NREL is a national laboratory of the U.S. Department of Energy

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This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

Wind and Solar Energy 

Curtailment: Experience and 

Practices in the United States

Lori Bird, Jaquelin Cochran, and Xi Wang

Technical Report

NREL/TP-6A20-60983

March 2014 
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Wind and Solar Energy 

Curtailment: Experience and 

Practices in the United States

Lori Bird, Jaquelin Cochran, and Xi Wang 

Prepared under Task No. AROE.1025

Technical Report

NREL/TP-6A20-60983

March 2014 
NOTICE

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iii

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Acknowledgments 

In 2010, the U.S. Department of Energy (DOE) awarded a grant under the American Recovery and 

Reinvestment Act of 2009 to the Western Governors’ Association to enhance member states’ 

capacity to participate in interconnection-wide transmission planning. Such planning in the West is 

done by the Western Electricity Coordinating Council (WECC), who also received a companion 

DOE grant to help with its own planning efforts. Associated with the Western Governors’ 

Association is the Western Interstate Energy Board, which received Western Governors’ Association 

grant funding for its State Provincial Steering Committee (SPSC)/Committee on Regional Electric 

Power Coordination (CREPC) to conduct studies and work relevant to the interests of its state 

electricity official members. At its October 2013 meeting, the SPSC/CREPC asked DOE’s Office of 

Electricity Delivery and Energy Reliability to help document and present curtailment practices for 

bulk power wind and solar generation. NREL was asked by DOE to provide the assistance.

The authors wish to thank the U.S. DOE Office of Electricity Delivery and Energy Reliability for 

funding the research that went into this report and in particular the support of Larry Mansueti. In 

addition, we thank Rebecca Johnson, who served as a liaison from the Western Interstate 

Energy Board. 

The authors appreciate the thoughtful review comments from: Kevin Porter, Exeter Associates, Inc.; 

Michael Goggin, AWEA; John Adams, DOE; Stephen Hall, Troutman Sanders; Charlie Smith, 

UVIG; Cameron Yourkowski, RNP; Ron Lehr, Western Grid Group; David Hurlbut, Jeffrey Logan, 

and Barbara O’Neill of NREL. The authors thank Mary Lukkonen of NREL for editorial support and 

Ksenia Kuskova-Burns for research assistance. The authors would also like to thank the individuals 

listed below who agreed to be interviewed and provided invaluable information this paper. Any 

errors or omissions are the responsibility of the authors. 

• Jacques Duchesne of Alberta Electric System Operator (AESO) 

• Ronald Flood of Arizona Public Service (APS) 

• Bart McManus of Bonneville Power Administration (BPA) 

• Clyde Loutan of California Independent System Operator (CAISO) 

• David Maggio of Electric Reliability Council of Texas (ERCOT) 

• Marc Matsuura of Hawaiian Electric Co (HECO) 

• Gerald Froese of Iberdrola 

• Justin Sharp, consultant, formerly of Iberdrola 

• Stephen Rourke and Eric Wilkinson of ISO New England (ISO-NE) 

• Kris Ruud of Midcontinent Independent System Operator (MISO) 

• Rich Salgo of NV Energy 

• John Apperson of PacifiCorp 

• Ken Schuyler and David Souder of PJM Interconnection, LLC (PJM)

• Drake Bartlett of Public Service Company of Colorado (PSCO) 

• Josh Jacobs of Puget Sound Energy 

• Dina Dubson of Renewable Northwest Project (RNP) 

• Vicken Kasarjian and Mark Willis of Sacramento Municipal Utility District (SMUD) 

• Mark Avery and David Crowell of Salt River Project (SRP) 

• Don Shipley of Southwest Power Pool (SPP) 

• Ron Belval, Sam Rugel, and Carmine Tilghman of Tucson Electric Power (TEP)

• Ed McNamara of State of Vermont Public Service Board

• Jeff Ackerman of Western Area Power Administration (WAPA) 
iv

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Executive Summary 

Curtailment is a reduction in the output of a generator from what it could otherwise produce 

given available resources, typically on an involuntary basis. Curtailment of generation has been a 

normal occurrence since the beginning of the electric power industry. However, owners of wind 

and solar generation, which have no fuel costs, are concerned about the impacts of curtailment 

on project economics. Operator-induced curtailment typically occurs because of transmission 

congestion or lack of transmission access, but it can occur for a variety of other reasons, such as 

excess generation during low load periods, voltage, or interconnection issues. Market-based 

protocols that dispatch generation based on economics can also result in wind and solar energy 

plants generating less than what they could potentially produce. 

This report examines U.S. curtailment practices regarding wind and solar generation, with a 

particular emphasis on utilities in the western states. The information presented here is based on 

a series of interviews conducted with utilities, system operators, wind energy developers, and 

other stakeholders. The report provides case studies of curtailment experience and examines the 

reasons for curtailment, procedures, compensation, and practices that can minimize curtailment. 

Key findings include: 

• In the largest markets for wind power, the amount of curtailment appears to be declining even as the 

amount of wind power on the system increases. Curtailment levels have generally been 4% or less of 

wind generation in regions where curtailment has occurred. Many utilities in the western states report 

negligible levels of curtailment. The most common reasons for curtailment are insufficient 

transmission and local congestion and excessive supply during low load periods. 

• Definitions of curtailment and data availability vary. Understanding curtailment levels can be 

complicated by relatively new market-based protocols or programs that dispatch wind down or limit 

wind generation to schedules and the lack of uniformity in data collection. 

• Compensation and contract terms are changing as curtailment becomes of greater concern to solar 

and wind plant owners. Increasingly there are negotiated contract provisions addressing use of 

curtailment hours and there is greater explicit sharing of risk between the generator and off-taker. 

• Automation can reduce curtailment levels. Manual curtailment processes can extend curtailment 

periods because of the time needed for implementation and hesitancy to release units from 

curtailment orders. 

• Market solutions that base dispatch levels on economics offer the advantages of creating 

transparency and automation in curtailment procedures, which apply equally to all generators. 

• Curtailed wind and solar resources may provide ancillary services to aid in system operations.

• A variety of solutions is being used to reduce curtailments: transmission expansion and 

interconnection upgrades; operational changes such as forecasting and increased automation of 

signaling; and better management of reserves and generation.
v 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Table of Contents

1 Introduction........................................................................................................................................... 1

2 Overview: Levels of Curtailment in the United States...................................................................... 3

3 Curtailment Experiences of Utilities and Grid Operators................................................................. 5

3.1 Bonneville Power Administration .................................................................................................... 5

3.1.1 Dispatch Standing Order 216 ............................................................................................ 5

3.1.2 Oversupply Management Protocol .................................................................................... 8

3.2 California Independent System Operator ......................................................................................... 8

3.3 Electric Reliability Council of Texas ............................................................................................... 9

3.4 Midcontinent Independent System Operator ................................................................................. 10

3.5 PJM Interconnection ...................................................................................................................... 11

3.6 Public Service Company of Colorado ............................................................................................ 12

3.7 Southwest Power Pool ................................................................................................................... 14

3.8 Western Area Power Administration ............................................................................................. 15

3.9 Other Western Utilities .................................................................................................................. 15

4 Synthesis of Curtailment Practices and Trends.............................................................................. 16

4.1 Reasons for Curtailment ................................................................................................................ 16

4.1.1 Transmission Constraints ................................................................................................ 16

4.1.2 System Balancing ............................................................................................................ 17

4.1.3 Other Reasons ................................................................................................................. 17

4.2 Methods of Implementing Curtailment .......................................................................................... 18

4.2.1 Signaling of Curtailment ................................................................................................. 18

4.2.2 Order of Curtailments ..................................................................................................... 19

4.3 Compensation of Curtailed Generators .......................................................................................... 21

4.4 Strategies to Mitigate Curtailment ................................................................................................. 24

4.4.1 Reserves and Generation Management ........................................................................... 24

4.4.2 Market Integration, Automation, and Negative Bidding................................................. 25

4.4.3 Strategies to Address Ramping ....................................................................................... 25

4.4.4 Transmission Planning Methods ..................................................................................... 26

4.4.5 Forecasting and Renewable Energy Visibility ................................................................ 26

5 Conclusions ........................................................................................................................................ 28

References................................................................................................................................................. 31

Appendix. Summary of Curtailment Experiences of Utilities and Grid Operators............................. 34
vi 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

List of Figures

Figure 1. Curtailment levels by region, 2007–2012 ............................................................................... 3

Figure 2. Wind energy curtailment events under the BPA DSO 216 program fourth quarter 2011 

through third quarter 2013 ............................................................................................................... 6

Figure 3. MISO-estimated energy manually curtailed in MWh versus dispatched down .................... 11

Figure 4. PJM wind reductions and associated lost opportunity cost payments .................................. 12

Figure 5. PSCO wind curtailments as a fraction of total wind generation ........................................... 13

List of Tables

Table 1. Summary of Curtailment Levels and Reasons for Curtailment ................................................ 4

Table 2. BPA Oversupply Curtailments ................................................................................................. 8

Table 3. MISO-Estimated Manual Curtailment and Dispatch Down ................................................... 10

Table 4. Summary of Methods Used to Implement Wind and Solar Curtailment................................ 19

Table 5. Compensation for Curtailment by Utility and System Operators ........................................... 21

Table 6. Strategies that Mitigate Wind and Solar Energy Curtailment ................................................ 24

Table 7. Utility and Grid Operator Experiences with Renewable Energy Curtailment ....................... 34
1 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

1 Introduction

Curtailment of variable renewable generation, particularly wind and solar energy, is becoming 

more widespread as wind and solar energy development expands across the country and 

penetrations increase. Curtailment can affect the revenue of wind and solar energy projects. 

These impacts are specific to each balancing area due to differences in grid characteristics, 

operating practices, and other factors such as weather. 

In this paper, we define curtailment as a reduction in the output of a generator from what it could 

otherwise produce given available resources (e.g., wind or sunlight), typically on an involuntary 

basis. Curtailments can result when operators or utilities command wind and solar generators to 

reduce output to minimize transmission congestion or otherwise manage the system or achieve 

the optimal mix of resources. Curtailment of wind and solar resources typically occurs because 

of transmission congestion or lack of transmission access, but it can also occur for reasons such 

as excess generation during low load periods that could cause baseload generators to reach 

minimum generation thresholds, because of voltage or interconnection issues, or to maintain 

frequency requirements, particularly for small, isolated grids. Curtailment is one among many 

tools to maintain system energy balance, which can also include grid capacity, hydropower and 

thermal generation, demand response, storage, and institutional changes. Deciding which method 

to use is primarily a matter of economics and operational practice.

“Curtailment” today does not necessarily mean what it did in the early 2000s. Two sea changes 

in the electric sector have shaped curtailment practices since that time: the utility-scale 

deployment of wind power, which has no fuel cost, and the evolution of wholesale power 

markets. These simultaneous changes have led to new operational challenges but have also 

expanded the array of market-based tools for addressing them. 

Practices vary significantly by region and market design. In places with centrally-organized 

wholesale power markets and experience with wind power, manual wind energy curtailment 

processes are increasingly being replaced by transparent offer-based market mechanisms that 

base dispatch on economics. Market protocols that dispatch generation based on economics can 

also result in renewable energy plants generating less than what they could potentially produce 

with available wind or sunlight. This is often referred to by grid operators by other terms, such as 

“downward dispatch.” In places served primarily by vertically integrated utilities, power 

purchase agreements (PPAs) between the utility and the wind developer increasingly contain 

financial provisions for curtailment contingencies. 

This report delineates several types of practices under the broad rubric of curtailment done for 

wind or solar generation. Some reductions in output are determined by how a wind operator 

values dispatch versus non-dispatch. Other curtailments of wind are determined by the grid 

operator in response to potential reliability events. Still other curtailments result from 

overdevelopment of wind power in transmission-constrained areas. Responses to all types of 

curtailment largely reflect the operating context, including whether the wind power is part of an 

centrally-organized wholesale market, or whether it is in a balancing authority area operated by a 

vertically integrated utility.
2 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Dispatch below maximum output (curtailment) can be more of an issue for wind and solar 

generators than it is for fossil generation units because of differences in their cost structures. The 

economics of wind and solar generation depend on the ability to generate electricity whenever 

there is sufficient sunlight or wind to power their facilities. Because wind and solar generators 

have substantial capital costs but no fuel costs (i.e., minimal variable costs), maximizing output 

improves their ability to recover capital costs. In contrast, fossil generators have higher variable 

costs, such as fuel costs. Avoiding these costs can, depending on the economics of a specific 

generator, to some degree reduce the financial impact of curtailment, especially if the generator's 

capital costs are included in a utility's rate base. 

Ascertaining the level of curtailment of wind and solar generation and its impacts is challenging. 

Often system operators or utilities do not track it or make data publicly available, and there are 

differences in terminology as well. Manual curtailment processes for wind have been replaced by 

economic dispatch protocols in a number of regions, and under the new protocols, dispatch 

below maximum output is typically not referred to as curtailment. In addition, energy lost due to 

line outages, and limits placed on deviations from schedule can all reduce wind generator’s 

production; some operators call these actions curtailment while others do not. 

This report examines curtailment practices for wind and solar energy in the United States, with a 

particular emphasis on utilities in the western states. Much of the experience documented in this 

report pertains to curtailment of wind power, which has reached higher penetrations of bulk 

system power, although solar curtailment is included where information is available.1

 This report 

builds on earlier reviews of domestic curtailment experience by Rogers et al. (2010) and Fink et 

al. (2009) and a recent review of international practices by Lew et al. (2013). The information 

presented here is based on a series of interviews conducted with utilities, system operators, wind 

energy developers and owners, and non-governmental organizations as well as other available 

data sources. This review was conducted to better understand the diversity of practices in place 

and the magnitude of curtailment that has been occurring. The report provides case studies of 

curtailment experience and examines the reasons for curtailment, curtailment procedures, 

compensation, and practices that can minimize curtailment of wind and solar. 

 

1 This report only looks at bulk power solar generation, not solar generation that occurs on a distributed 

generation level.
3 

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2 Overview: Levels of Curtailment in the 

United States 

Curtailment levels, where curtailment has occurred, are often in the range of 1% to 4% of wind 

generation, but higher levels have been reported by the Electric Reliability Council of Texas 

(ERCOT) in past years, as can be seen in Figure 1.

2

 However, the levels of wind curtailment 

experienced to date in the United States differ substantially by region and utility service territory, 

as discussed in Section 3. In many regions, curtailment is very low and not even tracked. 

Table 1 provides a summary of curtailment levels and causes for all of the utilities and grid 

operators interviewed for this study. Further discussion of the reason for curtailments is included 

in Section 3. Table A-1 in Appendix A summarizes experiences with wind and solar energy 

curtailment from all of the utilities and grid operators interviewed, including utilities that 

reported relatively low levels of curtailment. 

