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Contract No. DE-AC36-08GO28308

Integrating Wind and Solar 

Energy in the U.S. Bulk Power 

System: 

Lessons from Regional 

Integration Studies

L. Bird and D. Lew

National Renewable Energy Laboratory

Conference Paper - American Clean Skies Foundation: CERF III

NREL/CP-6A50-55830

September 2012
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Integrating Wind and Solar 

Energy in the U.S. Bulk Power 

System: 

Lessons from Regional 

Integration Studies

L. Bird and D. Lew

National Renewable Energy Laboratory

Prepared under Task No. WWJ1.1014

Conference Paper - American Clean Skies Foundation: CERF III

NREL/CP-6A50-55830

September 2012
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Introduction

With the pace of renewable energy development in the United States increasing, questions are arising 

about how to integrate higher penetrations of renewable energy into the bulk electric power system. 

Weather-induced variability of renewable energy sources, such as wind and solar, can pose challenges for 

electric power systems. While they are designed to handle variable loads, power systems may require 

some operational changes to handle the additional variability of renewable resources.

Two recent studies sponsored by the U.S. Department of Energy (DOE) and the National Renewable 

Energy Laboratory (NREL) have examined the impacts of integrating high penetrations of wind and solar 

energy on the Eastern and Western electric grids. The Eastern Wind Integration and Transmission Study 

(EWITS), initiated in 2007, examined the impact on power system operations of reaching 20% to 30% 

wind energy penetration in the Eastern Interconnection. The Western Wind and Solar Integration Study 

(WWSIS) examined the operational implications of adding up to 35% wind and solar energy penetration 

to the Western Interconnect. Both studies examined the costs of integrating higher penetrations of 

variable renewable energy generation into the grid as well as transmission and operational changes that 

might be necessary as a result.

This paper identifies key insights from these regional studies. The studies share a number of key findings, 

but other results vary due to differences in grid operations and markets, the geographic location of the 

renewables, and the need for transmission.

Study Methods and Assumptions

Both the Eastern and Western studies used production cost models to examine scenarios of variable 

renewable energy penetration. Each study relied on a technical review committee of power system 

industry stakeholders to review inputs and assumptions. Key objectives and design elements of each study 

are detailed below.

Eastern Wind Integration and Transmission Study

EWITS modeled four scenarios of high wind energy penetration representing different levels of wind 

development in the Eastern Interconnect by 2024. The study provided data on: 1) the amount of wind 

generation required to meet 20% of the electrical energy demand in the East in 2024, and 2) for each 

scenario, possible transmission development scenarios for delivering energy economically. EWITS 

examined the following scenarios.

• A Reference Scenario that approximates the current level of wind energy development in addition to

the expected level of near-term development considering project interconnection queues and state 

renewable portfolio standards (RPS) requirements. The wind energy in the reference scenario equals 

about 6% of the 2024 projected load requirements for the Eastern Interconnection.

• Scenario 1, 20% penetration assumes onshore wind with a high capacity factor utilizing highquality wind resources in the Great Plains and development of other good wind resources in the 

eastern United States. The 20% scenarios would call for about 225,000 megawatts (MW) of wind 

generation capacity, about a tenfold increase from current levels.

• Scenario 2, 20% penetration assumes both land-based and offshore wind, shifting some wind 

generation from the Great Plains to other areas in the East and assuming some East Coast offshore 

wind.

• Scenario 3, 20% penetration assumes local development with aggressive offshore wind 

development. More wind generation is moved east toward load centers, with the offshore wind 

assumptions representing an upper bound of offshore development by 2024.

