Renewable Electricity 

Futures Study

Bulk Electric Power Systems: 

Operations and Transmission 

Planning

Volume 4 of 4

Volume 2

PDF

Volume 3

PDF

Volume 1

PDF

Volume 4

PDF

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.
Renewable Electricity Futures Study 

Edited By

Hand, M.M.

National Renewable 

Energy Laboratory

Baldwin, S.

U.S. Department of 

Energy

DeMeo, E.

Renewable Energy 

Consulting Services, Inc.

Reilly, J.M.

Massachusetts Institute of 

Technology

Mai, T.

National Renewable 

Energy Laboratory 

Arent, D.

Joint Institute for Strategic 

Energy Analysis

Porro, G.

National Renewable 

Energy Laboratory

Meshek, M.

National Renewable 

Energy Laboratory

Sandor, D.

National Renewable 

Energy Laboratory

Suggested Citations 

Renewable Electricity Futures Study (Entire Report)

National Renewable Energy Laboratory. (2012). Renewable Electricity Futures Study. Hand, M.M.; 

Baldwin, S.; DeMeo, E.; Reilly, J.M.; Mai, T.; Arent, D.; Porro, G.; Meshek, M.; Sandor, D. eds. 4 vols. 

NREL/TP-6A20-52409. Golden, CO: National Renewable Energy Laboratory. 

http://www.nrel.gov/analysis/re_futures/. 

Volume 4: Bulk Electric Power Systems: Operations and Transmission Planning

Milligan, M.; Ela, E.; Hein, J.; Schneider, T.; Brinkman, G.; Denholm, P. (2012). Exploration of HighPenetration Renewable Electricity Futures. Vol. 4 of Renewable Electricity Futures Study.

NREL/TP-6A20-52409-4. Golden, CO: National Renewable Energy Laboratory.
Renewable Electricity 

Futures Study 

Volume 4: Exploration 

Bulk Electric Power 

Systems: Operations 

and Transmission 

Planning 

Michael Milligan,

1 Erik Ela,1 

Jeff Hein,

2 Thomas Schneider,1 

Gregory Brinkman,

1 Paul Denholm1 

1 National Renewable Energy Laboratory

2 National Renewable Energy Laboratory, 

formerly 
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Renewable Electricity Futures Study 

Volume 4: Bulk Electric Power Systems—Operations and Transmission Planning

iii

Perspective 

The Renewable Electricity Futures Study (RE Futures) provides an analysis of the grid 

integration opportunities, challenges, and implications of high levels of renewable electricity 

generation for the U.S. electric system. The study is not a market or policy assessment. Rather, 

RE Futures examines renewable energy resources and many technical issues related to the 

operability of the U.S. electricity grid, and provides initial answers to important questions about 

the integration of high penetrations of renewable electricity technologies from a national 

perspective. RE Futures results indicate that a future U.S. electricity system that is largely 

powered by renewable sources is possible and that further work is warranted to investigate this 

clean generation pathway. The central conclusion of the analysis is that renewable electricity 

generation from technologies that are commercially available today, in combination with a more

flexible electric system, is more than adequate to supply 80% of total U.S. electricity generation 

in 2050 while meeting electricity demand on an hourly basis in every region of the United States. 

The renewable technologies explored in this study are components of a diverse set of clean 

energy solutions that also includes nuclear, efficient natural gas, clean coal, and energy 

efficiency. Understanding all of these technology pathways and their potential contributions to 

the future U.S. electric power system can inform the development of integrated portfolio 

scenarios. RE Futures focuses on the extent to which U.S. electricity needs can be supplied by 

renewable energy sources, including biomass, geothermal, hydropower, solar, and wind. 

The study explores grid integration issues using models with unprecedented geographic and time 

resolution for the contiguous United States. The analysis (1) assesses a variety of scenarios with 

prescribed levels of renewable electricity generation in 2050, from 30% to 90%, with a focus on 

80% (with nearly 50% from variable wind and solar photovoltaic generation); (2) identifies the 

characteristics of a U.S. electricity system that would be needed to accommodate such levels; 

and (3) describes some of the associated challenges and implications of realizing such a future. 

In addition to the central conclusion noted above, RE Futures finds that increased electric system 

flexibility, needed to enable electricity supply-demand balance with high levels of renewable 

generation, can come from a portfolio of supply- and demand-side options, including flexible 

conventional generation, grid storage, new transmission, more responsive loads, and changes in 

power system operations. The analysis also finds that the abundance and diversity of U.S. 

renewable energy resources can support multiple combinations of renewable technologies that 

result in deep reductions in electric sector greenhouse gas emissions and water use. The study 

finds that the direct incremental cost associated with high renewable generation is comparable to 

published cost estimates of other clean energy scenarios. Of the sensitivities examined, 

improvement in the cost and performance of renewable technologies is the most impactful lever 

for reducing this incremental cost. Assumptions reflecting the extent of this improvement are 

based on incremental or evolutionary improvements to currently commercial technologies and do 

not reflect U.S. Department of Energy activities to further lower renewable technology costs so 

that they achieve parity with conventional technologies. 
Renewable Electricity Futures Study 

Volume 4: Bulk Electric Power Systems—Operations and Transmission Planning

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RE Futures is an initial analysis of scenarios for high levels of renewable electricity in the United 

States; additional research is needed to comprehensively investigate other facets of high 

renewable or other clean energy futures in the U.S. power system. First, this study focuses on 

renewable-specific technology pathways and does not explore the full portfolio of clean 

technologies that could contribute to future electricity supply. Second, the analysis does not 

attempt a full reliability analysis of the power system that includes addressing sub-hourly, 

transient, and distribution system requirements. Third, although RE Futures describes the system 

characteristics needed to accommodate high levels of renewable generation, it does not address 

the institutional, market, and regulatory changes that may be needed to facilitate such a 

transformation. Fourth, a full cost-benefit analysis was not conducted to comprehensively 

evaluate the relative impacts of renewable and non-renewable electricity generation options. 

Lastly, as a long-term analysis, uncertainties associated with assumptions and data, along with 

limitations of the modeling capabilities, contribute to significant uncertainty in the implications 

reported. Most of the scenario assessment was conducted in 2010 with assumptions concerning 

technology cost and performance and fossil energy prices generally based on data available in 

2009 and early 2010. Significant changes in electricity and related markets have already occurred 

since the analysis was conducted, and the implications of these changes may not have been fully 

reflected in the study assumptions and results. For example, both the rapid development of 

domestic unconventional natural gas resources that has contributed to historically low natural gas 

prices, and the significant price declines for some renewable technologies (e.g., photovoltaics) 

since 2010, were not reflected in the study assumptions. 

