Prepared for:

The National Renewable Energy Laboratory

Prepared by:

EnerNex Corporation

January 2010 

EASTERN WIND INTEGRATION 

AND TRANSMISSION STUDY:

Executive Summary and Project Overview
2
3

EASTERN WIND INTEGRATION 

AND TRANSMISSION STUDY:

Executive Summary and Project Overview

January 2010

Prepared for NREL by: EnerNex Corporation 

Knoxville, Tennessee

NREL Technical Monitor: David Corbus

Prepared under Subcontract No. AAM-8-88513-01

Subcontract Report

NREL/SR-550-47086

National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401

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-AC36-08GO28308
4

NOTICE

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its endorsement, recommendation, or favoring by the United States government 

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5

PREFACE

The Eastern Wind Integration and Transmission Study (EWITS) is the culmination of an 

effort that spanned two and one-half years. The study team began by modeling wind 

resources in a large part of the Eastern Interconnection and finished by conducting a 

detailed wind integration study and top-down transmission analysis. The study resulted 

in information that can be used to guide future work. A number of other studies have 

already examined similar wind integration issues, but the breadth and depth of the 

analysis in EWITS is unique. EWITS builds on the work of previous integration studies, 

which looked at considerably smaller geographic footprints, focused almost exclusively 

on wind integration, and did not include transmission. EWITS took the next step by 

expanding the study area and including conceptual transmission overlays.

Just a few years ago, 5% wind energy penetration was a lofty goal, and to some the idea 

of integrating 20% wind by 2024 might seem a bit optimistic. And yet, we know from 

the European experience—where some countries have already reached wind energy 

penetrations of 10% or higher in a short period of time—that change can occur rapidly 

and that planning for that change is critically important. Because building transmission 

capacity takes much longer than installing wind plants, there is a sense of urgency to 

studying transmission. It is already starting to limit wind growth in certain areas.

The goal of the EWITS team was not to further any specific agenda or regional vision of 

the future, but to be as objective as possible while conducting a technical study of future 

high-penetration wind scenarios. To help guide the EWITS work, the U.S. Department of 

Energy’s (DOE) National Renewable Energy Laboratory (NREL) convened a Technical 

Review Committee (TRC) composed of regional electric reliability council representatives, 

expert reviewers, transmission planners, utility administrators, and wind industry 

representatives. Over a period of 14 months while the study was in progress, the TRC 

held 6 full-day meetings along with numerous Webinars and conference calls to review 

study progress; comment on study inputs, methods, and assumptions; assist with 

collecting data; and review drafts of the study report.

Planning for the expansion of the electrical grid is a process that requires an immense 

amount of study, dialogue among regional organizations, development of technical 

methodologies, and communication and coordination among a multitude of important 

stakeholders. Keeping abreast of the changes is challenging because there are so many 

different developments, ideas, and viewpoints. It is my hope that the EWITS results will 

be helpful to all those involved in the planning of the future electrical grid and form a 

foundation for future studies.

This document is intended as a high-level overview of the full report, which is 

forthcoming and will be posted at http://www. nrel.gov/ewits/ when available.

David Corbus

Senior Engineer, NREL
6

ACKNOWLEDGMENTS

The National Renewable Energy Laboratory (NREL) thanks the U.S. Department 

of Energy (DOE) for sponsoring EWITS; the Technical Review Committee 

(TRC) for such great participation and input; and the study team of EnerNex 

Corporation, the Midwest Independent System Operator (Midwest ISO), and 

Ventyx for carrying out the work. Thanks also go to Study Lead Robert Zavadil, 

along with Michael Brower of AWS Truewind, who conducted the wind 

modeling study. 

PROJECT MANAGER

David Corbus NREL

STUDY TEAM

EnerNex Corporation: Jack King, Tom Mousseau, and Robert Zavadil

Midwest ISO: Brandon Heath, Liangying (Lynn) Hecker, 

John Lawhorn, Dale Osborn, and JT Smith

Ventyx: Rick Hunt and Gary Moland

TECHNICAL REVIEW COMMITTEE 

John Adams New York Independent System Operator 

(NYISO)

Mark Ahlstrom WindLogics

Jared Alholinna CapX 2020 (Great River Energy)

Steve Beuning Xcel Energy

Clifton Black Southern Company

Jay Caspary Southwest Power Pool (SPP)

Charlton Clark DOE

Cathy Cole Michigan Public Service Commission

David Corbus (co-chair) NREL

Dan Fredrickson Mid-Continent Area Power Pool (MAPP)

Michael Goggin American Wind Energy Association (AWEA)

Sasan Jalai (observer) Federal Energy Regulatory Commission (FERC)

Brendan Kirby NREL

Chuck Liebold PJM Interconnection

Michael Milligan NREL

Jeff Mitchell North American Electric Reliability Corporation 

(NERC; ReliabilityFirst)

Nathan Mitchell American Public Power Association (APPA)

Don Neumeyer Organization of MISO States 

(Wisconsin Public Service Commission)
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Mark O’Malley University College Dublin

Dale Osborn Midwest ISO 

Dick Piwko GE Energy

Matt Schuerger (co-chair) NREL

Ken Schuyler PJM Interconnection

Richard Sedano Regulatory Assistance Project

J. Charles Smith Utility Wind Integration Group (UWIG)

Jason Smith SPP

Dave Souder PJM Interconnection

Finally, we thank René Howard (WordProse, Inc.), Kathy O’Dell (NREL), and 

Christina Thomas (Sage TechEdit Inc.) for their help in editing and production 

and Mark Schroder (Purple Sage Design) for designing this Executive Summary

and Project Overview and the full report.
8

EXECUTIVE SUMMARY 

The total installed capacity of wind generation in the United States surpassed 

25 gigawatts (GW) at the end of 2008. Despite the global financial crisis, another 

4.5 GW was installed in the first half of 2009. Because many states already have 

mandates in place for renewable energy penetration, significant growth is 

projected for the foreseeable future. 

In July 2008, the U.S. Department of Energy (DOE) published the findings of 

a year-long assessment of the costs, challenges, impacts and benefits of wind 

generation providing 20% of the electrical energy consumed in the United States by 

2030 (EERE 2008). Developed through the collaborative efforts of a wide-ranging 

cross section of key stakeholders, that final report (referred to here as the 20% 

Report) takes a broad view of the electric power and wind energy industries. The 

20% Report evaluates the requirements and outcomes in the areas of technology, 

manufacturing, transmission and integration, environmental impacts, and markets 

that would be necessary for reaching the 20% by 2030 target. 

The 20% Report states that although significant costs, challenges, and impacts 

are associated with a 20% wind scenario, substantial benefits can be shown 

to overcome the costs. In other key findings, the report concludes that such a 

scenario is unlikely to be realized with a business-as-usual approach, and that 

a major national commitment to clean, domestic energy sources with desirable 

environmental attributes would be required. 

The growth of domestic wind generation over the past decade has sharpened the 

focus on two questions: Can the electrical grid accommodate very high amounts 

of wind energy without jeopardizing security or degrading reliability? And, given 

that the nation’s current transmission infrastructure is already constraining further 

development of wind generation in some regions, how could significantly larger 

amounts of wind energy be developed? The answers to these questions could hold 

the keys to determining how much of a role wind generation can play in the U.S. 

electrical energy supply mix. 

ABOUT THE STUDY

DOE commissioned the Eastern Wind Integration and Transmission Study 

(EWITS) through its National Renewable Energy Laboratory (NREL). The 

investigation, which began in 2007, was the first of its kind in terms of scope, 

scale, and process. The study was designed to answer questions posed by a 

variety of stakeholders about a range of important and contemporary technical 

issues related to a 20% wind scenario for the large portion of the electric load 
9

(demand for energy) that resides in the Eastern Interconnection (Figure 1). The 

Eastern Interconnection is one of the three synchronous grids covering the lower 

48 U.S. states. It extends roughly from the western borders of the Plains states 

through to the Atlantic coast, excluding most of the state of Texas.

Figure 1. NERC synchronous interconnections

Notes: NERC = North American Electric Reliability Corporation; WECC = Western 

Electricity Coordinating Council; TRE = Texas Regional Entity; ERCOT = Electric 

Reliability Council of Texas; MRO = Midwest Reliability Organization; SPP = Southwest 

Power Pool; NPCC = Northeast Power Coordinating Council; RFC = ReliabilityFirst 

Corporation; SERC = Southeastern Electric Reliability Council; FRCC = Florida Reliability 

Coordinating Council

EWITS is one of three current studies designed to model and analyze wind 

penetrations on a large scale. The Western Wind and Solar Integration Study 

(WWSIS), also sponsored by DOE/NREL, is examining the planning and 

operational implications of adding up to 35% wind and solar energy penetration 

to the WestConnect footprint in the WECC. The European Wind Integration 

Study (EWIS) is an initiative established by the European associations of 

transmission system operators in collaboration with the European Commission. 