• Scenario 4, 30% penetration assumes aggressive on- and offshore development. Meeting the 30% 

energy penetration level uses a substantial amount of the available higher quality wind resource, 
2

including substantial offshore wind. The 30% scenario equals about 330,000 MW of total wind 

capacity.1

Western Wind and Solar Integration Study

The WWSIS modeled several scenarios of wind and solar energy penetration in 2017 to determine 

potential impacts on grid operations. While WWSIS is not a transmission planning study, it did examine a 

number of options for expanding interstate transmission in the West. The study specifically examined: 1) 

several scenarios in which wind and solar energy penetration reached 11% to 35% of energy needs, 2) 

several scenarios reflecting possible differences in the geographic locations of the wind and solar 

development, and 3) a number of sensitivities to assess the impacts of fuel costs, reserve levels, storage, 

balancing area size, and other factors. WWSIS included three scenarios of possible development patterns 

to examine the impacts and tradeoffs between 1) resources with low capacity factors that are close to load 

and 2) remote resources with higher capacity factors that require long distance transmission to meet

loads.2 The four levels of wind and solar energy penetration assumed for the study scenarios were:

• The Preselected case assumes wind and solar capacity installed by the end of 2008, which is 

equivalent to 3% wind and solar in the study footprint and 2% wind in the rest of the Western 

Interconnect.

• The 10% case includes 10% wind energy and 1% solar energy of total annual load in the study 

footprint covering the WestConnect transmission region1 (about 11,000 MW), with the same fraction 

in the rest of the Western Interconnect (about 23,000 MW).

• The 20% case assumes 20% wind energy and 3% solar energy in the study footprint, with 10% wind 

energy and 1% solar energy in the rest of the Western Interconnect.

• The 20/20% case assumes 20% wind energy and 3% solar energy in the WestConnect study footprint

(about 23,000 MW), as well as in the rest of the Western Interconnect (about 25,000 MW).

• The 30% case assumes 30% wind energy and 5% solar energy in the study footprint (about 36,000 

MW), with 20% wind and 3% solar in the rest of the Western Interconnect (about 53,000 MW).

Shared Lessons from Eastern and Western Integration Studies

These studies shed light on the operational changes required to accommodate higher penetrations of 

renewable energy generation on the U.S. electric grid. We focus here on findings related to the level of 

penetrations that can be managed, integration costs, the impact of operational issues such as balancing 

area size, use of forecasting, scheduling and dispatch frequency, use of demand response, and the ability 

for wind and solar to contribute to resource adequacy.

Higher penetrations of variable renewable generation are manageable

How much variable renewable generation can U.S. power systems manage? The Eastern and Western 

studies found that by 2025, with operational changes and expanded transmission access, high 

penetrations—up to 30% or 35%—of variable renewable generation are technically feasible to integrate

so that load and generation can be balanced for all hours of the year.

In the Western study, the scenarios with 10% renewable energy penetration show substantial benefits in 

terms of operating costs with no negative impacts on system operations. A scenario of 20% renewable 

energy penetration found some instances of insufficient reserves on the system as a result of forecast 

errors. While these instances could be addressed, it is more challenging to do so than in the lower 

penetration scenario. Under the 30% penetration case, load and contingency reserve requirements are met 

only if the wind and solar forecasts are perfectly accurate.

 1 WestConnect includes Arizona, northern California, Colorado, Nevada, New Mexico, and Wyoming, 

see http://westconnect.com/aboutwc.php, accessed August 23, 2012.
3

Both the Eastern and Western studies found that annual operating costs are lower because of fuel and 

emissions savings (assuming carbon has a value) that result from increased levels of wind and solar 

energy on the system. In the Western study, the high renewable penetration case reduced annual operating 

costs by 40%, or $17 billion in 2009$, compared to the reference case. In EWITS, the high renewable 

energy case reduced the annual production costs by 10% ($69 billion in 2009$), compared to the 

reference case.

Larger balancing areas and geographic diversity of renewable resources are 

preferred to minimize impacts

Both the Eastern and Western studies as well as other recent studies3 show that large operating areas and 

sufficient transmission access are effective measures for managing wind energy. Larger operating areas 

provide benefits of reducing the variability of the wind and solar when it is spread over a larger 

geographic area and providing access to more resources for balancing the system. Costs can be reduced 

through reserve sharing over larger areas or balancing area cooperation that enables pooling of reserves.

