Subcontract Report

NREL/SR-550-47256

December 2009

Wind Energy and Power System 

Operations: A Review of Wind 

Integration Studies to Date

Jennifer DeCesaro and Kevin Porter 

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-550-47256

December 2009

Wind Energy and Power System 

Operations: A Review of Wind 

Integration Studies to Date

Jennifer DeCesaro and Kevin Porter 

Exeter Associates, Inc. 

Columbia, Maryland

NREL Technical Monitor: J. Hein

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

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1

Introduction

Wind energy continues to be the fastest growing energy resource in the world. The U.S. wind industry 

installed 8,358 MW of new wind capacity in 2008, raising total U.S. wind capacity to just over 25,000 

MW.

1 Wind power’s rapid expansion has been driven by a combination of its environmental benefits, 

various state and federal policies and incentives, and improving cost-competitiveness with other 

traditional generation technologies.

Certain natural characteristics of wind present challenges to power-system planners and operators. 

Wind plants operate when the wind blows, with power levels varying with the strength of the wind. 

Because of these characteristics, wind plants are not dispatchable in the traditional sense. As a result, the 

ability of system operators to control these plants while simultaneously maintaining the system’s 

balance between load and generation is impaired. 

To address these concerns, several different utilities have conducted studies on whether wind power can 

be integrated into the electric grid, and in some cases, at what cost. From 2003 through 2008, over a 

dozen integration studies were conducted across the United States. Moreover, the U.S. Department of 

Energy concluded that the United States can accommodate 20% energy from wind generation by 2030 

without the need for storage, assuming continued advances in transmission planning and grid 

operations.2

 The North American Electric Reliability Corporation (NERC) recently released a report 

suggesting that reliably incorporating high levels of variable resources (ocean, solar, and some types of 

hydropower, in addition to wind) will require changes to historic planning and operation methods for 

managing the grid.

This paper provides an overview of the challenges associated with wind integration and summarizes the 

findings of the wind integration studies conducted over the course of the past five years. We begin with 

an overview of the approximate time frames used in grid operations. We then describe how wind 

integration studies are conducted, discuss the results on wind integration costs and grid impacts from 

these grid integration studies, and assess some of the grid planning and operation changes that may be 

necessary to incorporate higher levels of wind generation. We close with several conclusions.

Time Frames for Wind Impacts

Wind integration studies typically divide grid operations into the following timeframes—regulation,

load following, and unit commitment. While not exactly mimicking grid operation for every grid 

operator, it provides a useful framework for considering the potential impacts of wind integration over 

multiple timeframes.

The regulation time frame covers the period during which generation automatically responds to minuteby-minute deviations in load. Typically, a system operator will send signals to one or more generators 

to increase or decrease output to match the change in load. The regulation covers a time scale ranging 

from about several seconds to 10 minutes. Changes in load during the regulation time are typically not 

predicted or scheduled in advance and must be met with enough generation that is online and gridsynchronized to ensure the changes in load are met.
2

The second time frame is load following, a longer period involving both capacity and energy. 

Generating units that have been previously committed, or can be started quickly, can provide this 

service, subject to physical constraints (e.g., state of the transmission system). The load following time 

frame covers periods ranging from 10 minutes to a few hours during which generating units are moved 

to different set points of capacity, subject to various operational and cost constraints, and in response to 

increasing load (in the morning) or decreasing load (late in the day). Load following is typically 

provided by generating units that are already committed or from generating units that can be started 

quickly, subject to operating constraints specific to the unit.

Unit commitment covers several hours to several days, and concerns the scheduling and committing of 

generation to meet expected electric demand. Generation in this time frame may require several hours, 

even days, to start-up and increase output to the preferred operating level. Similarly, taking a unit off-line 

may require several hours or days, and the unit may need several hours of cooling before restarting. 

Therefore, planning the “right” level of unit commitment is important. Scheduling too much generation 

may needlessly increase system operation costs, while scheduling too little generation may also increase 

costs by requiring the purchase of power at high market prices or running expensive, quick-start units. 

There may also be reliability issues if sufficient generation is not started or is not available on short notice.