Figure 1. Curtailment levels by region, 2007–2012

Note: Data are indicative. Inconsistent definitions and reporting of curtailment make it challenging to 

compare curtailment levels across regions. Data for MISO includes manual curtailments and wind 

dispatched down. NSP is reported separately but also captured in the MISO data. BPA DSO 216 

curtailments assumed to occur for one half hour per event. Sources: BPA (2013a; 2013b), ERCOT

(Maggio 2014), MISO (Rudd 2013; 2014), Xcel/PSCO (Bartlett 2014), PJM (2014), NYISO (2013), and 

Wiser and Bolinger (2013) 

 

2 Higher curtailment rates have also been reported in Hawaii. For example, 40% of wind generation was curtailed in 

Maui in February 2013, but levels dropped to 10%–15% of wind generation in the following months after minimum 

generation levels were modified on fossil plants; modeling suggests that 2%–4% curtailment is achievable. 

Modeling of Oahu found curtailment to range from 4% to 8% of wind and solar generation, but 1% might be 

achievable with operational changes (Corbus 2014). 

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

2007 2008 2009 2010 2011 2012 2013

BPA

ERCOT

MISO

PSCO

PJM

NSP

NYISO

Curtailment as Fraction of Wind Generation
4 

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Table 1. Summary of Curtailment Levels and Reasons for Curtailment

Utility/Grid Operator Wind and Solar 

Curtailment Levels 

Frequency

Primary Reasons for 

Curtailment

Alberta Electric System 

Operator (AESO)

Infrequent Oversupply; transmission 

constraints, high wind ramps

Arizona Public Service 

(APS)

Infrequent Local transmission outages or 

constraints

Bonneville Power 

Administration (BPA)

Varies by year; less than 

2% of wind production

Balancing issues related to 

exhaustion of reserves; 

oversupply

California Independent 

System Operator (CAISO)

Infrequent; not tracked Oversupply; transmission 

constraints, congestion

Electric Reliability Council 

of Texas (ERCOT)

Varies by year; 2% to 

4% in 2012–2013, but 

higher in previous years

Transmission constraints; 

oversupply, new transmission 

lagged wind capacity

Hawaiian Electric Co. 

(HECO), Hawaii Electric 

Light Co., (HELCO) and 

Maui Electric Co. (MECO)

Substantial curtailment 

on Maui and the island 

of Hawaii

Oversupply in low load periods 

and balancing challenges

ISO New England (ISO-NE) Infrequent, but some 

plants experienced 

substantial curtailment

Local transmission constraints; 

oversupply; voltage control; 

other (wildlife protection, ice 

formations)

Midcontinent ISO (MISO) 1%–4% of wind 

generation 

Transmission congestion; 

oversupply handled by 

downward dispatch

NV Energy Infrequent; 6–7 

occasions per year 

Oversupply; local transmission 

outages

PacifiCorp Much less than 1% of 

total wind production

Transmission congestion; avoid 

area control error (ACE)

violations

PJM Interconnection Not tracked Local transmission constraints,

Puget Sound Energy Infrequent in PSE 

balancing area and not 

tracked

PSE wind subject to BPA's 

curtailment protocols related to 

balancing and oversupply

Salt River Project Very infrequent Transmission issues and 

maintenance

Sacramento Municipal 

Utility District (SMUD)

Not tracked SMUD not affected by 

curtailments 

Southwest Power Pool 

(SPP)

Some wind generators 

report high levels

Local transmission constraints, 

expansion of wind outpaced new 

transmission build-out 

Tucson Electric Power Very infrequent Local outages

Western Area Power 

Administration (WAPA)

None None

Public Service Company of 

Colorado (PSCO) 

1%–2% of wind 

generation

Oversupply; transmission 

constraints
5 

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3 Curtailment Experiences of Utilities and 

Grid Operators

This section summarizes the experiences of many U.S. balancing areas with modest and 

significant renewable energy curtailment. The information was obtained from interviews with 

utilities, independent system operators (ISOs), wind developers, and non-governmental 

organizations. 

3.1 Bonneville Power Administration

BPA experienced a rapid increase in wind capacity between 2008 and 2012, growing 850 

megawatts (MW) annually, to a total of 4,515 MW by early 2013 (BPA 2013a). Most of the 

wind is geographically concentrated in one area—the Columbia River Gorge in northern Oregon 

and southern Washington—which at times causes relatively large wind ramps. BPA has 

implemented two processes that curtail wind generation: Dispatch Standing Order (DSO) 216 

and the Oversupply Management Protocol (OMP). BPA uses DSO 216 when planned amounts of 

balancing reserves are exhausted and OMP when hydropower generation creates oversupply. 

3.1.1 Dispatch Standing Order 216

BPA established DSO 216 in 2009 to help manage the under- and over-generation of wind 

relative to schedule. BPA distinguishes between two types of balancing reserves: DEC balancing 

reserves, which decrease BPA hydro in response to wind over-generation, and INC balancing 

reserves, which increase hydro generation. BPA sets the reserve levels for wind based on 

installed wind capacity (14% of wind capacity for INC reserves and slightly higher for DEC 

reserves) and uses the reserves to balance unscheduled or unforecasted changes in generation 

and load.3

 

3 Specifically, BPA uses reserves to balance the station control error (SCE) for generation (the difference between 

the scheduled generation and what is actually produced) and the load error (the difference between the load forecast 

and actual load).
6 

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Figure 2. Wind energy curtailment events under the BPA DSO 216 program fourth quarter 2011 

through third quarter 2013 

Regardless of cause for the imbalance, and regardless of whether BPA has other reserves 

available, when INC and DEC reserves set aside for wind generation are at least 90% depleted, 

wind generation that is over- or under-generating compared to forecast will be curtailed. This 

curtailment is defined as “limiting” when DEC reserves are 90%–100% exhausted and BPA 

limits over-generating facilities to their forecasted schedule.4 In under-generation contexts when 

INC reserves are 90%–100% exhausted, BPA “curtails” under-generating facilities’ e-Tags5

 to 

their actual generation in order to reduce BPA’s exposure to further system imbalance. 

The financial impact of e-Tag curtailment extends beyond reduced energy sales. Under the 

pro forma OATT, curtailments are permitted only for reliability reasons; however, under BPA’s 

DSO 216 protocol, wind generators can be curtailed for non-reliability reasons and when other 

balancing reserves are available. Consequently, the market perceives generation schedules 

subject to DSO 216 as a less firm, and therefore less valuable, product. When generators’ e-Tags 

are curtailed, the generators cannot deliver the expected schedule, and their energy is devalued to 

a non-firm, interruptible rate. 

In addition to the financial impacts associated with DSO 216, wind generators in BPA’s 

balancing authority area are also subject to BPA’s Persistent Deviation Penalty Charge, which 

allows BPA to charge generators a 125% penalty if they have three consecutive hours of 

schedule deviations that exceed 15% of the schedule and 20 MW. The financial impacts of 

curtailments and costs of operating in the balancing authority area prompted neighboring 

 

4 Unless otherwise specified, in this report, “curtailment” includes both limiting events (which are energy 

curtailments) and grid curtailments (capacity curtailments) as they are defined under DSO 216.

5

 E-tags, also called NERC tags, provide information on real-time energy scheduling and power flows, including 

where generated energy originates, where it flows, scheduled time, total megawatt-hours, and names of parties.

E-tags help identify contributors to congestion and enable system operators to modify dispatch in response.

0

5

10

15

20

25

30

35

40

October-11

December-11

February-12

April-12

June-12

August-12

October-12

December-12

February-13

April-13

June-13

August-13

DEC Limiting

Events

INC Curtailment

Events

Number of Events
7 

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PacifiCorp to change the telemetry of two wind facilities in early 2013, removing them from the 

control of BPA’s balancing authority and adding them to PacifiCorp’s.6

Several measures would allow the power system to operate more efficiently, and in the process 

greatly mitigate wind curtailment. Most importantly, sub-hourly generation dispatch, sub-hourly 

transmission scheduling, and setting generation schedules closer to real-time would greatly 

reduce wind, load, and conventional generator deviations from schedule. If the sub-hourly 

scheduling and dispatch practices were coordinated with neighboring balancing authorities, as 

would occur under the proposed energy imbalance market, any remaining deviations could be 

exchanged or netted out with other balancing authorities in the western United States. 

Discussions about implementing such a system are ongoing in the Pacific Northwest, and 

CAISO-PacifiCorp are moving forward with implementing an energy imbalance market in 

October 2014. 

BPA has considered using dynamic reserve requirements that vary hourly based on predicted 

conditions of the system rather than vary only on nameplate wind capacity. At this time, 

however, BPA has not found this to be viable due to the complexity of the Snake and Columbia 

River hydro system. Purchasing balancing reserves is another option under consideration so that 

BPA does not have to hold reserves for all hours. To facilitate more accurate scheduling, BPA 

has installed 14 wind anemometers that provide data to wind operators and forecast providers at 

5-minute intervals. BPA has also created an internal wind forecast to see more accurately what 

will be generated by the wind in the upcoming hours and days. 

BPA has also initiated a self-supply option (“Customer Supplied Generation Imbalance 

Initiative”) in which wind owners/operators provide their own balancing in exchange for a credit 

against the wind integration rate. Iberdrola Renewables is the only wind owner to use the option 

so far. Drawing on contracts with a variety of generators (e.g., combined cycle gas turbines and

hydro), Iberdrola integrates its trading operations, dispatch operations, and meteorology group to 

ensure that it provides energy as scheduled. Iberdrola is able to significantly reduce balancing 

costs by making purchases over multiple timescales (e.g., both days-ahead and intra-hour) and 

thereby bypass the less flexible hourly dispatch intervals that BPA uses to balance.7

 Iberdrola 

has reduced its integration costs significantly, compared with charges and penalties incurred as a 

variable generator under BPA (Froese 2013). 

 

6 In November 2013, FERC declined to grant BPA reciprocity treatment for its tariff provisions related to the 

provision of generator imbalance service, finding that BPA’s proposal to limit the provision of balancing reserves 

for variable resources to amounts established in BPA’s rate case did not conform with and was not superior to the 

pro forma OATT requirements. Further, FERC stated that, “to the extent [BPA] intends to employ DSO 216 or a 

similar operational protocol to enforce generator imbalance service limits, it should submit the protocol to FERC in 

a compliance filing so that the Commission can determine whether it should be included in the tariff (FERC 2013, 

p. 21). 7 A BPA program allows scheduling on the half hour, but energy purchases or sales at the half hour require a seller 

or buyer to complete the exchange. BPA is also working on implementing 15-minute scheduling.
8 

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3.1.2 Oversupply Management Protocol

The second formal process for curtailment, 

implemented in March 2012, relates to the 

oversupply of electricity due to excess hydro 

generation. Table 2 shows curtailments under OMP 

and its predecessor, Environmental Redispatch, for 

the last few years. During the spring run-off months 

when river levels are high (typically April through 

July), BPA must run water through its turbines and 

generate power when the use of spillwaysthe only 

alternative to generationwould increase total 

dissolved gases above federal limits and threaten 

fish. Unlike DSO 216, BPA compensates wind 

generators for curtailments under OMP. However, 

in the future, BPA may recover some percentage of 

this compensation back from the wind generators through a yet-to-be-filed oversupply rate, so 

wind generators will not ultimately receive full compensation for OMP curtailments. The Federal 

Energy Regulatory Commission (FERC) has ruled that a previous program that lacked 

compensation was discriminatory, violating the principle of open transmission access on terms 

comparable to what BPA provides to its own generators. Under the OMP, BPA initially proposed 

splitting the cost of the program equally between wind generators and BPA’s customers, but 

FERC rejected this cost-sharing mechanism and directed BPA to submit a revised proposal in a 

proceeding that is ongoing.8

 Also, wind generators contend that BPA has not exhausted noncurtailment options, such as allowing market prices to go negative in order to increase demand 

and reduce oversupply by providing market signals to other generators (Renewable Northwest 

Project 2013). 

DSO 216 curtailments are also exacerbated by the excess hydro generation in the spring season, 

when fewer DEC reserves are available to balance wind. For example, the number of DSO-216 

DEC events, normally about four per month, jumped to nearly 40 in May 2012. 

3.2 California Independent System Operator 

CAISO had about 5,800 MW wind and 1,350 MW solar as of early 2013 (Blatchford 2013) and 

is expecting rapid growth to levels of 18,000–20,000 MW wind and solar by 2020. Today 

curtailment is relatively modest, although CAISO does not track it. Curtailment occurs largely 

due to congestion or periods of oversupply, and it is expected to increase as additional wind and 

solar generation are added. At times, the ISO experiences over-generation and minimum 

generation levels on its inflexible conventional units at night. For solar, the challenge is in the 

afternoon from 1:00 p.m. to 2:00 p.m. CAISO has undertaken a process to address curtailment 

 

8 FERC rejected the 50-50 cost-sharing basis on the grounds of undue discrimination, arguing that wind generators 

are a group that utilizes only a small percentage of the overall transmission system and that placing half of the 

displacement costs on them does not satisfy FERC’s comparability standards under Order 890. This essentially 

means that BPA must follow the same tariff terms and conditions that it requires of its customers. BPA’s final 

decision in the OS-14 Rate Proceeding is expected in March 2014, at which point, it will go back to FERC for 

review. If approved by FERC, the cost allocation will retroactively apply from March 2012 to September 2015. 

Table 2. BPA Oversupply Curtailments 

Year Curtailments Under 

OMP and its 

Predecessor 

Environmental 

Redispatch

2011 97,200 MWh

2012 49,700 MWh

2013 0 MWh

Source: BPA 2013b 
9 

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due to over-generation and to estimate how much excess generation could be sold to other 

balancing areas. 

CAISO treats wind and solar generation as must-take resources, provided there are sufficient 

reserves and no problems on the system. However, CAISO is exploring market-based solutions 

to addressing over-generation. In the spring of 2014, the ISO will reduce its bid floor to -$150 

per megawatt-hour (MWh), from the current -$30/MWh. The current level does not prevent wind 

generators from bidding in to the system because the value of the federal production tax credit 

(PTC) makes it economic for them to bid at -$30/MWh. If dropping the bid floor to -$150/MWh 

does not address over-generation, the floor will drop again to -$300/MWh. 

3.3 Electric Reliability Council of Texas 

ERCOT has experienced wind curtailment rates of around 8% in recent years, even jumping to 

17% in 2009, but it has since added additional wind capacity and curtailment levels have fallen 

(Maggio 2013; see Figure 1). Two major changes have dramatically reduced curtailments to 4% 

in 2012 and 1.6% in 2013: transmission expansion and a market redesign to LMP pricing and 

faster schedules that improved overall system operations. Transmission capacity has expanded as 

part of the Competitive Renewable Energy Zone (CREZ) initiative, authorized by the Texas 

Legislature in 2005 to support the build-out of transmission in advance of anticipated wind 

development primarily in west Texas. The CREZ program was designed to build sufficient 

transmission to accommodate 18.5 gigawatts (GW) of total wind capacity. The lines were 

completed in early 2014 at a cost of approximately $6.8 billion (Wolff 2014). Some of the wind 

development in west Texas came online in advance of transmission, resulting in significant 

wind curtailment. 

