Subcontract Report

NREL/SR-550-46716

October 2009

Wind Energy Curtailment

Case Studies

May 2008 — May 2009

S. Fink, C. Mudd, K. Porter, and B. Morgenstern

Exeter Associates, Inc.

Columbia, Maryland
National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393

303-275-3000 • www.nrel.gov

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

Office of Energy Efficiency and Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

Contract No. DE-AC36-08-GO28308

Subcontract Report

NREL/SR-550-46716

October 2009

Wind Energy Curtailment

Case Studies

May 2008 — May 2009

S. Fink, C. Mudd, K. Porter, and B. Morgenstern

Exeter Associates, Inc.

Columbia, Maryland

NREL Technical Monitor: L. Coles

Prepared under Subcontract No. LAM-9-99431-01
NOTICE

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iii

Acknowledgments

The National Renewable Energy Laboratory’s Electricity, Resources and Building Systems 

Integration office funded the research that went into this report. The authors thank Lynn Coles 

of the National Renewable Energy Laboratory for supporting this work.

We also thank Erik Ela of the National Renewable Energy Laboratory; Matthew Schuerger of 

Energy Systems Consulting Services LLC; Michael Goggin of the American Wind Energy 

Association; and Mark Bolinger of the Ernest Orlando Lawrence Berkeley National Laboratory 

for their review comments. Ken Schuyler of PJM; David Edelson of the New York ISO; Sean 

Egusa, Bart McManus, Eric King and Doug Johnson of the Bonneville Power Administration; 

Lisa Dangelmaier of Hawaii Electric Co.; Tom Ferguson of Xcel Energy; Alberto Cena of 

Asociación Empresarial Eólica; Ole Langniss of Fichtner GMBH & Co.; and Niels Ehlers of the 

Technishe Universitat Berlin for reviewing draft sections of the report. Finally, the authors thank 

Bruce Green of the National Renewable Energy Laboratory for his editorial assistance.
iv

TABLE OF CONTENTS

I. Introduction......................................................................................................................... 1

II. Wind Power Curtailment Examples in the United States................................................... 7

Electric Reliability Council of Texas.................................................................................. 7

PJM Interconnection ......................................................................................................... 12

New York Independent System Operator......................................................................... 13

Bonneville Power Administration..................................................................................... 15

Midwest Independent System Operator............................................................................ 18

Hawaiian Electric Company ............................................................................................. 20

Xcel Energy ...................................................................................................................... 22

Southern California Edison............................................................................................... 26

III. Wind Power Curtailment Examples outside the United States......................................... 27

Alberta Electric System Operator..................................................................................... 27

Spain ................................................................................................................................. 33

Germany............................................................................................................................ 38

IV. Summary........................................................................................................................... 46
v

LIST OF TABLES

1. Examples of Wind Energy Curtailment Practices in the United States.............................. 4

2. Example of Daily Operating Limits for Wind in ERCOT.................................................. 8

3. Minnesota Wind Projects Participating in Xcel Energy’s Wind Curtailment Rotation.... 22

4. Transpower Projects of the Dena Network Study............................................................. 41

5. Instances of Wind Power Curtailment on the E.On Netz Distribution System ................ 42

6. Control Area of Vattenfall Europe Transmission: Wind Power Specifications

for 2007............................................................................................................................. 45

LIST OF FIGURES

1. Estimated Capacity of Wind Curtailed Daily during the Peak Hour in ERCOT................ 9

2. Percentage of Wind Curtailed Daily during the Peak Hour in ERCOT as Compared to 

Daily Aggregate Wind Output ......................................................................................... 10

3. ERCOT Nodal versus Zonal Market System.................................................................... 11

4. Wind Generation in BPA: March 2002 – March 2009.................................................... 16

5. Frequency and Duration of Wind Curtailment in the Midwest ISO................................. 20

6. Curtailment as a Percentage of Total Wind Generation for Xcel Energy in Minnesota... 23

7. Annual Wind Curtailment Payments in Minnesota by Xcel Energy ................................ 24

8. Monthly Wind Curtailment Payments in Minnesota by Xcel Energy .............................. 25

9. The AESO Dispatchable Generation ................................................................................ 28

10. Number of Hours of Wind Curtailment by Day by the Alberta Electric System 

Operator ............................................................................................................................ 31

11. Number of Hours of Wind Curtailment by Month by the Alberta Electric System 

Operator ............................................................................................................................ 32

12. Number of Hours of Wind Curtailment by the Alberta Electric System Operator........... 33

13. Reasons for Wind Production Curtailments in Spain in 2008 .......................................... 35

14. Real-Time Wind Power Generation in Spain for November 1-2, 2008 ........................... 36

15. Capacity of Wind Curtailed by Month in Spain ............................................................... 37

16. Installed Wind Capacity in Germany................................................................................ 38

17. Number of Days with Grid Congestion in Vattenfall Transmission System.................... 43

18. Vattenfall Grid Extension ................................................................................................. 44
1

I. Introduction

Wind energy development has increased dramatically over the last decade. Over 8,500 

megawatts (MW) of wind came online in the United States in 2008, bringing total U.S. installed 

wind capacity to about 25,000 MW.1 This represents nearly a tripling in wind capacity just since 

2006. According to the North American Electric Reliability Corporation (NERC), another 

145 GW of variable resources (mostly wind) are in various stages of planning.2 While not all of 

this capacity will come online, the amount of variable resource capacity that is under 

consideration in the United States is quite significant. 

Investment in the nation’s electric grid has failed to keep pace with the sharp rise in 

installed wind capacity in the United States. Transmission construction over the last 10-15 years 

has also fallen short of growth in electric demand. Though development of new transmission 

now appears to be increasing, lack of transmission is currently a primary barrier towards the 

expansion of wind capacity, in no small part because high-quality wind resources are typically 

located in areas far from load centers. In addition, wind development can generally proceed 

much more quickly than new transmission projects, leading to a timing mismatch between wind 

development and new transmission. Due to these factors, wind curtailment initiatives appear to 

be on the rise. 

This paper presents a series of case studies on how wind curtailment is being used by 

different entities. To date, it appears that wind curtailment occurs for two primary reasons: 

1) lack of available transmission during a particular time to incorporate some or all of the wind 

generation; or 2) high wind generation at times of minimum or low load, and excess generation 

cannot be exported to other balancing areas due to transmission constraints. In these instances, 

wind generation may be curtailed after other generation is running at minimum and imports 

reduced or curtailed as well.3

 

Wind curtailment initiatives are at an early stage of discussion or implementation, and 

what wind curtailment is in place differs across the country and is reflective of the regional 

electricity market that is in place. One can roughly categorize wind curtailment into the 

following categories:

• Curtailment as Condition of Generator Interconnection − Whereby wind 

generators are required to agree to curtailments if transmission constraints or 

system conditions require it. E.On Netz in Germany, for instance, requires wind 

generators to accept “wind power management” for interconnecting in SchleswigHolstein and Lower Saxony until transmission upgrades are completed.

 1 American Wind Energy Association, “Wind Energy Grows by Record 8,300 MW in 2008,” January 27, 2009, 

http://www.awea.org/newsroom/releases/wind_energy_growth2008_27Jan09.html. 2 North American Electric Reliability Corporation, Accommodating High Levels of Variable Generation, April 

2009, http://www.nerc.com/files/IVGTF_Report_041609.pdf. 3 Not discussed in this paper are wind curtailments due to environmental reasons, such as for reducing or preventing 

bird and bat mortality. Wind projects in Altamont Pass in California are subject to periodic curtailments to minimize 

avian mortality. Recently, testing at Iberdrola’s Casselman wind project in Pennsylvania found that turning off wind 

generation during low-wind-speed times during bat migration times reduced bat mortalities by over 70%. 
2

• Contractual − Some utilities have included wind curtailments in power purchase 

agreements with wind companies, whereby utilities can curtail a certain amount of 

wind generation either at no cost or reduced cost. Other utilities may curtail wind 

and pay the wind generator for the lost value of wind power, and, in some cases,

the lost value of the federal production tax credit.

• Bid-based Curtailment − More recently, the New York Independent System 

Operator (ISO) and PJM are allowing wind generators to bid a price that includes 

their willingness to curtail operations. Because of the value of the federal 

production tax credit and renewable energy credits, the wind bids may be zero or 

even negative.

• Daily Operating Limits − Until recently, the Electric Reliability Council of Texas 

(ERCOT) imposed daily operating limits on wind projects in West Texas by 

calculating the amount of generation that could be reliably operated within the 

area based on the projected daily dispatch of generating units (including wind) in 

the McCamey region. With the planned addition of new transmission and the 

implementation of a nodal market in late 2010, ERCOT removed the daily 

operating limits for wind in West Texas and made all wind in Texas subject to 

ERCOT’s transmission congestion protocols.

• Differences by Type of Wind Technology — ERCOT also distinguished between

wind plants in West Texas as either rapid response wind farms (RRWF), which 

are wind resources that can respond within 15 minutes of getting a request, or

slow response wind farms (SRWF), which must respond within 30 minutes of 

getting a request. RRWFs tended to be newer wind farms with more advanced 

control capabilities. The RRWFs were allowed to operate above their daily limit 

(SRWFs were not), but had to reduce generation upon request if reliability issues 

arose. If RRWFs were asked to reduce generation to deal with the congestion in 

the following hour, SRWFs were required to reduce generation by more than their 

pro-rata share to allow the RRWFs to recoup some of the lost generation and the 

associated revenues.

• Reserves − Bonneville Power Administration (BPA) will consider curtailing wind 

power in an over-generation situation if 90% of BPA’s balancing reserves have 

been utilized. BPA assigns a maximum generation limit for variable generators if 

BPA is in an over-generation situation. Once 90% of BPA’s reserves have been 

utilized, variable generators that have substantially over-generated relative to their 

schedule will be required to reduce generation to a specified level. Variable 

generators that have substantially under-generated relative to their schedule will 

be curtailed down to actual levels.
3

Table 1 provides more detail on various wind curtailment initiatives in the United States. It 

should be noted that grid operators, either through interconnection agreements or operating rules, 

may curtail any generation (including wind) to maintain reliability, such as during emergency 

situations, transmission constraints, or minimum load situations. In addition, generator 

curtailment may be an agreed-upon condition for certain transmission arrangements. Under 

transmission service agreements in non-regional transmission operator (RTO) markets, for 

example, non-firm transmission service provides transmission service when the transmission grid 

is not constrained, and the transmission service is reduced or cut when the transmission grid is 

constrained. Conditional-firm transmission service is another example, where transmission 

service is firm except during certain times or can be curtailed by the grid operator for a certain 

number of hours annually.
4

Table 1.

Examples of Wind Energy Curtailment Practices in the United States

Description Constrained Operation 

Procedures

Amount 

Curtailed Compensation

ERCOT

Congestion is currently managed by 

ERCOT on a zonal basis. The majority 

of wind is near McCamey, in the 

western zone. ERCOT used special 

rules for this zone as transmission 

constraints limited transfers from 

the zone into the load centers in 

eastern Texas. ERCOT imposed daily 

operating limits for wind plants in 

the McCamey area based on 

projected generation and demand. 

This protocol was removed effective 

Sep. 1, 2009, in preparation for the 

transition to nodal markets.

ERCOT may call upon wind plants 

in to make reductions in output 

during periods of transmission 

congestion. New nodal market 

rules being implemented.

January to August 

2008, curtailed 

approximately 140-

150 MW about 45-

50% of the days, 

via restricted daily 

operating limits. 

From December 

2008 to July 2009, 

curtailed between 

500 MW and 1000 

MW daily, and at 

times curtailing up 

to 3000 MW daily. 

If McCamey area 

plants were called 

upon for

curtailment, 

ERCOT paid outof-merit energy 

payments, but 

only up to the 

daily operating 

limit. New nodal 

market rules 

being 

implemented.

Midwest ISO

No specific wind curtailment 

program. Will curtail wind during 

Minimum Generation Events along 

with other generation resources 

according to economic order.

During Minimum Generation 

Events, will order curtailments in 

the following order:

1. Generation identified through

the Reliability Assessment 

Commitment process.

2. Generation above the dayahead schedule from non-DNRs 

(Designated Network Resources).

3. Generation above the dayahead schedule from DNRs.

4. Non-DNR committed in the Day 

Ahead Market.

5. DNRs and firm imports

committed in the Day Ahead 

Market

No ISO-wide data 

available.