Wind Integration Studies

In the United States, the majority of the wind integration studies have been prospective—looking at a 

potential future power system with wind—rather than retrospective—modeling what has actually 

happened. Generally, wind integration studies consist of multiple scenarios of steadily increasing wind 

penetration, starting with a base year and going into defined periods into the future while considering 

different levels of wind penetration. For electricity demand, either load forecasts are used, or past 

demand is scaled by a constant level (e.g., 1.5% per year). The studies assume transmission is built to 

meet future reliability needs and to accommodate higher wind penetration. Given the well-documented 

need for new transmission to interconnect remote renewable energy resources such as wind, the purpose 

of wind integration studies is to determine the operating impacts of adding large amounts of wind, not to 

serve as a transmission planning exercise.

For any wind integration study, it is imperative that the studies capture the coincidence of load and wind 

generation by ensuring wind and load generation data are from the same time period, as weather is a 

significant driver of both load and wind generation. Because wind integration studies are performed 

mostly on a prospective basis, wind data is typically not available at the beginning of the study. Wind 

generation data can be derived through large-scale, time-calibrated meteorological modeling that can recreate the weather coinciding to the time period(s) of historical load data that is used, and then 

converting the wind data to output using the power curve of wind turbines for the desired time period.3

Wind forecasts are simulated by statistical simulation or perturbations of model inputs or 

parameterization. Further research is needed to refine these approaches.

Two general approaches have been used to examine wind integration impacts in the United States. The 

first approach estimates the cost of increased reserves in the regulation, load-following, and unit 

commitment timeframes that are needed to balance the increased net load variability introduced by wind

generation. These studies typically focus on wind’s impact on ancillary services and compare wind with 

an energy-equivalent flat block of energy. The flat block will have no variability or uncertainty 
3

associated with it so that the operational differences can explicitly show these impacts. Although the 

flat block is a useful construct because of its inherent certainty and constant energy delivery, recent 

work has identified some weaknesses in this approach. Because the flat energy block is calculated to be 

the energy-equivalent to the wind, large inter-day ramps in this artificial benchmark unit can occur as a 

result of significant differences in day-to-day production between the wind energy and the flat block. 

This effect can be significant at high wind penetrations, and causes problems in the unit commitment 

and dispatch schedules inter-day. In addition, the flat block schedule tends to have more on-peak energy 

and less off-peak energy than wind generation. As a result, the daily flat block is worth $1.50 to 

$2.00/MWh more than the wind generation, and the resulting estimated wind integration costs may be 

overstated.4

The second approach does not directly calculate the cost of wind integration, but examines the impact 

that wind has on system commitment and dispatch, and calculates wind power’s net value compared to 

fuel and other variable cost reductions. This approach will compare the wind case with that of an 

identical system without wind power and compare all contrasting impacts as incremental impacts of 

adding high penetrations of wind power. Although this does not separate the impacts of wind on various 

levels of reserves, those impacts are captured implicitly in the modeling framework and results.

Common Findings 

Wind integration studies have evolved from “is it possible to integrate wind reliably” to focusing on the 

projected costs and actions necessary to integrate higher levels of wind generation with successive wind 

integration studies. As such, these studies have dispensed with several concerns with wind generation:

that wind will need a MW-for-MW backup (not necessary because the grid balances total generation and 

load, not a single group of generators or technology); that wind generation will drop to zero in seconds 

(individual wind turbines in a wind project respond differently to wind resources, leading to an overall 

smoothing in output); and that wind projects may cause the electric grid to collapse (wind projects may 

improve grid performance if equipped with reactive power capability and other grid-friendly features).

Furthermore, projected costs to integrate wind appear to be reasonable. In general, at wind penetrations 

of up to 20% of system peak demand, wind integration costs will amount to about 10% or less of the 

wholesale value of the wind generation. Note that wind integration costs for independent system 

operators (ISOs) and regional transmission operators (RTOs) are typically lower than for non-ISOs and 

RTOs. One reason for these results is that ISOs and RTOs typically operate sub-hourly markets (i.e., 

they dispatch generation on a five- to fifteen-minute time frame), while many of the non-ISOs or RTOs 

require generators to follow hourly schedules and obtain all sub-hourly balancing from regulating units.
4

Table 1. Key Results from Major Wind Integration Studies Completed 2003-2008.

Source: Lawrence Berkeley National Laboratory, 2009; National Renewable Energy Laboratory, 2008.

