Down). If a zone is 

unable to meet its Spinning Reserve requirement, shortage pricing would be invoked for 

just that zone for Spinning Reserve.

System-wide Contingency Reserve requirement and Regulation-Up requirement 

cannot be met, and zonal minimum requirements cannot be met; the RegulationDown requirement can be met

In this instance, market-clearing prices for Supplemental and Spinning Reserves are 

calculated as described in the preceding section and the market-clearing price for 

Regulation-Up will directly include that shortage price ($600, as described above). 

Again, the invocation of zonal shortage prices will only occur in those zones unable to 

meet their individual requirements.

System-wide Regulation-Up requirement cannot be met, all other minimum 

requirements (including zonal) can be met
63

In this instance, only one reserve product, Regulation-Up, is short. Because RegulationUp is the most valuable product and Spinning and Supplemental Reserves cannot 

substitute for it, only the market-clearing price for Regulation-Up and the energy LMP 

are impacted by shortage pricing. In this instance, the system-wide market-clearing price

for Regulation-Up will equal the sum of: (i) Spinning Reserve market-clearing price; (ii) 

system-wide Regulation-Up shortage price; and, (iii) the zonal Regulation-Up shortage

price. The only term in this equation that reflects shortage pricing is the second, which 

would be equal to $600.

System-wide Regulation-Down requirement cannot be met; all other requirements 

are met.

In this instance, none of the other reserve products are impacted by shortage pricing. 

Because there is no substitutability between Regulation-Down and the other products, 

there are no opportunity costs to account for and the market-clearing price for 

Regulation-Down is set equal to $600.

Energy Shortage

In each of the instance described above, the energy LMP will reflect, through opportunity 

costs, the shortage pricing effects imposed under the different scenarios. However, if 

SPP is short of all reserve products and is forced to short energy (i.e. shed load), the LMP 

will be calculated, explicitly accounting for each (additive) shortage price currently in 

effect. Further, SPP maintains a $50,000/MW “Global Power Balance” Violation

Relaxation Limit, meaning it will redispatch its system no matter the cost, up to and 

including $50,000/MW in order to avoid load-shedding due to a lack of energy available 

to balance resources and load.
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Appendix 7 Electric Reliability Council of Texas (ERCOT)

Shortage Definition

ERCOT is required to maintain at least between 2300 MW and 2800 MW of Physical 

Responsive Capability, depending on the level of wind on the system. Of this amount, up 

to half can be supplied by Interruptible Responsive Reserve which is provided by Load 

Resources that are automatically interrupted when system frequency decreases to 59.7 

Hz. The remaining requirement is met by both Synchronized and Non-Synchronized 

Reserves. In addition to these reserves, ERCOT also procures Regulation-Up and 

Regulation-Down Reserves and Non-Spinning Reserve Service. Regulation-Up can 

serve to offset part of ERCOT’s Non-Spinning Reserve Service requirement. ERCOT 

enters into an Energy Emergency Alert (EEA) whenever it is unable to meet its minimum 

requirements for Physical Responsive Capability. 

In order to avoid EEA conditions, ERCOT may take certain operator actions. ERCOT 

will issue an Operating Condition Notice to inform all Qualified Scheduling Entities of a 

possible future need for more Resources due to conditions that could affect ERCOT 

System reliability.124 If Physical Responsive Capability falls below 3000 MW, ERCOT 

can issue an Advisory which allows it to exercise its authority, in such circumstances, to 

increase operating reserve requirements above the quantities originally specified in the 

Day-Ahead in accordance with procedures and may require information from Qualified 

Scheduling Entities representing Resources regarding the Resources’ fuel capabilities. 

ERCOT may also issue an appeal through the public news media for voluntary energy 

conservation.125 If Physical Responsive Capability falls below 2500 MW, ERCOT can 

issue a Watch and may immediately procure Regulation Services; Responsive Reserves 

Services and Non-Spin services from existing offers. ERCOT may also issue Dispatch 

Instructions to Resources certified to provide the insufficient service, even though there is 

not an existing operating reserve offer for that resource.126

If Physical Responsive Capability falls below ERCOT’s minimum requirement (2300 to 

2800 MW), ERCOT will declare an Energy Emergency Alert Level 1. During EEA 

Level 1, ERCOT will request available Generation Resources that can perform within the 

expected timeframe of the emergency to come On-Line by initiating manual commitment 

or through Dispatch Instruction; use available DC Tie import capacity not already being 

used; issue a Dispatch Instruction for Resources to remain On-Line which, before start of 

 124 ERCOT, Nodal Protocols, § 6.5.9.3.1 (Operating Condition Notice).

125 ERCOT, Operating Procedure Manual, Transmission and Security Desk V1Rev31, § 4.9 (Responding to 

Diminishing Reserves); ERCOT, Nodal Protocols, § 6.5.9.3.2 (Advisory).