Locational 

marginal price 

(LMP) -based 

market, no 

additional 

compensation.

New York ISO

Wind integrated into real-time and 

day-ahead market dispatch. Wind 

bids price-quantity curve into realtime market and is dispatched 

economically along with other 

generation. Wind plants must 

participate in wind forecasting and 

be able to accept electronic 

basepoint dispatch signals.

During constrained operations 

generation will be curtailed 

according to economic bids. Wind 

plants must follow electronic 

basepoint dispatch signals within 

5 minutes or be assessed 

penalties for non-compliance.

No data available.

LMP-based 

market, no 

additional 

compensation.

PJM

Wind included in procedures for 

Emergency Events and Light Load 

Events. Wind curtailed along with 

other generation based on economic 

and emergency minimums. Wind 

assumed to have minimum of zero 

unless otherwise bid. Wind plants 

are required to participate in 

forecasting system and be able to 

accept electronic basepoint signals. 

During events, all generation 

reduced to economic minimums 

first. If additional curtailment 

needed, all generation reduced to 

emergency minimum levels. Wind 

plants are required to respond to 

electronic basepoint dispatch 

signals within 15 minutes or must 

notify PJM if they cannot respond 

that quickly.

No data available.

LMP-based 

market, no 

additional 

compensation.
5

Description Constrained Operation 

Procedures

Amount 

Curtailed Compensation

Bonneville 

Power 

Administration

Curtailment procedures included in 

wind Large Generation 

Interconnection Agreement for

system events. Wind plants required 

to participate in forecasting and be 

able to accept electronic basepoint 

signals.

When 90% of balancing reserves 

deployed, BPA can assign 

generation limits to wind plants 

based on scheduled output plus a 

pro rata allocation of balancing 

reserves. Wind plants must 

respond to electronic basepoint 

signals within 10 minutes or BPA 

can disconnect the plant. 

No data available. No 

compensation.

Hawaiian 

Electric 

Company

All wind plants are equipped with 

grid operator controlled curtailment 

interfaces. Grid operator sets 

electronic basepoint generation 

limits as necessary.

During system emergency events 

grid operator will use most 

effective control to address issue 

(such as reducing a specific wind 

plant output). During light load 

times, Must-Run Generators 

reduced to minimum levels, then 

As-Available Generators (including 

wind) curtailed according to a predetermined priority established 

via contractual agreements. 

No data available.

No additional 

compensation, 

curtailments built 

into contractual 

agreements.

Xcel Energy

Northern States Power MN (NSP) is 

in Midwest ISO and follows the 

Midwest ISO’s direction on whether 

curtailment is required.

Public Service of Colorado (PSCO) 

and Southwestern Public Service 

(SPS) have procedures to reduce all 

generation and prices/sales to 

minimum levels prior to ordering 

wind energy curtailments. 

NSP: agreements with wind plants 

in Southwest Minnesota to curtail 

on a rotational basis when 

required by Midwest ISO.

PSCO: contracts with wind plants 

to curtail a set amount per year on 

an as-needed basis. If additional 

curtailment required PSCO will call 

wind plants to reduce generation 

according to a schedule based on 

the day of the month.

NSP: about 23,000 

MWh in 2008.

PSCO: about 3,000 

MWh in 2008.

NSP: make whole 

kWh payments 

for both fixed and 

variable costs.

PSCO: contracted 

amounts are at 

no cost. 

Additional 

amounts made 

whole for energy 

plus Production 

Tax Credit.

Southern 

California 

Edison

Wind curtailment system in place for 

the Tehachapi region due to 

transmission constraints.

Agreement with Terra-Gen Power 

to reduce output on an as-needed 

basis.

About 15 MW for 

3-4 hours about 

every two days (or 

6-8% of the time). 

Make whole 

payment for 

energy.
6

Data on how much wind is being curtailed is difficult to obtain and inconsistent in format 

from grid operator to grid operator. ERCOT curtailed about 140-150 MW of wind for 45-50% 

of the days between January through August 2008. From December 2008 through July 2009, 

ERCOT curtailed between 500 and 1000 MW daily, and between 2500 MW and 3000 MW on 

some days between February and April 2009. BPA reported curtailing wind generation in July 

2008, although how much was curtailed is not known. Because of transmission issues, Xcel 

Energy curtailed 23,000 MWh of wind generation in the Midwest in 2008, at the direction of the 

Midwest ISO. From 2005 to 2007, nearly 5% of Xcel’s Minnesota wind generation was 

curtailed each year. Xcel Energy also made wind curtailment payments in Minnesota ranging 

from below $1 million in 2006 to nearly $6 million in 2007, then falling to $2.5 million in 2008. 

In Colorado, Xcel Energy curtailed about 3,000 MWh of wind generation in 2008. In Alberta, 

wind energy projects were curtailed for 860 hours in 2008. Southern California Edison estimates 

it curtails about 15 MW of wind generation for three to four hours every two days, or about 6-8% 

of the time, in the Tehachapi region, although the development of the $2 billion Tehachapi 

transmission project should ease (if not eliminate) the need for wind curtailment in that region. 

Wind curtailment has also occurred in Germany and Spain, although data on how much wind 

curtailment took place is also sparse. In 2007, 23.9 GWh of wind generation in Spain was 

curtailed, representing 0.09% of total wind production.

A key issue that will determine whether significant levels of wind power can be added is 

the availability of new transmission. High-quality wind resources tend to be in remote areas 

where the capacity of the transmission grid is inadequate relative to the available wind resource. 

Furthermore, there is a timing mismatch between the development of wind projects and the 

development of transmission projects, with transmission projects taking much longer than wind 

projects on average. Several transmission projects have been announced or are in planning that 

may accommodate thousands of megawatts of new wind projects by the time these transmission 

projects are in operation between 2013 and 2015. The timely completion of these transmission 

projects is by no means certain though, and wind curtailment will likely persist, if not worsen, 

until new transmission is available. Larger balancing areas, dynamic scheduling, and dynamic 

ratings of transmission lines may also reduce wind curtailment. 

This paper consists of a series of case studies that summarizes wind curtailment proposals 

and initiatives in the United States and abroad. To the extent possible, data on how much wind is 

curtailed is provided, although this data is not always easy to collect. The paper closes with a 

summary. 
7

II. Wind Power Curtailment Examples in the United States

Electric Reliability Council of Texas4

Texas has the most installed wind capacity of any state in the United States, with about 

8,000 MW in operation as of April 2009. Most of this wind capacity is in west Texas. Due to 

transmission constraints, ERCOT can accommodate only about 4,500 MW of wind, assuming 

there are no transmission outages.5 During periods of high wind production, generation can 

exceed the reliability limits on a given transmission line. ERCOT manages congestion on a zonal 

basis, and the generators that have the greatest effect on the constraint are typically curtailed 

first. 

Under its zonal system, ERCOT calculates a real-time market clearing price for energy 

(MCPE) every 15 minutes based on projected load and generator offers. ERCOT procures and 

schedules the amount of balancing energy needed for every 15-minute interval (paid the interval 

MCPE) through the market on a merit basis, awarding the opportunity to provide regulation 

energy to the lowest cost resources first. Because balancing energy is procured from the leastcost offers, the generators are not always optimally located and can lead to overloading of 

transmission lines in certain areas. To compensate for this, ERCOT also procures what is termed 

out-of-merit energy (OOME) from the units needed to alleviate congestion in a particular zone. 

Unit curtailments consist of OOME-Down instructions. In any given 15-minute interval, OOMEDown is paid the interval MCPE, i.e., the generator is compensated for lost production up to its 

scheduled output level. 

Conventional generators are required to operate within ±1.5% of their scheduled amount.

To accommodate wind energy variability, ERCOT granted wind generators the right to deviate 

from scheduled amounts by ±50%. This system created a perverse incentive for suppliers 

scheduling wind energy, leading them to over-schedule generation, which often resulted in them 

receiving additional OOME-Down payments.6 This was especially an issue in west Texas where 

transmission capacity is lacking to transport the energy from wind projects. From 2003 through 

August 2009, ERCOT assigned generation limits to wind projects in west Texas on a daily basis 

and OOME-Down payments were only made up to the daily limit. The way wind curtailment 

will be dealt with will change as ERCOT transitions to a nodal market system in late 2010. The 

nodal market will use locational marginal prices (LMPs) that factor in nodal congestion, and 

balancing energy procurement will become a market-based function (discussed in greater detail 

below).

Wind resources are particularly concentrated in the McCamey area in west Texas and 

thus, curtailment in this region is prevalent and until recently, was governed by special rules. 

ERCOT designated wind plants in McCamey as either RRWFs, wind resources that can respond 

 4 ERCOT declined to review this section. The information presented here is based on the authors’ understanding of 

wind curtailment in ERCOT.

5 Personal communications with ERCOT personnel, February 3, 2009. 6 R. Sioshansi and D. Hurlbut, "Market Protocols in ERCOT and Their Effect on Wind Generation," submitted to 

Energy Policy, http://iwse.osu.edu/isefaculty/sioshansi/papers/ERCOT_wind_mkt_design.pdf.
8

within 15 minutes of getting a request, and SRWFs, which must respond within 30 minutes of 

getting a request. RRWFs tend to be newer wind farms with more advanced control capabilities

(see Table 2). ERCOT currently procures balancing energy as spinning reserves and as nonspinning 30-minute reserves (on an as-needed basis). The variability of wind energy may require

response times shorter than 30 minutes, but of a long enough interval (10 to 15 minutes 

generally) that using spinning reserves is impractical and expensive. The RRWF plants can act in 

the shorter 10 to 15-minute interval, thereby reducing ERCOT’s need to maintain additional 

spinning reserves. Under the old protocol, ERCOT calculated a quantity of tradable generation 

rights (TGR), equivalent to the amount of generation that could be reliably operated within the 

McCamey area based on the projected daily dispatch of generating units in the region. The

TGRs, posted by ERCOT in the day-ahead market, were in the amount of the operating limits 

assigned to the wind plants for the next operating day. Tradability of the generation rights was 

not implemented, and plants were simply held to their operating limits, but concepts such as 

tradable rights are being discussed with regard to ERCOT’s proposed nodal market design. The 

daily operating limits protocol for the McCamey area was removed effective September 1st

, 

2009, in preparation for ERCOT’s nodal market.

Table 2.

Example of Daily Operating Limits for Wind in ERCOT

Wind Unit Name Capacity (MW) On-Peak Limit (MW) Off-Peak Limit (MW)

SW Mesa 75 67 65

Orion (RRWF) 83 82 78

Desert Sky 1 84 83 79

Desert Sky 2 77 76 73

Woodward Mount 1 (RRWF) 83 75 71

Woodward Mount 2 (RRWF) 77 69 66

King Mount NE 79 71 68

King Mount NW 79 71 68

King Mount SE 40 36 34

King Mount SW 79 71 68

Total 756 MW 701 MW 670 MW

Source: ERCOT, “Section 7.8 – Congestion Management in McCamey Area,” presentation for WMS Conference Call, 

May 31, 2007.

The RRWFs were allowed to operate above their daily limit (SRWFs are not), but would 

have to reduce generation upon request if reliability issues arose. During constrained periods, 

the transmission capacity was compared to the amount of TGRs in real time. If too many TGRs 

were present, meaning more generation was scheduled than could be accommodated by the grid, 

RRWFs were asked to reduce generation to deal with the congestion. In the following hour, 

SRWFs where then required to reduce generation by more than their pro-rata share to allow the 

RRWFs to recoup some of the lost generation and the associated revenues. On days that ERCOT 

was required to curtail wind from January through August 2008, the average amount curtailed 

was approximately 140-150 MW. ERCOT was required to curtail wind approximately 45-50%

of the days during that time period.7

 7 Personal communications with ERCOT personnel, February 3, 2009.
9

Data from December 2008 through July 2009 showed that ERCOT is curtailing a 

significant amount of wind power on a daily basis. Figure 1 indicates that ERCOT typically 

curtails between 500 and 1,000 MW of wind capacity daily during the peak hour, with much 

larger increases to between 2,500 and 3,000 MW on some days from February 2009 through 

April 2009. The wind curtailment is done in real time and does not include balancing down 

instructions that ERCOT sends as a result of ERCOT’s real-time balancing market. Furthermore, because only the peak hour is measured, not all wind curtailment throughout the day is 

represented.8

Figure 1.