EWIS is aimed at developing common solutions to wind integration challenges 

in Europe and at identifying arrangements that will make best use of the panEuropean transmission network, allowing the benefits of wind generation to be 

delivered across Europe.
10

EWITS was the first of its kind in terms of scope, scale, and process. Initiated 

in 2007, the study was designed to examine the operational impact of up to 

20% to 30% wind energy penetration on the bulk power system in the Eastern 

Interconnection of the United States. 

SCENARIO DEVELOPMENT AND ANALYSIS 

To set an appropriate backdrop for addressing the key study questions, the 

EWITS project team—with input from a wide range of project stakeholders 

including the Technical Review Committee (TRC)—carefully constructed four 

high-penetration scenarios to represent different wind generation development 

possibilities in the Eastern Interconnection. Three of these scenarios delivered 

wind energy equivalent to 20% of the projected annual electrical energy 

requirements in 2024; the fourth scenario increased the amount of wind energy 

to 30%. 

In each scenario, individual wind 

plants from the Eastern Wind Data 

Study database (see sidebar) were 

selected to reach the target energy 

level. The wind data consisted 

of hourly and 10-minute wind 

plant data for each of three years: 

2004, 2005, and 2006. Wind plants 

were available in all geographic 

locations within the Eastern 

Interconnection except off the shore 

of the southeastern United States 

and Canada (because of limitations 

on the scope of work for the wind 

modeling). Approximately 4 GW of new Canadian renewable generation was 

modeled to cover imports of new Canadian wind and hydro to the northeast. 

 A brief description of each scenario follows:

• Scenario 1, 20% penetration – High Capacity Factor, Onshore: Utilizes 

high-quality wind resources in the Great Plains, with other development 

in the eastern United States where good wind resources exist. 

• Scenario 2, 20% penetration – Hybrid with Offshore: Some wind 

generation in the Great Plains is moved east. Some East Coast offshore 

development is included. 

• Scenario 3, 20% penetration – Local with Aggressive Offshore: More wind 

generation is moved east toward load centers, necessitating broader 

use of offshore resources. The offshore wind assumptions represent an 

uppermost limit of what could be developed by 2024 under an aggressive 

technology-push scenario.

The Eastern Wind Data Study

A precursor to EWITS known as the Eastern Wind Data Study 

(AWS Truewind 2009) identified more than 700 GW of potential 

future wind plant sites for the eastern United States. All the 

major analytical elements of EWITS relied on the time series wind 

generation production data synthesized in this earlier effort. The 

data cover three historical years—2004, 2005, and 2006—at high 

spatial (2-kilometer [km]) and temporal (10-minute) resolution. 

On- and offshore resources are included, along with wind 

resources for all states.
11

What Are ISOs and RTOs?

In the mid-1990s, independent system operators (ISOs) and 

regional transmission operators (RTOs) began forming to support 

the introduction of competition in wholesale power markets. 

Today, two-thirds of the population of the United States and 

more than one-half of the population of Canada obtain their 

electricity from transmission systems and organized wholesale 

electricity markets run by ISOs or RTOs. These entities ensure that 

the wholesale power markets in their regions operate efficiently, 

treat all market participants fairly, give all transmission customers 

open access to the regional electric transmission system, and 

support the reliability of the bulk power system.

Source: Adapted from IRC (2009).

• Scenario 4, 30% penetration – Aggressive On- and Offshore: Meeting the 

30% energy penetration level uses a substantial amount of the higher 

quality wind resource in the NREL database. A large amount of offshore 

generation is needed to reach the target energy level.

The study team also developed a Reference Scenario to approximate the current 

state of wind development plus some expected level of near-term development 

guided by interconnection queues and state renewable portfolio standards (RPS). 

This scenario totaled about 6% of the total 2024 projected load requirements for 

the U.S. portion of the Eastern Interconnection.

Figure 2 depicts the installed 

capacity by regional entity (either 

independent system operators [ISOs] 

or regional transmission operators 

[RTOs]; see sidebar) for each of the 

wind generation scenarios in EWITS. 

Table 1 shows the contribution 

of total and offshore wind to the 

scenarios.

 Supplying 20% of the electric 

energy requirements of the 

U.S. portion of the Eastern 

Interconnection would call for 

approximately 225,000 megawatts 

(MW) of wind generation capacity, 

which is about a tenfold increase 

above today’s levels. To reach 30% energy from wind, the installed capacity 

would have to rise to 330,000 MW.
12

Figure 2. Summary of installed wind generation capacity by operating region 

for each scenario (Notes: ISO-NE = New England Independent System Operator, 

MISO = Midwest ISO, NYISO = New York ISO, PJM = PJM Interconnection, 

SERC = Southeastern Electric Reliability Council, SPP = Southwest Power Pool, 

TVA – Tennessee Valley Authority)

TABLE 1. TOTAL AND OFFSHORE WIND IN THE SCENARIOS

Region Scenario 1

20% High Capacity Factor, 

Onshore

Scenario 2 

20% Hybrid with Offshore 

Scenario 3 

20% Local, 

Aggressive Offshore 

Scenario 4 

30% Aggressive 

On- and Offshore 

TOTAL 

(MW) 

Offshore 

(MW)

Total 

(MW) 

Offshore 

(MW)

Total 

(MW)

Offshore 

(MW)

Total 

(MW)

Offshore 

(MW)

MISO/

MAPPa

 94,808 69,444 46,255 95,046

SPP 91,843 86,666 50,958 94,576

TVA 1,247 1,247 1,247 1,247

SERC 1,009 5,009 4,000 5,009 4,000 5,009 4,000

PJM 22,669 33,192 5,000 78,736 39,780 93,736 54,780

NYISO 7,742 16,507 2,620 23,167 9,280 23,167 9.280

ISO-NE 4,291 13,837 5,000 24,927 11,040 24,927 11,040

TOTAL 223,609 0 225,902 16,620 230,299 64,100 337,708 79,100

a MAPP stands for Mid-Continent Area Power Pool.
13

KEY STUDY FINDINGS 

The EWITS technical work yielded detailed quantitative information on

• Wind generation required to produce 20% of the projected electrical 

energy demand over the U.S. portion of the Eastern Interconnection 

in 2024

• Transmission concepts for delivering energy economically for each 

scenario (new transmission for each scenario is based on economic 

performance for the conditions outlined in that scenario) 

• Economic sensitivity simulations of the hourly operation of the power 

system defined by a wind generation forecast scenario and the associated 

transmission overlay

• The contribution made by wind generation to resource adequacy and 

planning capacity margin. 

The specific numeric results of the analysis are sensitive to the many assumptions 

that were required to define the 2024 study year. The study assumptions were 

developed in close coordination with the TRC. Changes in the assumptions, 

such as the cost of various fuels, the impact of regulation and policy, or the 

costs associated with new construction, would have a major influence. Other 

assumptions, such as the electrical energy demand and its characteristics—

penetration and capabilities of demand response, influence of smart grid 

technologies, or the very nature of the load itself (as in an aggressive plug-in 

hybrid electric vehicle [PHEV] scenario)—would be likely to have a measurable 

impact on the results.

In general, though, the study shows the following: 

• High penetrations of wind generation—20% to 30% of the electrical 

energy requirements of the Eastern Interconnection—are technically 

feasible with significant expansion of the transmission infrastructure.

• New transmission will be required for all the future wind scenarios in 

the Eastern Interconnection, including the Reference Case. Planning for 

this transmission, then, is imperative because it takes longer to build new 

transmission capacity than it does to build new wind plants.

• Without transmission enhancements, substantial curtailment (shutting 

down) of wind generation would be required for all the 20% scenarios.

• Interconnection-wide costs for integrating large amounts of wind 

generation are manageable with large regional operating pools and 

significant market, tariff, and operational changes.