By time frame of grid operation, U.S. integration studies have found that the impacts of wind power tend 

to increase with the time frame. Because the variations of load and wind tend to be uncorrelated in short 

time scales, most U.S. wind integration studies have found that only modest amounts of additional 

regulation are necessary with more wind. One exception is a 2007 study by the California ISO

(CAISO), which assessed the feasibility of incorporating 6,000 MW of wind in the Tehachapi Pass 

Region in southern California. CAISO determined that regulation requirements would increase by 

nearly a factor of two, from 100 MW to 170 MW, for “up” regulation (for generation to provide 

regulation when frequency is decreasing) and from 100 MW to 500 MW for “down” regulation (when 

generation must be ramped down because frequency is increasing and needs to be decreased). CAISO 

attributed this difference with other wind integration studies to the time lag in the generator’s response 

to dispatch commands.5

U.S. wind integration studies have typically found a larger increase in the need for load following with 

higher levels of wind generation. This is due in large part to wind’s diurnal output, which in many cases 

may be opposite of the peak demand period for electricity. For instance, wind output may fall off in the 

early morning hours when load is increasing, increasing the need for generating resources to ramp up to 

meet the increasing electric demand. Conversely, wind power production may be higher during off-peak 

hours when load is decreasing or at minimum levels, increasing the need for generating resources that

Date Study

Wind 

Capacity 

Penetration

Cost ($/MWh)

Regulation Load 

Following

Unit 

Commit.

Gas 

Supply TOTAL

2003 Xcel-UWIG 3.5% 0 0.41 1.44 Na 1.85

2003 We Energies 29% 1.02 0.15 1.75 Na 2.92

2004 Xcel-MNDOC 15% 0.23 na 4.37 Na 4.60

2005 PacifiCorp-2004 11% 0 1.48 3.16 Na 4.64

2006 Calif. (multi-year)* 4% 0.45 trace trace Na 0.45

2006 Xcel-PSCo 15% 0.20 na 3.32 1.45 4.97

2006 MN-MISO** 36% na na na na 4.41

2007 Puget Sound Energy 12% na na na na 6.94

2007 Arizona Pub. Service 15% 0.37 2.65 1.06 na 4.08

2007 Avista Utilities*** 30% 1.43 4.40 3.00 na 8.84

2007 Idaho Power 20% na na na na 7.92

2007 PacifiCorp-2007 18% na 1.10 4.00 na 5.10

2008 Xcel-PSCo**** 20% na na na na 8.56

* Regulation costs represent 3-year average.

** Highest over 3-year evaluation period.

*** Unit commitment includes cost of wind forecast error.

**** This integration cost reflects a $10/MMBTU natural gas scenario. This cost is much higher than the integration 

cost calculated for Xcel-PSCo in 2006, in large measure due to the higher natural gas price: had the gas price from 

the 2006 study been used in the 2008 study, the integration cost would drop from $8.56/MWh to $5.13/MWh. 
5

can ramp down. Therefore, adding wind generation will typically require more load following to 

counteract the combined net variability of load and wind. 

For the unit commitment time frame, wind generation introduces uncertainty in the day-ahead time 

frame of scheduling and committing generating units. This is the time scale that has the largest wind 

integration cost impacts, up to almost $9.00/MWh at wind capacity penetrations of up to 20% or 30%. 

Unit commitment cost impacts are contingent on the amount of and characteristics of dispatchable 

generation resources, the amount of the wind forecast error (and interactions with the load forecast 

error), the market and regulatory environment, and the characteristics of the wind generation resource as 

compared to load. The uncertainty of wind power production in the unit commitment time frame may 

result in higher variable costs through increased fuel consumption and increased operating costs. This 

may occur if too much generation is committed due to underestimating wind production, or if not 

enough generation is committed because of overestimating expected wind generation, necessitating the 

use of quick start units, or short-term market purchases.

In addition, U.S. wind integration studies have also determined that certain periods will pose particular 

stress on grid generators: the morning load pick-up, when wind generation is typically ramping down 

while load is picking up, and times of low or minimum load, when wind production may be high when 

load is low. Because some of these potential impacts may be more pronounced by season, some grid 

operators are contemplating varying their regulation and load-following reserve requirements at 

different times of the year, in anticipation of different levels of wind output, as opposed to procuring a 

flat amount annually.

Overall, the variability of wind power generation adds to the variability on the grid in most time scales, 

and a key question that wind integration studies must address is whether there is enough existing 

capability on the grid to manage that increased variability, or whether new sources must be added to 

manage that variability. Finally, with larger levels of wind, the distribution of hourly changes in load 

widens, with more frequent events of higher hourly changes in load, both positive and negative, 

resulting in a potential need for more ramping capability. This point is illustrated in Figure 1 that 

compares the frequency of hourly changes in load with and without wind from a study that assessed the 

impacts of 25% wind generation in Minnesota. 
6

Figure 1. Load following impact of wind.