Nonetheless, as the most comprehensive analysis of U.S. high-penetration renewable electricity 

conducted to date, this study can inform broader discussion of the evolution of the electric 

system and electricity markets toward clean systems. 

The RE Futures team was made up of experts in the fields of renewable technologies, grid 

integration, and end-use demand. The team included leadership from a core team with members 

from the National Renewable Energy Laboratory (NREL) and the Massachusetts Institute of 

Technology (MIT), and subject matter experts from U.S. Department of Energy (DOE) national 

laboratories, including NREL, Idaho National Laboratory (INL), Lawrence Berkeley National 

Laboratory (LBNL), Oak Ridge National Laboratory (ORNL), Pacific Northwest National 

Laboratory (PNNL), and Sandia National Laboratories (SNL), as well as Black & Veatch and 

other utility, industry, university, public sector, and non-profit participants. Over the course of 

the project, an executive steering committee provided input from multiple perspectives to 

support study balance and objectivity. 

RE Futures is documented in four volumes of a single report: Volume 1 describes the analysis 

approach and models, along with the key results and insights; Volume 2 describes the renewable 

generation and storage technologies included in the study; Volume 3 presents end-use demand 

and energy efficiency assumptions; and this volume—Volume 4—discusses operational and 

institutional challenges of integrating high levels of renewable energy into the electric grid. 
Renewable Electricity Futures Study 

Volume 4: Bulk Electric Power Systems—Operations and Transmission Planning

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List of Acronyms

AC alternating current

AGC automatic generation control 

BA balancing area 

Btu British thermal unit

CAISO California ISO

CREZ Competitive Renewable Energy Zones 

CSP concentrating solar thermal power plants

DC direct current

EIA U.S. Energy Information Administration 

ELCC effective load-carrying capability 

EPACT 1992 Energy Policy Act of 1992 

ERCOT Electric Reliability Council of Texas

EWITS Eastern Wind Integration and Transmission Study 

FERC Federal Energy Regulatory Commission 

FOA Funding Opportunity Announcement 

HVDC high-voltage direct current 

Hz Hertz

ISO Independent System Operator 

kW kilowatt 

kWh kilowatt-hour 

LMPs locational marginal prices

LOLE loss-of-load expectation

LOLP loss-of-load probability 

MISO Midwest ISO

MW megawatt

MWh megawatt-hour 

NERC North American Electric Reliability Corporation

NYISO New York ISO 

PJM Pennsylvania, New Jersey, and Maryland RTO

PV photovoltaic 

RE Futures Renewable Electricity Futures Study

ReEDS Regional Energy Deployment Systems 

RSG reserve-sharing group 

RTO Regional Transmission Organization 

WWSIS Western Wind and Solar Integration Study 
Renewable Electricity Futures Study 

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Table of Contents

Perspective .................................................................................................................................................iii

List of Acronyms......................................................................................................................................... v

Introduction ..............................................................................................................................................viii

Chapter 22. The North American Electric Power System: The Grid .................................................22-1

22.1 Balancing Authorities ................................................................................................. 22-2

22.2 Regional Entities ......................................................................................................... 22-2

22.3 Utilities and Power Pools ............................................................................................ 22-4

22.4 ISOs, RTOs, and other Transmission Organizations .................................................. 22-4

Chapter 23. Utility System Planning ....................................................................................................23-1

Chapter 24. Grid Reliability ................................................................................................................... 24-1

24.1 Planning Reserves (Reserve Margin) .......................................................................... 24-3

Chapter 25. Power System Operations................................................................................................25-1

25.1 Security-Constrained Unit Commitment .................................................................... 25-2

25.2 Economic Dispatch and Load Following .................................................................... 25-4

25.3 Frequency Response and Control ............................................................................... 25-4

Chapter 26. Transmission Technology and Institutional Issues.......................................................26-1

26.1 Transmission Technology ........................................................................................... 26-1

26.2 Transmission and Institutional Issues ......................................................................... 26-6

Chapter 27. Power System Considerations for High Levels of Renewable Generation.................27-1

27.1 Technical Challenge of Variable Generation .............................................................. 27-3

27.2 Institutional Challenges of Variable Generation ......................................................... 27-4

27.3 Impact of Variable Generation on Power System Operations .................................... 27-5

27.4 Impact of Variable Generation on Transmission ...................................................... 27-22

Chapter 28. Modeling of System Expansion and Operations for RE Futures Scenarios ...............28-1

28.1 The Regional Energy Deployment Systems Model .................................................... 28-1

28.2 The GridView Model .................................................................................................. 28-4

Summary and Conclusions...................................................................................................................29-1

References.............................................................................................................................. References-1
Renewable Electricity Futures Study 

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List of Figures

Figure 22-1. North American Electric Reliability Corporation synchronous interconnections 

and regional entities ....................................................................................................... 22-3

Figure 22-2. Independent system operators and regional transmission organizations of North 

America .......................................................................................................................... 22-5

Figure 24-1. Examples of reliability curves to illustrate effective load-carrying 

capability ........................................................................................................................ 24-4

Figure 25-1. Timescales for power system operation .......................................................... 25-1

Figure 25-2. Example conventional generator contingency event and response ................. 25-3

Figure 26-1. Comparison of costs to deliver 6,000 MW over various distances and voltages 

at 75% utilization ........................................................................................................... 26-3

Figure 26-2. Comparison of general right-of-way requirements for various transmission

types ............................................................................................................................... 26-4

Figure 27-1. Impact of high level of wind generation ......................................................... 27-6

Figure 27-2. Data from Western Wind and Solar Integration Study: Per-unit variability of 

wind power for four transmission zones ........................................................................ 27-7

Figure 27-3. Data from Eastern Wind Integration and Transmission Study: Normalized 

10-minute variability for five regional groups ............................................................... 27-8

Figure 27-4. Wind ramp event, Electric Reliability Council of Texas, February 26, 

2008.............................................................................................................................. 27-12

Figure 27-5. Simplified example for load alone ................................................................ 27-13

Figure 27-6. Elimination of hourly ramping ...................................................................... 27-18

List of Tables

Table 26-1. Ongoing Ultra-High-Voltage Projects in China, 2009 ....................................... 26-5

List of Text Boxes

Text Box 27-1. Locational Marginal Prices ......................................................................... 27-21
Renewable Electricity Futures Study 

Volume 4: Bulk Electric Power Systems—Operations and Transmission Planning

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Introduction

Today, the U.S. electric grid faces a number of technical and institutional challenges, including 

integrated management of both loads and generation, supporting wholesale electricity markets, 

facilitating customer participation in the marketplace, reducing carbon emissions, and reducing 

dependence on petroleum by electrifying transportation. Technical issues associated with these 

changes challenge legacy grid planning and operational practices, and they will likely require 

substantial, or perhaps even transformational, changes for the U.S. grid to respond effectively. 