• Transmission helps reduce the impacts of the variability of the wind, 

which reduces wind integration costs, increases reliability of the electrical 

grid, and helps make more efficient use of the available generation 

resources. Although costs for aggressive expansions of the existing 

grid are significant, they make up a relatively small portion of the total 

annualized costs in any of the scenarios studied. 
14

• Carbon emission reductions in the three 20% wind scenarios do not vary 

by much, indicating that wind displaces coal in all scenarios and that 

coal generation is not significantly exported from the Midwest to the 

eastern United States; carbon emissions are reduced at an increased rate 

in the 30% wind scenario as more gas generation is used to accommodate 

wind variability. Wind generation displaces carbon-based fuels, directly 

reducing carbon dioxide (CO2) emissions. Emissions continue to decline 

as more wind is added to the supply picture. Increasing the cost of carbon 

in the analysis results in higher total production costs. 

The scenarios developed for EWITS do not in any way constitute a plan; instead, 

they should be seen as an initial perspective on a top-down, high-level view of 

four different 2024 futures. The transition over time from the current state of 

the bulk power system to any one of the scenarios would require additional 

technical and economic evaluation, including detailed modeling of power 

flows and a study of the effects on the underlying transmission systems. A 

more thorough evaluation of the sensitivity of the EWITS results to the range 

of assumptions made would also be required to guide the development of any 

specific bottom-up plans. 

The significant amount of analytical 

work performed in EWITS, though, 

answers the questions posed at the 

outset of the project:

1. What impacts and costs do 

wind generation variability 

and uncertainty impose on 

system operations? With 

large balancing areas and 

fully developed regional 

markets, the cost of 

integration for all scenarios 

is about $5 (US$ 2009) per 

megawatt-hour (MWh) of wind, or about $0.005 per kilowatt-hour 

(kWh) of electricity used by customers. 

2. What benefits accrue from long-distance transmission that accesses 

multiple and geographically diverse wind resources? The study results 

show that long-distance (and high-capacity) transmission can assist 

smaller balancing areas with wind integration, allowing penetration 

levels that would not otherwise be feasible. Furthermore, all scenarios, 

including the Reference Case, made use of major transmission 

upgrades to better interlock Eastern Interconnection markets for 

assisting with wind integration.

Why Regional Markets?

Because they span large geographic areas, regional markets 

optimize the power grid by promoting efficiency through 

resource sharing. These organized markets are designed so 

that an area with surplus electricity can benefit by sharing 

megawatts with another region in the open market. This allows 

participants and operators to see the big picture when it 

comes to dispatching electricity in the most efficient manner. 

Source: Adapted from www.isorto.org. Accessed November 2009.
15

3. What benefits are realized from long-distance transmission that moves 

large quantities of remote wind energy to urban markets? Long-distance 

transmission, along with assumed modifications to market and system 

operations, contributes substantially to integrating large amounts of 

wind that local systems would have difficulty managing. In addition, 

long-distance transmission has other value in terms of system 

robustness that was not completely evaluated in EWITS.

4. How do remote wind resources compare to local wind resources? In the 

Eastern Interconnection, the Eastern Wind Data Study database (AWS 

Truewind 2009) shows that the higher quality winds in the Great Plains 

have capacity factors that are about 7%–9% higher than onshore wind 

resources near the high-load urban centers in the East. Offshore plants 

have capacity factors on par with Great Plains resources but the cost of 

energy is higher because capital costs are higher. 

5. How much does geographical diversity, or spreading the wind out across 

a large area, help reduce system variability and uncertainty? Quite 

substantially. 

6. What is the role and value of wind forecasting? With significant wind 

generation, forecasting will play a key role in keeping energy markets 

efficient and reducing the amount of reserves carried while maintaining 

system security. 

7. What benefit does balancing area cooperation or consolidation bring to 

wind variability and uncertainty management? This and other recent 

studies (see Bibliography) reinforce the concept that large operating 

areas—in terms of load, generating units, and geography—combined 

with adequate transmission, are the most effective measures for 

managing wind generation. 

8. How does wind generation capacity value affect reliability (i.e., supply 

resource adequacy)? Wind generation can contribute to system 

adequacy, and additional transmission can enhance that contribution. 

SCENARIO COSTS 

EWITS looks at a “snapshot” in time for a single year in the future. A 

transformation of the bulk power system in the Eastern Interconnection to 

the degree suggested by the study scenarios would result if many capital 

investments were made from the present through 2024. Consequently, economic 

analysis of the scenarios brings to light complicated questions that cannot be 

answered precisely without a detailed timeline of capital expenditures. 
16

Because the study scenarios need to be compared on an economic basis, total 

costs for each scenario are approximated by identifying the fixed (investment) 

and variable (production) cost components. These costs are then summed, 

allowing the study team to view some measure of economic performance for 

each scenario side by side. 

Study analysts calculated costs for each scenario as the sum of production-related 

costs (e.g., fuel costs) plus annualized amounts for capital investments in new 

conventional generation, wind plants, and transmission. The results for the 

Reference Case and the four high-penetration scenarios (Figure 3, in millions of 

US$2009) show that Scenario 1 is the least costly of the 20% scenarios, and that 

the increased cost of offshore wind adds to the costs in Scenarios 3 and 4.

Figure 3. Comparison of scenario costs

Although production-related costs constitute a large fraction of the total costs 

for all scenarios, these decline as the amount of wind generation increases. In 

scenarios 3 and 4, capital costs for wind generation increase because of slightly 

lower capacity factors and the much higher capital cost of offshore construction. 

Transmission costs are a relatively small fraction for all scenarios, with only a 

small absolute difference seen across the 20% cases. Wind integration costs are 

measurable but very small relative to the other factors. 

None of the initial scenarios include any costs associated with carbon, which 

increases production costs significantly. The carbon price was addressed in a 

sensitivity analysis for Scenario 2, as described later in this Executive Summary

and Project Overview.
17

STUDY METHODOLOGY 

The EWITS project consisted of three major tasks: (1) wind plant output data 

development, (2) transmission requirements analysis, and (3) wind integration 

analysis. In wind integration studies, it is important to use concurrent load and 

wind data to capture the correlations 

between load and wind (i.e., weather; 

see sidebar). 

The project team developed the 

quantitative information through a 

multistage analytical process, shown 

graphically in Figure 4. Methods 

developed and refined in previous 

integration studies formed the 

basis for the technical analysis, but 

were necessarily extended because 

the scope and size of this effort 

surpassed that of earlier studies. 

Focus on transmission requirements 

for the substantial amount of wind 

generation required to meet the 20% 

and 30% energy targets was a new and 

significant part of the study scope. 

The Role of Weather and Wind Forecasting

Using numerical weather prediction models, also known as 

mesoscale models, is an accepted method for producing a time 

series of wind plant output data. Essentially, physics-based, 

numerical simulations on supercomputers, integrated with 

observational data sets, re-create the weather of historical years 

and generate a four-dimensional gridded wind-speed data set. A 

wind speed time series data set can be extracted and converted 

to wind power output. This approach produces a temporally, 

spatially, and physically consistent wind data set. For EWITS, this 

was done for hundreds of wind plants and the study team used 

these data sets in the modeling of the different scenarios. 

Wind forecast data modeling is an increasingly common tool 

used by utilities and ISOs to schedule generation units. Wind 

integration studies typically include the effect of wind forecast 

errors on integration costs. 
18

Notes: A copper sheet simulation assumes no transmission constraints or congestion.

LOLE = loss of load expectation and ELCC = effective load-carrying capability

Figure 4. Study process

Current transmission expansion planning is based on a decision-making process 

that starts with the present and looks forward through time. The existing bulk 

power grid in the United States is the result of such a bottom-up approach. 

In EWITS, the project team used top-down economic methods to develop the 

conceptual transmission capacity needed to deliver energy to load. These topdown methods tend to create designs with more transmission than bottom-up 

methods. The primary reason is that the total economic potential of increasing 

the economic efficiency of the generation fleet—including wind generation in 

the Eastern Interconnection—is used to justify transmission expansion. The 

combination of capturing the economic potential of both nonwind and wind 

generation loads the transmission lines more efficiently (i.e., the lines are not just 

being used for wind). The transmission requirements are mainly off peak for the 

wind generation and on peak for the nonwind generation. 

Although the study assumptions were touched on previously, a more detailed 

look is helpful at this point. Peak demand and energy for all study regions 

was based on 2004–2006 Federal Energy Regulatory Commission (FERC) data 
19

combined with 2006 power flow data. These data had been compiled for a 

previous study, and were reviewed by all stakeholders at that time. To preserve 

correlation with the wind generation profile data, load data for EWITS were 

mapped to conform to actual wind profiles representing calendar years 2004, 

2005, and 2006.