The market redesign also helped reduce curtailments. The market redesign included shifting 

from 15-minute to 5-minute dispatch intervals, more centralized scheduling, and changes to how 

forecasting was integrated into market operations. The market rules were also modified to allow 

updates to generation schedules until ten minutes or less before the dispatch period, which 

greatly minimizes forecast errors. Wind resources participate in the ERCOT real-time and dayahead markets in much the same way as other resources, except that the first 48 hours of their 

operating plans must be based on ERCOT’s most recent short-term wind power forecast 

(ERCOT 2013a). Wind and solar resources may submit negative bids. Generation oversupply has 

contributed to instances of system-wide negative pricing in the middle of the night. ERCOT 

posts day-ahead and intra-day forecasted system conditions that will be used in unit commitment 

and dispatch, providing an automated, transparent mechanism to reduce generation output due to 

congestion, oversupply, ramping, and other aspects of system flexibility. (ERCOT 2013b) 

Reductions in output (“downward dispatch”) for wind and solar resources in ERCOT are 

primarily a result of local congestion. Dispatch instructions most often occur automatically as 

part of normal outputs from ERCOT’s security-constrained economic dispatch engine. 

However, under special circumstances, ERCOT may issue verbal dispatch instructions to 

specific resources, in which case the resources may be given special compensation based on the 

settlement prices in effect during the time of the instruction (ERCOT 2013c). 
10 

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3.4 Midcontinent Independent System Operator

MISO, which has more than 12 GW of wind capacity and a peak demand of 98 GW, 

implemented the Dispatchable Intermittent Resource (DIR) protocol in mid-2011, which requires 

wind plants operating on or after April 2005 to bid into the real-time market. Prior to the DIR 

program, MISO used only manual curtailments to address congestion, which operators used 

more than 1,000 times in each of 2009 and 2010 (Porter et al. 2012). 

Now, DIRs can set the LMP and can be dispatched down through an automated process. Similar 

to ERCOT, limitations on output due to downward dispatch (e.g., due to oversupply and ramping 

constraints) are not classified as curtailments. Unlike earlier years, MISO has not had an 

oversupply case in the past few years, but with downward dispatch, they are also not tracking 

these events. Moreover, in an integrated market it can be difficult to attribute causes. Ramprelated downward dispatch is not expected to be an issue until wind capacity is double current 

levels (expected in 2017–2018). Similar to ERCOT’s CREZ, new transmission projects are 

progressing in areas that will mitigate existing curtailment and likely attract significant 

investment in new wind generation. Of wind generators not participating in the DIR program, 

curtailment levels reached a high of 3.7% of total wind generation and have since fallen to 0.2% 

(Ruud 2014; McMullen 2013) and are primarily due to local congestion. Table 3 shows the 

number of curtailments, duration, and estimated energy curtailed as well as DIR dispatch down. 

Figure 3 compares estimated energy manually curtailed versus dispatched down monthly from 

July 2011 to January 2013. 

Table 3. MISO-Estimated Manual Curtailment and Dispatch Down 

2009 2010 2011 2012 Oct. 2013

Number of wind curtailments 1,141 2,117 2,034 889 N/A*

Estimated manual curtailment 

(MWh) 292,000 824,000 720,000 266,000 65,010

Duration (hours) 8,005 19,951 20,365 10,430 N/A*

DIR dispatch down (MWh) N/A N/A 130,296 582,653 972,580

Manual curtailment as % of 

wind generation 1.6% 3.7% 2.5% 0.8% 0.2%**

Manual curtailment and DIR 

dispatch down as % of wind 

generation

1.6% 3.7% 3.0% 2.5% 3.5%**

*Note: As of April 2013, the number of wind curtailments totaled 148 and the duration (hours) were 2,057. 

These data were not available for April through October 2013. 

**Estimated for full year based on average monthly curtailment and dispatch down rates. 

Source: McMullen 2013; Ruud 2013; Ruud 2014

Another advantage of DIR with regard to curtailment is the automation of the process. Manual 

curtailments require operators to track and judge events and evaluate when to release the 

curtailment, which could lead to prolonged curtailment events in some cases. Grid operators 

typically do not want to release the wind power too fast, as it can ramp up very quickly and 

contribute to reliability problems. To release wind from curtailments, grid operators often check 

near-term forecasts and grid status to determine when to allow wind to ramp up, or establish 
11 

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ramp-up limitations. DIR reduces the number of manual curtailment events that system operators 

need to address, enabling them to focus on other system issues. Reliability coordinators have 

appreciated the shift to DIR because the operator does not need to continue closely monitoring

the constraint after the event has been resolved. 

Figure 3. MISO-estimated energy manually curtailed in MWh versus dispatched down 

Source: Rudd 2014

One impact of the introduction of DIR is on contract language regarding compensation. Many 

agreements treat downward energy dispatch differently if the cause is economic rather than a 

reliability event. Wind generators and off-takers have been addressing these issues on an 

agreement-by-agreement basis.

3.5 PJM Interconnection 

In PJM, most wind energy curtailment is due to transmission constraints, often during 

maintenance. At this time, PJM does not have minimum load issues; it does allow negative 

pricing, which can help alleviate oversupply situations. Figure 4 shows the amount of wind 

energy reduced and the lost opportunity cost payments made to wind generators in 2012–2013. 

Wind reductions represented approximately 2% of wind generation in 2013. 

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

Jun-11

Aug-11

Oct-11

Dec-11

Feb-12

Apr-12

Jun-12

Aug-12

Oct-12

Dec-12

Feb-13

Apr-13

Jun-13

Aug-13

Oct-13

DIR Dispatch Down

Estimated Manual

Curtailment

MWh
12 

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Figure 4. PJM wind reductions and associated lost opportunity cost payments 

Source: PJM 2014

PJM has recently changed its curtailment signaling and compensation processes to try to increase 

efficiency. To initiate curtailment, PJM sends a curtailment flag to generators instructing them to

follow base-point signals down to the curtailed level. PJM has typically followed the automatic 

signals with a phone call, implemented manually by the grid operator. In November 2013, PJM 

adopted changes so that if wind generators do not follow the automatic base-point instructions 

and provide meteorological data needed by PJM to produce an accurate wind power forecast, 

they will no longer be eligible for make-whole payments paid out of operating reserves for 

curtailed generation. PJM expects this to minimize the need for manual processes, which should 

in turn reduce curtailment time. Along with these compensation changes, PJM has implemented 

a process to improve transparency by providing feedback to affected wind generators on their 

performance following base-point instructions, the day after curtailment events. Finally, to more 

precisely estimate curtailment, PJM has implemented a “backcast” to calculate what the wind 

farm could have produced if there was no constraint. Prior to August 2013 curtailment levels 

were estimated based only on the forecast. 

PJM has also made changes that could help reduce future curtailments. PJM has developed a 

light-load planning process to ensure that the transmission system is capable of delivering the 

system generating capacity at light load, when wind generation is typically higher. Based on the 

new criteria, PJM identified a number of required upgrades, the cost of which will be allocated to 

load, not individual wind generators. Going forward, generators requesting interconnection to 

PJM must pass this test in order to become a PJM capacity or energy resource. The 

interconnecting generator is responsible for the cost of upgrades needed to resolve light load 

criteria violations caused by that generator.

3.6 Public Service Company of Colorado

PSCO has brought considerable wind online in recent years, reaching about 30% of peak 

demandand even 60% of load served with wind during one hour in 2013. PSCO has had to 

curtail wind at times, primarily due to oversupply during low load periods and line constraints 

$0

$500,000

$1,000,000

$1,500,000

$2,000,000

$2,500,000

$3,000,000

$3,500,000

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

Jun-12

Sep-12

Dec-12

Mar-13

Jun-13

Sep-13

Dec-13

Wind MWh

Reduced

Wind Lost

Opportunity Cost

MWh
13 

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and outages, but it has also taken many actions to reduce curtailment and integrate more wind.

While total wind generation grew substantially from about 3.7 to 6.5 million MWh between 2010 

and 2013, curtailment levels as a fraction of total wind generation declined slightly over that 

period from 2.2% to 1.7% (see Figure 5). PSCO has been able to manage curtailments by 

implementing a variety of changes to its system operations. 

Figure 5. PSCO wind curtailments as a fraction of total wind generation

Source: Xcel Energy (Bartlett 2013)

A primary strategy to mitigate curtailments has been improved use of forecasting. PSCO has 

worked with the National Center for Atmospheric Research to improve its wind prediction 

models. Improved forecasting enables PSCO to turn down conventional resources when 

sufficient wind generation is predicted and to reduce curtailment from oversupply. Improved 

forecasting also eliminated curtailments related to ramping. 

A second strategy to mitigate curtailments is to cycle baseload generating units. Prior to 2010, 

PSCO’s dispatch policy was not to cycle baseload units. Since then, PSCO cycles baseload units 

to accommodate wind generation during windy periods of the year. In particular, it cycles 

combined cycle gas units on a daily basis, but it cycles coal units much less frequently due to the 

significantly higher cycling costs. In 2010, when there was a dramatic increase in wind 

curtailments primarily due to line outages, PSCO studied the costs of cycling baseload units 

versus curtailing wind. The costs were similar, so PSCO decided to cycle off thermal units at 

night to minimize wind curtailments.

Finally, PSCO has also put many wind facilities on automatic generator control (AGC), and it 

requires AGC on all new wind contracts as a bid condition, which reduces total curtailments.

Previously, PSCO would curtail in blocks (e.g., 100 MW) and balance with thermal units. Now 

PSCO can take thermal units to their minimum and balance with one wind generator on AGC 

(two-thirds of wind farms have AGC capability, but only one wind project is needed on AGC at 

a given time due to their fast response provided it is large enough to handle swings in load).

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

0.00%

0.50%

1.00%

1.50%

2.00%

2.50%

2008 2009 2010 2011 2012 2013

Wind Production

(MWh)

Curtailment as % of

Wind Generation
14 

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Wind farms on AGC can provide downward regulation to the minimum regulating range of the 

wind farm. PSCO also uses curtailed wind energy to provide positive reserves (upward 

regulation). 

Looking forward, PSCO is examining participation in an organized energy imbalance market, 

which would reduce the need for balancing and potentially broaden the supply of resources 

available to balance system variability. PSCO is also considering changing its use of pumped 

storage hydroelectricity; instead of pumping at night to serve peak load, PSCO might pump at 

other times during low net load periods to offset curtailment. 

Costs and risks of curtailment are factored into PPAs, and compensation varies by cause. For 

transmission-related causes, wind generators under some older contracts are compensated, but 

the majority of contracts do not allow for compensation for transmission causes beyond PSCO’s 

control, such as the unexpected loss of a line. If PSCO curtails for balancing purposes, it will 

compensate generators for the energy that they would have produced plus the value of PTC 

earnings. However, PSCO has negotiated annual maximums of free (uncompensated) curtailment 

hours with five of the fourteen wind farms. Currently PSCO receives a total of 60,000 annual 

free curtailment hours, but this drops to 30,000 by 2018, at which time a number of coal plants 

will be replaced by more flexible natural gas units (which begin to come on-line in 2015). 

3.7 Southwest Power Pool 

Wind generation in SPP has increased substantially in recent years, increasing from 3.5% of total 

generation in 2008 to 7.6% in 2012. In addition, 3,090 MW of wind was installed in SPP in 

2012, representing nearly half of all new capacity additions, and bringing total installed capacity 

to 7,790 MW (SPP 2013). Much of this wind generation has been brought on-line in advance of 

planned transmission upgrades in wind development areas, especially in the Texas Panhandle 

and western Kansas. As a result, some wind generators have informed SPP that they have 

experienced significant curtailments of production. In 2012, SPP issued 883 wind-related 

directives to manage congestion, an increase of 450% over the 197 issued in 2011 (SPP 2013). In 

2011 and earlier, overall wind curtailment levels in SPP had been less than 1% of potential wind 

generation, as can be seen in Figure 1 above (Wiser and Bolinger 2013). 

Further exacerbating the curtailments had been the manual process for imposing production caps. 

As of 2013, when SPP experienced an emergency N-1 event, the grid operator manually called

control rooms at each affected wind farm to set new limits on dispatch. Because the notifications 

could consume 30-40 minutes for a typical event (7-10 wind farms), SPP was reluctant to release 

these curtailments if they might be needed again soon, and wind generators could spend several 

days operating at curtailed outputs. 

To mitigate curtailments, SPP has been implementing a three-phase approach:

1. Automate curtailments (2013): To automate and shorten the duration of curtailments, SPP 

planned to reclassify curtailments as congestion management, rather than emergency, 

which carries the obligation for three verbal communications between the parties. 

Because this change in classification affects many contracts, in which off-takers bear the 

costs of economic-based curtailment, SPP had conducted regular meetings with wind 

developers and other stakeholders to discuss the ramifications of this proposed change. 
15 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

2. Introduce a day-ahead market, similar to MISO, PJM, and other RTOs with LMP-based 

markets (March 2014) 

3. Build new transmission (mid 2014–2015). 

As part of the three-phase approach, SPP has found that stakeholder outreach has been an 

effective component in their efforts to reduce curtailments. For example, wind project developers 

who went through the interconnection process and met requirements often understood the 

reliability risks, but those who purchased a project later sometimes did not. Although SPP 

provided correct and clear analyses as part of the interconnection agreements, SPP realized that it

could improve the investment environment by helping all their members—especially small, 

independent wind generators that lack operating expertise—to better understand curtailment 

risks. Other critical stakeholder outreach efforts included increasing the transparency of 

curtailment practices and causes, proposing cost-sharing with wind developers to conduct ‘hot” 

transmission upgrades in lieu of outages, and soliciting stakeholder ideas and concerns related to 

the three phases of mitigation. 

3.8 Western Area Power Administration

Like BPA, WAPA is one of the U.S. Department of Energy’s power marketing administrations 

responsible for marketing and delivering hydropower in its service territory. One of WAPA’s 

responsibilities is to provide ancillary services, including the use of hydro to provide regulation 

to its service territory. WAPA has experienced difficulties balancing wind when wind overgenerates compared to schedule and WAPA needs to drive its units down to minimum 

generation. The most significant occasion occurred in May 2013, when aggregate wind capacity 

exceeded schedules by 125 MW, and WAPA held its hydro below its preferred minimum 

necessary to meet water release restrictions. WAPA did not curtail the wind in this event because 

it is required under contract to accommodate the wind, and this contract has no clause that allows 

curtailment for oversupply. 

If wind over-generates compared to its schedule, WAPA assesses an energy imbalance charge on 

the operational entity. WAPA would like to make these charges more costly to encourage 

operational entities in the balancing authority to back down their coal and balance their loads 

during these oversupply periods. WAPA is also offering 15-minute scheduling (a requirement 

under FERC Order 764), which will allow generators to adjust schedules and reduce the duration 

spent out of schedule, if transmission can also be scheduled subhourly. As more wind enters its 

administrative area, WAPA wants to ensure that new contractual arrangements will provide 

WAPA more control over schedules and provide utilities an incentive to balance their load. 