The rapid deployment of renewable electricity—particularly the addition of 40,000 MW of wind 

generation—to the U.S. grid over the last 10 years is one driver of change. The Renewable 

Electricity Futures Study (RE Futures) examines the implications and challenges of renewable 

electricity generation levels—from 30% up to 90% of all U.S. electricity generation from

renewable technologies—in 2050. Additional sensitivity cases are focused on an 80%-by-2050 

scenario. At this 80% renewable generation level, variable generation from wind and solar 

resources accounts for almost 50% of the total generation. At such high levels of renewable 

electricity generation, the unique characteristics of some renewable resources, specifically 

resource geographical distribution, and variability and uncertainty in output, pose challenges to 

the operability of the U.S. electric system. 

RE Futures is documented in four volumes. Volume 1 describes the analysis approach and 

models, along with the key results and insights. Volume 2 describes the renewable generation 

and storage technologies included in the study. Volume 3 presents end-use demand and energy 

efficiency assumptions. Volume 4 (this volume) focuses on the role of variable renewable 

generation in creating challenges to the planning and operations of power systems and the 

expansion of transmission to deliver electricity from remote resources to load centers. The 

technical and institutional changes to power systems that respond to these challenges are, in 

many cases, underway, driven by the economic benefits of adopting more modern 

communication, information, and computation technologies that offer significant operational cost 

savings and improved asset utilization. While this volume provides background information and 

numerous references, the reader is referred to the literature for more complete tutorials.

1

This volume also provides an overview of today’s electric power system (the grid), including 

how planning and operations are carried out to ensure reliability. It then explores the challenges 

to the grid posed by high levels of variable renewable generation and some changes that are 

expected to occur in response to these challenges. Finally, this volume concludes with a 

discussion of the capacity expansion and production cost models used in RE Futures and how 

they represent the operational issues discussed earlier. 

 

1 For a full tutorial on the basics of power systems, see Casazza and Delea (2010) and Brown and Sedano (2004). 
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Chapter 22. The North American Electric Power System: The Grid

The electric power system is the infrastructure that converts fuel and energy resources into 

electric power (thus generating electricity) and carries and manages that electric power from 

where it is generated to where it is used.2 It is a system of systems that comprises physical 

networks that include fuel and resources; power plants of many different varieties; electric 

transmission and distribution line networks and measurement; information and control systems; 

and virtual networks of money, business relationships, and regulation. Achieving balance among 

all of these elements is a fundamental challenge for the planning, engineering, and operation of 

the overall system because of the variability and uncertainty of load and unexpected equipment 

failures that affect the generation and delivery of electricity. The system of systems is loosely 

referred to here as “the grid.”

The major physical elements of the grid are generation, transmission, distribution, and load. 

Generation is the collection of power plants electrically connected to the grid and ranging in size 

from very small, distributed units3 to central stations rated at over 1,000 MW (Casazza and 

Delea 2010). Transmission is the collection of networked high-voltage lines (above 100 kV) that 

tie generation to load centers. High-voltage lines also connect utilities to one another, reduce 

costs through sharing of resources, and provide enhanced reliability in case of events such as the 

loss of a large generator. The high-voltage transmission system also enables the wholesale 

marketplace for electricity. In general, the bulk or wholesale system refers to the network of 

interconnected generation and transmission lines, while the distribution system refers to the 

lower-voltage generally radial lines that deliver electricity to the final customer. The load—

created by the electrical equipment on the customer’s side of the meter—is electrically part of 

the overall power system and affects its operation; load completes the system. The largest 

industrial and commercial customers may be served by transmission directly; the rest are served 

by the lower-voltage distribution system. 

When the development of electric power began more than 130 years ago, generating plants were 

isolated and served dedicated customers. Over the next several decades, “utilities” began linking 

multiple generating plants into isolated systems. By the mid-1920s, it was clear that connections 

among utility systems could provide additional reliability and savings with fewer cumulative 

resources. The connection of neighboring utilities provided access to generation reserves in times 

of equipment failure, unexpected demand, or routine maintenance, as well as improved 

economics through reserve sharing and access to diverse and lower-cost energy resources. The 

U.S. grid today is the result of a complex web of legacy designs developed from the early 1920s 

to the present. By the 1980s, the North American electric system had been transformed from 

isolated utilities to an interregional grid spanning the continent. 

The three large areas or “interconnections” that operate as synchronous4

 interconnected systems 

in the contiguous United States, Canada, and a small portion of Mexico are the Western 

 

2 Electric power is in units of watts and electricity is in units of watt-hours; they are often used interchangeably. 3 Many small distributed generators or small power units are installed at hospitals, fire stations, and other critical 

facilities to provide power in case of emergencies or failure of the grid resulting in an interruption of the flow of 

electricity. These standby or emergency backup systems are not normally electrically connected to the grid. With the 

addition of proper control and switching systems, these units could be connected. 4 All of the generators are operating at the same synchronous frequency of 60 Hertz, producing AC electricity.
Renewable Electricity Futures Study 

Volume 4: Bulk Electric Power Systems—Operations and Transmission Planning

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Interconnection, the Eastern Interconnection, and Electric Reliability Council of Texas (ERCOT) 

in Texas (Figure 22-1). The three interconnections are connected by a small number of DC 

connections with very limited transfer capacity.5

 Quebec is also connected to the United States 

and neighboring Canada with HVDC ties. Alaska and Hawaii have their own systems.

Many entities—balancing authorities, regional entities, utilities, power pools, independent 

system operators (ISOs), regional transmission organizations (RTOs), and other transmission 

organizations—are involved in running the grid today. At the federal level, the Federal Energy 

Regulatory Commission (FERC) has regulatory authority over interstate sale of electricity and 

the operation of regional markets. The North American Electric Reliability Corporation (NERC) 

has the responsibility, under FERC authority, for power system reliability, operating, and 

planning standards in the United States, and coordinates with Canada. Every utility in the United 

States and Canada participates in the NERC reliability assessments to ensure that the 

transmission system meets standards and will perform reliably. Most criteria for planning of 

transmission are based on the NERC standards.

22.1 Balancing Authorities

From a system perspective, the balancing authority6 is the critical management element. As 

defined by NERC, the balancing authority (formerly called control area) is the responsible entity

for ensuring the electrical balance between load and generation; the balancing authority 

maintains frequency and ties to neighboring balancing authorities. Within the balancing 

authority’s area, generation schedules are established to meet the changing demand. Deviations 

from this balance result in changes to system frequency and net imports from, or exports to, 

neighboring balancing authorities. Generally, these imports and exports are scheduled in 

advance, but deviations from the schedule are common, with limitations on how often these 

deviations can occur and persist. 