In the 10% renewable penetration case, the Western study found system operating cost savings of $1.7 

billion in 2009$ from larger balancing areas. The study compared five large balancing areas versus 106 

zones in the southern part of the interconnection that are roughly equivalent to today’s regions. Sharing 

reserves over larger regions results in significant efficiency and costs savings even without wind and solar 

on the system.

Aside from merging smaller balancing authority areas, several other ways to achieve balancing area 

cooperation are already being implemented or considered in the Western United States, where small 

balancing areas are relatively prevalent. In the West, an energy imbalance market is under consideration 

and could if implemented help balancing authority areas manage variability by accessing flexible 

generation throughout a broader region. Implementing an energy imbalance market could substantially 

reduce the amount of reserves required to manage variable generation.4

Other mechanisms that could effectively enhance balancing area cooperation include: dynamic scheduling 

and the Area Control Error (ACE) Diversity Interchange (ADI), which enables participants to net out 

imbalances.

2 Dynamic scheduling allows generation to be controlled by a balancing authority area

authority other than the one where it is physically located. This can be beneficial for wind or solar energy 

projects in areas with limited ability to handle the added variability. The ADI takes advantage of the fact 

that some balancing authority areas have excess generation while others have shortages. It enables

participating balancing authority areas to net out imbalances, which increases system efficiency and 

reduces the amount of regulation reserves needed.

Sub-hourly scheduling and planning are preferred

Both studies reinforce the idea found by other integration studies that sub-hourly scheduling and dispatch 

can aide in the integration of higher penetrations of wind and solar on the grid. The Western study found 

that hourly scheduling as is used in areas of the West today had a larger impact on balancing needs than 

the additional variability introduced by higher penetrations of wind and solar. Sub-hourly scheduling and 

dispatch is beneficial because it reduces the reserves required by the system and reduces the movement 

needed by generators providing balancing service. The Western study found that with sub-hourly 

scheduling, the amount of maneuvering of combined cycle plants is about half of that which occurs with 

hourly scheduling. WWSIS also found that the use of hourly scheduling has a larger impact on resources 

 2 For additional information on ADI, see Southwest Power Pool presentation “ACE Diversity Interchange 

Program, April 14, 2009. 

http://www.spp.org/publications/SPP%20ADI%20Implementation%20for%20MOPC%20041409.pdf, 

accessed August 23, 2012.
4

needed to provide regulation service (balancing) than the variability introduced from the levels of wind 

and solar examined in the study.

In the Eastern interconnect, the wholesale power markets already use 5-minute scheduling and dispatch of 

generation. In the East, efforts are underway to increase the scheduling frequency across neighboring 

markets, which is expected to help integrate wind and solar more efficiently particularly in areas with 

transmission congestion.

5 In the West, sub-hourly scheduling and dispatch is being explored. In 

particular, the Energy Imbalance Market currently under consideration would lead to an imbalance energy 

market with 5-minute dispatch.

Using advanced forecasting can reduce costs

Forecasting is an important tool for reducing the uncertainty associated with variable generation. While 

forecast accuracy is increased closer to the time of actual generation, incorporating day-ahead forecasting 

into the process of committing generation units can help operators mitigate the uncertainty of wind 

generation.

The Western study found that using advanced forecasting in the day-ahead unit commitment process 

would reduce annual operating costs in the Western Interconnect by up to $4 billion in 2009$, compared 

to not considering renewables in unit commitment. If forecasts were perfectly accurate, they would reduce 

annual costs by another $425 million in 2009$. While forecasts will not be perfectly accurate, this metric 

indicates the upper bound of potential cost savings with improved forecasting.

Demand response can be cost-effective

Demand response is one mechanism for providing systems with operational flexibility. It can be useful for 

assisting with the integration of variable renewable generation by helping to address large loss of 

generation events. The Western study compared the use of demand response and spinning reserves to 

meet contingency reserve shortfalls resulting from wind forecast errors with higher penetrations of wind 

on the system. The study found that it was more cost-effective to rely on demand response to address 

contingency reserve shortfalls for the 89 hours/year when they were needed than to carry additional 

spinning reserves for all hours of the year. WWSIS found that using demand response rather than 

spinning reserves saved up to $510 million (2009$) in annual operating costs.