(Black shows no-wind case; gray shows net load and wind.)

Source: Enernex Corporation and Wind Logics Inc., Wind Integration Study—Final Report, Prepared for Xcel Energy and 

the Minnesota Department of Commerce, September 28, 2004, http://www.uwig.org/XcelMNDOCStudyReport.pdf. 

Strategies for Incorporating Higher Levels of Wind Generation

As noted earlier, 20% of wind generation can be accommodated on utility grids—but not by doing more 

of the same. Grid planning and operations will need to change in order to reach higher levels of wind 

and other renewable energy generation, as discussed further below.

In general, high-quality wind resources are not located where the highest demand for electricity is, or in 

areas with a robust transmission infrastructure. Therefore, new transmission will be instrumental

towards successfully integrating more wind generation. Wind power’s need for transmission coincides 

Transmission Additions and Upgrades
7

with a widespread recognition among policymakers and the electric power industry that more 

transmission is necessary, not only to aid in wind integration, but also to maintain reliability and to 

access other generating resources in addition to wind. Correspondingly, there is an explosion of 

proposed transmission projects under various stages of planning and consideration, with over two dozen

transmission projects under consideration in the western U.S. alone.6 Clearly, not all of these will be 

developed, and those that do proceed will not be ready for several years, but progress in this area will 

help immensely in wind integration. 

The development of large grid-connected wind projects in the United States occurred first in California 

in the 1980s. Typically during those early years, wind projects were disconnected during a grid 

disturbance, and wind projects were not brought back on line until the grid was brought back to a normal 

state of operation. As wind energy generation increases, the deployment of grid-friendly wind plants 

will be vital. Modern wind turbines can and are capable of providing reactive support and power factor 

control, voltage ride-through, power curtailment and ramping control, primary frequency regulation, and 

inertia response. 

Deployment of Grid-Friendly Wind Plants

The ease with which large amounts of wind power can be integrated into the electric system depends in 

large part on the size of the balancing area. Consolidating balancing areas into larger entities, accessing 

a larger balancing area through the use of dynamic scheduling, or implementing shared area control 

error or energy imbalances among multiple control areas act to facilitate the integration of larger 

amounts of wind into the system. Larger balancing areas also increase load diversity, which reduces the 

magnitude of the peak load with respect to installed generation capacity. In a similar vein, larger 

balancing areas help provide greater geographic wind diversity, which smoothes wind production and 

reduces the magnitude and frequency of extreme changes in wind production.

Balancing Areas

7 Ultimately, this serves to 

reduce the number of hours during which the most expensive units in the dispatch queue will be 

operating, subsequently reducing the operating reserve requirement and costs.

Wind Forecasting

Because of the variability and uncertainty of wind production, a common practice for grid operators and 

utilities historically in the United States has been to simply take the wind generation on an as-available 

basis and back off other generation that has been committed in order to incorporate the wind generation. 

In general, such practices are acceptable for installed wind generation amounting to small percentages of 

peak load, as the variability of the wind generation is swamped by load variability and could be easily 

absorbed. Such practices become untenable at higher levels of wind penetration, as it imposes 

operational inefficiencies and increased fuel consumption that becomes significant as wind penetration 

increases. A General Electric (GE) study assessing the potential grid impacts of 10% wind penetration 

determined that the variable operating cost savings increase from $335 million to $430 million when 

state-of-the-art wind forecasting is used, with another $25 million in benefits when perfect wind 

forecasting is used.8

 The Intermittency Analysis Project conducted by GE for the California Energy 

Commission demonstrated a benefit of $4.37/MWh with state-of-the-art wind forecasting and another 

$0.95/MWh for perfect wind forecasting.9

 Moreover, it is not only important to implement wind 

forecasting, but to incorporate it into control room operations to ensure that wind forecasting is 

accounted for in scheduling and dispatch decisions. It also will be important for wind forecasting 
8

systems to be able to successfully predict large wind ramps to allow utilities and RTOs to prepare for 

those events when they occur. 