22.2 Regional Entities

Eight regional entities provide a mechanism to address the differences across the regions in 

North America (see Figure 22-1). NERC works with the regional entities to improve the 

reliability of the bulk power system while acknowledging the differences between regions. 

Membership of the regional entities comes from all segments of the electric industry and 

accounts for virtually all the electricity supplied in the United States, Canada, and a portion of 

Baja California Norte, Mexico.

 

5 The reason that back-to-back HVDC ties are used rather than simpler AC connections is a consequence of some 

rather technical aspects of the operation of large AC power systems as well as certain aspects of the history of

development of transmission.

6 According to NERC (n.d.), the balancing authority is, “[o]ne of the regional functions contributing to the reliable 

planning and operation of the bulk power system. The Balancing Authority integrates resource plans ahead of time, 

and maintains in real time the balance of electricity resources and electricity demand.”
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Volume 4: Bulk Electric Power Systems—Operations and Transmission Planning

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Figure 22-1. North American Electric Reliability Corporation synchronous interconnections 

and regional entities

Eastern Interconnection: FRCC = Florida Reliability Coordinating Council

MRO = Midwest Reliability Organization

NPCC = Northeast Power Coordinating Council

RFC = Reliability First Corporation (PJM)

SERC = Southeastern Electric Reliability Council

SPP = Southwest Power Pool

Western Interconnection: WECC = Western Electricity Coordinating Council

Texas Interconnection: TRE = Texas Regional Entity or ERCOT (Electric Reliability Council of 

Texas)

Source: NERC
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22.3 Utilities and Power Pools

From the approval of the Federal Power Act in 1935 to the start of restructuring following 

enactment of the Energy Policy Act of 1992, the grid was designed to provide reliable electric 

power at minimum costs to customers and was regulated to ensure “just and reasonable” rates. 

The dominant business model for U.S. electric power during this period was that of a vertically 

integrated, investor-owned, and state-regulated local utility monopoly.7

 In addition to the 

investor-owned utilities, there were (and still are) federal, state, and municipal utilities, and rural 

cooperatives, totaling more than 3,000 load-serving entities. In a few regions—Pennsylvania, 

New Jersey, and Maryland (PJM); New England; and New York—utilities are organized into 

power pools to share savings through cooperation with neighbors. In general, utilities that 

controlled generation also owned and operated the transmission systems. Local utility companies 

and their customers benefited from the economic exchange of electric energy in power pools 

across regional networks. 

22.4 ISOs, RTOs, and other Transmission Organizations

The Energy Policy Act of 1992 mandated open access to the transmission system. Further access 

to the transmission system resulted from FERC Orders 888/889 with the creation of ISOs and 

subsequently in Order 2000 with the creation of RTOs to satisfy the requirement of providing 

non-discriminatory access to the transmission system. With Order No. 2000, FERC encouraged 

the voluntary formation of RTOs to operate the transmission grid on a regional basis throughout 

the United States. Order No. 2000 delineated 12 characteristics and functions that an entity must 

satisfy to become an RTO (Figure 22-2). In the Eastern Interconnection, the development of 

RTOs and organized wholesale power markets has transferred a large part of the resource 

procurement function from states to FERC jurisdiction. The operation and responsibilities of 

ISOs and RTOs are very similar.

8

 

Regions without ISOs and RTOs (such as the Pacific Northwest and the majority of Southeastern 

states) must conform to FERC’s open access mandate; the power exchange among utilities is 

mostly facilitated through bilateral contracts and power purchase agreements that limit the scope 

of market between buyers and sellers.

 

7 Vertically integrated, investor-owned utilities accounted for nearly 80% of generated electricity as of 2000. 8 According to FERC (n.d.), the designation of “Independent System Operators grew out of Orders Nos. 888/889 

where the Commission suggested the concept of an Independent System Operator as one way for existing tight 

power pools to satisfy the requirement of providing non-discriminatory access to transmission. Subsequently, in 

Order No. 2000, the Commission encouraged the voluntary formation of Regional Transmission Organizations to 

administer the transmission grid on a regional basis throughout North America (including Canada). Order No. 2000 

delineated twelve characteristics and functions that an entity must satisfy in order to become a Regional 

Transmission Organization.”
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Volume 4: Bulk Electric Power Systems—Operations and Transmission Planning

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Figure 22-2. Independent system operators and regional transmission organizations 

of North America

Source: Energy Velocity

In addition to ISOs and RTOs, there are three other types of “transmission organizations” in the 

United States: 

• Traditional utilities that participate in ISOs/RTOs can also consist of utilities from 

one or several states, and can have planning processes and market functions that 

incorporate the RTO footprint 

• Traditional utilities that do not participate in an RTO, and have their own regional 

planning 

• Merchant transmission organizations that plan transmission and seek participants to 

help fund the transmission project. 

The treatment of balancing authorities, regional entities, utilities and power pools, transmission 

organizations, interconnections, and other such aspects of the U.S. grid within RE Futures is 

described in Chapter 28. 
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Volume 4: Bulk Electric Power Systems—Operations and Transmission Planning

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Chapter 23. Utility System Planning

Utility system planning is a complex process that starts with projection or forecasting of demand 

for electricity and develops alternative scenarios for the adequacy of generation resources and 

necessary transmission and distribution system additions. This endeavor is especially complex 

because the lives of the components and subsystems often exceed 40 years. 

The roles and responsibilities for planning the future grid have evolved over the decades, and 

they continue to change. Prior to industry restructuring in the 1990s, planning for future 

infrastructure investments was largely in the hands of the vertically integrated, investor-owned 

utilities that planned both generation and the delivery system with cooperation among neighbors 

through the then-existing power pools or the large federal utility entities in the West and the 

Tennessee Valley Authority in the East (Stoll 1989, Balu et al. 1991).

The Energy Policy Act of 1992 (EPACT 1992) required open access to transmission and created 

a new class of generators called exempt wholesale generators. Behind these changes was the 

intent to open competition in the electricity sector and permit wholesale customers to buy in a 

competitive open market. FERC Orders 888 and 889 issued in 1996 started the regulatory 

implementation of the EPACT 1992, and significant restructuring of the industry resulted. Order 

888 fundamentally changed the dominant business model of the investor-owned utility industry 

by unbundling transmission services from the sale or marketing of electricity. 

With these changes, the integrated utility planning process was fundamentally changed. The 

following decade saw a significant decline in transmission investment Orders 888 and 889 

created challenges to coordination of transmission and generation planning. Coordinated 

planning of transmission expansion and generation was the standard within the vertically 

integrated utility prior to restructuring, and was generally precluded by Order 888 as a 

consequence of the resulting separation of transmission from generation in many regions (Hirst

and Kirby 2001).