3.9 Other Western Utilities

Other western utilities interviewed for this study—APS, NV Energy, Salt River, and Tucson 

Electric—have experienced very little curtailment, the causes of which primarily relate to local 

transmission constraints, although NV Energy has curtailed wind on a few occasions due to 

oversupply during low load hours. These utilities also are distinguished by their compensation 

practices, in most cases compensating for curtailments within their control. However, like PSCO, 

APS holds contract clauses that allow it to curtail a certain number of hours without 

compensation. 
16 

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4 Synthesis of Curtailment Practices and Trends

This section synthesizes the experiences of utilities and grid operators along four aspects of 

curtailment: reasons, implementation methods, compensation practices, and mitigation strategies.

4.1 Reasons for Curtailment 

Reasons for curtailment include transmission constraints, including congestion and system 

balancing challenges related to oversupply situations and ramp events. 

4.1.1 Transmission Constraints

Transmission constraints have been the most common reason for wind curtailments in the United 

States to date. Most curtailment has occurred when the construction of necessary transmission 

lags behind the pace of wind farm development, resulting in infrastructure that is insufficient for 

the amount of wind generation on line. In ERCOT and SPP, for example, substantial amounts of 

wind generation were brought online before the necessary transmission could be built and 

energized, leading to wind curtailments. ERCOT’s reported wind curtailments rose from about 

1% in 2007 to a peak of more than 17% in 2009. Since the construction of new transmission and 

the adoption of new transmission operating procedures that increased the transfer capacity on 

existing transmission, curtailments fell to 4% in2012, and further to 1.6% in 2013 (Maggio 

2014), although some of the reduction could be attributed to market changes. A few wind 

generators in SPP have reported that in 2012 a substantial fraction of expected generation was 

curtailed due to insufficient transmission access. 

Many utilities have also experienced more modest levels of wind energy curtailment as a result 

of local congestion on transmission lines. Congestion or local transmission constraints have 

caused curtailments in MISO, ISO-NE, ERCOT, PacifiCorp, PJM, and SPP, among other areas. 

In MISO, some generators are not dispatched by the market and can be subject to manual 

curtailments primarily due to congestion. ISO-NE has also reported curtailments of wind 

generation when local lines are unable to accept all available wind generation. 9 It is worth noting 

that, in areas with wholesale electricity markets, the minimum interconnection standard assumes 

that generation resources will be competing to sell power into the grid and therefore generators 

in the same local area may not be dispatched at the same time. Consequently, developers may 

choose to undertake an interconnection review that provides sufficient information to ensure a 

safe interconnection, but does not indicate whether the resource can deliver into the market while 

other local resources are also generating. This is particularly problematic for wind generators as 

the available wind resource tends to be clustered and wind generators end up competing with 

other wind generators for limited transmission capacity.

While all regions have occasional transmission line outages due to accidents or maintenance, we 

do not focus on this type of curtailment in this report, as these are common to all forms of 

 

9 For additional information, see Vermont Department of Public Service 2013 Recommendation on Issues Related to 

the Curtailment of In-State Electric Generation Plants, 

https://leg2.vermont.gov/sites/legislature/EGAC/Shared%20Documents/Recommendation%20Issues%20Related%2

0Curtailment%20In-state%20EG%20Facilities.pdf
17 

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generation. Often, these curtailments are not tracked, but many utilities report that such instances 

are relatively rare.

4.1.2 System Balancing 

Some renewable energy curtailment has been attributed to challenges in balancing the system 

with higher penetrations of wind energy due to oversupply of generation, typically during low 

load periods. Some utilities or grid operators have curtailed generation from wind plants when 

minimum generation levels on fossil-fuel plants are reached, because stopping and restarting 

fossil units within a few hours can be significantly more expensive than paying for a few hours 

of wind curtailment. This type of situation can occur at night when there are substantial amounts 

of wind generation but loads are low, and it can be exacerbated in small balancing areas. 

For example, PSCO has reported periods of very high levels of wind generation relative to total 

demand and has curtailed on the order of 1%–2% of wind generation annually in recent years. 

Curtailments during low net load periods have been reported by several utilities and system 

operators, including CAISO (CAISO 2010), Hawaii, NV Energy, BPA, Alberta ISO, and ISO 

New England. Hawaii has reported curtailing wind as a result of significant amounts of solar 

generation at mid-day. In areas with day-ahead energy markets, such as ISO New England, 

resources that do not bid into the day-ahead market (DAM) are curtailed during low load events 

before resources that have participated in the DAM and received a financially binding 

commitment. Because intermittent resources, unlike other generation types, are not required to 

participate in the DAM these resources are more likely to be curtailed.

In some areas with wholesale power markets, such as MISO and ERCOT, the amount of wind 

generation utilized is a function of market pricing. When prices are low or negative (e.g., due to 

oversupply or congestion), wind generators that bid above the market-clearing price will not 

be dispatched. 

Similarly, environmental constraints on hydro plants that affect their operations have been a 

factor resulting in curtailment of wind generators in the Pacific Northwest. Oversupply of 

hydropower may occur at times when plants have to run water through the turbines rather than 

spill it over the dam to control dissolved oxygen levels that relate to fish protection. Some hydro 

units also have constraints related to protecting irrigation or recreation access that affect output 

levels. In the BPA service territory, seasonal oversupply of hydropower, combined with the 

absence of negative prices to dispose of excess hydropower, resulted in the curtailment of about 

3% of available BPA wind capacity in the spring of 2011 and about half that amount in the 

spring of 2012 (BPA 2013b). No oversupply-related curtailments had been reported for 2013. 

Curtailment has occurred in some instances, such as in ERCOT and AESO, to slow a rapid 

change in wind output, which can make it difficult to balance the system if other generation 

sources are not able to change output levels fast enough to compensate. In Alberta, Canada, for 

example, AESO has curtailed wind at times when it is unable to manage substantial ramps in 

wind output. 

4.1.3 Other Reasons

Curtailment is also used to address voltage issues, address interconnection issues, and maintain 

frequency and stability requirements. Curtailments have occurred for voltage reasons in ISO-NE
18 

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in weak areas of the grid and in areas where older wind plants are unable to provide necessary 

grid support. These events would have been unlikely to occur if the local transmission system 

were stronger. If grid upgrades are not undertaken to address interconnection issues, particular 

projects can be subject to curtailment ahead of other generators that have completed required 

upgrades. In addition, maintaining frequency and stability requirements can be an issue for small 

or isolated grids, such as Hawaii. In some cases, limits may be placed on nonsynchronous 

generation levels to address these concerns and to ensure the system can adequately react to a 

contingency event. Conventional synchronous generation sources typically provide inertial and 

governor responses in the case of contingencies. If significant amounts of wind and solar 

generation are on the system, they may either need to provide these services to the grid or be 

curtailed to maintain frequency requirements and system stability. 

Some wind generators have agreed to self-curtail for reasons such as protecting bats and enabling 

de-icing. For example, in ISO-NE some wind generators have volunteered to self-curtail for up 

to 120 nights per year to protect bat populations. This has also occurred in other wind plants in 

the East. Wind generators must also self-curtail when ice forms on the turbines, and many wind 

farms are installing cameras to more quickly confirm ice-free status and come back online. 

4.2 Methods of Implementing Curtailment

Implementation methods include both the method of signaling curtailments and the rules 

governing the order that plants are curtailed. These implementation methods vary by cause and 

by grid operator. Lack of automation can pose challenges in regions where significant 

curtailment occurs, as manual curtailments can prolong curtailment of renewable generators. 

Table 4 summarizes methods used to implement curtailment by utilities and grid operators.

4.2.1 Signaling of Curtailment

Automatic signaling is used to curtail wind generators in a number of areas, including wholesale 

market environments such as AESO and ERCOT, as well as the BPA balancing area and Hawaii. 

Supervisory control and data acquisition (SCADA) systems, which are a category of software 

applications used for transferring data and controlling equipment remotely, are used in these 

areas to send signals in real time to renewable energy facilities. The AESO send pro rata

directives by SCADA when conditions for wind power management are met. To initiate 

curtailments, BPA sends a signal via SCADA (initiated in AGC) and requires confirmation from 

the wind facilities. Similarly, system operators on Oahu and the island of Hawaii use SCADA to 

send curtailment limits. 

In some markets, regular market operator signals can be used to signal curtailments. For 

example, ERCOT automatically signals base-point instruction to all generators every five

minutes and provides a ramped set-point value every two to six seconds. ERCOT sends a flag to 

generators that need to be dispatched below their highest dispatchable level and assesses 

penalties to wind and solar generators that deviate from base-point levels when they are flagged. 

PJM has a similar process, but has typically followed base-point instructions with a phone call to 

ensure wind generators curtail as required. To try to reduce the need for manual processes, PJM 

recently made changes in that it will no longer compensate for curtailment if wind generators 

must be contacted by phone. 
19 

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Table 4. Summary of Methods Used to Implement Wind and Solar Curtailment 

Utility or Grid Operator Automated Signaling Manual Signal 

(Phone)

AESO x

APS x

BPA x

ERCOT x

HECO; HELCO; MECO x (Maui, Oahu and Hawaii)

ISO-NE x

MISO X (DIR program) x

NV Energy x x

PacifiCorp x

PJM x x

Puget Sound Energy x (BPA curtailments)

Salt River Project x

Tucson Electric Power x

WAPA x 

PSCO x (not all) x

At least two utilities place wind plants on AGC to control their output. For example, on Maui, 

AGC controls are used to curtail wind as needed if other units are generating at minimum levels. 

Maui also uses wind to provide down reserves. Two-thirds of PSCO’s wind facilities have AGC 

capabilities, which allow for more efficient curtailment because of rapid and more precise 

signaling. PSCO can take thermal units to their minimum and balance with one AGC-equipped 

wind plant (only one wind plant is needed on AGC at a given time due to their fast response). 

Remaining wind facilities are manually curtailed via phone or set-point instruction via the energy 

management system. Because the operators have the ability to adjust the curtailment as often as 

they wish via set-point control, the curtailments can be fine-tuned to a more precise level than 

block curtailments done by phone. 

In many areas, curtailments are implemented manually whereby grid operators call wind 

facilities to issue curtailment directives. Manual curtailment instructions are used by APS, Salt 

River Project, Tucson Electric, ISO-NE, PacifiCorp, SPP, and MISO. PacifiCorp's generation 

center can manually control wind output levels for wind facilities they own. In MISO, wind 

generators not participating in the DIR program are subject to manual curtailments; reliability 

coordinators call wind generators and coordinate these directives with the local balancing 

authority and transmission authority. In ISO-NE, grid operators call wind facility operators to 

provide new not-to-exceed instructions to curtail. NV Energy uses a blend of automatic and 

manual approaches. The operator sets the new not-to-exceed instructions through the automatic 

system, and in tandem, calls the wind operation staff to explain the situation. In areas such as 

those covered by AESO, SPP, and ERCOT, the manual approach used in the past has itself 

contributed to curtailed hours because it takes 30–40 minutes typically to implement curtailment 

orders, and grid operators have been reluctant to release these curtailments if they were to be 

needed again soon. 

4.2.2 Order of Curtailments 

The methods for determining the order in which resources are curtailed can vary. Criteria often

depend at least in part on the reason for curtailment. Curtailment order can be influenced by 
20 

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market design, contracts, and plant economics, as well as whether the curtailment relates to local 

transmission congestion or is caused by balancing-related challenges (e.g., oversupply on the 

system that affects a broader region). 

Typically congestion-related curtailments are based on the effectiveness of generators in 

alleviating constraints. For example, in CAISO, generators that are most effective in relieving 

congestion will be curtailed to their scheduled output first. In MISO, the determination of 

curtailment order is based on which generators impact congestion the most and whether they 

have firm transmission service. In SPP, wind generators are subject to curtailment if they 

contribute 5% or greater to a constraint. If more than one generator creates this impact, the 

curtailment is divided equally. SPP is reviewing its approach for prioritizing curtailments of 

multiple generators based on who has firm service. 

In ISO-NE, curtailments are pro-rated equally among affected generators for renewable 

resources that self-schedule in the day-ahead market but must be curtailed in real-time. In some 

cases, required network upgrades were not completed for some wind generating capacity. These 

generators must back down first if local constraints are the cause for curtailment. Once upgrades 

(e.g., new breakers and lines) are complete, open access transmission dictates that all generation 

is treated the same.

A number of utilities and grid operators base curtailments on contracts and wind plant 

economics. If there are transmission constraints, AESO cuts the most expensive energy first from 

among all generators, including wind. Occasionally, AESO will place limits on a transmission 

line and allow the relevant utility to decide which generators to curtail. For PacifiCorp and 

PSCO, the order of curtailment is based on the cost of the generators as well as contractual 

issues. PSCO first curtails generators with which they have negotiated “free” curtailment hours 

under a PPA. Next, PSCO curtails generators that receive the federal investment tax credit (in 

lieu of the PTC). Those facilities that utilize the PTC must generate electricity in order to take 

advantage of the tax credit; therefore, their financial losses (tax credit and the energy value) are 

higher than investment tax credit (ITC) plants if curtailed. Next, PSCO curtails generators on 

AGC; finally, other wind generators are curtailed as necessary.

In Hawaii, curtailment is generally applied in reverse installation order. However, renewable 

energy facilities can lose their curtailment priority if they do not produce at least 60% of annual 

estimated energy production over four years. However, net-metered solar photovoltaic (PV) and 

feed-in tariff projects are exempt from this requirement and are allowed to operate without 

curtailment controls. Also, if a cause for curtailment is directly attributed to a specific renewable 

energy facility, the reverse chronological order may not apply.
21 

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4.3 Compensation of Curtailed Generators 

Compensation to wind generators for curtailment varies across balancing authorities and offtakers and typically depends upon the cause of the curtailment.10 Table 5 summarizes 

compensation practices for the grid operators and utilities we interviewed. 

Table 5. Compensation for Curtailment by Utility and System Operators

Utility or Grid 

Operator

Compensation 

Provided?

Limits 

Specified in 

Contracts

Reasons for 

Compensation

Limits to 

Compensation

AESO No Wind generators are not 

compensated.

APS Yes x Limited annually; do 

not pay if directed by 

other transmission 

operators

BPA OMP 

curtailment is 

compensated; 

DSO is not

Wind generators 

may absorb costs for 

OMP.

CAISO Varies x Some contracts for RE

brought online before 

sufficient transmission 

include compensation

No compensation for 

reliability caused; or 

issues in 

interconnection 

studies

ERCOT No Wind generators are not 

compensated.