126 ERCOT, Operating Procedure Manual, Transmission and Security Desk V1Rev31, § 4.9 (Responding to 

Diminishing Reserves); ERCOT, Nodal Protocols, § 6.5.9.3.3 (Watch).
65

emergency, were scheduled to come Off-Line; and at ERCOT’s discretion, deploy 

available contracted Emergency Response Service loads with a 30-minute ramp period.127

If Physical Responsive Capability falls below 1750 MW, ERCOT will declare an EEA 

Level 2. Under EEA Level 2, ERCOT will instruct transmission and distribution service 

providers to reduce Customers’ Load by using distribution voltage reduction measures, 

instruct Qualified Scheduling Entities to deploy Emergency Response Service with 10-

minute ramp periods, and deploy Responsive Reserves Services capacity supplied by 

Load Resources.128

If Physical Responsive Capability continues to drop or ERCOT is unable to maintain a 

frequency of 59.8 Hz, ERCOT will implement EEA Level 3, which requires transmission 

and distribution service provides to shed firm load in 100 MW blocks until the system 

can maintain 59.8 Hz.129

Shortage Pricing

Depending on the level of deficiency and actions taken, as described above, two shortage 

pricing methods can come into effect. ERCOT implements administrative shortage 

pricing when their Security Constrained Economic Dispatch software needs to dispatch 

regulation resources to provide energy in order to maintain power balance (rather than to 

provide Regulation Reserve). This administrative pricing is referred to as the Power 

Balance Penalty Curve and it acts as if it were an energy offer curve for a virtual 

Generation Resource injecting the amount of the Power Balance mismatch into the 

ERCOT system.130

 127 ERCOT, Nodal Protocols, § 6.5.9.4.2 (EEA Levels).

128 Id.

129 Id.

130 ERCOT Business Practice, Setting the Shadow Price Caps and Power Balance Penalties in Security 

Constrained Economic Dispatch, at 20-21(April 18, 2014).
66

Table 18. ERCOT Power Balance Penalty Curve131

MW Violation Price/MWh

≤ 5 $250 

5 < to ≤ 10 $300 

10 < to ≤ 20 $400 

20 < to ≤ 30 $500 

30 < to ≤ 40 $1,000 

40 < to ≤ 50 $2,250 

50 < to ≤ 100 $3,400 

100 < to ≤ 150 $4,600 

150 < to ≤ 200 $5,800 

200 or more $7,001 

On June 1, 2014, ERCOT implemented an Operating Reserve Demand Curve which is 

used both to price reserves and as a price adder to the real-time energy price. The 

Operating Reserve Demand Curve is designed to ensure that reserve and energy prices 

reflect the likelihood that ERCOT will have to shed firm load, measured by the Loss of 

Load Probability, which can vary from hour-to-hour or day-to-day, and the value of 

shedding that firm load, the Value of Lost Load. The Operating Reserve Demand Curve 

ORDC adder therefore is computed as (Value of Lost Load – energy price) * Loss of 

Load Probability. This curve slopes upwards starting at 5000 MW of reserves before 

becoming vertical at 2,000 MW and is capped at Value of Lost Load, which is currently 

set at $9000.132 . The minimum contingency level of 2000 MW reflects the belief that at 

this point the probability of losing load is so large that prices must be increased to Value 

of Lost Load. 133 

Shortage Pricing Events

Table 19 shows that shortage pricing in ERCOT is rare and that shortage pricing was 

much more prevalent in 2011 than any time since. Given ERCOT’s pricing rules, LMPs 

in excess of $3000/MWh can be expected to reflect shortage pricing for the entire 

 131 Id. at 25-26.

132 See ERCOT, Market Training, Operating Reserve Demand Curve Workshop at 9 (2014), available at 

http://www.ercot.com/content/wcm/training_courses/107/ordc_workshop.pdf.

133 ERCOT, Methodology for Implementing Operating Reserve Demand Curve (ORDC) to Calculate RealTime Reserve Market Adder, at 2, available at

http://ercot.com/content/mktinfo/rtm/kd/Methodology_for_Implementing_Operating_Reserve_Demand_Curve_.doc

.
67

hour.134 LMPs in excess of $2000/MWh probably reflect shortage pricing for several 

five minute intervals but not for the entire hour and LMPs in excess of $1000/MWh 

reflect shortage pricing for a few five minute intervals. 

Table 19. ERCOT Number of Hours with High LMP, 2011—2014135

2011 2012 2013 2014 All Years

> $3000 all zones 9 0 0 1 10

> $2000 all zones 14 2 1 1 18

> $1000 all zones 8 2 2 2 14

> $1000 zones 1-3 3 0 2 1 6

> $1000 total 34 4 5 5 48

 134 The one hour of high LMPs in 2014 were in excess of $4500/MWh.

135 Data Source: Ventyx.