Because of the very large amount of wind generation studied, it was important 

to establish a framework for the day-to-day operations of the Eastern 

Interconnection in 2024. Results from past integration studies have shown that 

operational structure plays a major role in determining the difficulty or ease with 

which wind generation is integrated. 

Small balancing areas, which were 

the original building blocks of 

today’s major interconnections, 

can be significantly challenged by 

large amounts of wind generation. 

Large effective balancing areas (see 

sidebar) have more supply resources 

to deploy and benefit substantially 

from diversity in both load and 

wind generation. 

Extrapolating from trends that 

have been seen for the past 

decade, the study team—with 

input from the TRC—assumed 

that by 2024 operations in the 

Eastern Interconnection (at least 

the significant fraction modeled 

explicitly in EWITS) would be 

conducted under the auspices of 

seven large balancing areas, which 

are shown in Figure 5. The structure 

as it existed in August 2007 was 

used for comparison. Five of the seven correspond to existing RTOs in the 

Eastern Interconnection. 

The project team also assumed that operations in each area would conform 

to the same structure. For example, on the day before the operating day, all 

generating units bid competitively to serve load, and after market clearing, 

operators perform a security-constrained unit commitment to ensure that 

adequate capacity will be available to meet forecast load. During the operating 

day, generators are dispatched frequently to follow short-term demand trends 

under a fast, subhourly market structure. A competitive ancillary services market 

Operating the Grid

Balancing Authority

A balancing authority is the responsible entity that maintains 

load resource balance within a given, predefined area (the 

balancing authority area). The authority develops integrated 

resource plans, matches generation with load, maintains 

scheduled interchanges with other balancing authority areas, 

and supports interconnection frequency of the electric power 

systems in real time.

Reliability-Related Services 

In the NERC Functional Model, which defines the set of functions 

that must be performed to ensure the reliability of the bulk 

electric system, these include the range of services, other than 

the supply of energy for load, that are physically provided by 

generators, transmitters, and loads in order to maintain reliability. 

In wholesale energy markets, they are commonly described as 

“ancillary services.” 

Source: Adapted from http://www.nerc.com/files/opman_12-13Mar08.pdf.

Accessed November 2009.
20

supplies regulation, balancing, and unused generation capacity to cover large 

events such as the loss of major generating facilities. 

The assumptions made about operating structure are very significant given 

the current operations in the Eastern Interconnection. The assumed market 

mechanisms, however, are actually in use today, albeit not uniformly, and have 

been shown in previous studies to be of substantial value for wind integration. 

There is some probability that developments in market operation over the next 

decade could further enhance the ability to integrate wind energy. 

Figure 5. Assumed operational structure for the Eastern Interconnection in 2024 

(white circles represent balancing authorities; Entergy is operated as part of SERC)
21

PROJECT OVERVIEW

This section describes the transmission requirements, wind operational impacts, 

production-cost modeling results, wind integration costs, carbon sensitivity 

analysis, and the wind contribution to resource adequacy for EWITS.

TRANSMISSION REQUIREMENTS

EWITS uses a deterministic, chronological production-cost model (PROMOD 

IV®)

1

 for evaluating transmission requirements. The study process began with 

locating wind generation across the interconnection, and then determining 

what additional nonwind capacity would be required in each region to 

maintain reliability for the projected energy demand in the study year. No new 

transmission was considered at this stage. This step allowed the study analysts to 

identify the locations of electrical energy supply and locate the loads or demand 

for the energy. To develop the transmission overlays, then, the project team used 

economic signals to connect the “sources” (supply) to the “sinks” (loads). 

The study team used an economics-based expansion planning methodology to 

develop transmission requirements for each scenario based on the output of the 

different production simulations. Before each set of simulations, the additional 

nonwind capacity required to reliably serve the projected load was determined 

using traditional generation expansion methodologies. Wind generation was 

assigned a firm capacity value of 20%. Next, wind generation and the indicated 

conventional expansion were added to the production-cost model that contained 

the existing transmission network. 

After simulating system operation over an entire year of hourly data, study 

analysts then compared the results of this modeling simulation to those from 

a similar simulation in which constraints on the transmission system were 

removed. The comparison indicates how regional or interconnection-wide 

production costs increase because of transmission congestion, or put another 

way, what value could be achieved by eliminating or reducing transmission 

constraints. Differences between the “constrained” case and the “unconstrained” 

case yield the following information:

• The areas of economic energy sources and sinks 

• The interface flow changes to determine the incremental transfer 

capacity needs

• The total benefit savings, which in turn gives a rough estimate of a 

potential budget for building transmission to relieve constraints and 

reduce congestion costs 

1 PROMOD IV (developed by Ventyx) is an integrated electric generation and transmission market simulation system that 

incorporates extensive details of generating unit operating characteristics and constraints, transmission constraints, generation 

analysis, unit commitment/operating conditions, and market system operations. PROMOD IV performs an 8,760-hour 

commitment and dispatch recognizing both generation and transmission impacts at the bus-bar level. (Bus-bar refers to 

the point at which power is available for transmission.)
22

Transmission flows between regions in EWITS are determined in part by the 

differences between production simulations using a “copper sheet” (i.e., no 

transmission constraints, no congestion) versus the existing transmission system. 

Transmission capacity is designed to deliver 80% of the desired energy flow. 

Figure 6 shows the annual generation differences between the unconstrained and 

constrained cases for Scenario 2. This helps to define the energy source and sink 

areas and gives insight into the optimal locations for potential transmission lines 

and substations. Red represents the energy source areas; blue signifies the energy 

sink areas. As Figure 7 illustrates, the price signal drives energy from low-cost 

source areas to high-cost sink areas if the transmission system is not constrained 

across the study footprint.

Figure 6. Scenario 2, annual generation differences between unconstrained 

case and constrained case (Note: Because price contours developed from defined 

pricing hubs, they do not correspond exactly to geography.)
23

Figure 7. Scenario 2, annual generation weighted locational marginal price 

(LMP) for constrained case

Using these comparative results as a guide, and with input from the TRC, the 

study team developed transmission overlays for each scenario. 

The conceptual transmission overlays, shown in Figure 8, consist of multiple 

800-kilovolt (kV) high-voltage direct current (HVDC) and extra-high voltage 

(EHV) AC lines with similar levels of new transmission and common elements 

for all four scenarios. Tapping the most high-quality wind resources for all 

three 20% scenarios, the project team arrived at a transmission overlay for 

Scenario 1 that consists of nine 800-kV HVDC lines and one 400-kV HVDC line. 

For Scenario 2, analysts moved some wind generation eastward, resulting in 

a reduced transmission overlay with seven 800-kV HVDC lines and one 400-

kV HVDC line. As more wind generation is moved toward the east and more 

offshore resources are used in Scenario 3, the resulting transmission overlay has 

the fewest number of HVDC lines, with a total number of five 800-kV HVDC 

lines and one 400-kV HVDC line. To accommodate the aggressive 30% wind 

target and deliver a significant amount of offshore wind along the East Coast in 

Scenario 4, the overlay must be expanded to include ten 800-kV HVDC lines and 

one 400-kV HVDC line. 
24

Figure 8. Conceptual EHV transmission overlays for each study scenario

Tables 2 through 4 summarize the transmission and construction cost-permile assumptions by voltage level, the estimated total line miles by voltage 

level, and the estimated cost in US$2024 for the four wind scenario conceptual 

overlays, respectively. In Table 4, the total AC line costs include a 25% margin 

to approximate the costs of substations and transformers. In addition, the total 

HVDC line costs include those for terminals, communications, and DC lines. 

Costs associated with an offshore wind collector system and those for some 

necessary regional transmission upgrades are not included in the total estimated 

cost and would increase total transmission costs. With approximately 22,697 

miles of new EHV transmission lines, the transmission overlay for Scenario 1 has 

the highest estimated total cost at $93 billion (US$2009). 
25

Specific findings and conclusions from development of the transmission overlays 

for each scenario include the following: 

• The 800-kV HVDC and EHV AC lines are preferred if not required 

because of the volumes of energy that must be transported across and 

around the interconnection, as well as the distances involved. 

• Similar levels of new transmission are needed across the four scenarios, 

and certain major facilities appear in all the scenarios. This commonality 

is influenced by the top-down method used and the location of the wind 

generation in each scenario. The study focuses on four possible 2024 

“futures.” Determining a path for realizing one or more of those futures 

was outside the study scope. Large amounts of transmission are also 

required in the Reference Case.