HECO, HELCO, 

MECo

No

ISO New 

England (ISONE)

No No market-based 

compensation, but 

off-taker contracts 

could have some

MISO Yes x Wind generators eligible 

for MISO’s make-whole 

payments; off-taker 

contracts may specify 

NV Energy Yes x Compensated for nonemergency situations, or 

those unrelated to 

reliability requirements

Curtailment not 

compensated under 

specific scenarios

 

10 Internationally, some countries compensate renewable generators for curtailment. Compensation varies by type of 

curtailment, amount compensated, and specific renewable technologies and jurisdictions. Most commonly, 

generators are compensated at the prevailing market value for the electricity curtailed, but this does not usually 

include revenue lost from green energy credits or other types of support mechanisms. Examples of this include 

Ireland and Romania. In other countries, generators are compensated for a fraction of the energy lost—varying from 

15% to 50% or more. For example, Greece compensates for 30% of annually curtailed energy, but the compensation 

only applies to wind facilities. Sometimes, compensation only applies to specific types of curtailments. An oftenused dichotomy is that congestion curtailments are compensated while those related to security are not. This is the 

case in Belgium and Germany. Spain uses another dichotomy: real-time curtailments are compensated (albeit only 

15%) while scheduled curtailments due to technical constraints are not. For more information on international 

curtailment practices, see Lew et al. (2013).
22 

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Utility or Grid 

Operator

Compensation 

Provided?

Limits 

Specified in 

Contracts

Reasons for 

Compensation

Limits to 

Compensation

PacifiCorp Unknown Unknown

PJM yes If wind curtailed below 

economic base point 

No compensation if 

wind resource is not 

providing required 

data and following 

PJM dispatch 

signals

PSCO Yes x Balancing purposes Transmission 

causes beyond 

control; limited 

annually

Puget Sound 

Energy

Follow BPA 

rules

Salt River 

Project 

Yes Take-or-pay contracts

SMUD Yes If CAISO curtails due to 

oversupply, SMUD 

compensates.

SPP Yes (changing 

with new 

market rules)

x Congestion-based 

curtailment has been 

compensated.

No compensation for 

reliability-based 

curtailment 

Tucson Electric 

Power 

Yes x For reasons under TEPs 

control

No compensation for 

curtailments caused 

by others

WAPA No

Compensation for curtailed energy is typically negotiated and stipulated in PPAs between the 

off-taker and the generator on an individual basis. Under “take-or-pay” contracts, the off-taker 

will pay generators for the energy curtailed and usually the value of lost tax credits (e.g., PTCs). 

Salt River Project is an example of a utility with take-or-pay contracts, as are older PSCO 

contracts. Under this type of contract, even if the curtailment directive is given by a system 

operator, the off-taker is responsible for compensation per the terms of the contract with the 

generator. In many take-or-pay contracts, curtailments due to congestion, scheduled 

maintenance, and oversupply may be compensated while those due to emergencies are not. 

Increasingly in some areas, PPAs include an annual curtailment quota before off-takers 

must compensate. 

A number of western utilities employ take-or-pay contracts, although more recent contracts have 

modified the bases for payment. For example, PSCO compensates generators if they are curtailed 

for balancing reasons, but newer PPAs generally do not compensate for transmission-related

curtailments. If PSCO curtails for balancing purposes, it will compensate generators for the 

energy that they would have produced plus the value of PTC earnings. However, PSCO has 

negotiated annual blocks of free (uncompensated) curtailment hours with 5 of the 14 wind plants. 

Other utilities have also placed limits on compensated curtailments. While APS generally 

compensates for curtailments unless the curtailment is a directive from other transmission 

operators, in some contracts, APS has included “emergency curtailment rights,” which allow 
23 

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APS to curtail a certain number of hours per year without compensation. NV Energy 

compensates for curtailment under specific situations but curtails wind without compensation to 

day-ahead forecasted levels when the utility cannot back down conventional resources. In 

Hawaii, there is no direct compensation for curtailment; rather, the cost of curtailment is built 

into the price of fixed-price contracts.

Compensation for curtailment in the BPA balancing area has changed over time and has been a 

subject of ongoing litigation. In 2012, BPA developed a mechanism for compensating 

curtailments related to hydro operations under the OMP, but the proportion of the cost to be 

shared by the generators is currently being debated in a BPA rate case. At the conclusion of that 

proceeding, it will be subject to review by FERC. BPA does not compensate for curtailments 

under its DSO 216 program, which can curtail wind projects to scheduled levels for balancing. 

In some wholesale power markets, there is no compensation for economic curtailment unless 

stipulated in bilateral PPAs between generators and off-takers outside of the market settlement 

mechanisms. Within the market, the decision to generate is based on the economics of dispatch. 

If a plant bids higher than the market clearing price, which for wind could occur if prices are 

negative, the plant is not dispatched and does not generate revenue. Some wind generators in 

market areas hold contracts with off-takers that allow for compensation outside the market, but 

the markets in AESO and ISO-NE have few off-taker contracts; therefore, compensation for 

curtailment is limited. 

Other grid operators will compensate at the prevailing settlement price if they issue verbal 

dispatch instructions to curtail generators below economic dispatch levels. For example, PJM 

will compensate for curtailment and provide make whole payments if automatic curtailment 

instructions are followed by wind generators. 

In some wholesale market areas, such as MISO, significant wind development occurred in 

advance of market designs that dispatch wind based on market-clearing prices. As a result, the 

transitions to markets that automate the dispatch of wind based on market clearing prices have 

affected contracts that were written to address manual wind curtailments. For example, the 

initiation of the DIR program in MISO affected the contracts between wind generators and offtakers that compensated curtailment. 

In SPP, contract language is also affected by the movement toward a more automated approach 

as an interim solution to reduce curtailments and the new market design in 2014. The 

modification to curtailment procedures—the interim solutionis intended to reduce curtailments

by increasing automation and reducing the stringency of protocols needed to address reliability 

events. The change in protocol necessitates that the curtailments be reclassified from reliabilitybased, which are typically not compensated, to congestion management events, which under 

many contracts would be compensated. Because this change will not be a formal directive, offtakers and wind generators will need to come to an agreement, and negotiations will likely result 

in reduced compensation for congestion management eventsa trade-off that would still be in 

the generators’ financial interests if overall curtailment levels were reduced as a result. 
24 

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4.4 Strategies to Mitigate Curtailment

Grid operators have developed a variety of strategies to minimize curtailment of renewable 

energy sources. These strategies are part of a broader collection of practices to manage the 

variability and uncertainty of variable renewable generation and thereby reduce curtailments 

(Schwartz et al. 2012; Cochran et al. 2012). The strategies highlighted in Table 6 are a subset of 

the broader suite of practices specifically cited in interviews as tools to reduce the magnitude and 

duration of curtailment. They include changes in the way reserves and conventional generation 

are managed, automation of curtailment signals, market design issues such as negative pricing, 

transmission planning, and renewable energy forecasting. 

Table 6. Strategies that Mitigate Wind and Solar Energy Curtailment 

Reserves and Generation Management Utilities or ISOs That Implement

Automation (i.e., AGC) ERCOT, PSCO

Use curtailed generators for positive reserves PSCO

Reduction of minimum generation levels HECO (Maui)

Increase scheduling frequency WAPA (adopting)

Market Integration and Negative Bidding Utilities or ISOs That Implement

Economic dispatch ERCOT, MISO, SPP (adopting)

Negative pricing CAISO, ERCOT, MISO, PJM, ISO-NE (adopting)

Energy imbalance market CAISO, PacifiCorp

Other Strategies Utilities or ISOs That Implement

Wind power ramp management system AESO

Increase transmission capacity ISO-NE, ERCOT, MISO, PJM, SPP

Improve forecasting ISO-NE, PSCO, NV Energy, SMUD 

4.4.1 Reserves and Generation Management

Utilities have adopted a number of strategies to change the way they manage system reserves and 

operate conventional power plants to help minimize curtailment. For example, PSCO has 

reduced total curtailments by putting many of its wind facilities on AGC and using them to help 

balance the system. 

PSCO also uses curtailed wind energy to provide positive reserves to utilize the otherwise 

curtailed wind whenever possible. PSCO has moved to cycle baseload generating units more to 

reduce instances of oversupply at night. In 2010, when there was a dramatic increase in wind 

curtailments primarily due to line outages, PSCO studied the costs of cycling baseload units 

versus curtailing wind. The costs were similar, so PSCO decided to cycle off thermal units at 

night to minimize wind curtailments. PSCO is also considering changing its use of pumped 

storage hydroelectricity.

To utilize more wind energy and reduce curtailment, HECO (Maui) has adopted multiple 

strategies, including reducing minimum loads on must-run units, running units at lower load 

levels, modifying units so that they can turn off daily, reducing reserves for quick start units, 

incorporating demand response into reserves, and running smart grid demonstrations that 

improve control over distributed solar. HECO has also begun programs to increase demand. 

HECO is installing 20 quick charging electric vehicle stations and developing eco-tourism 

through a fleet of electric vehicles (EVs), which will eventually be sold to the public. CAISO is 
25 

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also studying ways to shift load to different periods to absorb over-generation and is 

investigating options through conventional units, storage, and demand response. 

To reduce balancing-related curtailments (under DSO 216), BPA initiated a program (the 

Customer-Supplied Generation Imbalance Initiative) that allows wind generators to self-balance,

and it has expanded its intra-hour scheduling program. For oversupply-related curtailments 

(under OMP), BPA has implemented spill exchanges with non-federal hydro dams, asked the 

regional nuclear plant to schedule maintenance during the high season, maximized pump load 

during light load hours, and acquired additional reservoir storage. Also, BPA and others in the 

Pacific Northwest are discussing the potential implementation of an energy imbalance market, 

which would greatly reduce the need for wind energy curtailment and enable more efficient 

operation of the power system. 

4.4.2 Market Integration, Automation, and Negative Bidding

Several regions have integrated variable renewable energy generators more fully into the market

to enable economics to determine which generators curtail their output. For example, in mid2011, MISO implemented the DIR protocol. Thus, their operations are based on economic 

market dispatch. Similarly, ERCOT integrated wind into the market and replaced manual 

curtailments with an automated system that more efficiently uses market bids to set the order of 

dispatch. SPP is introducing a day-ahead market in March 2014 that will include wind generation 

and operate similar to the MISO program. In the near term, SPP is shifting toward a more 

automated system to implement curtailments to reduce the time that generators are curtailed, to 

address the prolonged curtailments that have occurred using manual processes. 

Negative pricing is used in several markets, including MISO and ERCOT, to address periods of 

oversupply and reduce manual curtailments. Enabling prices to go negative can discourage 

generators from bidding into the system during low load periods and reduce oversupply, and it 

can encourage flexible loads to increase demand because they get paid to use electricity. For 

example, with the expectation of higher renewable energy penetration levels in the future, 

CAISO is lowering the limit on negative bids from the current -$30/MWh, which is not sufficient 

to overcome the PTC incentive for wind to generate during oversupply periods, to -$150/MWh. 

If that were insufficient to address oversupply issues, the limit would be dropped to -$300/MWh. 

An energy imbalance market is under development by CAISO and PacifiCorp, which is 

expected, among other benefits, to reduce curtailments by automating processes and enabling 

better access to balancing resources in the region. Under the system, imbalance energy will be 

dispatched at 5-minute intervals. An energy imbalance market could reduce the need for 

curtailments by broadening the supply of resources available to balance renewable energy 

generation, more efficiently managing transmission resources to minimize congestion, and better 

managing wind ramps through an automated process rather than manual.

SMUD is working with CAISO on proposed market changes that would enable CAISO to curtail

unscheduled wind. SMUD is also seeking ways to increase the financial cost of congestion. 

4.4.3 Strategies to Address Ramping

AESO implemented in December 2011 a Wind Power Ramp Up Management system to manage 

wind ramps, in which a 10-minute cap can be placed on wind, when the system cannot handle 
26 

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wind ramping up. AESO has only used the tool for a few hours to date but expects the frequency 

will increase as wind penetration levels increase. 

APS is managing solar variability by including thermal storage on its Solana concentrating solar 

facility. The thermal storage allows the variability to be smoothed and shifted to meet evening 

peak load. 

Because of its large footprint, MISO can handle existing wind energy ramps now (at about 

13 GW of wind capacity) but anticipates this could be an issue when wind energy thresholds 

reach 20–25 GW. Similarly, the value of using curtailed energy for ancillary services is not yet 

economic, at least in MISO, for the majority of hours. 

4.4.4 Transmission Planning Methods

Transmission expansion activities are underway in a number of regions that have or are expected 

to reduce curtailment. ERCOT has expanded its transmission capacity under the CREZ program, 

which alleviated what had been the dominant cause for curtailments. Additional 345-kilovolt 

(kV) lines will be in service by 2014. MISO is also expanding its multi-value transmission 

projects to move wind to load centers and more robust parts of the grid. SPP is currently building 

new transmission capacity, an important tranche of which is expected to come online by mid2014 to 2015 and help alleviate curtailments. 

PJM has recently developed a light load planning process to ensure that the transmission system 

is capable of delivering the system generating capacity at light load, when wind generation is 

typically higher. Based on the new criteria, PJM identified a number of required baseline 

upgrades, the cost of which will be allocated to load, not to individual wind generators. 

ISO-NE has several plans that can mitigate curtailments, including expanding transmission 

capacity in Maine. ISO-NE plans to conduct wind interconnection studies in batches of wind 

plants, rather than individually, to provide more accurate information on impacts of multiple 

wind plants. This is currently done in PJM and MISO. 

4.4.5 Forecasting and Renewable Energy Visibility

Forecasting has been used by a variety of utilities and markets to manage wind on the system 

more efficiently. Widiss and Porter (2014) provide an overview of forecasting practices in the 

West. PSCO has undertaken a variety of strategies to accommodate increasing wind penetrations. 

Foremost is its improved use of forecasting. PSCO worked with the National Center for 

Atmospheric Research to improve its wind prediction models. Improved forecasting enables 

PSCO to turn down conventional resources when sufficient wind generation is predicted and to 

reduce curtailment from oversupply. Improved forecasting also eliminated curtailments related to 

ramping. NV Energy uses a few different forecasting services to improve short-term (i.e., 1–3 

hours) forecasting and avoid curtailments. 

ISO-NE plans to improve its wind forecasting to provide generators better information and 

enable them to participate more fully in the day-ahead market. Currently, lack of adequate 

forecasting impedes some wind farms from fully self-scheduling in the day-ahead market, and 

this in turn can restrict wind from producing at full capacity if day-ahead commitments fully 

meet demand. ISO-NE also plans to acquire more information on wind profiles at each station to 
27 

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be able to automatically and more precisely (at increments of every few seconds) provide not-toexceed instructions.