Estimated Capacity of Wind Curtailed Daily during the Peak Hour in ERCOT

December 2008 – July 2009

Source: Estimated from Monthly Staff Presentations to the ERCOT Board of Directors, December 2008 through 

July 2009.

 8 For the data in Figures 1 and 2, ERCOT mostly used average wind output and wind curtailment for the peak load 

hour of the day, but for May and July, ERCOT used actual wind output and both resource-specific and portfolio 

curtailments averaged over the entire day. ERCOT said this will be the method they will use going forward. 

0

500

1000

1500

2000

2500

3000

3500

MW
10

Encompassing the same December 2008 through July 2009 period, Figure 2 depicts the 

proportion of wind that was curtailed daily as compared to the total amount of daily wind output. 

Although the percentage of wind curtailed in ERCOT varies considerably from day to day, it 

exceeds 30% on over 20 occasions, over 40% on nine days, and over 50% on one day.

Figure 2.

Percentage of Wind Curtailed Daily during the Peak Hour in ERCOT

as Compared to Daily Aggregate Wind Output

December 2008 – July 2009

Source: Estimated from Monthly Staff Presentations to the ERCOT Board of Directors, December 2008 through 

July 2009.

Transition to a Nodal Market

ERCOT is in the process of implementing a new market design by late 2010, designated 

the Texas Nodal Market, as directed by the Public Utility Commission of Texas (PUCT) in 2003

(see Figure 3). The Nodal Market will establish a day-ahead market for energy, ancillary service 

capacity, and certain congestion revenue rights, and will use LMPs at individual bus-bars. 

0.00%

10.00%

20.00%

30.00%

40.00%

50.00%

60.00%

12/1/2008 1/1/2009 2/1/2009 3/1/2009 4/1/2009 5/1/2009 6/1/2009 7/1/2009
11

Figure 3.

ERCOT Nodal versus Zonal Market System

Source: ERCOT, Understanding: Texas Nodal Market Implementation, January 23, 2008, 

http://nodal.ercot.com/about/kd/understandingNodal012308.pdf. 

In ERCOT, generators and load-serving entities (LSEs) do not always deal directly with 

ERCOT system operators. Generators and load-serving entities are represented by qualified 

scheduling entities (QSEs)9 that handle (among other things) scheduling and financial 

settlements. Currently, ERCOT does not have a day-ahead market for energy. Energy is 

scheduled by QSEs for the next operating day through bilateral agreements. ERCOT runs a 

separate ancillary services market for capacity for the next operating day. Under the nodal 

market, these two functions will be centralized into the day-ahead market, where ERCOT will 

clear the market for day-ahead energy and ancillary service capacity simultaneously. The current 

balancing energy system where generators receive OOME payments will also be replaced. The 

new Reliability Unit Commitment (RUC) process will ensure sufficient capacity is available at 

each node and will be calculated on a day-ahead and an hourly basis for each node. 

The new security-constrained economic dispatch (SCED) will settle the markets in realtime every 5 minutes using LMPs at each node. The SCED will dispatch individual resources

(including wind) throughout the grid in economic merit order, managing congestion and 

maintaining security on a nodal basis. Under a nodal system and with additional transmission 

being constructed to access wind energy in west Texas, the special rules governing the 

McCamey area plants will no longer be required. ERCOT is in the process of changing its 

procedures and wind management protocols to integrate wind into the nodal market system, 

where wind will be bid into the markets and treated in the same way as other generation 

 9 A generator or load-serving entity (LSE) can also be a QSE.
12

resources. A protocol revision request (PRR 810)10 was submitted in April 2009 and approved in 

August 2009, to remove the congestion protocols for wind projects in McCamey, and allow wind 

projects in west Texas to be treated in the same fashion as other wind projects in terms of their 

impact on transmission congestion in ERCOT. 

PJM Interconnection11

PJM encompasses all or parts of 13 states and the District of Columbia, and includes 

about 163 GW of generation. Wind makes up a small but growing generating resource in PJM, 

with about 2,200 MW of wind in operation and another 1,700 MW under construction.12

Generation facilities can choose to be capacity or energy-only resources. Wind generation 

facilities that choose to be counted as capacity resources and participate in PJM’s Reliability 

Pricing Model (PJM’s three-year forward capacity market) have their capacity value calculated 

annually based on historical performance during the three previous summers.13

In late 2008, PJM formed the Intermittent Resources Working Group (IRWG) to examine 

market, operational, and reliability issues associated with intermittent resources. The IRWG is 

developing recommendations for fully integrating wind energy into the PJM market. In June 

2009, PJM implemented changes to its dispatch software so that wind generators located in 

constrained areas receive an appropriate price signal to curtail generation. Additionally, PJM is 

initiating a wind forecasting program. In conjunction with the integration of wind power 

forecasting into PJM markets, IRWG will consider changes to how operating reserve charges are 

applied to intermittent resources. PJM selected a wind forecast vendor (Energy and Meteo 

Systems GmbH) and launched its wind forecasting system in April 2009. Ultimately, Energy and 

Meteo Systems GmbH will produce multiple forecasts, including hourly forecasts for the week 

ahead and short-term forecasts every five minutes for the operating day. 

Wind curtailment may be applied for two different market circumstances − during 

constrained operations and during light load events. During constrained operations, PJM curtails 

generation based on a cost-effective re-dispatch calculation. When more generation is needed, 

wind generators will not be dispatched upward, as they are assumed to be operating at their 

maximum economic generation. By contrast, during emergency events when generation needs to 

be reduced, wind units may be dispatched down. 

 10 ERCOT, PRR810 – Remove McCamey Congestion Management, approved August 18, 2009, 

www.ercot.com/.../810PRR-01_Remove_McCamey_Congestion_Management_040109.doc. See also ERCOT 

News: August Board Meeting Highlights; IMM Report, August 19, 2009, 

www.texasenergyreport.com/energypress/downloadep.cfm?dcid=45. 11 Much of the information in this section taken from PJM Intermittent Resources Working Group materials, 

accessed February 1, 2009, http://www.pjm.com/committees-and-groups/working-groups/irwg.aspx. 12 Sanjay Patil, “Wind Forecasting Process Development,” Presentation before the Utility Wind Integration Group 

Annual Meeting, Philadelphia, PA, April 2, 2009. 

13 A default 13% capacity value is the class average for wind facilities in PJM and is re-evaluated annually by PJM. 

For more information, see the following: PJM, Manual M-21, Rules and Procedures for Determination of 

Generating Capability, Revision 7, June 2008, available at: 

http://www.pjm.com/~/media/documents/manuals/m21.ashx. 
13

During constrained operations, wind generation is subject to curtailment if it has an 

impact of greater than 5% for contingency overloads and 3% for actual overloads. PJM will 

curtail wind down toward its Economic Minimum on a cost-effectiveness basis. When 

determining what generation should be re-dispatched or curtailed to manage congestion, PJM 

subtracts the generating unit bid price from the dispatch price, then divides the result by the 

generation shift factor as calculated by PJM in real-time.14 Curtailments will be based on the 

unit offer and lowest $/MW relief on constraint. Wind generation being lowered for a constraint 

may contribute to setting LMP. PJM wants wind plants to achieve the required curtailment 

within 15 minutes or within a timeframe that the wind farm technology permits. If the 

curtailment will take longer than 15 minutes, then PJM should be notified. Once economic redispatch is exhausted, PJM may request further curtailment of wind generation toward the 

Emergency Minimum limit if the constraint still exists. The Emergency Minimum for wind 

plants is set at zero. The Economic Minimum is also assumed to be zero unless some other value 

has been submitted by the wind generator based on blade feathering capability or other control 

limit. PJM allows all generators (including wind generators) to bid in negative prices; therefore,

wind plants can submit bid curves with negative prices. This may be desired due to federal 

production tax credits and the sale of renewable energy credits.

PJM publishes market notices if a light load event is expected. Light loads generally 

occur during the spring and fall, and sometimes on summer weekends. The market notice will 

explain what percentage of generation is expected to be reduced by market participants after all 

economic curtailment is utilized. In real-time operations, a Minimum Generation Emergency 

Event is initiated after all units are at Economic Minimum and additional generation reduction is 

required. During a Minimum Generation Emergency Event, all Emergency Reducible Generation 

(ERG) is reduced by an equal percentage (i.e., 20%, 30%, etc.), where the available ERG is 

equal to the Economic Minimum minus Emergency Minimum. PJM does not differentiate 

between resource types during a Minimum Generation Emergency Event. However, after all 

ERG has been utilized, PJM will consider the impact of directing wind to shut down prior to decommitting steam generation. PJM dispatchers can recommend that specific generating units not 

required for current area protection or not required for the subsequent on-peak period be shut 

down first.15 This is due to long turn-around times of baseload steam units that may be required 

for the next operating day’s on-peak period. 

New York Independent System Operator16

As of February 2009, the New York ISO’s (NYISO) total wind power capacity was 

1,274 MW and may reach 6,500 MW by 2011.17

 14 The generation shift factor predicts the effect of changes in generation on transmission line flow.

The wind development is located primarily in 

15 PJM, “Manual 13: Emergency Operations, Section 2: Capacity Emergencies,” Revision 36, Effective Date: 

June 30, 2009, http://www.pjm.com/documents/~/media/documents/manuals/m13.ashx. 16 Information in this section from the New York ISO, Integration of Wind into System Dispatch, A New York ISO 

White Paper, October 2008, 

http://www.nyiso.com/public/webdocs/documents/white_papers/wind_management_whitepaper_11202008.pdf. 17 NYISO press release, “NYISO Marks Wind Power Milestone,” February 26, 2009, 

http://www.nyiso.com/public/webdocs/newsroom/press_releases/2009/NYISO_Marks_Wind_Power_Milestone_02

262009.pdf. 
14

the northern and western regions of New York and there is typically insufficient transmission 

capacity to transfer the large amounts of wind expected in the area to the load centers of 

southeastern New York. NYISO anticipates that dispatching other resources around the 

availability of wind plant output, which has been the standard procedure, will soon become an 

inadequate solution and longer-term solutions are needed. The long-term solutions identified in a 

NYISO white paper released in October 2008 are:

• Facilitate the building of additional transmission to the north and west.

• Promote energy storage development to absorb the excess off-peak power.

• Implement new operational rules.

NYISO is working on all three solutions and in early 2009 started implementing their 

new market rules for variable resources. In moving to a more market-based system for operation 

of wind power facilities, NYISO anticipates having more efficient dispatch orders during 

constrained periods. NYISO’s new dispatch system went into operation in May 2009.

Under the new dispatch procedures, NYISO evaluates each generating resources’ 

(including wind) economic preferences based on their submitted offers to determine the leastcost means of meeting load requirements while maintaining reliability. This transforms NYISO’s 

wind plant control method from one of manual curtailment-upon-need to a market-based wind

plant management system. NYISO integrated wind plants into its economic dispatch to ensure

they will be treated like all other generators. 

In the NYISO market, conventional generators indicate their willingness to re-dispatch 

through their economic offers. Under the new procedures, wind plants are required to submit 

economic price curves into the real-time market, which are due 75 minutes before each operating 

hour. These price curves, or bids, consist of price-quantity pairs that indicate the LMPs at which 

the wind plant would prefer to operate. Up to 11 price-quantity pairs can be submitted each time 

and they can vary each time. Recognizing that wind plants cannot offer to increase production, 

the offers from wind plants indicate the prices below which a wind plant no longer wants to 

produce. NYISO’s Security Constrained Economic Dispatch software (SCED) can accommodate 

both zero and/or negative offers and prices in its algorithm. NYISO evaluates all generator 

offers, including wind, and the load forecast to produce a least-cost dispatch solution every 

5 minutes. If NYISO is transmission constrained, NYISO will select the most economic solution 

for curtailment. 

During unconstrained operation, wind plants will operate as normal and be paid for all 

their output, as per the NYISO special market rules for renewables. When the wholesale markets 

first opened, NYISO created special market rules for intermittent renewable resources that

exempt wind and run-of-river hydro units from financial penalties for deviations from expected 

schedules, up to a maximum installed capacity of eligible renewable energy capacity. The initial 

cap on the total amount of renewable resources that could operate under the special market rules 

was set at 500 MW, but was increased to 1,000 MW in 2006 and to 3,300 MW in 2008. 