• The modeling indicates that significant wind generation can be 

accommodated as long as adequate transmission capacity is available and 

market/operational rules facilitate close cooperation among the operating 

regions.

TABLE 3. ESTIMATED LINE MILEAGE BY SCENARIO

Estimated Line Mileage Summary

Voltage 

Level

345 kV 345 kV AC 

(double 

circuit)

500 kV 500 kV AC 

(double 

circuit)

765 kV 400 kV DC 800 kV DC TOTAL

Reference 3,106 292 593 494 2,624 470 2,400 9,979

Scenario 1 1,977 247 1,264 243 7,304 560 11,102 22,697

Scenario 2 1,977 247 1,264 243 7,304 560 8,352 19,947

Scenario 3 1,977 247 1,264 742 7,304 769 4,747 17,050

Scenario 4 1,977 247 1,264 742 7,304 560 10,573 22,667

TABLE 4. ESTIMATED COSTS BY SCENARIO (US$2009, MILLIONS)

Estimated Cost Summary (US $2024, millions)

Voltage 

Level

345 kV 345 kV AC 

(double 

circuit)

500 kV 500 kV AC 

(double 

circuit)

765 kV 400 kV DC 800 kV DC Total

Reference 5,607 880 1,367 1,900 10,790 1,383 9,243 31,170

Scenario 1 3,569 743 2,916 935 30,033 1,539 53,445 93,179

Scenario 2 3,569 743 2,916 935 30,033 1,539 40,206 79,941

Scenario 3 3,569 743 2,916 935 30,033 1,898 22,852 64,865

Scenario 4 3,569 743 2,916 935 30,033 1,539 50,898 92,551

TABLE 2. TRANSMISSION COST ASSUMPTIONS

Cost-per-Mile Assumption

Voltage Level 345 kV 345 kV AC 

(double 

unit)

500 kV 500 kV AC 

(double 

circuit)

765 kV 400 kV DC 800 kV DC

US$2024 (millions) 2,250,000 3,750,000 2,875,00 4,792,00 5,125,000 3,800,000 6,000,000

US$2009 (millions) 1,440,000 2,410,000 1,850,00 3,080,00 3,290,000 2,440,000 3,850,000
26

• Transmission offers capacity benefits in its own right, and enhances wind 

generation’s contribution to reliability by a measurable and significant 

amount.

• The EHV DC transmission that constitutes a major portion of the overlays 

designed for the scenarios in EWITS has benefits beyond those evaluated 

here. For example, it would be possible to schedule reserves from one area 

to another, effectively transporting variability resulting from wind and 

load to areas that might be better equipped to handle it. And the transfer 

capability of the underlying AC network could be enhanced by using the 

DC terminals to mitigate limitations caused by transient stability issues. 

WIND OPERATIONAL IMPACTS

Reliable delivery of electrical energy to load centers entails a continuous process 

of scheduling and adjusting electric generation in response to constantly changing 

demand. Sufficient amounts of wind generation increase the variability and 

uncertainty in demand that power system operators face from day to day or even 

from minute to minute. Quantifying how the amounts of wind generation in 

each of the study scenarios would affect daily operations of the bulk system and 

estimating the costs of those effects were major components of EWITS.

Using detailed chronological production simulations for each scenario, the 

study team assessed impacts on power system operation. The objective of 

these simulations was to mimic how day-to-day operations of the Eastern 

Interconnection would be conducted in 2024 with the prescribed amounts of wind 

generation in each scenario, new conventional generation per the expansion study, 

and the transmission overlays the study team developed. Ways to manage the 

increased variability and uncertainty attributable to wind generation, along with 

the resulting effect on operational costs, were of primary interest. 

EWITS uses a deterministic production-cost model to run hourly power system 

operational simulations using the transmission overlays for each scenario and 

the wind plant outputs and actual load data for 2004, 2005, and 2006. The model 

takes the wind generation at each “injection bus” (i.e., the closest transmission 

connection to the wind plant) and dispatches nonwind generation units 

accordingly for each market region while solving at the model node for the LMP. 

The tool simulates actual power system operations by first solving the unitcommitment problem (i.e., what conventional generators will be dispatched to 

meet load), then using the wind power and load forecasts, and finally dispatching 

the units based on the actual modeled wind and load data. Obtaining realistic 

results is necessary because unit-commitment decisions must actually be made 

well in advance, allowing generators sufficient time to start up and synchronize 

to the grid. A hurdle rate accounts for hourly transactions among eight different 

market regions. The simulation is done over the entire study region and the wind 

plant and load time series data capture geographic diversity. 
27

RESERVE REQUIREMENTS

With large amounts of wind generation, additional operating reserves (see 

sidebar) are needed to support interconnection frequency and maintain balance 

between generation and load. Because the amounts of wind generation in any 

of the operating areas, for any of the scenarios, dramatically exceed the levels 

for which appreciable operating experience exists, the study team conducted 

statistical and mathematical analyses of the wind generation and load profile 

data to estimate the additional 

requirements. These were used 

as inputs to the production-cost 

modeling. The analysis focused on 

the major categories of operating 

reserves, which included needs 

for regulation, load following, and 

contingencies.

In the production simulations 

for each scenario, study analysts 

took into account the additional 

uncertainty and variability resulting 

from wind generation by 

• Incorporating the increased 

operating reserves as constraints 

on the commitment and 

dispatch of generating resources 

in each operating area

• Committing generating units 

for operation based on forecasts 

of load and wind generation, 

then dispatching the available 

units against actual quantities.

The levels of wind generation 

considered in EWITS increase 

the amount of operating reserves 

required to support interconnection 

frequency and balance the system in 

real time. Contingency reserves are 

not directly affected, but the amount 

of spinning reserves assigned to 

regulation duty must increase 

because of the additional variability 

and short-term uncertainty of the 

balancing area demand.

Types of Reserves

In bulk electric system operations, different types of generation 

reserves are maintained to support the delivery of capacity and 

energy from resources to loads in accordance with good utility 

practice. 

Contingency Reserves

Reserves to mitigate a “contingency,” which is defined as the 

unexpected failure or outage of a system component, such as a 

generator, a transmission line, a circuit breaker, a switch, or another 

electrical element. In the formal NERC definition, this term refers to 

the provision of capacity deployed by the balancing authority to 

meet the disturbance control standard (DCS) and other NERC and 

regional reliability organization contingency requirements.

Operating Reserves

That capability above firm system demand required to provide for 

regulation, load forecasting error, forced and scheduled equipment 

outages, and local area protection. This type of reserve consists 

of both generation synchronized to the grid and generation that 

can be synchronized and made capable of serving load within a 

specified period of time. 

Regulating Reserves

An amount of reserve that is responsive to automatic generation 

control (AGC) and is sufficient to provide normal regulating 

margin. Regulating reserves are the primary tool for maintaining 

the frequency of the bulk electric system at 60 Hz. 

Spinning Reserves

The portion of operating reserve consisting of (1) generation 

synchronized to the system and fully available to serve load within 

the disturbance recovery period that follows a contingency event; 

or (2) load fully removable from the system within the disturbance 

recovery period after a contingency event.
28

The assumption of large balancing areas does reduce the requirement, however. 

Under the current operational structure in the Eastern Interconnection, the total 

amount of regulation that would need to be carried would be dramatically higher. 

Using the methodology developed for EWITS, the study team calculated 

regulating reserve requirements for each region and each scenario from hourly 

load data and 10-minute wind production data. The result is an hourly profile 

that varies with both the amount of load and the level of wind generation. The 

calculations account for important characteristics of the wind generation scenario, 

such as the amount of geographic diversity and its influence on the aggregate 

short-term variability. 

Figure 9 summarizes the regulating reserve requirements for each region and each 

scenario. The value indicated by the bar is the average of the annual hourly profile. 

The load-only case is a reference for calculating the incremental requirement 

resulting from wind generation. 

Figure 9. Regulating reserve requirements by region and scenario. The 

incremental amount resulting from wind generation is the difference between the 

scenario number and the load-only value.

Current operating experience offers little guidance on managing the incremental 

variability and uncertainty associated with large amounts of wind generation in 

the operating footprints defined for EWITS. The statistical analysis conducted 

on the time series data from the scenarios, however, forms a highly reasonable 
29

analytical foundation for the assumptions and reserve requirement results that the 

study team carried forward to the production simulations. 