ISO-NE has initiated a Distributed Generation Forecast Working Group that will help improve 

visibility of distributed solar, which appears as reduced load, to help understand system changes 

that can influence unit commitment and balancing. ISO-NE wants to standardize reporting 

standards for distributed solar across states to help more accurately assess resources within 

the system. 
28 

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5 Conclusions 

While a greater number of regions are experiencing some form of curtailment of wind and solar 

resources, the relative magnitude of curtailment appears to be declining in the largest markets for 

wind power even as the amount of wind power on the system increases. New transmission 

capacity and better operating practices, such as greater automation and the use of forecasting and 

other operational practices, are now resolving challenges for grid operators, often circumventing 

the need for curtailment. As penetrations of wind and solar energy increase, curtailment practices 

and the use of strategies to mitigate the potential for curtailment may become increasingly 

important and may impact wind and solar energy project economics. Nevertheless, as wind and 

solar energy penetrations increase, there may come a time when changes in operating protocols 

would not lead to reduced curtailments, and rather that curtailment volumes could rise as a 

fraction of total wind and solar generation. 

Curtailment levels have generally been 4% or less of wind energy generation in regions where 

curtailment has occurred. A notable exception is ERCOT, where curtailment levels reached 17% 

in one year, primarily because wind generation came online ahead of transmission capacity. 

These levels have since receded to less than 2%. Many utilities in the western states report 

negligible levels of curtailment. The most common reasons for curtailment are insufficient 

transmission and local congestion, and excessive supply during low load periods. One challenge 

to determining curtailment levels is that data are not uniformly collected. 

Definitions of curtailment vary. Understanding curtailment levels can be complicated by 

relatively newly implemented market-based protocols or programs that limit wind generation to 

schedules. Now that economic dispatch is being used in several areas, wind generators can be 

dispatched down based on market prices, but this reduction of output is not characterized as 

curtailment. In some cases, wind generators are not able to exceed scheduled levels—a process 

that is referred to in the BPA balancing area as limiting output rather than curtailment. 

Curtailment order varies and is often based on plant economics or ability to alleviate local 

congestion. For curtailments that are needed to address balancing or system operations, the most 

expensive generators are often curtailed first. For wind projects, one consideration is whether the 

project utilizes the federal PTC or ITC. Generators reliant on the PTC, which is provided based 

on project output, face greater financial impacts from curtailment (the value of the PTC as well 

as the energy) than wind generators that received the upfront ITC. To address local congestion 

issues, curtailment is often applied equitably across generators that are most able to alleviate 

congestion. Hawaii provides preference to projects based on the order that they were installed 

(i.e., curtailing the most recently installed resources first), which limits the financial impacts and 

risks of curtailment for existing renewable energy facilities. 

Compensation and contract terms are changing for curtailment. Contracts between generators 

and off-takers have in some cases included provisions whereby the off-taker will compensate for 

curtailment for reasons such as congestion, scheduled maintenance, and operator errors, but 

typically not for curtailment ordered by other entities. However, contracts are increasingly 

reflecting a negotiated number of annual hours in which curtailments are not compensated, 

despite the cause, and there is greater sharing of risk between the generator and off-taker. In 

some cases, when new curtailment procedures are adopted, the need to renegotiate contract 
29 

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language has posed implementation challenges. In wholesale power markets, the grid operator 

sometimes compensates if it calls for units to deviate from initial dispatch orders. 

Automation can reduce curtailment levels. Manual curtailment processes for wind have been 

found to extend curtailment periods because of the time required to implement curtailment and 

hesitancy to release units from curtailment orders. Automatic communication procedures can 

speed the implementation of curtailment orders and reduce overall curtailment time. 

Market solutions that base dispatch levels on economics offer the advantages of creating 

transparency and efficiency in curtailment procedures, which apply equally to all generation 

sources. Programs like the MISO DIR utilize economic dispatch to determine which units will 

generate at a given time. During periods of oversupply, the use of negative pricing to determine 

dispatch order can eliminate the need for manual curtailments. Some wind developers have 

expressed a preference of the market-based dispatch framework because it reduces market 

distortions and allows wind generators to participate alongside conventional generators. The use 

of market-based approaches with their associated automation can also minimize curtailment by 

improving operational efficiency and reducing the burden on grid operators of implementing 

manual processes. 

Curtailed wind resources can provide ancillary services to aide in system operations. PSCO uses 

curtailed wind resources to provide both up and down regulation reserves for the balancing area. 

Wind turbines can provide quick response to signals, which can be valuable for the system. 

MISO assessed this and found it was economically viable only 2% of the time, however. ERCOT 

requires all wind turbines that can be retrofitted with governor response to do so in order to 

provide primary frequency response if they are curtailed. 

Transmission expansion and interconnection upgrades can be one of the most direct ways to 

reduce curtailments. ERCOT’s expansion of transmission in recent years through CREZ has 

alleviated wind generator curtailments. A key challenge is that renewable energy projects can be 

built much more rapidly than transmission lines. The CREZ program identified the need for 

transmission to particular regions to facilitate wind energy expansion. SPP is building new 

transmission capacity that is expected to alleviate current curtailment levels, while MISO is 

pursuing multi-value transmission projects to move wind to load centers and more robust parts of 

the grid. 

Forecasting can decrease uncertainty associated with wind and solar resources, reducing the 

need for curtailments due to unexpected changes. Improved forecasting can enable utilities or 

grid operators to turn down conventional resources when sufficient wind generation is predicted 

and to reduce curtailment from oversupply. Improved forecasting can also reduce curtailments 

related to ramping. Wind forecasting can provide generators better information and enable them 

to participate more fully in the day-ahead market. Improved data on wind profiles may help grid 

operators provide more precise not-to-exceed instructions, enabling increased wind generation 

output. Grid operators could also improve visibility of distributed solar, which appears to grid 

operators as reduced load, to help understand system changes that can influence unit 

commitment and balancing to minimize curtailments. 
30 

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Firming resources can decrease curtailments and increase financial certainty for generators, but 

they are not necessarily the most cost-effective system-wide solution. Iberdrola in BPA has found 

it more cost-effective to balance its own resources than it is to pay integration charges and be 

exposed to uncompensated curtailments under DSO 216. Nevertheless, developer-specific 

balancing, through options such as storage and natural gas, may likely be less cost-effective at a 

system-wide level than it would be for the utility or grid operator to adopt operating practices 

that minimize the need to curtail, such as dynamic reserves, negative pricing, and 

improved forecasting. 
31 

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References 

Apperson, John. (2013). Pacificorp, personal communication, August 6, 2013. 

Bartlett, Drake. (2014). Personal communication with Xcel Energy Renewable Energy Analyst 

providing curtailment data, September 11, 2013 and March 10, 2014. 

Blatchford, Jim. (2013). “View of the ISO,” Presentation to the Utility Variable Generation 

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2013. http://transmission.bpa.gov/business/operations/wind/ 

BPA. (2013b). Seasonal Power Oversupply in 2012, February 2013. 

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CO: National Renewable Energy Laboratory, 142 pp. Accessed December 16, 

2013: http://www.nrel.gov/docs/fy12osti/53732.pdf. 

Corbus (2014). Hawaii Integration Studies: Overview and Lessons Learned, NREL presentation. 

ERCOT (2013a). ERCOT Nodal Protocols Section 3: Management Activities for the ERCOT 

System. Revised Dec. 1, 2013 

ERCOT (2013b). ERCOT Nodal Protocols Section 4: Day-Ahead Operations. Revised Oct. 1, 

2013. 

ERCOT (2013c). Nodal Protocols Section 6: Adjustment Period and Real-Time Operations. 

Revised Oct. 7, 2013. 

Federal Energy Regulatory Commission (FERC) (2013) Order on Petition for Declaratory 

Order, 145 FERC P 61,150 (2013) at P 21.

Fink, S.; Mudd, C.; Porter, K.; Morgenstern, B. (2009). Wind Energy Curtailment Case Studies: 

May 2008 - May 2009. SR-550-46716. Golden, CO: National Renewable Energy Laboratory. 

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Lew, D.; Bird, L.; Milligan, M.; Speer, B.; Wang, X.; Carlini, E. M.; Estanqueiro, A.; Flynn, D.; 

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Altiparmakis, A.; Yoh, Y. (2013). Wind and Solar Curtailment: Preprint. CP-5500-60245. 

Golden, CO: National Renewable Energy Laboratory, 54 pp. Accessed December 16, 

2013: http://www.nrel.gov/docs/fy13osti/60245.pdf. 
32 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Lew, D.; Brinkman, G.; Ibanez, E.; Florita, A.; Heaney, M.; Hodge, B.-M.; Hummon, M.; Stark, 

G.; King, J.; Lefton, S.A.; Kumar, N.; Agan, D.; Jordan, G.; Venkataraman, S. (2013). The 

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National Renewable Energy Laboratory. Accessed October 7, 2013: http://www.nrel.gov/ 

docs/fy13osti/55588.pdf. 

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Regional Operations Engineering, via email, March 7, 2014. 

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Monitoring Unit, May 17. http://spp.org/publications/2012-State-of-the-Market-Report.pdf
33 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Widiss, R.; Porter, K. (2014). Survey of Variable Generation Forecasting in the West: 2013 

Update. NREL/SR-6A20-61035. Golden, CO: National Renewable Energy Laboratory. 

Wiser, R.; Bolinger, M. (August 2013). 2012 Wind Technologies Market Report. Berkeley, CA: 

Lawrence Berkeley National Laboratory. 

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February 3, 2014. http://www.snl.com/InteractiveX/Article.aspx?id=26708514 
34 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix. Summary of Curtailment Experiences of Utilities and Grid 

Operators

Table 7 summarizes the experiences of the utilities and grid operators that were interviewed for this report had with curtailment of 

renewable sources of energy. It includes including utilities that reported lower levels of curtailment.

Table 7. Utility and Grid Operator Experiences with Renewable Energy Curtailment 

Entity 

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Alberta Electric 

System Operator 

(AESO) 

10,600 MW peak 

demand11

Wind: 1,090

MW12

Curtailment occurs 

infrequently. Curtailments 

due to oversupply occur 

once or twice per year, 

lasting a few hours. 

Curtailments due to 

transmission constraints 

and outages are not 

tracked. 

Wind generators are not 

compensated. AESO is 

a deregulated market 

with no PPAs; wind 

generators receive the 

average pool price per 

hour (AESO does not 

use LMPs and instead 

settles at a single 

market-wide price).

AESO implemented in 

December 2011 a Wind Power 

Ramp Up Management system 

to manage wind ramps, in which 

a 10-minute cap can be placed 

on wind. But, AESO has only 

used the tool for a few hours. 

AESO uses SCADA to signal 

curtailments to wind 

generators.

If there are transmission 

constraints, AESO cuts the 

most expensive energy first 

from among all generators, 

including wind. Sometimes 

AESO will put a limit on a line 

and allow the relevant utility to 

decide what to curtail.

 

11 Jacques Duchesne interview – June 17, 2013 12 http://www.energy.alberta.ca/Electricity/682.asp, June 2013; communication from Jacques Duchesne – Jan 16, 2014
35 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Arizona Public 

Service (APS)

7,300 MW peak 

demand13 

Wind: 290 MW14

Solar: 348 MW15

(including 

distributed 

generation)

Curtailment occurs 

infrequently. Line 

overloads occur 2–3 times 

per year. Wildfires in 2013 

resulted in several weeks 

of local line outages. 

Curtailment is caused by 

single-time events (e.g., 

transmission outage, fire 

near transmission lines, 

line constraint). For 

example, the Solana 

Generating Station has 

been curtailed for a few 

hours due to problems at 

the delivery location.

Many solar facilities are 

connected to the 

distribution networks, 

usually at the substations, 

and in remote locations. 

On rare occasions, these 

substations are taken out 

of service for maintenance 

(lasting a few hours).

APS has primarily takeor-pay contracts and 

compensates for 

curtailments unless the 

curtailment is a directive 

from other transmission 

operators. APS has 

included in some 

contracts “emergency 

curtailment rights,” which 

allow APS to curtail a 

certain number of hours 

per year without 

compensation. 

APS is managing changes that 

have emerged from distributed 

solar, which has affected ramp 

rates needed to follow load. APS 

has found the ramps more 

difficult to predict. But variability 

from cloud cover is minimized 

because the solar is widely 

distributed over an 80-mile eastwest span. The Solana plant has 

thermal storage, which also 

allows the variability to be 

smoothed and shifted to meet 

evening peak load.

Schedulers call wind 

generators to issue curtailment 

directives.

 

13 Ronald Flood Interview- July 12, 2013 14 100 MW within APS’s balancing area (near Williams, Arizona); 190 MW (100 + 90) from two wind farms in a neighboring balancing area (in New Mexico) 15 Wind and solar installed capacity from APS January 2013 http://www.aps.com/en/Documents/pdf/company/RenewableEnergyPort.pdf
36 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Bonneville 

Power 

Administration 

(BPA) 

11,500 MW peak 

demand16

Wind: 4,515 

MW17

DSO 216 curtailments 

2012: 95 events, 683 MW 

total capacity per event; 

2013 January-June: 15 

events, 213 MW total 

capacity per event; 11,855 

MW

OMP Curtailments

2011: 97.2 gigawatt-hours 

(GWh); 2012: 49.7 

GWh 182013 YTD: 0 GWh 

Curtailment occurs:

(1) Under DSO 216 when 

balancing reserves are 

exhausted;

(2) Under the OMP when 

mandatory hydropower 

generation creates 

oversupply

DSO 216 events are not 

compensated. OMP 

curtailment is 

compensated, but wind 

generators may absorb 

some of the costs for 

compensation.

To reduce curtailments under 

DSO 216, BPA is considering 

purchasing balancing reserves, 

has installed 16 wind 

anemometers to provide data to 

wind operators at 5-minute 

intervals, created an internal 

wind forecast, and has initiated a 

program that allows wind 

generators to self-balance 

(Customer Supplied Generation 

Imbalance Initiative). 

For OMP, BPA has implemented 

spill exchanges with non-federal 

hydro dams, asked the regional 

nuclear plant to schedule 

maintenance during the high 

season, maximized pump load 

during light load hours, and 

acquired additional reservoir 

storage.

BPA uses different signaling 

methods, including SCADA 

ICCP, GenICCP, and SCADA 

RTU, as well as a Web 

application. 

 

16 GL_2013 Wind Integration AWEA Windpower.pptx, GL Garrad Hassan, Wind Power 2013: Integrating Wind in Future Markets 17 http://transmission.bpa.gov/business/operations/Wind/WIND_InstalledCapacity_Plot.pdf, April 13, 2013 18 BPA, Seasonal Power Oversupply in 2012, February 2013 
37 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

California 

Independent 

System Operator 

(CAISO)

50,270 MW

peak demand19

Wind: 6,000 

MW20

Solar: 2,800 MW

Curtailment is not tracked 

and is currently a small 

percentage of load.

 

The reasons for 

curtailment are not tracked 

but include transmission 

constraints and 

oversupply. Constraints 

include congestion, and in 

some locations, wind and 

solar were brought online 

in advance of sufficient 

transmission. Oversupply 

events have been 

exacerbated by a 

decrease in net load in the 

last five years due to the 

growth of distributed 

generation and because 

CAISO's portfolio contains 

a high number of nondispatchable generation 

units.