During constrained operating periods, NYISO will provide an electronic re-dispatch 

signal arising from its market-based economic solution. The least-cost economic solution will be 
15

calculated from all generation offers, including wind plant offer curves. The price-quantity offers 

submitted by each wind plant will determine the basepoint amount set for each plant. If they are 

not fully economic, wind plants must follow the re-dispatch signal and meet the basepoint output 

limit within 5 minutes. Wind plants will be paid for their output at or below the re-dispatch 

basepoint. If a wind plant does not respond to the market basepoint and reduce output 

accordingly, a financial penalty will apply. The penalty structure is as follows:

MWs above basepoint * Regulation Clearing Price

NYISO allows a 3% bandwidth margin for error, based on the wind plants’ upper operating 

limit. 

Bonneville Power Administration

As of March 2009, BPA has over 2,000 MW of installed wind power capacity connected 

to its 10,500 MW peak load balancing area, and expects that amount to double within the next 2 

to 3 years. BPA expects to experience wind penetration rates by capacity of up to 30% in 2009, 

with projections of up to 39% penetration by 2010 (see Figure 4).

18 Additionally, many of the 

wind projects are in the same general area, the Lower Columbia region, which means wind 

generation tends to move up and down together, leading to large swings in wind generation. To 

date, BPA has provided balancing from its hydro plants, but with the projected addition of wind 

power projects in the next two years, the ability of the hydro system to balance the BPA grid is 

becoming more limited. A lack of sub-hourly markets in the Pacific Northwest also makes wind 

integration more difficult. 

In July 2008, a large increase in wind power taxed the availability of BPA’s balancing 

reserves and BPA’s calls to wind producers to request curtailment mainly reached answering 

machines. BPA succeeded in getting only one wind farm to curtail production.19

• Building (and financing) new transmission to interconnect remote renewable 

resources to load centers;

Since this 

occurrence, BPA has implemented new procedures and communications systems, and has had 

full compliance whenever BPA has called on wind plants to limit output. BPA is working with 

other regional stakeholders through the Wind Integration Team (WIT) on integrating increasing 

amounts of wind energy into the transmission grid by:

• Revamping the way BPA operates its grid to work with large amounts of variable 

generation; and

• Creating new wind energy-friendly business practices and working with other 

utilities across the Western Interconnection to find regional solutions. 

 18 Silverstein, Brian, Bonneville Power Administration, “Integrating Renewable Resources Into the Electric Grid,” 

presentation before the FERC Technical Conference on Integrating Renewable Resources into the Wholesale

Electric Grid, March 2, 2009. 19 Kinsey Hill, Gail, “Wind power surge forces BPA to spill at Columbia Basin dams,” The Oregonian, July 5, 2008, 

http://www.oregonlive.com/environment/index.ssf/2008/07/columbia_basin_river_managers.html. 
16

Figure 4.

Wind Generation in BPA: March 2002 – March 2009

Source: Bonneville Power Administration, How BPA Supports Wind Power in the Pacific 

Northwest, BPA Fact Sheet, March 2009, 

http://www.bpa.gov/corporate/pubs/fact_sheets/09fs/BPA_supports_wind_powe

r_for_the_Pacific_Northwest_-_Mar_2009.pdf.

The WIT established a new Work Plan in early 2009, focusing primarily on the following 

critical areas:

1. New operating protocols − BPA has already established protocols in Dispatch 

Standing Orders to limit variable generators, as outlined in the Wind Integration 

Team’s report.

20

 20 Bonneville Power Administration, Connecting Variable Generating Resources to the Federal Columbia River 

Transmission System (FCRTS), January 29, 2009, 

This approach for dealing with over-generation (and other 

situations) has been incorporated into their Large Generator Interconnection 

Agreements for variable resources. In over-generation situations, balancing reserves 

will be utilized first to restore the load and generation balance. However, after 90%

of all balancing reserves are deployed, BPA may require variable generators such as 

wind plants to limit wind output in order to reduce excess generation or curtail

schedules to actual generation plus a reserve allocation. In such situations, variable 

generators are assigned a maximum generation limit based on their scheduled 

output plus a proportional allocation of balancing reserves. The following protocols 

will be used to limit variable generators when 90% reserve deployment is reached:

http://www.bpa.gov/corporate/windpower/docs/Connecting_Variable_Generating_Resources_to_Grid_Mar_5_final.

pdf. 
17

• Variable generators that have substantially over-generated relative to their 

schedule will be required to reduce generation to a specified level.

• Variable generators that have substantially under-generated relative to their 

schedule will have schedules curtailed to actual levels plus the allocated 

amount of reserve.21

BPA is also automating its dispatch process to signal variable generation operators 

to feather their turbines to comply with an order to reduce generation within ten 

minutes. If a variable generator fails to respond to three orders within a two-year 

period, BPA requires automatic generation control equipment to be installed at the 

site to allow BPA to send a generation limit directly into the wind facility’s 

controlling computer.

BPA has also launched an Internet application known as Generation Adviser to 

monitor the current balancing reserves limit, the amount of balancing reserves that 

are in use, and certain limit and curtailment alarms. A warning alarm will sound if 

either incremental or decremental (i.e., inc or dec) balancing reserves exceed 85% 

for 30 seconds continuously, and a limit alarm if 90% or more of the inc or dec 

balancing reserves are in use for 30 seconds continuously. 

2. Wind forecasting − BPA and wind operators are also working to create a more 

accurate wind forecasting system to provide more up-to-the-minute scheduling data 

for dispatchers. BPA is installing 14 additional meteorological devices to assist the 

wind operators and forecasting companies in creating better forecasts of wind 

output. BPA plans to begin within-hour in-house wind forecasting by May 2010.

3. Sub-hourly scheduling pilot − BPA is developing systems and processes that will 

enable schedule changes on a sub-hourly basis. Market participants will be able to 

schedule excess wind generation from the BPA balancing area on the half-hour, 

making it possible for excess power that may have needed to be limited, to be sold 

instead. By December 2009, BPA plans to start offering reservation and 

transmission scheduling and power exports on half-hour intervals for the excess 

energy.

4. Dynamic transfer limits study − BPA is working with other utilities to develop new 

power dispatch protocols and scheduling systems so that BPA-region wind plants 

can be electronically controlled and supported by adjoining balancing authorities. 

This work will begin with a comprehensive study to evaluate the criteria and 

necessary requirements on four specific paths; the Northern Intertie, Southern 

Intertie, Idaho to Boardman, and Libby to Garrison. 

5. Customer supplied generation imbalance − Some wind plant owners have expressed 

interest in self-supplying some capacity reserves to reduce their reliance on BPA 

 21 Silverstein, Brian, Bonneville Power Administration, “Integrating Renewable Resources Into the Electric Grid,” 

presentation before the FERC Technical Conference on Integrating Renewable Resources into the Wholesale 

Electric Grid, March 2, 2009.
18

reserves (and associated charges). BPA will begin examining systems and processes 

that could be implemented by October 2010 to allow customers to supply a portion 

of their own generation imbalance service either from their own resources or 

through contracts with other resource owners. 

6. Third-party supply pilot − BPA is proposing to examine balancing area reserve 

augmentation through the use of third party supply of within-hour balancing 

reserves that would respond directly to BPA’s Automatic Generation Control 

signal.22

Midwest Independent System Operator

The Midwest Independent System Operator (ISO) has over 6,500 MW of wind capacity 

and total installed generation capacity of over 159,000 MW. A new wind outpeak record of 

5,280 MW was set on September 28, 2009. In late 2008, the Midwest ISO formed the Minimum 

Generation Task Force (MGTF), a stakeholder process to examine minimum generation 

situations and provide input, policy guidance, and recommendations on how to best mitigate and 

deal with issues that arise during surplus situations. The Midwest ISO reported 17 minimum 

generation events in 2008, a significant increase over past years.23 The Midwest ISO speculates 

this is partly due to the increasing levels of wind energy in the Midwest ISO footprint and a 

decrease in the ability of certain baseload coal units to be able to reduce generation as a result of 

the addition of NOx controls.24 

The MGTF has evaluated previous minimum generation events and continues to evaluate 

new events as they occur. The MGTF is in the process of developing recommendations for 

changes to grid operating procedures and market rules that may help mitigate the impacts of 

and/or reduce the frequency of future minimum generation events. Possible items to be reviewed 

may be how import and export schedules are treated (including ramp limit adjustments) during 

supply surplus situations, an examination of how to better utilize price signals or LMP 

adjustments leading up to an event, and possible changes to the market rules associated with 

intermittent resources.

25 At an MGTF meeting on May 27, 2009, there was discussion of 

potential tariff changes to mitigate the key drivers of minimum generation events. These drivers 

include the persistence of price signals (e.g., imports/exports, economic/emergency minimum 

prices, and pumped storage, etc), the unit commitment process (timing and amount), wind 

generation (e.g., more in real time than was cleared in the day ahead market), and forecast errors 

(load and wind generation). The priority is on getting the price signals correct during Minimum 

Generation Events and then letting the market work.

 22 BPA, Work Plan cover letter, June 16, 2009, 

http://www.bpa.gov/corporate/WindPower/docs/Work_Plan_cover_letter,_June_16,_2009.pdf. 23 Midwest ISO, Forecast Accuracy & Impact of Min Gen Events. November 5, 2008, 

http://www.midwestiso.org/publish/Folder/45e84c_11cdc615aa1_-7eb10a48324a?rev=2. 24 Midwest ISO, Midwest ISO Stakeholder Governance Guide, Appendix E, Proposal For Minimum Generation 

Task Force. October 15, 2008 (draft), 

http://www.midwestiso.org/publish/Document/45e84c_11cdc615aa1_-7c560a48324a?rev=1. 25 Ibid.
19

The Midwest ISO’s Emergency Operating Procedures include protocols for supply 

surplus events. A Minimum Generation Emergency Alert is issued if system load and 

interchange are expected to fall to within 2,000 MW of minimum non-emergency scheduled 

supply. This alert initiates reviews of unit commitment and dispatch operations, and asks 

generation operators to verify preparedness to operate at emergency levels. A Minimum 

Generation Emergency Warning is issued if system load and interchange are expected to fall 

below the non-emergency minimum. A Minimum Generation Emergency Event (Min Gen) is 

declared when the short-term forecasted load and interchange falls below non-emergency supply. 

This allows the Unit Dispatch System to utilize the emergency range of online resources. If this 

action is insufficient, generation may be de-committed. In March 2009, the Midwest ISO 

implemented a “short term” interpretation of the current Min Gen curtailment procedures to 

mean that resources with the “shortest restart time” (i.e., variable resources such as wind) are 

always curtailed first when an event stage is reached and the emergency ranges in the first phase 

of the event stage are not sufficient. A Min Gen event occurred on June 1 that lead to intermittent 

resources being curtailed at 4:05 AM for about two and a half hours. The event was declared at 

1 AM and by 4 AM the Midwest ISO had reduced all their conventional units to minimum 

emergency dispatch levels. The Midwest ISO then asked for 100 MW of intermittent resource 

curtailments pro rata across the on-line units. 

In early May, the MGTF approved non-tariff changes to the Emergency Operating 

Procedure for Supply Surplus (RTO-EOP-003, Min Gen) that include a curtailment sequence 

which comes close to treating wind similar to other technologies. If curtailments are required,

de-commitment of generation or reduction in scheduled generation will be executed in the 

following order:

1. Generation identified in the Reliability Assessment Commitment process.

2. Generation above the day-ahead schedule from non-DNRs (designated network 

resources).

3. Generation above the day-ahead schedule from DNRs.

4. Non-DNR committed in the Day Ahead Market.

5. DNRs and firm imports committed in the Day Ahead Market.26

Within each of these groups, the generation shall be de-committed in reverse economic 

order regardless of the type of resource. The procedure changes were presented to the Market 

Subcommittee and the Reliability Subcommittee and are now in the next step of the Procedure 

Review Process. As currently written, this version of the Supply Surplus Procedure would 

replace the “short term” interpretation that disadvantages intermittent resources.

The Midwest ISO has a separate set of procedures if generation curtailment is necessary 

because of transmission congestion. If a generator is coming online but is not yet considered 

commercial, test energy will be curtailed first before LMP Binding Procedures and Transmission 

Loading Relief (TLR) are imposed. If transmission congestion is local and not impacted by any 

other generator, then wind is normally curtailed on a pro-rata basis by order of transmission 

priority. If the transmission congestion is regional and can be addressed or is impacted by other 

 26 Midwest ISO, Midwest ISO Supply Surplus Procedures, RTO-EOP-003-R9, effective date: January 6, 2009, 

redline version, not yet fully approved or implemented, accessed June 8, 2009. 
20

generators, the TLR process is used first. If that does not provide sufficient relief, then wind 

may be manually curtailed on a pro-rata basis in order of transmission priority. 