The team’s analysis of reserve requirements with substantial amounts of wind 

generation resulted in the following findings and conclusions:

• The assumptions made about how the Eastern Interconnection will be 

operated in 2024 played an important role in minimizing the additional 

amounts of spinning reserve that would be required to manage the 

variability of large amounts of wind generation.

• The large size of the market areas assumed in the study allows substantial 

benefits of geographic diversity to be realized. 

• The pooling of larger amounts of load and discrete generating resources via 

regional markets also realizes diversity benefits. The per-unit variability of 

load declines as the amount of load increases; larger markets also have more 

discrete generating units of diverse fuel types and capabilities for meeting 

load and managing variability.

• With real-time energy markets, changes in load and wind that can be forecast 

over a short interval—10 minutes in EWITS, 15 to 20 minutes in current 

practice—are compensated for through economic movements of participating 

generating units. Because load changes over 10-minute intervals can be 

accurately forecast, they can be cleared in a subhourly market.

• The fastest changes in balancing area demand—on time scales from a few to 

tens of seconds—are dominated by load, even with very large amounts of 

wind generation.

• Incremental regulating reserve requirements are driven by errors in 

short-term (e.g., 10 to 20 minutes ahead) wind generation forecasts. 

• Data from the Eastern Wind Data Study can be used to characterize both 

variability and uncertainty for a defined scenario. With more wind generated 

over a larger geographic area, percentages of aggregate wind variability 

and uncertainty decrease. These quantitative characterizations are useful for 

estimating incremental reserve requirements.

• Current energy market performance shows that, on average, subhourly 

market prices do not command a premium over prices in the day-ahead 

market. Consequently, the hourly production simulation will capture most 

of the costs associated with units moving in subhourly markets, 

and the spinning reserve requirements for regulation and contingency will 

appropriately constrain the unit commitment and dispatch.

The EWITS analysis addresses these requirements only; as wind displaces 

marginal conventional generation, those nonwind resources deliver less energy 

and thus realize less revenue. With large amounts of wind generation such as those 

considered in EWITS, additional costs could be associated with those displaced 

marginal units that are not captured in the production modeling.
30

PRODUCTION-COST MODELING RESULTS

The project team ran annual production simulations for all three wind and load 

years and all scenarios. The raw results included hourly operations and costs for 

each generator and flows on each transmission element in the model, but because 

of the sheer volume of data generated, the project team had to analyze summary 

information. 

The detailed production modeling of a system of such size and scope reduces the 

number of assumptions and approximations required. Although the large volume of 

results is a disadvantage, the results do contain information from which conclusions 

can be drawn—with relatively high confidence—about wind generation impacts on 

other system resources. Specifically,

• Generation displacement depends on the location and amount of wind 

generation.

• Because of its low dispatch price, wind generation will reduce LMPs. The effect 

in a particular region is greater with local wind resources.

• The addition of overlay transmission works to equalize LMPs across the 

footprint. Because of transfer limits, there are still price differences across the 

footprint, but the magnitude of the difference is reduced with the overlays. 

• Offshore wind has more effect on LMPs in eastern load centers because of its 

proximity to large load centers otherwise served by generation with higher costs.

Figure 10 shows total production costs for each of the high-penetration wind scenarios 

and for the Reference Case. The primary effect of wind generation is to displace 

production from conventional sources; as the amount of wind generation increases, so 

does the magnitude of the displacement. The location of wind generation, however, 

also has an influence. Under the baseline assumptions used for the study, energy 

prices are higher in the East and lower in the western portion of the interconnection. 

Consequently, production costs are reduced more by wind in areas with higher costs; 

the production costs shown in Figure 10 do not account for the capital costs of the 

wind or infrastructure required to deliver wind energy to load.
31

Figure 10. Annual production-cost comparison (US$2009, millions)

WIND INTEGRATION COSTS

Assessing the costs for integrating large amounts of wind generation was another 

key aspect of EWITS. Team members used methods and analytical approaches 

employed in earlier integration studies as their starting point. As interim results 

became available, nuances in and challenges to applying that methodology to a 

large, multiarea production model became apparent. This project significantly 

bolstered the knowledge base and perspective on the components of the total 

cost associated with managing wind energy delivery.

The study team computed the cost of managing the delivery of wind energy (i.e., 

the integration cost) by running a set of comparative production simulations. 

In these cases, analysts assumed that wind energy did not require carrying 

additional regulating reserves for managing variability and short-term 

uncertainty. They also assumed that the hourly wind energy delivery was 

known perfectly in the unit-commitment step of the simulation. The differences 

in production costs among these cases and the corresponding cases where 

wind generation is not ideal can be attributed to the incremental variability and 

uncertainty introduced by the wind resource. 

Figure 11 shows the calculated integration cost for each scenario. Costs vary by 

scenario and by year, but all are less than 10% of the bus-bar cost of the wind 

energy itself.
32

Figure 11. Integration cost by scenario and year (US$2009) 

Salient points from the integration impacts and costs analysis include the following:

• Because the production simulation model contains multiple operating areas, 

and because transactions between and among these areas are determined on 

an economic basis, variability from wind in a given area is carried through 

economic transactions to other areas. In earlier integration studies, wind 

impacts were isolated in the subject area by restricting transactions to 

predefined shapes based on historical contracts.

• Costs for integrating wind across the interconnection vary by scenario. For 

the 20% cases, Scenario 1 shows the highest cost at $5.13/MWh (US$2009) 

of wind energy; Scenario 3 shows the lowest integration cost at $3.10/MWh 

(US$2009).

• Integration costs average $4.54/MWh (US$2009) for the 30% scenario, which 

is roughly a combination of scenarios 1 and 3.

• Results for the 20% scenarios show that spreading the wind more evenly 

over the footprint reduces integration costs. This is particularly noticeable 

in the East, where there is more load and a larger number of resources to 

manage variability.

The project team also analyzed production simulation results to assess curtailment 

of wind generation resulting from transmission congestion or other binding 

constraints. Such constraints include excess electricity supply relative to demand 

and must-run generation (“minimum generation” limits), limitations in ramping 

capability, or availability of adequate operating reserves. 
33

Varying amounts of wind generation curtailment were observed in the 

production simulation results. Findings include the following:

• Wind generation was assigned a very low dispatch price in the 

production simulations, allowing other sources to be redispatched first 

to relieve congestion. Even so, study analysts observed a modest amount 

of curtailment in some operating areas. This is likely the result of local or 

subregional transmission congestion. 

• After conducting a sensitivity analysis consisting of additional production 

simulation runs, the study team determined that transmission congestion 

caused most of the curtailment. In these results, minimum generation 

levels, reserve constraints, and 

ramp limitations accounted for 

less than 1% of the curtailed 

energy.

• In developing the conceptual 

transmission overlays, facilities 

were sized to accommodate a 

large fraction—though not 

100%—of the transaction energy 

from the unconstrained 

production simulation case. 

Consequently, a certain amount 

of wind generation curtailment 

was a likely outcome.

CARBON SENSITIVITY ANALYSIS

The entire analytical methodology, except for the loss of load expectation 

(LOLE) analysis (see the next section for more information on LOLE), 

was run for a scenario that considered a carbon price of $100/metric ton. 

The study team determined that the high price was necessary to bring 

about a significant change in the type of new generation built during the 

expansion modeling process. In addition, because it was a sensitivity 

analysis, choosing a high price helped to illustrate sensitivities. Figure 12 

shows the results of the expansion, and Figure 13 compares the expansion 

for the carbon sensitivity case to the base scenarios and the existing 

Eastern Interconnection queue.

Results from the production simulations show that the impact on carbon 

emissions is substantial. Even though the carbon sensitivity case was 

based on Scenario 2, in which wind generation provides 20% of the 

energy in the Eastern Interconnection, carbon emissions are lower than 

those from Scenario 4, in which wind generation delivers 30% of that 

energy (Figure 14).

Ramp Rates

For a generator, the ramp rate (typically expressed in megawatts 

per minute) is the rate at which a generator changes its output. 

For an interchange, the ramp rate or ramp schedule is the rate, also 

expressed in megawatts per minute, at which the interchange 

schedule is attained during the ramp period.

Because wind is variable and results in ramping, it is important to 

understand these ramp rates and maintain reserves to cover them 

as needed.
34

Little impact was observed on wind generation curtailment or integration 

cost. Relative to the original Scenario 2 (Figure 15), fossil-fuel generation 

is reduced; nuclear generation increases because the nuclear share of the 

new generation expansion is larger. Energy from combined-cycle plants 

also increases because it became the preferred resource for managing 

variability. 