Integration costs are manageable

Systems can incur costs due to increased balancing resources needed to manage variable renewable 

energy generation on the system. The costs can include the need for additional operating reserves, 

changes in dispatch, and new transmission. When considering renewables integration costs, it is also 

important to keep in mind that all generation sources have costs associated with managing them on the 

grid.6

The Eastern study estimated that the cost of integrating renewable energy is less than $5 per megawatthour (MWh) of wind generation, or $0.005 per kilowatt-hour (kWh), assuming large balancing areas and 

full regional markets. Thus, the costs for integrating high penetrations of wind in EWITS are manageable 

given significant operational changes and large regional operating systems.

The EWITS integration cost estimates are consistent with estimates from other integration studies. 

Integration costs for penetrations of wind energy up to about 40% of peak system loads are below 

$10/MWh and often below $5/MWh.

7 Cost estimates vary depending on calculation methodologies, 

market and power system operating characteristics, wind penetration levels, fuel price assumptions, and 

other factors.

A study by the ISO/RTO Council notes that the costs of integration vary based on the generation dispatch 

interval and the balancing area size. For example, Table 1 compares the difference in integration costs for 

areas with and without sub-hourly scheduling and dispatch. In areas with 5- or 10-minute generation 
5

dispatch, integration costs associated with dispatching units (not including transmission) ranged from $0-

$4/MWh, while integration costs were $8-$9/MWh or higher in regions with hourly dispatch.8

Table 1: Comparison of Wind Integration Costs in Five Studies

Study Date Study ISO/RTO Wind 

Capacity 

Penetration 

Integration Cost: 

$/MWh of Wind 

Output 

Energy 

Market 

Interval 

March 2005 NYISO Yes 10% Very low 5 minute 

Dec. 2006 Minnesota/MISO Yes 31% $4.41 5 minute 

Feb. 2007 GE/Pier/CAIAP Yes 33% $0–$0.69 10 minute 

March 2007 Avista No 30% $8.84 1 hour 

March 2007 Idaho Power No 30% $7.92 1 hour 

Source: ISO/RTO Council 2007

Renewables can play a role in resource adequacy – capacity value

While wind and solar are primarily energy resources, they can contribute to resource adequacy of the 

system. However, in contrast to conventional generators, only a portion of the capacity of wind and solar 

facilities can be relied on to be available to meet peak demand. The capacity value is to the fraction of the 

nameplate capacity rating of a wind or solar facility that can be considered as firm capacity. Both studies 

evaluated a range of capacity valuation techniques based on traditional Loss of Load expectation (LOLE) 

data to estimate the contribution of the wind and solar to the resource adequacy of the system.

In EWITS, wind generation was found to have an effective load carrying capability (ELCC) of 24% to 33% 

of the rated capacity. Additional transmission access was found to enhance the contribution of wind to 

resource adequacy. With expanded transmission access, the ELCC of wind generation was increased from a 

few to nearly 10 percentage points depending on the transmission scenario. It is important to note, however, 

that the analysis is based on three years of data that were available for the analysis, rather than the 10-15 

years of data typically required for such analysis. Although wind generation cannot be relied upon for 

dispatch during system peaks, EWITS shows some probability that wind generation would be available 

during peak demand periods or periods when additional energy is needed to meet demand.

In the Western study, the evaluated wind generation resources were found to have capacity values of 10% 

to 15%. These values are relatively low because wind energy generation tends to be higher at night and 

during the winter and spring seasons, when system loads are not at peak levels. The study found that solar 

PV facilities have capacity values in the range of 25% to 30% (based on the DC rating of the PV). These 

values are higher than for wind but still limited because PV generates electricity during the day, but 

output generally declines in the late afternoon and early evening which are often peak demand periods. 

For concentrating solar plants with thermal energy storage, capacity values were in the range of 90% to 

95%, similar to conventional generators.