Figure 5 presents the number of hours and instances that the Midwest ISO has curtailed 

wind between January and June of 2009. Note that because the data includes multiple wind 

facilities, the total number of curtailed hours may exceed the hours in a month. 

Figure 5.

Frequency and Duration of

Wind Curtailment in the Midwest ISO

January – June 2009

Source: Midwest ISO, “Wind Resources—Underutilized Flexibility,” presentation before the Midwest ISO Wind 

Workshop, September 29, 2009, http://www.midwestiso.org/publish/Document/6b6059_1239ec7b046_-

78210a48324a/Underutilized_Wind_Flexibility.pdf?action=download&_property=Attachment. 

Hawaiian Electric Company

The Hawaiian Electric Company (HECO, serves Oahu) along with its subsidiaries, the 

Hawaii Electric Light Company (HELCO, serves the Big Island) and the Maui Electric Company 

(MECO, serves Maui, Lanai, and Molokai) provides electricity service to most of the Hawaiian 

Islands. Installed capacity in the control areas as of August 2008, was: 

0

20

40

60

80

100

120

140

160

180

January February March April May June

# of instance curtailed

0

200

400

600

800

1000

1200

1400

1600

Hours

Frequency

Duration (hrs)
21

• HECO – approximately 1,800 MW (no installed wind energy at this time). 

• HELCO – approximately 300 MW plus about 33 MW of wind. 

• MECO – approximately 280 MW plus about 30 MW of wind.27

Being islands, the Hawaiian electric systems are relatively small isolated grids without 

any interconnections. The small grid size along with the generation mix results in a relatively 

small frequency bias. In 2008, peak load was 198.2 MW for HELCO and 199 MW for MECO. 

All three islands are evening peaking utilities and demand has dropped since 2008. The daytime 

peak is presently running around 160 MW for HELCO and evening peaks are about 170 MW for 

HELCO and in the 180’s for MECO. Minimum load is approximately 50% of the evening peak, 

typically between 80 to 90 MW. Due to a combination of factors including limited geographic 

area; lack of interconnections, degree of volatility in output second to second, sustained ramps by 

the wind plants, and (for HELCO) a large amount of non-flexible generation from hydro and 

geothermal resources, integration of the wind plants onto the MECO and HELCO systems have 

presented challenges for system balancing and frequency control. In addition, the low minimum 

load coupled with the large amount of as-available resources and must-take generation 

(particularly from the geothermal facility for HELCO and the biomass facility for MECO), 

creates excess energy problems during lower-load periods. 

Primary system balancing and frequency control is provided by the conventional 

generating units through droop response. On a longer time scale, with a 4-second control cycle, 

automatic generation control provides supplemental frequency control and economic dispatch. 

The two newer wind plants on the HELCO system and the 30-MW plant on the MECO 

system are equipped with grid operator-controlled curtailment interfaces that allow the operator 

to issue a set point that limits the output of the wind plant to no more than the set amount.

HELCO uses generation curtailment, from wind or from other generating plants, in two general 

circumstances:

28

1) System events where there is a system problem that is best addressed through 

reduction in a plant’s output – In such a case, the most effective control to address the 

system problem is employed, which may include reduction of a wind plant’s output 

through curtailment. Examples include:

• Transmission line overload conditions (congestion) – The most effective control 

for the particular overload is employed, which may be curtailment of a wind plant 

or a conventional generator. 

• The transmission line is open and cannot close due to excessive phase angle –

This would require reduction in power flow at a particular point on the system.

• Fast time-scale variability of a particular wind plant is causing system frequency 

to deviate – Curtailment of that plant is used as a means to reduce the variability. 

 27 Hawaiian Electric Company Fact Sheet, “Power Facts,” August, 2008, 

http://www.heco.com/vcmcontent/StaticFiles/pdf/01_01_PowerFacts.pdf. 28 Information in this section is from a personal communication with Lisa Dangelmaier, Hawaiian Electric 

Company, January 28, 2009.
22

Due to the manner in which curtailments are effected at the wind plant through 

the controls, the curtailment has the effect of smoothing the output. 

2) Conditions of excess generation – Transmission-side as-available generation 

suppliers, including wind power suppliers, are curtailed according to a pre-determined 

priority that was established at the time of the contract agreement. Prior to 

curtailment for excess energy, HELCO and MECO will reduce output of the must-run 

generation to minimum levels, taking into consideration regulating reserve 

requirements (for down regulation). If time permits, intermediate units are then taken 

off-line, with consideration given for load demand changes, observed variability of 

wind output and the minimum down time for bringing these intermediate units back 

on-line. This is the primary cause of the majority of curtailments of wind energy on 

the HELCO and MECO systems.

Xcel Energy

Xcel Energy has utility operations in three separate regions through its regulated 

subsidiaries: the Public Service Company of Colorado (PSCO) serving portions of Colorado; the 

Southwestern Public Service Company (SPS) serving portions of New Mexico and Texas; and 

the Northern States Power Company with divisions in Minnesota and Wisconsin. The Northern 

States Power Company (NSP) is a part of the Midwest ISO. As of 2008, Xcel Energy has almost

1,300 megawatts of wind energy capacity in Minnesota, North Dakota and South Dakota, with 

the majority of this generation concentrated in southwestern Minnesota. Transmission issues in 

this region resulted in the regional curtailment of approximately 23,000 MWh of wind generation 

in 2008, at the direction of the Midwest ISO. Xcel Energy has an agreement with the wind 

generators in southwestern Minnesota establishing responsibility for curtailment on a rotational 

basis between the various plants (see Table 3).

Table 3.

Minnesota Wind Projects Participating in Xcel Energy’s Wind 

Curtailment Rotation (as of 2007)

Wind Plant Capacity (MW)

Lake Benton Power Partners I 107.25

Lake Benton Power Partners II 103

Chanarambie Power Partners 85.5

Moraine Wind 51

Northern Alternative Energy 27*

Norgaard 8.75**

Total 382.5

* Consists of several facilities below 2 MW

** Consists of seven 1.25-MW facilities

Source: Minnesota Public Utilities Commission, Report to the Legislature on Wind 

Curtailment Payments under Minnesota Statutes §216B.1681, July 2008, 

http://www.puc.state.mn.us/portal/groups/public/documents/pdf_files/000805.pdf. 
23

Wind plants that are curtailed are made whole by Xcel Energy, covering both the lost 

value of the federal production tax credit (PTC) and energy. Wind generation has been 

continuously curtailed in this area since 2004, when nearly 14% of wind generation had to be 

curtailed. New transmission as part of the Southwestern Minnesota transmission project in late 

2004 helped decrease the level of wind curtailment after 2004. From 2005 to 2007, nearly 5% of 

Xcel Energy’s Minnesota wind generation was curtailed each year (see Figure 6). Wind 

curtailment increased slightly in 2007 as existing transmission facilities had to be taken out of 

service to allow continued construction of the Southwestern Minnesota transmission facilities.29 

For 2008, Xcel Energy estimated it curtailed about 23,000 MWh in the Midwest ISO’s service 

territory.30 

Figure 6.

Curtailment as a Percentage of Total Wind

Generation for Xcel Energy in Minnesota

2003-2007

Source: Minnesota Public Utilities Commission, Report to the 

Legislature on Wind Curtailment Payments under Minnesota Statutes 

§216B.1681, July 2008, 

http://www.puc.state.mn.us/portal/groups/public/documents/pdf_files/0

00805.pdf.

Figure 7 shows Xcel Energy’s annual wind curtailment payments in Minnesota. Total 

wind curtailments began at below $1 million in 2006, then increased sharply to nearly $6 million 

in 2007 before decreasing to about $2.5 million in 2008. As noted earlier, the large increase in 

wind curtailment payments in 2008 is likely due to taking some transmission facilities out of 

service to allow construction of transmission facilities in southwestern Minnesota.

 29 Minnesota Public Utilities Commission, Report to the Legislature on Wind Curtailment Payments under 

Minnesota Statutes §216B.1681, July 2008, 

http://www.puc.state.mn.us/portal/groups/public/documents/pdf_files/000805.pdf. 30 Personal communication, Tom Ferguson, Xcel Energy, May 12, 2009.
24

Figure 7.

Annual Wind Curtailment Payments in

Minnesota by Xcel Energy

2006 – 2008

Source: Xcel Energy Monthly Fuel Adjustment Charge Reports, as filed with the Minnesota Public Utilities 

Commissions.

Figure 8 presents Xcel Energy’s monthly wind curtailment payments between September 

2005 and July 2009. The monthly wind curtailment payments were generally below $500,000 

with some large jumps in December 2007 and in July 2008.

$-

$1 

$2 

$3 

$4 

$5 

$6 

$7 

2006 2007 2008

Millions
25

Figure 8.

Monthly Wind Curtailment Payments

in Minnesota by Xcel Energy

September 2005 – July 2009

Source: Xcel Energy Monthly Fuel Adjustment Charge Reports, as filed with the Minnesota Public Utilities 

Commissions.

The PSCO and SPS (which is in the Southwest Power Pool) regions operate under a 

separate policy. Under this policy, eight steps must be taken before any wind generation is 

curtailed, including backing down gas and coal generation to minimums, lowering power 

purchases and increasing sales, and reducing sales prices to $0.31

 31 Xcel Energy, Generation Plant Reliability, Wind Dispatch Policy, Revision 1.2, 

In Colorado, Xcel Energy had

1,060 MW of wind energy as of the end of 2008, and has a contractual arrangement with the 

Logan Wind plant to provide up to 14,000 MWh of annual curtailment at no cost. A number of 

other wind generators have similar contracts for less amounts of energy, and are curtailed after 

Logan, followed by curtailment of energy purchases. After these steps are exhausted, wind 

generation may be curtailed outside of these no-cost agreements, with Xcel Energy paying for 

http://www.xcelenergy.com/SiteCollectionDocuments/docs/CRPExhibit5OperatingProcedures.pdf. 

$-

$500,000 

$1,000,000 

$1,500,000 

$2,000,000 

$2,500,000 

$3,000,000 

$3,500,000 

Sep-05

Nov-05

Jan-06

Mar-06

May-06

Jul-06

Sep-06

Nov-06

Jan-07

Mar-07

May-07

Jul-07

Sep-07

Nov-07

Jan-08

Mar-08

May-08

Jul-08

Sep-08

Nov-08

Jan-09

Mar-09

May-09

Jul-09
26

the energy it is not receiving as well as the federal PTC. The choice of which plants are curtailed 

is predetermined by a schedule based on the day of the month. In Colorado, Xcel Energy 

curtailed about 3,000 MWh of wind generation in 2008. 32

Southern California Edison33

Southern California Edison (SCE) has approximately 700 MW of wind generation in the 

Tehachapi region. The primary transmission path to the Tehachapi region is the GoldtownLancaster 66-kV line, which often becomes overloaded. The lack of adequate transmission has 

forced SCE to curtail wind production to reduce loading on the line. SCE has an agreement with 

Terra-Gen Power, which operates about 187 MW of wind power in the region, to curtail 

production when the need arises. SCE then makes payments for this service by covering the lost 

energy, though not the federal PTC. SCE estimates that it is forced to curtail about 15 MW of 

wind generation for 3 or 4 hours every two days.34 The development of the $2 billion Tehachapi 

transmission project that can access up to 4,500 MW of wind power will significantly ease the 

need for wind curtailment. The first phase of the Tehachapi transmission project could come online as early as this year (2009).

 32 All estimates for PSCO are from personal communication, Tom Ferguson, April 24, 2009. 33 Southern California Edison did not review this profile. The information presented here is based on the authors’ 

understanding of how wind curtailment is done in Southern California Edison’s service territory.