The Electricity Reliability Council of Texas (ERCOT) and the New York ISO (NYISO) implemented 

central wind forecasting systems in 2008. PJM and the Midwest ISO will also implement a central wind 

forecasting system in 2009. They join CAISO, which implemented the nation’s first central wind 

forecasting system in 2002; CAISO is in the process of expanding and improving their system. In 

addition, Xcel Energy is collaborating with the National Center for Atmospheric Research and the 

National Renewable Energy Laboratory (NREL) in developing high-resolution wind forecasts every 

three hours for wind projects in Colorado, Minnesota, New Mexico, Texas, and Wyoming. 

Market and policy changes will likely be a necessary feature of accessing greater flexibility from either 

new or existing generation units, and that may take a combination of expanded ancillary service 

markets, incentives, and market requirements. In Texas, the GE-ERCOT study made an overarching 

recommendation that both day ahead and shorter term forecasts be used as the basis for ancillary service 

procurement. With respect to specific services, the study recommended that ERCOT consider 

introducing a new non-spinning reserve service with a startup time of 10 to 15 minutes. This service has 

the potential to reduce the amount of responsive reserves needed for identified periods of wind 

generation drop risk. With respect to regulation service, the study recommended that forecast data be 

used to adjust regulation service procurements for each hour on a day-ahead basis.

New Market Features and Products

10

Further market or policy changes may be necessary to accommodate large-scale wind ramps, which are 

relatively slow and infrequent and occur over several hours, as compared to a sudden generator trip. As 

such, wind ramps more closely resemble large load ramps than sudden unscheduled generator outages or 

trips. The ancillary service requirements from large wind ramps are more closely aligned with nonspinning reserves and supplemental operating reserve that are provided by generators and responsive loads 

that can respond within 10 to 30 minutes. Yet current reliability rules in the United States require nonspinning reserves and supplemental operating reserves to only be in service for a period of time (usually 1 

to 2 hours) that is shorter than the wind ramps that may occur over a longer period of several hours. 

Because of that, system operators may follow large wind ramps with regulation, at a cost that is 10 to 40 

times that of non-spinning reserves and supplemental operating reserves. By way of comparison, nonspinning and supplemental operating reserves are estimated to cost about $1.50/MWh on average in 

California and New York in 2008, while regulation costs ranged between $33/MWh and $60/MWh.11

Adding variable generation sources will increase the need for generation resource flexibility, i.e., the 

ability for generation to move up and down in response to changing net load as opposed to baseload 

resources that have long start-up and shut-down times and are most cost-efficient and cost-effective 

when running at full output. Generation resource flexibility will be needed at different time scales. The 

need for resource flexibility is more pronounced during times of minimum load, when generation that 

can be cycled down will be valued in order to accommodate higher levels of wind generation, as well as 

during times of low wind production, whereby generation that can ramp up will be needed. This can be 

accomplished through adding flexible sources of new generation or from garnering more flexibility from 

existing generators. 

Increasing Operational Flexibility
9

That said, while operational flexibility is of high value to grid operators, it has correspondingly little 

value for power suppliers unless compensated, as deeper turn-back, more rapid cycling and load 

following, and more frequent starts and stops all cause higher costs and revenue reductions for 

generation suppliers. Market and policy changes will likely be necessary for achieving greater amounts 

of flexible generating resources and may take a combination of expanded ancillary service markets, 

incentives, and market requirements. 

Fast, sub-hourly energy markets will also aid in integrating greater amounts of wind power and at a 

reduced cost. Sub-hourly energy markets can tap flexibility from existing generating units at little or no 

cost, and reduce the need for regulation, the most costly ancillary service. It also matches the timing of 

wind’s variability in that wind output varies more in the sub-hourly to multiple-hour time frame, not on 

a minute-to-minute basis that is characteristic of regulation. Fast, sub-hourly markets tend to be 

characteristic of ISOs and RTOs. Areas without ISOs and RTOs generally allow hourly generation 

schedules only, and most generators have to follow flat hourly schedules set one hour or more in 

advance. At least in part for this reason, wind integration costs tend to be higher in regions that do not 

have sub-hourly scheduling as compared to regions that do. 

Faster Markets

Shifting load to correspond to periods with high wind production may help avoid curtailment of wind 

generation and help manage conditions of high wind generation or times of low or minimum load. To 

date, demand response programs have been designed for reducing peak electricity demand or for 

allowing customers to self-generate using distributed generation, also during times of peak demand, not 

for aiding wind integration. One recent instance of using demand response in conjunction with wind 

production is when ERCOT called on 1200 MW of load response in February 2008 to help remedy 

falling frequency from an imbalance between generation and load.