No compensation is 

offered for reliability 

reasons or issues 

identified in 

interconnection studies. 

For example, some of 

the contracts for wind 

and solar brought online 

in advance of sufficient 

transmission include 

provisions for 

curtailment.

CAISO received 

approval to curtail plants 

back to schedules, but 

otherwise, renewable 

energy generation is 

must-take based on a 

2010 FERC ruling.

CAISO has several strategies to 

mitigate curtailment from 

oversupply, particularly with the 

expectation of higher renewable 

energy penetration levels. 

CAISO will lower negative bids 

from the current -$30/MWh 

(which is not sufficient to 

overcome the PTC incentive for 

wind to generate during 

oversupply) to a two-step price 

structure: first -$150/MWh, and if 

that is insufficient, -$300/MWh.

CAISO is also studying ways to 

shift load to different periods to 

absorb over-generation, and 

investigating options through 

conventional units, storage, and 

demand response.

Additionally, CAISO is creating a 

scalable energy imbalance 

market (EIM) that allows 

balancing areas to share 

reserves and more costeffectively balance. 

Curtailments are based on 

effectiveness: generators that 

are most effective in relieving 

congestion will be curtailed 

first; if effectiveness is the 

same (e.g., between 

conventional and wind plants), 

the curtailment is split between 

them.

 

19 CAISO 2012 http://www.caiso.com/Documents/CaliforniaISOPeakLoadHistory.pdf, August 2012 20 Clyde Loutan Interview – August 23, 2013
38 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Electric 

Reliability 

Council of Texas 

(ERCOT)

68,000 MW peak 

demand21

Wind: 11,000+ 

MW

2013: 479 GWh, 1.6% of 

total annual potential wind 

generation22

2012: 1,038.0 GWh, 

3.7%23 

2011: 2,621.5 GWh = 

8.5%

Curtailment is a function of 

market bids—-when 

market-clearing prices are 

negative (e.g., due to 

oversupply or congestion), 

renewable energy 

generators that bid above 

the market-clearing price 

will not be dispatched. 

The treatment of 

compensation in PPAs is 

unknown.

Higher prices in west 

Texas have helped 

alleviate the financial 

impact of curtailments in 

that area.

ERCOT made two major 

changes to reduce curtailments: 

(1) Transmission expansion 

under CREZ, which alleviated 

what had been the dominant 

cause for curtailments. 

Additional 345-kV lines will be in

service by 2014.

(2) Market integration of variable 

renewable energy and use of 

negative prices. Curtailments, 

which had been conducted 

manually, have largely been 

replaced by an automated 

system in which market bids, 

including negative bids, set the 

order of dispatch.

ERCOT uses telemetry to 

signal base-point instruction to 

all generators every five

minutes. A ramp value is also 

provided every six seconds. 

ERCOT sends a flag to 

generators that need to be 

dispatched below the limit. 

Penalties occur for wind and 

solar generators when they 

are flagged and deviate from 

base point.

 

21 GL_2013 Wind Integration AWEA Windpower.pptx, GL Garrad Hassan, Wind Power 2013: Integrating Wind in Future Markets 22 Maggio (2014) 23 LBNL_2013_2012 Wind Technologies Market Report.pdf, page 44
39 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Hawaii Electric 

Co. [HECO], 

Hawaii Electric 

Light Co.

[HELCO], and 

Maui Electric Co.

[MECO]) 

2,237 MW peak 

demand:24

HECO: 1,200 

MW

MECO: 200 MW

HELCO: 195

MW25

Total wind: 206 

MW26

Total solar: 166 

MW27 (including 

distributed 

generation)

HECO: 100 MW 

wind,

28 135 MW 

solar

MECO: 73 MW 

wind, 31 MW 

solar

HELCO: 33 MW 

wind

Curtailment levels have 

been considerable in Maui 

(MECO) and on the island 

of Hawaii (HELCO) due to 

oversupply and negligible 

in Oahu (HECO). 

Curtailment in MECO and 

HELCO occur primarily 

during low load hours, 

which has been 

exacerbated by the rapid 

growth in PV installations 

(from single digits to 30 

MW over a few years). 

The small balancing areas 

with limited 

interconnection make it 

especially challenging to 

integrate renewable 

generation without 

curtailment.

HECO contracts do not 

compensate for 

curtailment, but the 

curtailment estimates 

are built into the 

contracts in the form of 

tiered pricing. For 

example, the contract 

with the third wind farm 

on Maui presumes 

around 40 GWh in 

annual sales (50% of 

potential). The price 

reflects revenue needed 

to cover the cost of 

capital at that generation 

level. If HECO can take 

more of that energy, the 

energy price for that 

amount is much 

cheaper.

The exponential growth in PV 

was not anticipated when the 

initial wind integration studies 

were conducted—-hence wind 

sales have been less than 

expected, and HECO finds itself 

buying net-metered PV at close 

to $0.40/kWh, which displaces 

less expensive wind.

To try to take more wind, HECO 

(Maui) has adopted multiple 

strategies to reduce curtailment, 

including reducing minimum 

loads on must-run units, running 

units at lower load levels, 

modifying units so that they can 

turn off daily, reducing reserves 

for quick start units, 

incorporating demand response

into reserves, and running smart 

grid demonstrations that improve 

control over distributed solar. 

HECO has also begun programs 

to increase demand. HECO is 

installing 20 quick charging EV 

stations and developing ecotourism through a fleet of EVs, 

which will eventually be sold to 

the public.

On Oahu and the island of 

Hawaii, system operators use 

SCADA to send curtailment 

limits. On Maui, AGC controls 

are used to curtail wind as 

needed if other units are at 

minimum. Maui also uses wind 

to provide down reserves.

Generally, curtailment is 

applied in reverse installation 

order. If a renewable energy

plant cannot produce at least 

60% of annual estimated 

energy production over four

years, the plant loses its 

curtailment priority over later 

entrants for the portion that 

could not be delivered. The 

exceptions are net-metered 

PV and feed-in tariff projects 

that are allowed to operate 

without curtailment controls 

and if a cause for curtailment 

is directly attributed to a 

specific facility, in which case 

reverse chronological order 

may not apply. 

 

24 http://energy.hawaii.gov/wp-content/uploads/2011/10/DBEDTEnergyFactSheets_6.13.12.pdf, Hawaii Energy Facts and Figures, June 2012 25 http://puc.hawaii.gov/wp-content/uploads/2013/04/RSWG-Facilitators-Report.pdf, p. 478, Reliability Standards Working Group, Silverstein, Alison 26 http://www.windpoweringamerica.gov/wind_installed_capacity.asp, Data derived from the American Wind Energy Association Fourth Quarter Market Report, 

December 2012

27 http://www.seia.org/state-solar-policy/Hawaii, Solar Energy Industries Association, 2012 28 Marc Matsuura Interview – August 8, 2013 
40 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

ISO New 

England (ISONE)

27,379 MW peak 

demand29

Wind: 700 MW30

Some individual plants 

have experienced 

substantial curtailments. 

The development of wind 

generation has occurred in 

western and northern 

Maine and northern 

Vermont—areas with 

strong wind resources, but 

low load, and transmission 

capacity (e.g., a single 

115-kV line) is inadequate 

to move the energy to 

higher load areas. Some 

of these areas also have 

hydro that competes for 

transmission capacity. 

Conditions are most 

challenging during 

spring—a confluence of 

low load, high wind, and 

strong hydro from snow 

melt. Northern Maine and 

Vermont also have weaker 

standards for voltage 

control—older wind plants 

do not provide necessary 

grid support—causing 

curtailments for voltage 

reasons. 

Ninety-three percent of 

all generation in ISO-NE 

are merchant-generators 

and are compensated 

exclusively from energy 

sold in the wholesale 

market; there is no 

market-based 

compensation for 

curtailed energy. If wind 

contracts directly with a 

utility off-taker, 

compensation for 

curtailment is unknown.

ISO-NE has plans to mitigate 

curtailments, including 

expanding transmission capacity 

in Maine. ISO-NE plans to 

conduct wind interconnection 

studies in batches of wind farms 

rather than individually to provide 

more accurate information on 

impacts of multiple wind farms. 

ISO-NE is working to improve 

visibility of distributed solar, 

which appears as reduced load. 

Currently, each state has 

different reporting standards for 

solar distributed generation, and 

ISO-NE wants to standardize 

this. ISO-NE also plans to 

acquire more information on 

wind profiles at each station to 

be able to automatically and 

more precisely (every few 

seconds) provide not-to-exceed 

instructions. Finally, ISO-NE will 

improve its wind forecasting to 

enable generators to more fully 

participate in the day-ahead 

market. Currently, lack of 

adequate forecasting impedes 

some wind farms from fully selfscheduling in the day-ahead 

market, and this in turn can 

restrict wind from producing at 

full capacity if day-ahead 

commitments fully meet demand.

Curtailments are pro-rated 

equally among affected 

generators for renewables that 

self-schedule in the day ahead 

market but must be curtailed in 

real time. 

In some cases, wind 

generators have not 

completed required upgrades 

to the network. These 

generators must back down 

first if local constraints are the 

cause for curtailment. Once 

upgrades (e.g., new breakers, 

lines) are complete, open 

access transmission dictates 

that all generation is treated 

the same.

During curtailments, grid 

operators call wind facility 

operators to provide new notto-exceed instructions.

 

29 ISO-NE Top 10 Demand Days, http://www.iso-ne.com/nwsiss/grid_mkts/demnd_days, accessed December 10, 2013 30 ISO-NE (2013), Summary of Wind Power and Curtailment in New England, June 28, 2013 http://www.isone.com/pubs/pubcomm/corr/2013/curtailment_summary_2013.pdf
41 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

ISO New 

England (ISONE)

To protect bat populations, 

some wind generators 

volunteered to self-curtail 

up to 120 nights/year, 

which they have since 

reduced to only nights of 

greatest concern for the 

bats. Wind generators also 

must curtail when ice 

forms on the turbines, and 

many are installing 

cameras to more quickly 

confirm ice-free status and 

come back online.
42 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Midcontinent 

ISO (MISO)

98,000 MW peak 

demand31 

Wind: 12,270 

MW32

Manual wind curtailments 

have fallen from nearly 4% 

in 2010 to about 0.2% in 

2013. Wind reductions 

from DIR plus manual 

curtailments have ranged 

from about 3-4%. 

Manual curtailment 

experienced by wind 

generators exempt from 

DIR protocol33

As in ERCOT, curtailment 

is a function of market bids 

for wind participating in 

DIR. Wind that does not 

clear the market price 

(e.g., due to negative 

pricing that results from 

oversupply or ramping 

constraints) is not 

classified as curtailment. 

Manual curtailments are 

caused primarily by local 

transmission congestion.

The introduction of DIR, 

with the shift from 

reliability-based 

curtailments to marketbased dispatch, affected 

contract language, and 

many contracts have 

been adjusted as a 

result. Also with DIR, 

wind generators are 

eligible for MISO’s 

make-whole payments if 

they follow dispatch. 

Despite the uncertainties 

created by this shift, 

developers that we 

interviewed preferred the 

market framework, 

which reduces market 

distortions and in which 

wind generators can 

participate as regular 

generators. 

In mid-2011, MISO implemented 

the DIR protocol, which requires 

all wind plants operating on or 

after April 2005 to bid into the 

real-time market. MISO is also 

expanding its multi-value 

transmission projects to move 

wind to load centers and more 

robust parts of the grid. 

For manual curtailments, 

reliability coordinators call 

wind generators and 

coordinate these directives 

with the local balancing area 

and transmission authority. 

Determination of curtailment 

order is based on who is 

impacting congestion the most 

and whether they have firm 

transmission service. 

 

31 https://www.misoenergy.org/Library/Repository/Report/IMM/2012%20State%20of%20the%20Market%20Report.pdf, 2012, p. ii 32 Rudd 2014; McMullen 2013, MISO, Presentation to UVIG Forecasting Workshop, February 33 Rudd 2014; McMullen 2013, MISO, Presentation to UVIG Forecasting Workshop, February
43 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

NV Energy North balancing 

area: 2,100 MW 

peak demand

South balancing 

area: 6,100 MW 

peak demand34 

Wind: 149 MW

Solar: 170 MW35 

Curtailment occurs 

infrequently. Oversupply 

during low load hours 

(early morning hours in fall 

and spring): NV Energy 

has curtailed generation to 

forecast but not yet below 

forecast, on 6–7 occasions 

over a calendar year. 

Each event lasts no longer 

than 2–3 hours and ends 

by the morning ramp.

Line outages (planned and 

unplanned) have also 

resulted in curtailments 

(e.g., in late summer 2012, 

two fires caused three

weeks of line outages that 

affected renewable energy 

generation). 

The PPA with wind 

includes a provision to 

curtail without 

compensation under 

specific scenarios, 

including curtailing 

output to day-ahead 

forecasted levels when 

NV Energy cannot back 

down conventional 

resources.

NV Energy uses a few different 

forecasting services to improve 

short-term (i.e., 1–3 hours) 

forecasting and avoid 

curtailments.

The operator sets the new notto-exceed instructions through 

the automatic system, and in 

tandem, calls the wind 

operation staff to explain the 

situation.

 

34 Communication from Rich Salgo, NV Energy, 1/17/2014 35 NV Energy 2013 Renewable Energy: https://www.nvenergy.com/brochures_arch/RenewablesBrochure.pdf, 2012 
44 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

PacifiCorp 9,830 MW peak 

demand36 

Wind: 2,500 

MW37 (1,000 MW 

owned, 1,000 

MW purchased, 

500 in balancing 

areas that are 

neither owned 

nor purchased)

The biggest reason for 

curtailment—much less 

than the 1% total annual 

production within 

PacifiCorp's balancing 

area—is transmission 

congestion (e.g., not 

enough export capability, 

transmission outage). The 

second reason for 

curtailment is ACE control, 

for example, if wind output 

increases quickly. In both 

instances, thermal is 

curtailed first, but if those 

plants cannot respond 

quickly enough, wind is 

backed down until thermal 

can respond (duration of 

minutes or tens of 

minutes, not hours). 

PacifiCorp's PPAs 

address compensation, 

but this information was 

not made public.

When PacifiCorp had 

two wind plants exposed 

to BPA's DSO 216 and 

OMP, PacifiCorp lost 

expected revenue most 

significantly from PTCs 

but also from energy 

sales and renewable 

energy certificates 

(RECs). 

In February 2013, PacifiCorp 

began telemetering its two wind 

facilities out of BPA's balancing 

area into its own.

PacifiCorp also plans to also 

enter into an EIM with CAISO, in 

which some wind generation will 

be dispatched by the EIM at 5-

minute intervals. In this larger 

footprint, wind ramps will be 

managed better automatically

(rather than manually). 

PacifiCorp's generation center 

can manually control wind 

output levels for wind facilities 

they own. 

The order of curtailment is 

based on the cost of the 

generators as well as 

contractual issues. 