The Energy Policy Act of 1992 and the diverse industry response across the various regions 

within the United States increased the diversity and complexity of utility planning. Where 

wholesale markets and independent power producers are significant, the responsibility for 

transmission planning largely rests with the RTO/ISO as does the procurement of generation 

resources. Where vertically integrated utilities continue, the process is still more complicated due 

to the existence of exempt wholesale generators, open transmission access, and the FERC orders.

Using funds from the American Recovery and Reinvestment Act of 2009 (Recovery Act), the 

U.S. Department of Energy has initiated coordinated, interconnection-wide transmission

planning, with broad stakeholder input, and processes to feed these transmission plans back into 

decision-making at all levels (Funding Opportunity Announcement, FOA #68).9 This 

interconnection-wide planning activity is meant to facilitate development of robust transmission 

 

9

 The America Recovery and Reinvestment Act of 2009 directed the U.S. Department of Energy to provide 

assistance for the development of interconnection-wide transmission plans for the Eastern and Western 

Interconnections, and for Texas (ERCOT). 
Renewable Electricity Futures Study 

Volume 4: Bulk Electric Power Systems—Operations and Transmission Planning

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networks that can enable the use of new, clean energy generation and address the weaknesses

that exist in the grid. 

In 2011, FERC issued Order 1000, Transmission Planning and Cost Allocation by Transmission 

Owning and Operating Public Utilities, a continuation of Orders 888 and 890. This new order 

contains guiding language regarding how transmission planning cost allocation should occur.10

This order is expected to result in greater emphasis on coordination of generation and 

transmission planning and more cooperation among neighboring utilities. 

A well-planned regional or interregional transmission system has many economic and reliability 

benefits, which include but are not limited to improving load diversity, providing access to 

lower-cost remote generation, diversifying the resources portfolio (capacity and energy), sharing 

of resources and reserves among neighbors, enabling development of new resources and their 

integration, mitigating market power, and reducing price volatility. Reliability benefits include 

reduction of outages from multiple system contingencies and sharing of reserves, both of which 

also provide economic benefits. Transmission provides these benefits while accounting for less 

than 10% of the final delivered cost of electricity [total electricity retail sales revenue was $372 

billion in 2011 (EIA n.d.)]. In general, three transmission expansion-planning approaches are in 

use:

1. Plan incremental transmission and generation additions to ensure system reliability

2. Plan incremental transmission and generation additions to ensure reliability and relieve 

system congestion or constraints and improve economics 

3. Plan a transmission “overlay” that would realize the broad benefits discussed in addition

to allowing remote resources to reach all energy markets—without adversely affecting 

underlying AC transmission systems through appropriate upgrades. 

The first two approaches generally look out 10 years or fewer. Many transmission organizations 

refer to their 10-year plans as “long-term” and adjust these “long-term” plans with “near- or 

short-term” plans to account for recent system changes. These plans typically study incremental 

transmission additions, new generation, and load growth projections to address reliability and, in 

some cases, how to mitigate transmission system constraints and allow more economic 

operation.11 The adoption of the third approach, which generally looks out 15 years to more than 

20 years, is a recent trend among utilities in transmission planning and signals a return to the 

longer-term planning that was common before restructuring. The benefit of this approach is that 

long-term needs of the transmission system, in terms of capacity and corridor requirements, can 

be identified by analyzing various scenarios and identifying common transmission needs in a 

proactive approach. This information can then be used in subsequent feasibility and detailed 

system studies that address reliability concerns, transmission system constraints, access to 

lowest-cost generation resources, and impacts to underlying systems. A combination of these 

three approaches is best employed to address the particular needs of the system being studied. A 

bottoms-up approach can address short-term reliability and constraint mitigation needs, and a 

 

10 For the complete Order 1000 text, see http://www.ferc.gov/whats-new/comm-meet/2011/072111/E-6.pdf. 11 Constraints (also referred to as congestion) are a condition of the transmission system in which the transmission 

line loading has met the operating limit criteria for which it was designed. It is a problem to the extent that lowercost resources are prevented from reaching higher-priced markets. 
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top-down, “value-based”12approach might best address the system’s long-term reliability and 

economic needs.

Short-term studies may work well in some applications, but they may not adequately identify the 

longer-term (20-year and beyond) needs of the transmission system. Reliance on the short-term 

approach may lead to sub-optimization of the bulk electric system over time (e.g., inadequate 

transmission capacity and voltage selected). For example, in the short term, a lower-voltage and 

less expensive line addition may be adequate but may require an expensive upgrade within a 

decade; in contrast, an initially more expensive and higher-capacity line might be less expensive 

in the long term. Short study periods and their potential sub-optimization—given the 40–60-year 

(or more, in many cases) in-service life of transmission lines—may limit the possibility of 

constructing higher-efficiency multiple-line systems and identifying underlying system upgrades 

to fully realize the reliability and economic benefits a robust transmission system provides.

As states and federal agencies work to implement new energy policies, the process of utility 

planning will continue to change and evolve. New and emerging technologies discussed in 

Section 26.1 offer new technical solutions, and new institutional arrangements may facilitate 

their adoption. Barriers to institutional innovation may also bar adoption of new technological 

solutions. The cooperation being promoted by the interconnection-wide planning activities of the 

Recovery Act as well as the new FERC Order 1000 may be critical elements to utility planning. 

 

12 A value-based approach seeks to quantify the cost of outages and balance it with the cost of infrastructure to avoid 

or minimize the costs of outages to customers. 13 All planning must meet NERC standards as shown on its website at 

http://www.nerc.com/page.php?cid=2|20. 
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Chapter 24. Grid Reliability

As discussed in Chapter 22, electricity production and demand must be dynamically balanced at 

all times. Achieving this balance is a challenge for the planning,13 engineering, and operation of 

the power systems because of variability and uncertainty of load and unexpected equipment 

failures that affect the generation and delivery of electricity. Maintaining this dynamic balance 

and the significant consequences of failure to do so is a fundamental challenge. Many elements 

contribute to the operability of an electric power system at many scales, from purely local to 

regional. Local reliability issues can range from a small electrical disturbance that lasts from a 

fraction of a second to a few minutes, or a more extended interruption of electric supply as a 

consequence of a local event such as a tree falling across a power line a few blocks away due to 

severe weather. The consequences can range from a loss of power quality to an outage that can 

last from hours to days. 

NERC defines electric system reliability as “the ability to meet the electricity needs of end-use 

customers, even when unexpected equipment failures or other factors reduce the amount of 

available electricity (NERC n.d.).” Maintaining reliability involves ensuring that adequate 

resources are available to provide customers with a continuous supply of electricity as well as 

having the ability to withstand sudden, unexpected disturbances to the electric system (NERC 

n.d.). NERC describes power system reliability more completely in terms of electric system 

adequacy and security.