34 Personal communication with Southern California Edison personnel, May 2009.
27

III. Wind Power Curtailment Examples outside the United States

Alberta Electric System Operator35

The Alberta Electric System Operator (the AESO) began studying the integration of wind 

into their system in 2004. Studies performed in 2005 and 2006 indicated that the AESO did not 

have the procedures in place to be able to accommodate the increasing amounts of wind power 

being planned in Alberta. The AESO is a fairly isolated system with limited interconnections to 

grids outside Alberta, and therefore a limited ability to share balancing services. Additionally, 

the generation in the AESO is mainly large baseload coal-fired plants along with a significant 

amount of cogeneration. In 2006, the AESO placed a temporary cap of 900 MW of wind 

capacity on their grid. The AESO’s peak load is approximately 9,700 MW; therefore, the 

temporary cap represented about 9% total wind penetration by capacity. Current wind capacity 

on the AESO system is approximately 500 MW, more than 5% of peak load by capacity. There 

is more than 11,500 MW of additional wind power projects in the AESO’s interconnection 

queue.36

Under the (AESO’s) Operating Policy and Procedure 103 (OPP 103), “Dispatching 

Multiple $0 Offers,” wind generation is exempt from curtailment because such generation is of 

“undetermined or uncertain minimum stable generation.” Wind power is a non-dispatchable 

resource, along with cogeneration and some baseload units that are must-run, that does not 

submit offers into market. Wind power is accepted as delivered and treated as a price taker 

supplying energy to the market at a $0 bid price. Therefore, wind power is only curtailed to 

manage transmission constraints and other reliability events. Figure 9 shows the amount of 

dispatchable capacity on the AESO system, which can vary from 1,000 to 3,000 MW in a oneweek period. Capacity available for dispatch includes unloaded capacity from regulating reserves 

as well as generation offers not included as must-run baseload. 

 35 The Alberta Electric System Operator did not review the information in this section. The information presented 

here is based upon the authors’ understanding of how the Alberta Electric System Operator uses wind curtailment. 36 Alberta Electric System Operator, Implementation of Market & Operational Framework For Wind Integration in 

Alberta, March 2009, http://www.aeso.ca/downloads/WI_Paper-_Final.pdf. 
28

Figure 9.

The AESO Dispatchable Generation

Source: Alberta Electric System Operator, Implementation of Market & Operational Framework For 

Wind Integration in Alberta, March 2009, http://www.aeso.ca/downloads/WI_Paper-_Final.pdf.

The Energy Market Merit Order (EMMO) is the AESO electricity market control 

software and consists of all the offers and bids for supply and demand that is sorted in order of 

offer and bid price blocks and dispatched in relative economic order. Generation that is subject to 

curtailment is divided into two groups; inflexible and flexible generation. When the EMMO 

receives a quantity of $0 bids indicating that supply exceeds demand, flexible generation is 

curtailed by an amount related to its contribution to the power supply. If this is not enough to 

achieve balance, imports will be curtailed, followed by reductions of inflexible generators to 

their respective minimum generation levels. In September 2007, the AESO released the Market 

and Operational Framework (MOF) study for wind integration.37 The study recommended that 

the AESO develop a wind forecasting system, procure more regulating reserves and that wind 

generators should be subject to wind power management (WPM). Under WPM, wind power 

facilities would be required to have the capability to reduce output. WPM includes on-site power 

management such as curtailment, power limiting, and ramp limiting. WPM will be integrated 

with the current EMMO, regulating services, and load and supply following services, allowing 

wind power the opportunity to participate in providing these services, along with conventional 

generators. When other measures are insufficient to absorb forecasted or actual wind generation, 

WPM will be used to curtail wind power. Three work groups (i.e., Supply Surplus Protocol, 

Wind Power Management Protocol (WPMP), and Wind Power Management technical 

requirements) are studying how to implement the MOF. Wind generators will be responsible for

the costs of wind forecasting and any equipment associated with WPM. In addition, wind 

generators will not be compensated for lost production due to curtailment.

 37 Alberta Electric System Operator, Market & Operational Framework For Wind Integration in Alberta, September 

26, 2007, http://www.aeso.ca/files/MOF_Final__Sept26.pdf. 
29

An August 2008 report by the WPMP supply surplus working group suggested changes 

to OPP 103 in order to implement the MOF.38

The first set of recommendations for implementing WPM was released by the Market and 

Operational Framework working group in March 2009.

The proposal suggests that OPP 103 should be 

amended to no longer exempt wind generation from being power limited. The work group 

suggested a sharing of the burden of curtailments between inflexible, flexible, and wind 

generation. The WPMP report recommends an adoption of a system similar to ERCOT where the 

AESO will use data from EMMO, ancillary services requirements, load and wind power 

forecasts, and measurements of potential MW availability from operating wind projects to 

calculate a System Wind Power Limit (SWPL). The SWPL amount will then be allocated 

amongst the wind power generators on a pro rata basis. The WPMP also recommended that wind 

curtailment be re-assessed and re-allocated every 20 minutes if the limit for any one wind project 

changes by more than 5 MW. 

39

• Wind power forecasting requirements: The MOF working group recommends 

procuring a centralized wind forecasting system, starting a stakeholder process to 

define a set of rules, procedures, standards, and technical requirements for data and 

communications protocols, establishing a data management system, and making 

aggregated wind forecasts available to market participants. 

The recommendations include rules, 

practices and procedures, and requirements need to implement the MOF. These 

recommendations are:

• Wind power curtailment protocol: The MOF working group recommends adopting 

the WPMP recommendation on how to allocate system wind power limits to 

individual facilities. The working group proposed the Potential MW Capability 

approach, a pro-rata allocation of system-wide wind curtailments based on the current 

MW capability of each wind plant, with reassessments and re-allocations every 

20 minutes if the limit for any one wind plant has changed by more than 5 MW. 

• Supply surplus protocol: The MOF working group recommends including wind 

facilities in operating procedures, developing a minimum operating level for wind 

plants, and developing a market notification system for notifying generators of 

supply surplus conditions to encourage voluntary curtailment actions. 

In June 2009, the AESO issued its final recommendations concerning the MOF. The 

AESO supports implementing centralized wind forecasting and plans to issue an RFP for wind 

forecasting services. The AESO also intends to develop requirements for wind generators to 

submit wind and turbine data that would be necessary inputs for the AESO centralized wind 

forecast, and to publish and make available to market participants aggregated wind forecasts. 

The AESO also will pursue a rule development process for implementing WPM and endorsed 

 38 Alberta Electric System Operator, Wind Power Management Protocol for Alberta: Wind Power Management 

Work Group Recommendation to the Alberta Electric System Operator, August 15, 2008, 

http://www.aeso.ca/downloads/WPM_Protocol_Work_Group_Paper.pdf. 39 Alberta Electric System Operator, Implementation of Market & Operational Framework For Wind Integration in 

Alberta, March 2009, http://www.aeso.ca/downloads/WI_Paper-_Final.pdf.
30

the SWPL methodology. The AESO said it will first use EMMO and then use available ancillary 

services before turning to WPM.40

The WPMP is also working on a set of congestion management protocols where WPM 

can be integrated into real-time system operations to curtail wind power when necessary during 

times of transmission congestion. In September 2007, the AESO removed the limit on wind 

power and is in the process of developing transmission system upgrades to accommodate 

additional wind power projects in the Province – the 240-kV Pincher Creek to Lethbridge 

transmission line to interconnect up to 1,000 MW of wind in the southwest; a 240-kV southern 

loop to interconnect up to 2,700 MW of wind over next 10 years; and scoping for new facilities 

in central Alberta (Hanna area) to interconnect up to 1,400 MW of wind.

 

41

The AESO plans to continue stakeholder consultations and expects that its market rule 

will change over the next few years as the market continues to evolve and adapt to the additional 

wind generation in Alberta.

Figure 10 presents the number of hours per day at the number of wind facilities that the 

AESO curtailed, from November 2007 through mid-August 2009. The number of hours that 

AESO curtailed wind was higher in the spring and fall, with one noticeable spike to over 

70 hours in January 2009.

 40 Alberta Electric System Operator, Final Recommendations Regarding Implementation of Market and 

Operational Framework for Wind Integration in Alberta and AESO Response to Stakeholder Comments, June 18, 

2009, http://www.aeso.ca/downloads/MOF_stakeholder_comments_and_AESO_response_matrix_cover_letter.pdf. 41 Alberta Electric System Operator, “Implementation of Market & Operational Framework for Wind Integration,” 

presentation at Stakeholder Information Session, March 23, 2009, http://www.aeso.ca/gridoperations/17383.html. 
31

Figure 10.

Number of Hours of Wind Curtailment by Day 

by the Alberta Electric System Operator

November 2007 – July 2009

Source: Alberta Electric System Operator, “Weekly Wind Power Operational and Market Reports,” 

http://www.aeso.ca/gridoperations/14246.html. 

Figure 11 shows the number of hours by month that AESO curtailed wind generation. 

Again, the spring and fall months showed jumps in wind curtailment, with some increases in 

wind curtailment some winter months as well. 
32

Figure 11.

Number of Hours of Wind Curtailment by Month by the Alberta

Electric System Operator

December 2007 – July 2009

Source: Alberta Electric System Operator, “Weekly Wind Power Operational and Market Reports,” 

http://www.aeso.ca/gridoperations/14246.html. 

Figure 12 depicts the number of hours wind energy projects were curtailed in Alberta in 

2008, and the number of hours that wind energy projects have been curtailed in 2009 through 

July. In all, the AESO curtailed wind for 860 hours in 2008, and for 329 hours from January 

through July of 2009.

0

50

100

150

200

250

300

# of Hours

Number of Hours
33

Figure 12.

Number of Hours of Wind Curtailment by the

Alberta Electric System Operator

2008 and through July 2009

Source: Alberta Electric System Operator, “Weekly Wind Power Operational and Market Reports,” 

http://www.aeso.ca/gridoperations/14246.html.

Spain

Spain has more than 16,700 MW of wind power capacity installed and predicts that it will 

have more than 20,000 MW by 2010. At times, the highest wind production times occur during 

times of low or declining periods of electricity demand. On November 24, 2008, at 

approximately 5:00 AM, wind power contributed more than 46% of the total electricity demand 

providing 9,250 MW when there was a demand of 21,264 MW.42

 42“La eólica ha alcanzado un nuevo récord de generación con 11.159 MW simultáneos y de producción diaria con 

23.060 MWh,” press release of the Asociación Empresarial Eólica, January 23, 2009, available at: 

On this date and at other times, 

the wind power facilities were asked to curtail their operations, limiting output or disconnecting 

http://www.aeeolica.es/prensa_notas.php; supplemented with data collected by Red Eléctrica España, Wind Power 

Generation in Real Time, available at: http://www.ree.es/ingles/operacion/curvas_eolica.asp#. 

0

100

200

300

400

500

600

700

800

900

1000

2008 2009 (Jan - July)
34

from the grid altogether. This summary explores some of the operating procedures and tools used 

to determine when curtailment might be required, as well as a summary of research and analysis 

used to improve the integration of wind power into the Spanish electric power system.

Grid Operation: Provisions for Renewable Resources

The Red Eléctrica de España (REE), the grid operator in Spain, created the Control 

Centre for Renewable Energies (CECRE) as the central point for coordination of the 

interconnected renewable energy resources greater than 10 MW into the operations of the 

Electrical Control Centre (CECOEL), the Spanish system operator. Put into service in 2006, the 

objective of CECRE is to achieve a high level of integration for renewable energy sources 

without compromising system security. In order to achieve this objective, CECRE groups 

renewable energy facilities by General Coordination Centers (GCCs) to coordinate, control, and 

supervise all generation units as necessary via supervisory control and data acquisition (SCADA) 

systems. Every wind power facility of 10 MW or greater must be directly connected to a GCC 

which must then have sufficient local controls to execute CECRE orders within 15 minutes. 

The real-time data transferred by wind farms to the GCC and on to the CECRE includes the 

following:

• Active power,

• Reactive power,

• Connectivity (connected/disconnected),

• Voltage level,

• Wind speed and direction (if available), and

• Ambient temperature (if available).

43

With this information, CECRE is able to estimate the maximum output of the wind farm 

and is also able to monitor the stability of the electricity network with regards to wind power 

production. The information is transmitted every 12 seconds to CECRE and is fed into 

simulation models to determine the need, if any, for curtailment of wind power facilities. 

CECRE operates a computer model called GEMAS, (Generación Eólica Máxima 

Admisible en el Sistema -- Maximum Admissible Wind Power Generation in the System). 