Demand Response

12 

The U.S. Department of Energy determined that the United States can accommodate as much as 20% 

wind power generation without requiring storage. It will be many years before the levels of wind 

generation will be significant enough in the United States before storage may be needed, and in that 

time, changes in resource mix, market rules, and the other factors discussed earlier may ease large-scale 

wind integration without the need for storage technologies. Consistent with this time frame, several 

storage technologies are at an advanced R&D or demonstration stage and are not available at a large 

scale currently. That said, storage systems have recently been installed and/or tested in PJM, NYISO, 

CAISO, and ISO New England, as well as by American Electric Power and Golden Valley Cooperative 

in Alaska. These systems were not installed to “back up” wind, but to provide essential grid services 

such as regulation and voltage support. Indeed, storage should be viewed as providing grid services, not 

for supporting any individual plant or technology.

Is Storage Necessary for Integrating Wind?

Maximum wind production can be several times larger than average wind production, meaning that at 

20% wind penetration by energy, wind production may equal consumer demand for some hours. More 

recent U.S. wind integration studies have stated that at higher levels of wind penetration, wind 

generation may need to be curtailed during some portion of the year, such as during periods of low 

demand and high wind production. 

Wind Curtailment
10

Wind curtailment is occurring presently in some regions, in large part because of transmission 

constraints. ERCOT, for instance, assigns daily limits on wind generation, as there is about 8,000 MW 

of wind in an area that can accommodate about 4,500 MW of generation.13 NYISO is requiring wind 

generators to bid an economic offer price. During transmission-constrained hours, NYISO would direct 

a wind generator to reduce output if the market clearing price drops below the wind generator’s 

economic offer price. 

Conclusions

Wind integration studies have progressed from whether it is possible to incorporate wind generation to 

focusing on how to do it and at what cost. More wind integration studies are underway. ISO New 

England, the Southwest Power Pool, the Nebraska Power Association, and NYISO all have wind 

integration studies underway, and CAISO is evaluating how to incorporate 33% renewable energy 

generation. Furthermore, NREL is involved in two significant regional wind integration studies 

covering the Eastern Interconnection and the Westconnect region of the Western Interconnection that 

will shed even more light on incorporating higher levels of wind generation.14 Finally, NERC will be 

implementing a number of follow-on activities to its variable generation report, including preparing a 

reference manual for system operators on operating the grid with large amounts of variable energy 

generation.

Yet wind integration will not be accomplished successfully by doing “more of the same”—it will require 

significant changes in grid planning and operations, continued technical evolution in the design and 

operation of wind turbines, further adoption and implementation of wind forecasting in the control room, 

and consideration and incorporation of market and policy initiatives to encourage more flexible 

generation. And given the rapid increase in wind capacity in the United States over the past few years, it 

may be worthwhile to re-run some wind integration studies with actual wind power production and wind 

forecast data and determine the difference in study results between the simulated wind data that has been 

used and actual wind production data. That said, it appears that there are no fundamental and 

insurmountable obstacles when incorporating greater levels of wind power into the U.S. grid.

Authors’ Biography

Jennifer DeCesaro is a Senior Energy Analyst with Sentech, Inc., a clean energy and energy efficiency 

consulting company based in Bethesda, Maryland. At Sentech, she supports the U.S. Department of 

Energy Solar Energy Technologies Program, leading the state and utility technical outreach efforts for 

the market transformation team. She provides strategic direction on how to further the development of 

solar markets in the United States through direct outreach to state government officials and utility 

company executives. Prior to joining Sentech, Jennifer was a senior analyst at Exeter Associates, where 

she worked on issues with renewable energy integration onto the electric grid and on transmission policy

issues. She also has worked for the Clean Energy Group, the National Conference of State Legislatures,

the Catamount Institute, and as an environmental consultant in the U.S. Virgin Islands. She holds a B.A. 

in Environmental Biology from Colorado College and a Master’s Degree in Environmental Law from 

the Vermont Law School.
11

Mr. Porter is a Vice President and Principal at Exeter Associates, Inc., with over 25 years of experience 

in renewable energy technologies, state and federal regulation of the electric power industry, and 

transmission access and policy. He leads and performs research in the design, implementation, and 

evaluation of renewable energy policies; on grid integration of renewable energy technologies; and on 

development and implementation of transmission policies. Mr. Porter’s recent work includes studies of 

the Federal Energy Regulatory Commission’s generation interconnection policies, the development of 

state transmission infrastructure authorities, the performance of state renewable portfolio standards in 

the Northeastern United States, and state and regional initiatives to develop new transmission. He also 

led a large study for the California Energy Commission that assessed the feasibility of incorporating up 

to 33% renewable energy generation by 2020. He holds a B.S. in Environmental Studies from Lewis & 

Clark College in Portland, Oregon, and an M.A. in Economics from The American University in 

Washington, D.C.