With the high cost of carbon, energy prices increase across the footprint 

(Figure 16). The present value of the accumulated costs more than 

doubles from the base scenarios (Figure 17).

Figure 12. Generation expansion for the Scenario 2 carbon sensitivity case
35

CC = combined cycle; CT = combustion turbine; DR = demand response; IGCC = integrated gas 

combined cycle; IGCC/Seq = integrated gas combined cycle with sequestration; CC/Seq = combined 

cycle with sequestration; RET Coal = coal plant retirements; Replacement CC = replacement 

combined cycle

Figure13. Generation expansion by scenario, including the carbon sensitivity case

Figure 14. Carbon emissions for different scenarios (carbon price applies only to 

carbon scenario)
36

Figure 15. Generation utilization by unit and fuel type for Scenario 2 and 

carbon sensitivity case

Figure 16. Comparison of generation-weighted LMP by region for Scenario 2 

and carbon sensitivity case
37

Figure 17. Present value of accumulated costs for base scenarios and carbon 

sensitivity (US$2009)

CONTRIBUTIONS TO RESOURCE ADEQUACY

Having sufficient generation capacity to meet forecast load is an important aspect 

of bulk power system reliability. 

Although wind generation cannot 

be dispatched to meet peak loads, 

EWITS shows some probability 

that wind generation would be 

available during periods of system 

stress (i.e., it needs additional 

energy to meet demand). Unlike 

conventional generating units, only 

a small fraction of the nameplate 

capacity rating of a wind plant 

can be counted on to be available 

for serving peak loads. With the 

amounts of wind generation 

considered in EWITS, though—more 

than 200,000 MW—understanding 

the small fraction in quantitative 

detail is important because it 

equates to billions of dollars of 

capital investment. 

Reliability of the Grid

EWITS: The EWITS results represent a first detailed look at 

several “snapshots” of the Eastern Interconnection as it could exist 

in 2024 and is therefore not intended to provide a complete 

analysis of the reliability impacts to the present bulk power 

system. EWITS is aimed at characterizing the operational

impacts for future scenarios, primarily through economicsbased transmission expansion planning, resource adequacy

studies, and hourly modeling simulations. Important technical

aspects in the study related to Bulk-Power System reliability

were not studied or were represented approximately or by

means of best engineering judgments. A variety of

comprehensive power system engineering analyses and studies

still need to be conducted (see Summary and Future Work

Section) to determine what additional situations should be

addressed to maintain system reliability from the present to the 

2024 study year when integrating large quantities of renewable 

generation.
38

The fraction of the nameplate rating 

of a wind plant that can be counted 

as dependable or firm capacity, 

expressed as a percentage, is known 

as the capacity value.

To estimate a 2024 capacity value 

for wind, the study analysts used 

the 2004, 2005, and 2006 effective 

load-carrying capability (ELCC) of 

wind at the future penetration level. 

The team analyzed each of the highpenetration wind scenarios that were 

explored in the operational analysis.

The EWITS team examined three 

different levels of transmission 

sensitivities. The level of 

transmission being modeled varied from no ties between areas to the different 

transmission levels of each existing and conceptual overlay scenario. These 

transmission sensitivities were

• Isolated system, stand-alone zone (no zone-to-zone interfaces modeled)

• Existing transmission system (constrained case and interface limits)

• Conceptual transmission overlay (increased zone-to-zone interface limits 

and new ties).

Data from the operational simulations were conditioned into the correct 

format for implementation into the LOLE model. Because that model uses a 

transportation representation for the transmission network, the study team ran 

a large number of additional production simulations to estimate the import 

capacity for each reliability zone. Predefined regional and planning areas 

were used as the modeling zones. Table 5 lists these zones along with the total 

nameplate amount of wind generation for each EWITS scenario.

Reliability of the Grid (continued)

Federal Energy Regulatory Commission (FERC) Study: FERC is

conducting a new study with Lawrence Berkeley National

Laboratory that is intended to validate whether frequency

response is an appropriate metric for gauging the impacts 

on reliability of integrating increasing amounts of variableoutput generation capacity into the three electrical 

interconnections. The study will do this by using today’s 

transmission networks and generating facilities—including 

facilities under construction—as the basis for the models and 

studies in contrast to the alternative scenarios for 2024 used 

in EWITS. The new study is intended to investigate the 

frequency metric as an approach to identifying critical factors 

when integrating large amounts of variable generation into the 

bulk power system.
39

TABLE 5. RELIABILITY ZONES FOR LOLE ANALYSIS WITH INSTALLED WIND 

GENERATION CAPACITY (NAMEPLATE WIND IN MEGAWATTS)

Zone Scenario 1 Scenario 2 Scenario 3 Scenario 4

MISO West 59,260 39,953 23,656 59,260

MISO Central 12,193 11,380 11,380 12,193

MISO East 9.091 6,456 4,284 9,091

MAPP USA 13,809 11,655 6,935 14,047

SPP North 48,243 40,394 24,961 50,326

SPP Central 44,055 46,272 25,997 44,705

PJM 22,669 33,192 78,736 93,736

TVA 1,247 1,247 1,247 1,247

SERC 1,009 5,009 5,009 5,009

NYISO 7,742 16,507 23,167 23,167

ISO-NE 4,291 13,837 24,927 24,927

Entergy 0 0 0 0

IESOa 0 0 0 0

MAPP Canada 0 0 0 0

FULL STUDY SYSTEM 223,609 225,902 230,299 337,708

a Independent Electricity System Operator

Results of the ELCC analysis, shown graphically in Figure 18 for the cases with 

existing and overlay transmission, indicate that the transmission network has 

a significant positive impact on the capacity value of wind generation. For the 

calendar year with the smallest contribution, the aggregate capacity value of wind 

generation by scenario ranges from 53 GW to almost 65 GW. 

Although the influence of transmission on wind generation capacity value 

is intuitive, the magnitude of the contribution is striking. Considering both 

the existing and the overlay transmission concepts developed for EWITS, the 

aggregate wind generation capacity value is increased by more than 20 GW in the 

20% cases, and by nearly 30 GW at 30% wind penetration. 

The capacity value results vary depending on the year, which is consistent 

with observations in previous studies (see Bibliography). The magnitude of the 

interannual variation is actually smaller than that seen in some of the earlier 

results. This could be a consequence of both the scale of the model and the large 

volume of wind generation. 

Assessing the capacity value of wind generation has been a staple of most of the 

integration studies conducted over the past several years. The approach taken in 

the EWITS project likely represents the most thorough and detailed investigation to 

date because of the size and scope of the model, the process by which area transfer 

limits were determined, and the sensitivities evaluated. The wind capacity values 
40

calculated in EWITS are significantly higher than those found in previous 

studies. The study team recognizes that the results represent a macro view, in 

which some important intraregional transmission constraints are not considered. 

Because the project focuses on transmission, though, the results represent a target 

resource adequacy contribution that could be achieved for the wind generation 

scenarios studied.

Figure 18. LOLE/ELCC results for high penetration scenarios, with and without 

transmission overlays

Specific findings and conclusions include the following:

• The LOLE analysis performed for EWITS shows that the existing 

transmission network in the Eastern Interconnection contributes roughly 

50,000 MW of capacity benefits. With the transmission overlays developed for 

the EWITS wind scenarios, the benefit is increased by up to 8,500 MW. 

• The LOLE analysis of the Eastern Interconnection with wind generation and 

the transmission overlays shows that the ELCC of the wind 

generation ranges from 24.1% to 32.8% of the rated installed capacity. 

• The transmission overlays increase the ELCC of wind generation 

anywhere from a few to almost 10 percentage points (e.g., 18% to 28%). 

• The ELCC of wind generation can vary greatly by geographic region depending on which historical load and wind profiles are being studied. Although 

interannual variations were observed, they are much smaller than those seen 

in previous studies (see, for example, EnerNex 

Corporation [2006]).

• Characteristics of the zonal ELCC differences among profiles tended to 

be the same across all four scenarios.
41

SUMMARY AND FUTURE WORK 

The EWITS results represent a first detailed look at a handful of future snapshots 

of the Eastern Interconnection as it could exist in 2024. The analysis was driven 

primarily by economic considerations, with important technical aspects related to 

bulk power system reliability represented approximately or through engineering 

judgments. 

EWITS is an important step in the uncertain world of long-range planning 

because it addresses questions such as feasibility and total ultimate costs, and 

begins to uncover important additional questions that will require answers. 