 

36 Porter_2013_EIM Coordination CAISO PacifiCorp_UVIG presentation, slide 2, 2012 37 Interview w/ John Apperson of PacifiCorp 8/6/13
45 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

PJM 155,185 MW 

weather 

normalized 

summer 2013 38

Wind: 6500 MW 

Solar: 200–300 

MW, not 

including 

distributed39

Most curtailment is due to 

transmission constraints, 

particularly during 

maintenance periods. 

Oversupply is not typically 

a problem; PJM has 

negative pricing. 

PJM recently modified 

compensation protocols 

to compensate only with 

make-whole payments 

for curtailment when 

generators follow 

automatic base-point 

instructions. If a phone 

call is needed to 

implement curtailment, 

no compensation is 

provided.

PJM implemented forecasting 

and negative pricing in 2009. In 

2011, PJM implemented a lightload planning process to identify 

transmission reinforcements 

needed to improve generator 

deliverability. In 2013, PJM

modified compensation protocols 

to reduce reliance on manual 

processes to reduce curtailment. 

PJM sends curtailment flag to 

generators to follow base-point 

instructions down, and they 

follow these with a phone call 

to ensure the order is followed. 

They now have a “backcast” 

for assessing actual 

curtailment. 

Puget Sound 

Energy (PSE) 

5,000 MW peak 

demand 

Wind: 733 MW,

40

500 MW in BPA 

balancing area

Solar: 0.5 MW 

Wind curtailments in the 

PSE balancing area are 

minimal and are not 

tracked. Because much of 

PSE's wind fleet is in 

BPA's balancing area, 

PSE's generators are 

subject to OMP and 

DSO 216 curtailments. 

Curtailments happen 

infrequently in PSE's 

balancing area because 

wind is fully integrated and 

PSE has an hourly 

economic dispatch 

process. 

Facilities within BPA's 

balancing area receive 

compensation for OMP 

curtailments. Within 

PSE's balancing area, 

PSE has no PPAs with 

wind generators.

PSE is advocating for a regional 

EIM.

For BPA curtailments, BPA 

sends a signal via SCADA 

ICCP and requires 

confirmation from the wind 

facilities. 

 

38 PJM Load Forecast Report, January 2014. http://www.pjm.com/~/media/documents/reports/2014-load-forecast-report.ashx 39 Interview w/ Ken Schuyler and Dave Souder of PJM 12/19/13 40 Puget Sound Energy IRP_2013_Appendices.pdf, page D-7, 2012
46 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Salt River 

Project (SRP) 

6,660 MW peak 

demand41

Wind: 177 MW, 

including a 

contract for 50 

MW firm 

(backed) energy, 

which will end in 

201342 

Solar: 100 MW 

(60 MW rooftop; 

40 MW 

connected to 

transmission 

network)

Wind has been curtailed 

once or twice; solar has 

never been curtailed. Wind 

has been curtailed on a 

few occasions due to 

transmission or equipment 

issues and for 

maintenance. 

Currently, all PPAs in 

SRP are take-or-pay, so 

facilities are 

compensated.

Solar ramps have been small 

and more predictable than wind, 

although high, fast-moving 

clouds can cause spikes that are 

faster than the regulating 

machines. But installed capacity 

is still low enough that overall 

impacts are small, and SRP has 

not experienced difficulties 

forecasting load affected by 

distributed solar, even without 

good measurements of PV 

output. (Distributed solar output 

is estimated based on installed 

capacity factors). No additional 

mitigation strategies are 

planned.

To curtail, operators manually 

call the wind generator's 

control center.

Sacramento 

Municipal Utility 

District (SMUD) 

3,300 MW peak 

demand43 

Wind: 200–300 

MW in CAISO's 

service territory; 

none in SMUD. 

SMUD owns but 

does not 

schedule this 

wind. 

Solar: Significant 

PV (rooftop and 

farms): ~200 MW

SMUD does not track 

curtailments. 

SMUD is not affected by 

wind curtailments because 

CAISO ensures firming 

and fuel availability.

SMUD operations absorb 

variability of solar. For 

wind in CAISO, all 

curtailments have been 

transmission-related.

Some of SMUD's wind 

generation in CAISO is 

owned by third parties. If 

CAISO curtails due to 

oversupply, SMUD will 

fully compensate for the 

value of the lost 

generation and PTC; 

SMUD would absorb the 

loss of those.

 

SMUD is working with CAISO on 

a study on impacts of variable 

resources. SMUD's focus has 

been on how much thermal 

generation and hydro capacity it 

needs to compensate for the 

variability of renewable energy. 

SMUD is also working with 

CAISO on proposed market 

changes that would enable 

CAISO to not accept 

unscheduled wind. SMUD would 

also like to increase the financial 

cost of congestion and 

encourage merchants to develop 

better forecasting tools. 

 

 

41 http://www.srpnet.com/about/Facts.aspx#power, Fiscal Year (FY) 2013 May 1, 2012- April 30, 2013 42 Salt River Project – 7/15/13 – Mark Avery (Manager of Transmission Services) and David Crowell (Principal Analyst) (Interview) 43 SMUD Interview: Vicken Kasarjian and Mark Willis September 13, 2013
47 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Southwest 

Power Pool 

(SPP) 

47,142 MW peak 

demand44 

Wind: 7,790 

MW45

Unknown but isolated 

reports by generators to 

SPP have suggested 

curtailment levels as high 

as 40%–50% at some 

locations. Local 

transmission constraints 

are the primary cause for 

curtailment; wind 

generators connected to 

the grid ahead of planned 

transmission upgrades. 

Further exacerbating the 

curtailment levels 

historically have been the 

manual processes for 

imposing production caps. 

SPP manually called

control rooms at each 

affected wind farm to set 

new limits on dispatch. 

Because the notifications 

could consume 30–40 

minutes for a typical event, 

SPP has been reluctant to 

release these curtailments 

if they might be needed 

again soon, and wind 

generators might spend 

several days operating at 

curtailed outputs.

Reliability-based 

curtailments are typically 

not compensated. The 

proposed reclassification 

of most curtailments 

from reliability to 

congestion management 

affects contract 

language on 

compensation. 

To mitigate curtailments, SPP 

has been implementing a threephase approach:

(1) Automate and shorten 

curtailments by reclassifying 

them as congestion 

management, rather than 

emergency 

(2) Introduce a day-ahead 

market, which will include wind 

generation, similar to MISO (, 

March 2014)

(3) Build new transmission

(mid 2014–2015).

If a wind generator contributes 

5% or greater to a constraint, 

that generator is subject to 

curtailment. If more than one 

generator creates this impact, 

the curtailment is divided 

equally. SPP is reviewing the 

legality of prioritizing 

curtailments of multiple 

generators based on who has 

firm service. 

SPP curtails wind using threeway verbal communication.

Tucson Electric 

Power (TEP) 

2,300 MW peak 

demand

Curtailment occurs 

infrequently. Curtailments 

can take two forms: 

PPAs specify that events 

outside of TEP's control 

(e.g., outages, WECC 

curtailments) are not 

TEP currently does not 

experience difficulties with 

balancing as a result of its wind 

and solar—cloud impacts are 

TEP manually calls wind 

generators.

 

44 SPP-2012-State-of-the-Market-Report.pdf, p. 24, May 17, 2013 45 SPP-2012-State-of-the-Market-Report.pdf, p. 36, May 17, 2013
48 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Tucson Electric 

Power (TEP) 

Wind: 60 MW: 50 

in PNM control 

area, 10 in 

Unisource area46

Solar: 103 MW

(1) WECC-initiated 

curtailments can occur 

(but have not yet) if 

generation that uses 

TEP's transmission 

contributes to an 

unscheduled flow event in 

WECC. TEP would 

implement the curtailment, 

which is based on a set 

methodology (e.g., if a unit 

contributes to 20% of 

overload and WECC is 

curtailing the overload by 

half, WECC will curtail the 

20% contribution by half). 

This type of curtailment 

could occur in the future if 

TEP adds more remote 

generation, which might 

impact the qualified paths 

most at risk for WECC 

curtailment.

(2) TEP-initiated 

curtailments rarely occur; 

for example, once in 2012 

TEP curtailed two solar 

projects radially connected 

to the same distribution 

circuit when a breaker 

tripped. The event lasted 

about a half hour.

compensated. TEP 

compensates wind 

generators for 

curtailments based on 

events that occur under 

TEP's control (e.g., 

scheduled maintenance, 

operator errors, 

balancing).

The calculations used to 

assess compensation 

vary between wind and 

solar contracts. In 

general, wind payments 

are based on lost 

revenue (including 

electricity sales, PTCs, 

RECs). Solar 

compensation is based 

on the average 

generation over the 

same period before and 

after the incident. In 

future contracts, TEP 

might include 

"curtailment rights" (i.e., 

rights to curtail without 

compensation for a 

certain number of 

hours).

noticeable but manageable. As 

TEP adds wind and solar, it 

might import more power, 

allowing TEP to back off 

conventional generation and use 

that generation instead for 

regulation and ramping. If 

renewable penetration levels get 

so high that TEP cannot 

maintain balance, even with 

imports, TEP might curtail 

renewable energy generation to 

stay in compliance with ACE. 

 

46 Tucson Electric Interview - C. Tilghman July 25, 2013
49 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

WAPA 7,027 MW47" 

peak demand 

Wind: WAPA has 

wind in the 

balancing area, 

which it regulates 

but does not own 

or operate wind. 

They have 300 

MW installed and 

are expecting 

shortly another 

300 MW.

48

None. WAPA has 

experienced difficulties 

balancing wind when wind 

over-generates compared 

to schedule and WAPA 

needs to drive its units to 

minimum generation. The 

most challenging occasion 

occurred in May 2013 

when wind over-generated 

by 125 MW, and WAPA 

held its hydro below its 

preferred minimum 

necessary to meet water 

release restrictions. WAPA 

did not curtail the wind 

during this event because 

it is required under 

contract to regulate the 

wind, and this contract has 

no clause that allows 

curtailment for oversupply.

If wind over-generates, 

the operational entity 

where wind is located 

(e.g., Tri-State, Platte 

River) must pay energy 

imbalance charges. 

WAPA would like to make these 

charges more costly to 

encourage operational entities in 

the balancing authority to back 

down their coal and balance their 

loads. WAPA is also offering 15-

minute scheduling (a 

requirement of FERC). As more 

wind enters its administrative 

area, WAPA wants to ensure 

that new contractual 

arrangements will provide WAPA 

more control over schedules and 

provide utilities an incentive to 

balance their load.

WAPA calls the operational 

entities in the balancing area

but does not communicate

directly with wind farms.

 

47 on July 16, 2010, http://ww2.wapa.gov/sites/Western/newsroom/FactSheets/Pages/glance.aspx 48 WAPA Jeff Ackerman Interview September 13, 2013
50 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Xcel Energy / 

Public Service 

Co. of Colorado 

7,000 MW peak 

demand49 

Wind: 2,200 

MW50

Solar: 266 MW51

(includes utilityscale and 

distributed 

generation) 

Curtailment has been less 

than 2% of wind 

generation in recent years. 

The primary cause for 

curtailment in any given 

year varies between 

balancing (e.g., 

oversupply) and 

transmission (e.g., line 

constraints and outages). 

Ramping constraints had 

been a cause for 

curtailment before 

forecasting improved but 

are almost never a cause 

now. Curtailment levels 

peaked in 2010 due to 

transmission outages.

Costs and risks of 

curtailment are factored 

into PPAs, and 

compensation varies by 

both PPA cause. For 

transmission-related 

causes, wind generators 

under some older 

contracts are 

compensated, but the 

majority of contracts do 

not allow for 

compensation for 

transmission causes 

beyond PSCO’s control 

(PSCO will compensate 

for planned outages). If 

PSCO curtails for 

balancing purposes, it 

will compensate 

generators for the 

energy that they would 

have produced plus the 

value of PTC earnings. 

However, PSCO has 

negotiated annual blocks 

of free (uncompensated) 

curtailment hours with 5 

of 14 wind farms. 

Currently, PSCO holds a 

total of 60,000 

curtailment hours, but 

this drops to 30,000 by 

2018, at which time 

PSCO has taken many 

strategies to accommodate 

increasing wind penetrations. 

Foremost is its improved use of 

forecasting. PSCO has worked 

with the National Center for 

Atmospheric Research to 

improve its wind prediction 

models. Improved forecasting 

enables PSCO to turn down 

conventional resources when 

sufficient wind generation is 

predicted and to reduce 

curtailment from oversupply. 

Improved forecasting also 

eliminated curtailments related to 

ramping.

A second strategy to mitigate 

curtailments is to cycle coal units 

more. In 2010, when there was a 

dramatic increase in wind 

curtailments primarily due to line 

outages, PSCO studied the 

costs of cycling base load units 

versus curtailing wind. The costs 

were similar, so PSCO decided 

to cycle off thermal units at night 

to minimize wind curtailments.

Finally, PSCO has also put many 

wind facilities on AGC, which 

reduces total curtailments.

Previously, PSCO would curtail 

Curtailment to units on AGC is 

signaled through AGC. The 

rest of the facilities are 

curtailed manually by phone.

The order of curtailment is 

based on economics. PSCO 

will first curtail generators with 

which they have negotiated 

free curtailment hours; then, 

PSCO will curtail generators 

that do not receive PTC (older 

farms or ones that have 

elected the ITC in lieu of the 

PTC); next, PSCO will curtail 

generators on AGC (which 

allows more efficient 

curtailment); and finally, 

manually operated farms are 

curtailed based on random 

assignment. 

 

49 Drake Bartlett –Xcel Interview, August 23, 2013 50 Xcel Energy http://www.xcelenergy.com/Environment/Renewable_Energy/Wind/Colorado_Wind_Power, Accessed July 2013 51 At the end of 2012, Xcel Energy http://www.xcelenergy.com/Environment/Renewable_Energy/On_Our_System/Solar_Power_on_Our_System
51 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Entity

Total Peak 

Demand and 

Wind and Solar 

Capacity 

Current Wind and Solar 

Curtailment Levels and 

Reasons for Curtailment Compensation Mitigation Strategies Curtailment Procedures

Xcel Energy / 

Public Service 

Co. of Colorado 

many coal plants will be 

replaced by more 

flexible natural gas 

(which begin to come 

on-line in 2015).

in blocks (e.g., 100 MW) and 

balance with thermal units. Now 

PSCO can take thermal units to 

their minimum and balance with 

one wind generator on AGC 

(two-thirds of wind farms have 

AGC capability, but only one 

wind farm is needed on AGC at 

a given time due to their fast 

response). PSCO also uses 

curtailed wind energy to provide 

positive and negative reserves.

Looking forward, PSCO is 

advocating for an organized EIM, 

which will broaden and the 

supply of resources available to 

balance renewable energy 

generation. PSCO is also 

considering changing its use of 

pumped storage 

hydroelectricity—instead of 

pumping at night to serve peak 

load, PSCO may pump during 

the day during low net load 

periods to offset curtailment