 1 American Wind Energy Association, Wind Energy Grows by Record 8,300 MW in 2008, press release, January 28, 2009. 2 U.S. Department of Energy, 20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity Supply,

July 2008, http://www.20percentwind.org/20p.aspx?page=Report. 3 The North American Mesoscale Model refers to the numerical weather prediction model run by National Centers for 

Environmental Prediction for short-term weather forecasting. The model is run four times a day (00, 06, 12, 18 UTC) out to 

84 hours. It is currently run with 12-km horizontal resolution and with 1-hour temporal resolution, providing finer detail than

other operational forecast models. Numerical weather prediction uses current weather conditions as input into mathematical 

models of the atmosphere to predict the weather. Use of model ensemble forecasts helps to define the forecast uncertainty 

and extend weather forecasting farther into the future than would otherwise be possible. 4 Michael Milligan and Brendan Kirby, Calculating Wind Integration Costs: Separating Wind Energy Value from 

Integration Cost Impacts, National Renewable Energy Laboratory, NREL/TP-550-46275, July 2009, 

http://www.nrel.gov/wind/systemsintegration/pdfs/2009/milligan_wind_integration_costs.pdf. 5 California ISO, Integration of Renewable Resources, November 2007,

http://www.uwig.org/CAISOIntRenewablesNov2007.pdf. 6 Western Interstate Energy Board, “Western Transmission Expansion: Proposed Transmission Projects,” 

http://www.westgov.org/wieb/transmission/projects.html, accessed August 28, 2009. 7 Michael Milligan, Brendan Kirby, Rob Gramlich, and Michael Goggin, Impact of Electric Industry Structure on High Wind 

Penetration Potential, National Renewable Energy Laboratory, NREL/TP-550-46273, July 2009, 

http://www.nrel.gov/wind/systemsintegration/pdfs/2009/milligan_electric_structure_impact.pdf. 8 GE Energy; The Effects of Integrating Wind Power on Transmission System Planning, Reliability and Operations. Prepared 

for the New York State Energy Research and Development Authority, March 2005, http://www.uwig.org/nyserdaphase2.pdf. 9 GE Energy, Intermittency Analysis Project, Appendix B: Impact of Intermittent Generation on Operation of California 

Power Grid, July 2007, http://www.uwig.org/CEC-500-2007-081-APB.pdf. 10 GE Energy, Analysis of Wind Generation Impact on ERCOT Ancillary Services Requirements, March 28, 2008, 

http://www.uwig.org/AttchB-ERCOT_A-S_Study_Final_Report.pdf. 11 Testimony of Brendan Kirby, Consultant to the American Wind Energy Association, to the Federal Energy Regulatory 

Commission, March 2, 2009.

12 Erik Ela and Brendan Kirby, ERCOT Event on February 26, 2008: Lessons Learned, National Renewable Energy 

Laboratory, NREL/TP-500-43373, July 2008, http://www.nrel.gov/docs/fy08osti/43373.pdf. 13 A proposal to remove these limits for wind and subject all wind capacity to ERCOT transmission congestion protocols is 

working its way through the ERCOT stakeholder process.

14 For more information, see http://wind.nrel.gov/public/EWITS/ for the Eastern Wind Integration and Transmission Study 

and http://wind.nrel.gov/public/WWIS/ for the Western Wind and Solar Integration Study. 
F1146-E(10/2008)

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4. TITLE AND SUBTITLE

Wind Energy and Power System Operations: A Review of Wind 

Integration Studies to Date

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DE-AC36-08-GO28308

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Jennifer DeCesaro and Kevin Porter 

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NREL/SR-550-47256

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This paper provides an overview of the challenges associated with wind integration and summarizes the findings of 

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Wind; integration; grid; utilities; RTOs; ISOs; system impacts; transmission; planning

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