• Adequacy is “the ability of an electric system to supply the aggregate electrical 

demand and energy requirements of the end-use customers at all times, taking into 

account scheduled and reasonably14 expected unscheduled outages of system 

elements” (NERC n.d.). 

• System security or operating reliability is “the ability of an electric system to 

withstand sudden disturbances such as electric short circuits or unanticipated loss of 

power system element(s)” such as a power plant or a transmission line (NERC n.d.). 

The stability of the grid is the ability of an electric power system to maintain a state of 

equilibrium between generation and demand during normal and abnormal conditions or 

disturbances. If the system becomes “unstable,” it may experience a “collapse” of system voltage 

and, as a consequence, protective equipment may open circuit breakers and disconnect areas 

from the interconnection, in hopes of keeping smaller areas within operational limits and 

subsequently causing the interconnection to break into pieces as it did in the August 2003 

blackout. 

Power systems are planned and operated so that a credible disturbance, event, equipment failure, 

or other contingency will not cause any area of an interconnection to be operated outside of 

specified voltage and frequency and not cause generation or transmission equipment to operate 

 

13 All planning must meet NERC standards as shown on its website at http://www.nerc.com/page.php?cid=2|20. 14 The question of what are reasonable contingencies to examine is a very complex one. The complexity increases 

greatly as the number of simultaneous contingencies increases. If there are N elements in the system, contingencies 

are referred to as N-1 (Class B), N-2 (Class C and D), etc. Very-large-scale blackouts are often preceded by an N-3 

contingency.
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outside normal limits. The participants in the grid follow rules and principles to ensure reliability 

for planning and operating the interconnections; these criteria form the basis for reliability 

standards (NERC 2012). 

A complete analysis of power system reliability comprises the following: 

• System adequacy: To fully understand overall system adequacy, Monte Carlo 

simulations are generally required to measure LOLP with the appropriate probability 

density functions of various power system variables. Many scenarios would need to 

be analyzed to understand whether the overall electric system has adequate system 

capacity to meet load under a variety of operating conditions. With conventional 

generation units, this type of study typically involves running reliability models using 

the forced outage rate and mean time to repair for the full suite of units, while also 

considering possible changes in electricity demand, to estimate the LOLP. With high 

amounts of variable generation, analyses of this type become somewhat more difficult 

due to the unique behavior of variable generation. 

• High-resolution production modeling: In most electricity systems today, load 

changes in somewhat regular patterns from one hour to the next, and within each 

hour. Load typically increases during the morning period and falls off in the evening. 

With high levels of variable renewable generation, however, net load15 may vary 

more irregularly and on shorter time frames. Running simulations at sub-hourly levels 

or even at sub-minute levels may be needed to fully understand the impacts of these 

changes in net load and to assess the quantity of reserves needed to manage 

variability and forecast errors that occur within the hour. 

• AC analysis: Many power system models use what is called a direct current (DC) 

power flow assumption, which approximates how power flows on the system in order 

to readily solve optimization problems. In practice, this means that the voltage of the 

system is ignored, reactive power flows on the system are ignored, and line losses are 

approximated. A full AC analysis can more accurately estimate power flows on the 

system and address these concerns. In RE Futures, while GridView provided DC 

power flow analysis, a full AC analysis was not done.

• Power system stability studies: Stability is a condition of equilibrium between 

opposing forces, and maintaining power system stability is essential to ensuring a 

reliable electricity system. Rotor angle stability refers to maintaining synchronism 

between synchronous machines—these are primarily the large-scale power generation 

units in central station power plants. Small signal stability refers to maintaining 

synchronism following small disturbances, and transient stability refers to 

maintaining synchronism following severe disturbances. A variety of studies are 

necessary to address these aspects of power system stability, including analyses of 

synchronism during transmission system faults as well as other studies that evaluate 

frequency response during loss-of-supply events. As one example of the issues in 

question, many variable renewable generators cannot currently respond to system-

 

15 Net load is calculated by subtracting all forms of variable generation from the native load. The net load is what 

must be managed by the remainder of the power system, assuming all variable generation can be used when 

available.
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wide frequency deviations with off-the-shelf technology, and analyses are therefore 

needed to assess (1) future electricity systems where substantial amounts of 

generation do not have frequency response capabilities as well as (2) new 

technologies that might be used to manage those possible deficiencies. Voltage 

stability, meanwhile, refers to maintaining steady and acceptable voltages at all buses

(major points of connection) in the system under both normal conditions and 

following disturbances. Regardless of the specific aspect of system stability under 

consideration, stability studies require very high time-resolution analysis, usually at 

the hundredths-of-a-second timescale but for only the first few seconds following 

disturbances. 

• Contingency analysis: Power systems are typically designed for high reliability and 

therefore need to be secure following severe but credible contingency events. Real 

power systems are operated with various contingencies in mind, and careful 

consideration is required to determine which contingencies should be monitored and 

how the system should operate to maintain a stable system following contingency 

events. Analysis of such issues usually includes determining those contingencies that 

are most likely based on historical evidence as well as those that are most severe, 

based on contingency screening. The complexity of contingency analysis generally 

increases with the dimension (i.e., number of nodes and connecting lines) of the 

system or region being considered and the number of simultaneous events involved. 

In RE Futures, the grid reliability analyses described above have not been done. However, the 

modeling tools employed in the study required adequate reserves to be available, in some cases 

based on statistical proxies (see Chapter 28 for more information). 

24.1 Planning Reserves (Reserve Margin)

A key step in addressing operating reliability and ensuring system adequacy is determining the 

needed generation capacity that must be installed to meet future demand. Additional capacity 

above and beyond the expected peak load is needed so that sufficient resources are available at 

all times to meet load. This additional margin is called planning reserves. Historically, planning 

reserves have been defined and calculated as a percentage of peak demand (load) and can vary 

by utility and/or region. Typical traditional values for planning reserve margin range from 12%–

15% of annual peak load. Dispatchable generators contribute name-plate capacity toward 

planning reserves. 

After the demand has been forecasted for a given time horizon, generation expansion or related 

models are used to assess system adequacy (i.e., to determine whether there is sufficient 

generation to meet the future load). Additional capacity is needed to cover possible generation 

outages or peak load forecasting error. Because of the stochastic nature of generator outages, 

robust probabilistic methods are used to assess generation adequacy. Models that calculate lossof-load probability (LOLP) or related metrics such as loss-of-load expectation (LOLE) can be 

used to assess the probability that there is insufficient generation to cover loads. A typical LOLE 

target is that there would only be a shortage for 1 day in 10 years (see Figure 24-1). 