Although the TRC’s representation from the Eastern Interconnection is extensive, 

the study team also recognizes that additional key stakeholders must be involved 

to further develop an interconnection-wide view of transmission system plans.

A complete evaluation of any of the scenarios would require a significant amount 

of additional technical analysis. The framework established by the scenario 

definitions and transmission overlay concepts, however, forms a foundation 

for conducting conventional power system planning to further evaluate the 

feasibility of these high-penetration scenarios and to improve the cost estimates. 

Production simulation results from EWITS could be used to identify times of 

binding constraints or other periods of interest, such as large changes in wind 

production, minimum load periods, and conditions where loss of significant 

generation would raise questions about the security of the system. The state of 

the system during these periods—loads, committed generation and dispatch 

levels, and wind generation levels, among others—would be transferred to an 

appropriate AC power system model. A variety of power system engineering 

analyses could then be conducted to determine what additional equipment or 

operating limitations would be necessary to maintain system reliability. These 

analyses would include the following.

• An AC analysis that examines in more detail the power transfer 

limitations assumed in the production modeling. For EWITS, the team 

conducted production simulations using a DC power flow that does not 

consider the wide range of issues associated with voltage control and 

reactive power dispatch. An AC analysis would involve power flows that 

look at voltage and reactive compensation issues, dynamic and transient 

stability, and HVDC terminal control. Local and regional transmission 

needs could then be analyzed in much greater detail. 

• Longer term dynamic analysis, where the actions of AGC, load tap 

changing on transformers, and capacitor or reactor switching for 

voltage control can be simulated and analyzed in much greater detail. 

Such dynamic analysis could examine subhourly market operation and 
42

the response of generation to either AGC or market dispatch instructions 

while considering the limitations caused by prime mover or governor 

response, HVDC control actions, or special protective schemes. This 

analysis could be used to zoom in on system operation in real time, 

resulting in a higher confidence estimate of the operating reserve 

requirements and policies needed to maintain performance and reliability.

The analysis suggested for the large footprint considered in EWITS would 

require that many entities across the interconnection participate and collaborate. 

Personnel engaged in running similar studies with a regional focus would need 

to be involved, at a minimum, in a review capacity and for interpreting results. 

National entities such as NERC would also need to be engaged to oversee the 

development of the data sets and models. And because the size and scope of the 

system models might also require computational power beyond what is used 

today in the power industry, these suggested analyses could involve universities 

or national laboratories with appropriate resources.

The top-down views of the interconnection that EWITS yields constitute, in 

essence, the starting point for a substantially significant amount of subsequent 

engineering analysis. The analysis would paint a more accurate picture of the 

total transmission investment necessary, and illuminate measures necessary to 

preserve the security of the bulk power system. As with EWITS, such an effort 

would be beyond the scope of previous attempts, and would require cooperation 

and coordination at many levels to succeed. 

Although EWITS is a technical study that examines future wind scenarios, the 

results pose some interesting policy and technology development questions:

• Could the levels of transmission, including the Reference Case, ever be 

permitted and built, and if so, what is a realistic time frame?

• Could the level of offshore wind energy infrastructure be ramped up fast 

enough to meet the aggressive offshore wind assumption in the EWITS 

scenarios?

• Would a different renewable profile or transmission overlay arise from a 

bottom-up process with more stakeholders involved?

• How can states and the federal government best work together on 

regional transmission expansion and the massive development of onshore 

and offshore wind infrastructure?

• What is the best way for regional entities to collaborate to make sure wind 

is optimally and reliably integrated into the bulk electrical grid? 

• What is the difference between applying a carbon price instead of 

mandating and giving incentives for additional wind?
43

As is expected in a study of this type, especially when a wide variety of 

technical experts and stakeholders are giving ongoing input, a number of 

important variations on the 2024 future scenario can be envisioned. In addition, 

several technical areas in the study present opportunities for further technical 

investigation that could deepen understanding or reveal new insights:

• Further analysis of production-cost simulation results: The output from the 

many annual production simulations performed in EWITS contains detail 

on every generator and monitored transmission interface in the Eastern 

Interconnection. Because of scope and schedule constraints, the EWITS 

analysis was necessarily limited to summary results. Further analysis of 

these output data would likely generate additional valuable insights on 

impacts of wind generation on nonwind generation, and help define more 

detailed analyses that could be conducted in the future.

• Smart grid implications and demand response sensitivities: The Eastern 

Interconnection load considered in EWITS was based on regional projections 

out to the study year (2024). For the most part, load was considered “static.” 

Major industry initiatives are currently exploring means by which at least a 

portion of the load might respond like a supply resource, thereby relaxing 

the constraints on scheduling and dispatch of conventional generating units. 

The implications for wind generation are potentially very significant, which 

is why alternative 2024 scenarios that consider the range of smart grid 

implications for the bulk electric system merit further consideration (scope 

limitations prevented these from inclusion in this phase of EWITS). 

• Nighttime charging of PHEVs: Widespread adoption of electric vehicles has 

the potential to alter the familiar diurnal shape of electric demand. Because 

the wind resource is abundant at night and during the low-load seasons, 

increases in electric demand during these times could ease some of the 

issues associated with integration. 

• Commitment/optimization with high amounts of wind: The approach for 

scheduling and dispatching generating resources used in the production 

simulations is based on current practice. In the future, new operating 

practices and energy market structures might be implemented that take 

advantage of the fact that uncertainty declines as the forecast horizon is 

shortened (for both load and wind generation). Intraday energy markets 

that allow reoptimization of the supply resources more frequently could 

offer some advantage for accommodating large amounts of variable and 

uncertain wind energy. 

• Fuel sensitivity: In this phase of EWITS, the study team considered a single 

future for prices of other fuels used for electric generation. As history attests, 

there is much uncertainty and volatility inherent in some fuel markets, 

especially for natural gas. Alternate scenarios that explore the impacts of 

other fuel price scenarios on integration impacts and overall costs would 

be valuable. 
44

• The role and value of electrical energy storage: With the substantial 

transmission overlays and the assumption of large regional markets, 

the EWITS results show that large amounts of wind generation can be 

accommodated without deploying additional energy storage resources. 

The ability to store large amounts of electrical energy, though, could 

potentially obviate the need for some of the transmission and reduce 

wind integration impacts. Analysis of bulk energy storage scenarios with 

generic storage technologies of varying capabilities would quantify the 

costs and benefits of an alternate means for achieving high penetrations of 

renewable energy. 

• Transmission overlay enhancement: As described earlier, the analytical 

methodology was based on a single pass through what is considered to 

be an iterative process. Further analysis of the existing results could be 

used to refine the transmission overlays, which would then be tested in 

additional production simulations and LOLE analyses, along with AC 

power flow and stability analyses. This could reduce the estimated costs 

of the overlay and bolster the view of the required regional transmission 

expansion that would be needed to deliver the large amounts of wind 

energy to load. 

• Sequencing of overlay development: EWITS focused on a snapshot of a 

2024 scenario using a top-down perspective. The resulting transmission 

overlays and substantial amounts of wind generation would be 

developed over many years. An analysis over time—beginning now 

and extending to 2024—would yield important insights into the overall 

feasibility and costs of an aggressive transmission development future. 

• Wind generation curtailment: Using wind generation curtailment 

selectively and appropriately could have high operational value. 

Although wind plants cannot increase their output at will without first 

spilling wind generation, downward movement is easily accomplished 

with today’s wind generation technology. This could have very high 

economic value under certain circumstances. Wind generation is very 

capable of “regulating down”; for example, in an ancillary services 

market where the regulation service is bifurcated (i.e., regulation up 

and regulation down are separate services). Additional analysis of the 

scenarios studied in EWITS could help quantify what such a service 

would be worth to wind plant operators.

The current installed capacity of wind generation in many areas of the United 

States, coupled with prospective development over the next several years, requires 

that assessments of the bulk electric power system take a much broader view 

than has been typically employed. In addition, the unique characteristics of wind 

generation as an electrical energy supply resource are leading the power industry 

to new approaches for planning and analyzing the bulk electric power system. 
45

Several of these techniques were demonstrated in EWITS, and are also being used 

in other large-scale wind integration analyses. The data sets compiled for the study 

represent the most detailed view to date of high-penetration wind energy futures 

and potential transmission. Given the significant changes coursing through the 

electric power industry, many alternative scenarios for the Eastern Interconnection 

in 2024 can be postulated. In that sense, EWITS is a solid first step in evaluating 

possibilities for the twenty-first century grid in the United States, with many 

more to follow. 
46

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