GEMAS uses switching studies to simulate the likelihood of faults under various real-time 

situations. Switching over-voltage might occur with abrupt changes in load or supply on a 

transmission line or as a result of circuit breaker malfunction. The magnitude and shape of the 

switching over-voltages vary with the system parameters and network configuration, and thus the 

switching studies are designed to predict and prevent network faults under a variety of 

conditions. As part of the analysis, the production of every wind farm connected to the GCCs is 

fed into CECRE’s GEMAS model which simulates three-phase solid faults in the bus bars of 

70 substations every 20 minutes. Simulation results are continuously compared with real faults 

 43 A. Ceña Lázaro and J. Gimeno Sarciada, “The Spanish Experience in the Integration of the Electricity from Wind 

Power Plants into the Electrical System,” 7th International Workshop on Large Scale Integration of Wind Power 

and on Transmission Networks for Offshore Wind Farms, May 2008.
35

and have been found to be consistent in predicting system faults in a majority of instances.44 

GEMAS is an analytical model that is used to predict the likelihood of faults from real-time wind 

predictions and thus, is used to indicate a need for curtailment providing specific generation set 

points, or reduction amounts, based on the real-time data input to GEMAS. For 2007, 23.9 GWh 

of wind generation was curtailed, representing 0.09% of total wind production.45 In 2008, the 

majority of curtailments were due to problems of grid overloads on distribution networks, legally 

defined in Spain as power lines rated less than 220 kV, as depicted in Figure 13 below:

Figure 13.

Reasons for Wind Production Curtailments in Spain in 2008

Source: Alberto Ceña, “The Impact of Wind Energy on the Electricity Price and on the Balancing 

Powers Costs: the Spanish Case,” presentation before the European Wind Energy Conference, 

March 19, 2009. 

According to the Association Empresarial Eolica (AEE), there were eight notable wind 

curtailment incidents in 2008. The most significant was an incident on November 1 when a large 

number of wind power facilities were disconnected from the electric grid on a weekend morning 

as hurricane force winds came ashore on the north-eastern seaboard. At approximately 7:00 AM,

REE ordered the shutdown of 2,700 MW of wind capacity after which power production 

increased from 1,868 MW to 7,517 MW over an eight-hour period, starting shortly before 

Recent Events

 44 M. de Torre, T. Domínguez, G. Juberías, E. Prieto, O. Alonso, “Operation of a Power System with Large 

Integration of Renewable Energies,” 7th International Workshop on Large Scale Integration of Wind Power and on 

Transmission Networks for Offshore Wind Farms, May 2008. 45 T. Dominguez, M. de la Torre, G. Juberias, E. Prieto, R. Rivas, and E. Ruiz. Renewable energy supervision and 

real time production control in Spain, undated paper, http://www.icrepq.com/icrepq-08/302-dominguez.pdf. 
36

midnight on November 1 (Figure 14). At the time of the ordered curtailment, total demand was 

approximately 20 GW, with wind capacity serving an estimated 38% of the total load. Demand 

had been falling throughout the early morning hours. Prior to ordering the curtailment of wind 

power, REE reduced hydro production to zero and curtailed four combined-cycle gas power 

facilities by a combined 1,500 MW, dropping the output of the thermal facilities to what is 

described as the absolute technical minimum output.46 

Figure 14.

Real-Time Wind Power Generation in Spain for November 1-2, 200847

Source: Red Eléctrica España, Wind Power Generation in Real Time, and Electric Power Demand in Real 

Time for November 1, 2008, available at: http://www.ree.es/ingles/operacion/curvas_eolica.asp#.

Further analysis of the November curtailment indicates that between 800 and 1200 MW 

of the curtailed capacity was shutdown erroneously, the miscalculations occurred in part because 

communication signals that typically provide real-time information (every 12 seconds) on 

electricity supply and demand were delayed due to satellite communications interference caused 

by the strong winds. As a result, and consistent with default protocols, CECRE ordered the 

shutdown of every wind power production facility where GCC was experiencing communication 

problems. The affected GCCs accounted for more than 800 MW of the wind capacity that was 

curtailed. This 800 MW of curtailed power was not considered at the time that calculations were 

made to estimate the need for further shutdown requests. Thus, the calculations determining the 

need for wind curtailment assumed that the 800 MW − shut down due to communication 

 46 Michael McGovern, “Grid Operator Unplugs Huge Volume of Wind Plant,” Windpower Monthly, Volume 24, 

No. 12, December 2008, pp. 27-28. 47 Data collected by Red Eléctrica España, Wind Power Generation in Real Time, and Electric Power Demand in 

Real Time for November 1, 2008, available at: http://www.ree.es/ingles/operacion/curvas_eolica.asp#.
37

problems − were still on line, leading to the call to curtail more wind power than was actually 

necessary given the actual situation. 

Initially, REE curtailed wind output if wind power penetration exceeded 12% of demand.

This protocol was the result of a study that was conducted in 2002 and found that the grid 

functioned adequately at peak with a peak demand of 36,500 and with 10,000 MW of wind, or 

27% of demand. According to the study, system problems emerged during minimum demand 

periods at 25,000 MW, with more than 5,000 MW of wind on line. At peak times, REE believed 

that as much as 20% could be met by wind, or 13,000 MW, assuming that REE can curtail wind 

production during periods of minimum demand.

48 REE relaxed this restriction when the wind 

target was raised to 20 GW and with the adoption of grid management practices. However, the 

amount of wind power curtailed as part of the congestion management program has increased 

steadily over the past two years (Figure 15). Lessons learned from the November event, and 

others, led to closer coordination between AEE and CECRE to improve wind balancing 

methodologies and practices.49

Figure 15.

Capacity of Wind Curtailed by Month in Spain

2007 – 2008

Source: Alberto Ceña, “The Impact of Wind Energy on the Electricity Price and on the Balancing Powers Costs: the 

Spanish Case,” presentation before the European Wind Energy Conference, March 19, 2009. 

 48 Craig, Dr. Lucy, “Large-Scale Integration of Wind Power into Power Systems—the Spanish Experience,” 

presented before the Fifth International Workshop on Large-Scale Integration of Wind Power and Transmission 

Networks for Offshore Wind Farms, Glasgow, Scotland, April 7-8, 2005. 49 Michael McGovern, “System Operator Admits Errors,” Windpower Monthly, Volume 25, No. 5, May 2009, 

pp. 34-35.
38

Germany

There are more than 20,000 wind turbines connected to the German electricity grid, with 

an overall capacity of 23,903 MW as of the end of 2008 (see Figure 16).

50 Lower Saxony is the 

first German federal state to exceed 6,000 MW of total installed capacity and has a goal of 

10,000 MW by 2020. 

Large-scale wind power generation has caused some controversy with German utilities,

warning that there are bottlenecks in power transmission grids due to the difficulties of 

integrating high amounts of wind energy. In addition, there are costs for redispatch and grid 

development to meet the requirements of the Renewable Energy Act. According to RWE, one of 

the German Transmission System Operators (TSOs) and the grid manager for the German and 

Northern European System, the balancing power needed for wind power feed-in accounts for 

almost one fifth of the grid costs.51 At times, it appeared as though the German TSOs were

unable or unwilling to take all of the wind power produced due to transmission congestion. 

German wind operators complain of the use of ‘curtailment’ (shutting down of wind power 

stations) in the effort to alleviate transmission constraints. According to the German environment 

ministry, 74 GWh of wind power were curtailed between 2004 and 2006, and wind companies 

had lost revenues of €17,600/MW in 2006 alone.52

Figure 16.

Installed Wind Capacity in Germany

Source: Windpower Wind Turbines and Windfarms Database, 

http://www.thewindpower.net/country-datasheet-2-germany.php.

 50 Windpower Wind Turbines and Windfarms Database, http://www.thewindpower.net/country-datasheet-2-

germany.php. 51 RWE Webpage, company portrait, available: 

http://www.rwetransportnetzstrom.com/web/cms/en/132902/company/portrait/. 52 Sara Knight, “Owners Compensated for Lost Production,” Windpower Monthly, September 2009, p. 84. 
39

German policy is to continue to encourage the development of renewable resources. 

Passed in 2004, the Renewable Energy Sources Act (EEG) was amended in 2009 that, among 

other things, allowed voluntary bilateral agreements between a transmission operator and a wind 

company. These agreements allowed wind companies to interconnect new wind projects if they 

agree to follow curtailment orders without compensation, thus allowing for the connection of 

wind projects on the grid that may not have occurred otherwise. E.On Netz alone estimates that 

these voluntary agreements allowed for more than 1,000 MW of wind capacity to be connected 

in its service area alone since June 2003.

53

To further facilitate the development of renewable energy resources, the EEG was 

amended in June 2008 and entered into force on January 1, 2009. The revised act includes 

several provisions that are aimed at reducing the amount of curtailment occurring by grid 

operators faced with congestion and an oversupply of wind power during periods of low demand.

Furthermore, cooperation among transmission system operators in Germany and surrounding 

countries will better facilitate the integration of wind power facilities. Transmission System 

Operators in Austria, Switzerland, Germany, the Netherlands, Poland, and the Czech Republic

launched the regional “TSO System Security Cooperation” in December 2008, with the objective 

of achieving a common platform for data exchange and grid security. Under this regional 

initiative, the German TSOs began sharing wind forecasts and near-to-real time data of wind 

generation to their partners of the TSO Security Cooperation (TSC). This allows TSOs of 

Austria, Czech Republic, The Netherlands, Poland, and Switzerland to have instantly a better and 

broader view of the interconnected electricity system in order to better take care of their 

respective responsibilities and will likely reduce unexpected cross-border flows of electricity 

during periods of high wind output. 

There are four German TSOs: Transpower Stromübertragungs GmbH (Transpower), 

RWE Transportnetz Strom GmbH, Vattenfall Europe Transmission AG, and EnBW 

Transportnetze AG. In compliance with the German EEG, each of the transmission operators is 

obligated to take all electricity generated from renewable energy sources within their control area 

and compensate the generators for their electricity at an established tariff rate. Amendments to 

the Renewable Energy Act modified the payment provisions of feed-in tariffs, effective January 

2009. In 2009, the initial tariff paid for onshore wind-powered installations is generally set at 

9.2 euro cents, depending on the quality of the site, and is to be paid for the first five years of 

operation. The final tariff, paid beginning of year 6 and through year 20, is set at 5.02 euro cents. 

Both the initial tariff and the final tariff decrease each year by one percent. In the case of 

offshore wind power facilities, the initial tariff is set at 13 euro cents for the first 12 years of 

operation. There is also a bonus of 2 euro cents per kilowatt hour generated for offshore facilities 

commissioned prior to January 1, 2016. Depending on the location of the facility, the initial tariff 

and bonus tariff might be extended beyond the 12-year time period. The further the facility is 

located offshore and the deeper the water, the longer the bonus and initial tariff would be 

extended. The final tariff, paid after the termination of the initial tariff and through year 20 of 

operation, is set at 3.5 euro cents. The offshore feed-in tariff decreases by 5% each year with the 

first degression taking place in 2015. 

Regulations

 53 Ibid. p. 52. 
40

The amount of renewable energy produced and put onto the German grid is pooled in a 

common electricity market and balanced among the four German TSOs. Therefore, the cost of 

purchasing the renewable energy is shared equally by the four TSOs even though two of the 

TSOs (Vattenfall and Transpower) have substantially more wind power facilities connected to 

the grid. The balancing of the renewable energy takes place within the day-ahead market of the 

European Energy Exchange (EEX), and the real-time market exchange and is settled accordingly 

with settlement data and payments reported by each of the TSOs in an annual report.54

According to the EEG amendments in 2008, electric power facilities with over 100 kW of 

power input will be subject to generation management, e.g., forced curtailment of power 

production, as grid bottlenecks occur. According to the revised regulations, grid operators will 

need to pay compensation for energy left unused due to grid management and curtailment 

procedures.55 In addition, wind turbines installed before 2009 must be retrofitted so generation 

can be curtailed at a TSO’s request. The TSOs may recover curtailment costs from customers, 

but it must first demonstrate that all possible measures to optimize, improve, and expand network 

capacity were taken before undertaking curtailment. However, the rate at which facilities are 

compensated from energy being curtailed is not specified in the law. The German wind 

association, Bundesverband Windenergie (BWE) negotiated an agreement with Transpower, a 

subsidiary of E.On Netz, and one of four transmission grid operators in Germany, and plans to 

pay the electricity tariff rate for 90% of the lost revenues for the duration of the curtailment, a 

proposal that was accepted by the wind power plant operators. BWE is hopeful it can reach 

agreement with the other three TSOs.56

Since the Renewable Energy Act first went into effect in 2000, there has been a major 

increase in the installed capacity of wind energy plants. However, as described above, network 

operators are required without prejudice to accept all production of renewable energy facilities. 