The effective load-carrying capability (ELCC) is a measure of the additional load that can be 

supplied after adding new generation, holding the LOLE constant. The ELCC approach 

calculates LOLP over all hours of the year (multiple years are recommended). Times of high 
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LOLP are relatively few and typically occur during peak or near-peak periods. This approach 

explicitly quantifies and holds constant the risk of having insufficient native generation to cover 

load. The ELCC approach is robust across all technologies; in particular, it can be applied to both 

conventional and variable generation technologies.16 In modern interconnected systems, LOLP 

and LOLE measure the likelihood that imports will be necessary to meet load during high-risk 

periods. 

Figure 24-1 shows the relationship between LOLE and load. At the presumed target adequacy 

level of 1 day in 10 years, if new generation is added, the curve shifts to the right. Holding the 

reliability target constant, the horizontal difference between the curves is the ELCC of the new 

generator. 

Figure 24-1. Examples of reliability curves to illustrate effective load-carrying capability

Source: Milligan and Porter 2008

 

16The ELCC method is recommended by the IEEE Task Force on Wind Capacity Value (Keane et al. 2011).
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Chapter 25. Power System Operations

Power systems operational procedures can generally be divided by timeframe, as depicted in 

Figure 25-1. A balance between total customer demand and total system generation needs to be 

maintained essentially instantaneously at all times. The balancing process is carried out in 

several different time frames. Generating units are typically committed to operation a day in 

advance to cover the forecasted load profile for that day plus a reserve margin. Scheduling (or 

economic dispatch) of plant output levels is then carried out generally on an hour-by-hour basis. 

Some plants are designated to follow load variations within the hour, and other plants provide 

regulation service to balance instantaneous load variations in the seconds-to-minutes timeframe. 

Figure 25-1. Timescales for power system operation

The figure is illustrative and not to scale. The notch at 18–19 hours represents a 

secondary peak that occurs in some regions in early weekday evenings as commercial 

load drops off and residential loads ramp up.

This section discusses several elements of power system operations, including forecasting and 

the day-ahead schedule or unit commitment, within-a-day economic dispatch, frequency 

response and control, and operating reserves. These functions are initially described in the 

absence of variable generation. Later sections discuss the impact of large-scale variable 

generation on each of these operational timeframes.
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25.1 Security-Constrained Unit Commitment

Unit commitment is a process of determining which generating units will be needed for the 

following day, and ensuring that any needed large thermal units are started and synchronized to 

the grid. This process is based on day-ahead load forecasts, and is necessary because many large 

thermal units take many hours to reach operating temperature before generating energy. Typical 

load forecast accuracy depends on many factors, including the size and characteristics of the 

system itself. Generally, however, a typical error of a day-ahead load forecast is about 2%–3% of 

the peak load. A typical schedule is planned hourly for the next 24–48 hours, depending on 

operating practice at the balancing authority. The unit commitment process aims for an 

economically efficient solution, given the various physical and institutional constraints involved. 

Because the future is uncertain, there is some risk that either too much or too little capacity is 

committed, resulting in challenges during the operating day. To help mitigate this risk, the power 

system operator will commit an additional level of capacity, operating reserves, which can be 

called upon if load forecasts are in error or if there is an equipment failure. The cost of overcommitment can be significant because some generation may be forced to run at inefficient 

output levels, or even curtailed. Similarly, the cost of under-commitment can be significant if 

expensive peaking units must be started to meet load that could have been met by less expensive 

thermal units. However, the consequences of unit commitment errors vary widely based on 

system characteristics. 

In most electricity markets and utility operator balancing authorities in the United States, the unit 

commitment process and schedule are generally established once a day, with schedules due midday on the day prior to the operating day. 

25.1.1 Operating Reserves

Power system operators ensure that there is available generation capability above that which is 

scheduled for energy, or operating reserves that can respond to the inherent variability in load 

and unforeseen events such as the sudden failure of a key transmission line or generator. These 

reserves can be broadly defined as event-based reserves or non-event-based reserves. A 

complete discussion is beyond the scope of this report, but details can be found in Ela et al.

(2010).17 When units are committed for day-ahead, sufficient operating reserves must be a part 

of the determination of the unit commitment stack. 

Contingency reserves18 are used in the event of sudden generator or transmission failure. The 

balancing authority carries sufficient reserves to cover the loss of the largest contingency, 

although variations on this are possible. In addition, the proliferation of reserve-sharing groups 

has allowed sharing of the contingency reserve burden across multiple balancing authorities

within the same interconnection, and subject to transmission constraints. 

A contingency event occurs very suddenly—within a cycle—when a unit trips or a line opens. 

Several types of reserve come in to play after the contingency occurs so that the activated 

reserves can be replaced in case another contingency event occurs. 

 

17 Milligan et al. 2010 provides an international context for operating reserves. 18 Contingency reserves are used to balance resources and load and return interconnection frequency to within 

defined limits following a “reportable disturbance” (a loss of power system element). Contingency reserves can be a 

mix of spinning, non-spinning, and interruptible load according to requirements established by the balancing 

authority and reserve-sharing group. 
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Non-events include the normal operation of the power system. Reserves in this category include 

regulating reserve, a capacity-only service,

19 which is used to manage short-term fluctuations in 

demand that occur continuously, and load-following reserve (Ela et al. 2011), which at present is 

not a well-defined product but includes an energy component and occurs over time periods from 

several minutes to a few hours. Reserves can be separated into categories based on required 

response time. Fast reserves generally must be available within 10 minutes, whereas a slower 

response may be required for load-following or replacement reserves. 

The only specific reserve that is required by NERC is contingency reserve; however, the 

balancing authority’s ability to meet its required balancing standards (control-performance 

standards) results from holding regulating reserves and other balancing reserves. Because these 

reserves are required in the operating timeframe, they are often referred to as operating reserves, 

which distinguishes them from planning reserves. There are many variations in terminology 

regionally and internationally. Some reserve types can be split between spinning (i.e., committed 

and synchronized) and non-spinning (i.e., capable of connecting and synchronizing within a 

prescribed time period, typically 10 minutes). Regulating and frequency-control reserves, by 

their nature, must be entirely spinning, whereas other reserves can consist of a combination of 

spinning and non-spinning reserve. 

If a large thermal generator is suddenly lost, the instantaneous impact of such a loss to the 

surrounding power system and system operating reserves requirements is depicted in Figure 

25-2. Turbine speed governors and the system’s automatic generation control (AGC) sense a 

drop in system frequency and initiate corrective action to increase power from generators that are 

still operating.