Conclusion

Regional integration studies are an important means of understanding how to integrate higher penetrations 

of renewable generation. They build upon the extensive body of literature on grid integration and provide 

additional empirical evidence with respect to the needs for managing higher penetrations of wind and 

solar on regional electrical grids in the United States. These studies show that integrating penetrations of 

20% to 35% renewable energy is technically feasible in regional grids, with added transmission and

operational changes. In the Eastern and Western interconnects, operational changes, such as balancing 

area cooperation, sub-hourly scheduling, advanced forecasting, use of demand response, as well as 
6

increased access to transmission, can help integrate higher penetrations of variable renewable generation.

Some of these changes are already underway. For example, some steps toward balancing area cooperation 

have been implemented in the West and faster scheduling between balancing areas is being implemented 

between the Pacific Northwest and California and in the Eastern markets.

However, questions remain. The second phase of these studies, now underway, is examining in greater 

detail issues raised by the initial studies. For example, the second phase of the Western study is 

examining the impacts of 1) cycling and ramping thermal plants to accommodate variability in the system 

and the associated emissions, 2) higher penetrations of renewable energy on the system, and 3) faster 

dispatch, using models that can simulate 5-minute dispatch. The second phase of the Eastern study is 

examining how to plan and operate the Eastern Interconnection in an uncertain future, with sensitivity 

analyses of load growth, fuel prices, policy drivers, and transmission expansion. Additional emphasis in 

the Eastern study is being placed on enhancing operational flexibility in the system, reserves analysis, 

regional and inter-regional impacts, and potential mitigation strategies, such as energy storage, plug-in 

hybrid electric vehicles, curtailment, and demand response.

 1 For additional information on the study design, assumptions and results, see the Eastern Wind 

Integration and Transmission Study, prepared by EnerNex Corporation for the National Renewable 

Energy Laboratory, Golden: CO, revised February 2011 

http://www.nrel.gov/wind/systemsintegration/pdfs/2010/ewits_final_report.pdf

2 For additional information on the study design, assumptions and results, see the Western Wind and Solar 

Integration Study, prepared by GE Energy for the National Renewable Energy Laboratory, Golden: CO, 

May 2010 http://www.nrel.gov/wind/systemsintegration/pdfs/2010/wwsis_final_report.pdf

3 See for example, Corbus, D., D. Lew, G. Jordan, W. Winters, F. Van Hull, J. Manobianco, and R. Zavadil. 

November/December 2009. “Up with Wind: Studying the Integration and Transmission of Higher Levels of 

Wind Power.” IEEE Power and Energy, 7(6): 36–46.

4 J. King, B. Kirby, M. Milligan and S. Beuning, Flexibility Reserve Reductions From an Energy 

Imbalance Market With High Levels of Wind Energy in the Western Interconnection, NREL Report No. 

TP-5500-52330, October 2011, http://www.nrel.gov/docs/fy12osti/52330.pdf

5 ISO/RTO Council (2011). Briefing Paper: Variable Energy Resources, System Operations and 

Wholesale Markets, August . http://www.isorto.org/atf/cf/%7b5B4E85C6-7EAC-40A0-8DC3-

003829518EBD%7d/IRC_VER-BRIEFING_PAPER-AUGUST_2011.PDF

6 Milligan, M.; Ela, E.; Hodge, B. M.; Kirby, B.; Lew, D.; Clark, C.; DeCesaro, J.; Lynn, K. (2011). CostCausation and Integration Cost Analysis for Variable Generation. Electricity Journal, 24(9), November.

7 U.S. Department of Energy, 2011. 2010 Wind Technologies Market Report, Prepared by Lawrence 

Berkeley National Laboratory, June. http://eetd.lbl.gov/ea/EMP/reports/lbnl-4820e.pdf

8 ISO/RTO Council , (2007). Increasing Renewable Resources: How ISOs and RTOs Are Helping Meet 

This Public Policy Objective. October 16. http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-

8DC3-003829518EBD%7D/IRC_Renewables_Report_101607_final.pdf