Under the Renewable Energy Act, TSOs must interconnect facilities of 100 kilowatts or more, 

providing grid extension and upgrades in the affected area of the network that would otherwise 

be overloaded by the power supplied. Furthermore, as projected in the dena Grid Study, 

approximately 850 km of new high-voltage transmission lines will be needed in order to reliably 

interconnect wind power facilities by 2015.

Transpower

57 Subsequently, Transpower is working on five grid 

expansion projects with a combined 370 km of high-voltage transmission lines, and two 

interconnection projects, including a 380-kV line to the port city of Wilhelmshaven designed to 

interconnect offshore wind power facilities (Table 4). 

 54 “Renewables Management,” Vattenfall website, 

http://www.vattenfall.de/www/trm_en/trm_en/942105renew/942123renew/index.jsp. 55Information provided by Niels Ehlers, Technishe Universitat Berlin, Institut für Energietechnik, Berlin, Germany 

with reference to the German Wind Energy Association, http://www.wind-energie.de/de/themen/windenergie-imstromnetz/; and Transpower, http://www.transpower.de/pages/tso_de/EEG__KWK-G/Erneuerbare-_EnergienGesetz/EEG-Anlagen/Einspeisemanagement/index.htm. 56 Sara Knight, “Owners Compensated for Lost Production,” Windpower Monthly, September 2009, p. 84. 57 Planning of the Grid Integration of Wind Energy in Germany Onshore and Offshore up to the Year 2020 (dena 

Grid study), Deutsche Energie-Agentur, March 2005.
41

Table 4.

Transpower Projects in the dena Network Study

Altenfeld - Redwitz (Thüringen, Bavaria) approx. 25 km 

Diele - Niederrhein (Lower Saxony) approx. 50 km 

Ganderkesee - St. Hülfe (Lower Saxony) approx. 60 km

Hamburg/Nord - Dollern (Schleswig-Holstein, Lower Saxony) approx. 45 km

Wahle - Mecklar (Lower Saxony, Hesse) approx. 190 km

Power Plant Connections

Stade – Dollern approx. 20 km

Wilhelmshaven – Conneforde approx. 40 km

Source: Transpower web site, 

http://www.transpower.de/pages/tso_en/Tasks/Network_development/index.htm. 

Furthermore, Transpower established a power production management system that 

curtails wind power at times when the grid is overloaded. This permits the continued connection 

of decentralized energy production plants such as wind farms, solar energy plants, and biomass 

power stations until the necessary network development has been completed in SchleswigHolstein and Lower Saxony.

While grid management practices, including increased use of wind forecasting tools and 

market-based capacity auctions, have helped to mitigate some curtailment and related crossborder congestion, there are still instances of curtailment among wind power facilities connected 

to the E.On Netz distribution system. In the first six months of 2009, there were 15 instances of 

congestion and curtailment on the E.On Netz distribution system, affecting 1,080 MW of wind 

capacity. Table 5 provides the duration and location of each major incident, as reported by 

E.On Netz on their grid management website. The wind curtailments lasted from 27 minutes to 

305 minutes. The Dithmarschen and Ostholstein regions of Schleswig-Holstein are home to a 

significant share of German wind power, including hundreds of smaller installations 

interconnected at the distribution level, as well as some of the larger coastal and offshore systems 

recently installed and interconnected to the Transpower transmission system. 
42

Table 5.

Instances of Wind Power Curtailment 

on the E.On Netz Distribution System

January – June 2009

Date Duration 

(minutes)

 Region Maximum 

Reduction

January 20 82 Nordfriesland,

Schleswig-Holstein

60%

March 17 305 Dithmarschen, 

Schleswig-Holstein

30%

March 17 164 Ostholstein,

Schleswig-Holstein

60%

March 22 131 Lower Saxony 60%

March 22 136 Dithmarschen,

Schleswig-Holstein

60%

March 23 164 Ostholstein,

Schleswig-Holstein

60%

March 24 62 Ostholstein,

Schleswig-Holstein

60%

May 6 247 Ostholstein,

Schleswig-Holstein

60%

May 18 27 Nordfriesland,

Schleswig-Holstein

60%

May 27 95 Nordfriesland,

Schleswig-Holstein

30%

May 28 27 Ostholstein,

Schleswig-Holstein

60%

June 12 159 Nordfriesland,

Schleswig-Holstein

60%

June 26 199 Ostholstein,

Schleswig-Holstein

60%

June 26 180 Dithmarschen, 

Schleswig-Holstein

60%

Source: E.On Netz Einspeisemanagement Einsätze, available at: http://www.eonnetz.com/pages/ehn_de/EEG__KWK-G/Erneuerbare-_EnergienGesetz/Einspeisemanagement/Einspeisemanagement_Einsaetze/index.htm#tabelle.

Vattenfall

As required by regulation, Vattenfall Europe Transmission guarantees that all energy fed 

into its control area shall be fully accepted and transmitted in accordance with the German 

Federal Act on Granting Priority to Renewable Energy Sources (EEG). However, the number of 

days in which congestion occurs on Vattenfall transmission lines has increased over the past 

three years. In 2008, there were 175 days in which grid congestion occurred, a 13% increase over 

2007 during which congestion was present for 155 days (Figure 17). In its annual report to the 
43

German grid regulator, Vattenfall Europe specifically cited wind power as a contributing factor 

to the transmission bottlenecks which created critical situations on the grid.58

Vattenfall currently has approximately 425 km of new transmission projects in various 

stages of development. The grid extension is specifically designed to help transmit wind power 

located in remote areas to regions with greater electricity demand (Figure 18).

Figure 17.

Number of Days with Grid Congestion in

Vattenfall Transmission System

Source: Dirk Bierman, Vattenfall Europe Transmission GmbH, Incentive Regulation for German TSOs – A Major 

Challenge in a Changing Environment, 4th Conference on Energy Economics and Technology, Dresden, 2009.

 58 Frederik Richter, German Utilities Warn of Power Bottlenecks Due to Wind Integration, Thomson Financial, 

January 31, 2008. 
44

Figure 18.

Vattenfall Grid Extension

Source: Dirk Bierman, Vattenfall Europe Transmission GmbH, Incentive Regulation for German TSOs - A Major Challenge in a 

Changing Environment, 4th Conference on Energy Economics and Technology, Dresden, 2009.

In addition to balancing overall electricity supply and demand in cooperation with 

neighboring TSOs, Vattenfall requires that “renewable energy substitutes” be available to help 

smooth fluctuations in energy supply, in particular from wind power. These “renewable energy 

substitutes” are pre-qualified energy resources that are able to provide positive and/or negative 

primary, secondary, and “minute” reserves. Pre-qualified resources bid into a regional market 

and are dispatched according to economic efficiency as needed to provide “renewable 

compensation energy.” Table 6 provides data pertaining to wind power in the control area of 

Vattenfall, demonstrating the positive and negative increases in wind power production that 

would require the use of renewable energy substitutes.59

 59Vattenfall, “Wind Power,” http://www.vattenfall.de/www/trm_en/trm_en/941994gridx/942069windx/index.jsp. 
45

Table 6.

Control Area of Vattenfall Europe Transmission: Wind Power 

Specifications for 2007 on the Basis of Information from 

Distribution System Operators (actual values)

Average installed capacity of wind power plants 8,573 MW

"Secured" capacity (power credit acc. to dena)

(4–5% of installed capacity of wind power plants) 420 MW

Maximum wind power in-feed 7,511 MW 

Minimum wind power in-feed 2 MW

Largest quarter-hourly jump in wind power +638 MW /

–977 MW

Largest hourly jump in wind power +1,601 MW /

–1,618 MW

Largest daily jump caused by wind power +6,146 MW /

–6,398 MW

Energy-based supply ratio 21.88%

Installed capacity of wind power plants at the end of 2007 8.970 MW

Source: Vattenfall, “Wind Power,” 

http://www.vattenfall.de/www/trm_en/trm_en/941994gridx/942069windx/index.jsp.

RWE

As the “control block” coordinator, RWE coordinates the load and frequency control for 

the four German TSO areas. RWE is also responsible for the coordination, energy exchange, and 

system accounting both for not only the German transmission grid, but the entirety of the 

northern part of the European interconnected system (Belgium, Bulgaria, Germany, The 

Netherlands, Austria, Poland, Romania, Slovakia, Czech Republic, and Hungary). The GermanDutch security center, which was established in concept in July 2008, went into operation in 

January 2009. The center will locate bottlenecks in the grid and support the system operation 

activities. The center is considered to be an important new tool that will enhance the security of 

the system and allow for better management of the fluctuations in the electricity flows on the 

grid that come from large amounts of wind power.

60

 60 RWE, “First European Security Center Taken into Action,” RWE Press Release issued January 5, 2009,

http://www.rwetransportnetzstrom.com/web/cms/en/133208/press-releases/. 
46

IV. Summary

Wind curtailment initiatives appear to be increasing, perhaps in part because of the rapid 

growth of wind power, and the lack of development of supporting transmission infrastructure to 

keep up. To date, with the exception of isolated systems such as Hawaii, it appears that wind 

curtailment occurs for two primary reasons: 1) lack of available transmission during a particular 

time to incorporate some or all of the wind generation; or 2) high wind generation at times of 

minimum or low load, as wind generation in some regions may have production characteristics 

nearly opposite of electricity demand, and the energy cannot be exported to other balancing areas 

because of lack of transmission. As wind penetration levels in most balancing areas in the United 

States are still quite low, the primary cause of most wind curtailments can be attributed to a lack 

of transmission capacity.

A wide variety of approaches are being taken with wind curtailment, perhaps not only 

reflective of the early stage of wind curtailment initiatives, but also representative of regional 

markets that may not be transferrable to other regions. Some regions with LMP tend to allow

market price signals to drive the need for curtailment by wind power and conventional facilities, 

only taking prescriptive action when market forces are inadequate, or during emergency events. 

For example, PJM and the NYISO are incorporating wind into their economic dispatch systems,

and are requiring wind generators to submit economic price curves to determine at what price a 

wind generator will be willing to be curtailed. Both also allow generators to submit negative 

LMP bids. 

Conversely, BPA does not have LMP; instead BPA ties its wind curtailment to the 

amount of available reserves. BPA may require wind generators to curtail after 90% of BPA’s 

reserves have been deployed. BPA assigns maximum generation limits based on their scheduled 

output, plus a proportional allocation of balancing reserves. When BPA is using 90% of its 

reserves, it will require variable generators that have over-scheduled to reduce generation to a 

specified level, while variable generators that have under-generated will have schedules curtailed 

to actual levels, plus the allocated amount of reserve. Others, such as Southern California Edison 

and Xcel Energy’s subsidiaries that are not in the Midwest ISO, have contractual provisions that 

allow each utility to call upon wind curtailment under certain conditions. Still others have tied 

curtailment to grid interconnection and set daily capacity limits for wind generation.

Given the early stage of wind curtailment initiatives, it is difficult to point to best 

practices or to make any generalizations. Nevertheless, some principles can be articulated. First, 

the grid operator should ensure that all actions have been taken before curtailing generation, such 

as ensuring that all non-wind generation is running at minimum, that import schedules have been 

reduced or eliminated, and that opportunities to export power have been maximized. Second, if 

generation is to be curtailed, all generation should be treated comparably. Wind power should 

not be the first to be curtailed simply because it is new and unfamiliar, or because wind is 

extremely quick to respond to instructions from the system operator. Third, to the extent 

regional markets allow it, generators (including wind) should have the option to bid in a price at 

which they are willing to be curtailed. Alternatively, allowing the trading of daily capacity limits 

among wind generators (as was done in ERCOT until recently) is another potential strategy. The 
47

question of whether generators (including wind) should be paid if curtailed, and on what basis, 

should also be addressed. 

The amount of wind curtailment in the United States will likely rise in the near future as 

more wind is added, and the nation tries to work through issues regarding transmission siting and 

cost allocation. Should significant new transmission be developed in the United States over the 

next several years, the need for wind curtailment would likely drop as new transmission comes 

on line. Additional measures that could reduce wind curtailment include large balancing areas, 

dynamic scheduling, and dynamic ratings of transmission lines. 
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Wind Energy Curtailment Case Studies: May 2008 - May 2009

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This paper presents a series of case studies on how wind curtailment is being used by different entities. 

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Wind; curtailment; integration; grid; electricity; power; renewables; clean energy; interconnection; transmission.

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