Figure 25-2. Example conventional generator contingency event and response

Source: Ela et al. 2011

 

19 A regulating unit sometimes provides energy and sometimes absorbs energy on a second-to-second basis to 

maintain instantaneous system balance. On average, essentially no energy is provided to the power system by 

regulating units
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25.2 Economic Dispatch and Load Following

During the operating day, in addition to the generation already committed to serving load, the 

system operator has quick-start generation on reserve to help cover unexpected changes in 

demand or contingencies and may have access to electricity markets that can provide additional 

generation. These sources of energy may be used to meet both the anticipated changes in energy 

demand throughout the day, and any unanticipated changes in demand. 

The load-following timeframe generally refers to time steps from tens of minutes to a few hours. 

Load swings are matched by changing generation schedules. These changes are accomplished by 

adjusting, or dispatching, generating units to minimize the economic cost of meeting demand, 

subject to their physical characteristics. This process is called economic dispatch. 

Regions of the United States that participate in large wholesale energy markets, such as Midwest 

ISO (MISO) and PJM, typically perform the economic dispatch sub-hourly—in increments of 5 

minutes. This means that any generator that is capable of responding—both in its physical and 

economic capabilities—is available to help manage the variability inherent in the power system. 

In most regions of the Western Interconnection, the economic dispatch function is performed 

once an hour. This practice places an artificial restriction on generation that is technically 

capable of responding to variability; there is no institutional mechanism that allows such units to 

respond, even if economic. 

25.3 Frequency Response and Control

Frequency control (60 Hz) is the basis for several reliability metrics. The deviation of line 

frequency from its nominal value of 60 Hz is the first indicator of a problem in the power 

system, and, in general, the larger the deviation, the bigger the problem. The problem typically 

begins with the sudden failure of a large conventional generating plant or the loss of transmission 

capacity, resulting in too little power generated and transmitted to fully meet the load. This 

generally causes the frequency to drop from its 60-Hz value (see Figure 25-2) as large 

electromechanical generators, motors, and other equipment slow. In correcting this, many factors 

influence the frequency response and control of the power system. Balancing and frequency 

control occur over a continuum of time using different resources. Frequency response begins to 

stabilize the system frequency within the first few seconds following a disturbance. Abnormal 

frequencies can damage power system equipment, especially large steam turbines. Frequency 

response from generators actually helps protect the turbines from exposure to abnormal 

frequencies by limiting the magnitude of the frequency change during events. As more 

generators participate in frequency response, overall frequency response will increase within the 

interconnection and the abnormal frequency deviation will be reduced.
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Chapter 26. Transmission Technology and Institutional Issues

The design and engineering of the transmission system is affected by both technical and 

institutional issues—business, regulatory, and political. This chapter provides a brief overview of 

transmission technology and then an introduction to the basic institutional issues. 

Casazza (1993) documents the drivers and benefits of the expansion of transmission systems 

over the decades and the development of today’s interregional grid that spans North America. 

The value of transmission comes from many sources of savings, such as:

• Delivering electricity from lower-cost remote resources

• Sharing large low-cost generation among systems 

• Reducing the need for both planning and operating reserves 

• Allowing production of electricity from the lowest-cost supplies at all times

• Taking advantage of seasonal, weekly, and hourly load diversity among systems 

• Making remote hydropower and “mine-mouth”20 coal plants available to more users

• Permitting “surplus” hydropower generation in one system to be used in another. 

Today, this list can be expanded to include more economic operation of large regional wholesale 

markets, access to higher quality, lower-cost remote renewable generation, and reducing 

variability and uncertainty of variable renewable generation over a large geographical region. 

As identified in the National Interest Electric Transmission Corridors and Congestion Study 

(DOE 2009), there would be general economic benefit from strengthening the transmission 

system; however, the relationship between this general economic benefit and the private return to 

companies paying for new transmission is often insufficient or too uncertain to spur investment. 

New transmission could address the general increase seen in grid congestion and support the 

creation of broader markets for electricity, as well as support the future integration of renewable 

resources.

26.1 Transmission Technology

The highest operating voltage transmission lines in the United States, which operate at a nominal 

765 kV, came into service in the 1970s. Worldwide, the transmission technologies in use and 

functioning today, either broadly or in initial installations, for transmitting bulk electrical power 

are high, extra-high, and ultra-high-voltage AC transmission systems up to 1,000 kV (Global 

Transmission 2009); high and ultra-high-voltage DC transmission systems; and underground 

cables (e.g., solid dielectric and gas-insulated). All of these technologies have unique application 

characteristics, as discussed in the following sections. 

This brief overview of basic transmission technology provides a backdrop for understanding the 

right-of-way requirements for the siting and permitting of transmission lines. The transfer of 

large amounts of electricity within and among regions can provide economic benefits as 

 

20 “Mine-mouth” refers to a generating station located at a coal mine in order to be close to the fuel source instead of 

transporting the coal to the generating facility.
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discussed previously, but those benefits can be limited by institutional barriers to expansion of 

the transmission system. The current motivation for pursuing new higher capacity transmission 

technology is the growth of large regional markets and the opportunity for greater economic 

exchange. The future value for this technology may include enabling the transfer of renewable 

energy from more remote locations, where the higher-quality and lower-cost resources are 

available to serve load centers, and continuing to support the trend of wider area operational 

coordination, which can reduce the variability and uncertainty of variable renewable generation. 

26.1.1 Alternating Current Transmission Systems 

The majority of transmission systems in the United States and worldwide are conventional AC 

lines. In the United States, these are often referred to as high-voltage (up to 345 kV) and extrahigh-voltage (above 345 kV to 765kV). Over the decades since AC technology was first 

developed, transmission voltages steadily increased as the technology of the grid improved. 

Higher voltages result in lower losses and higher capacity for a given right-of-way. Higher 

voltages require greater distances between the wires or conductors as well as better and longer 

insulators and higher towers, but the net effect is still a significant increase in the power transfer 

capability for a given width of right-of-way, and higher voltages are preferred for longer 

distances and larger transfer capacity. Figure 26-2 provides an artist representation of the space 

requirements for different levels of voltage. Although the highest voltage transmission lines in 

use in North America are 765-kV AC, transmission voltages continue to increase worldwide. 

26.1.2 High-Voltage Direct Current Transmission Systems

High-voltage direct current (HVDC) is occasionally used for very long distance or very high 

capacity lines. HVDC lines cost less than overhead high-voltage AC lines of the same voltage 

and have lower operating losses. However, HVDC convertor stations, located at each terminal of 

the line, cost significantly more than AC substations. Figure 26-1 shows the relative cost of 

extra-high-voltage AC versus 800-kV DC for constructing a transmission line to transmit 6,000 

MW over various distances at 75% utilization.21 In general, the 765-kV AC, 500-kV HVDC, and 

800-kV HVDC systems appear to be the best options. These general performance indicators are 

subject to project-specific requirements. When performing transmission system expansion 

planning studies, these project-specific requirements—specifically distance and loading—would 

be analyzed to determine the optimal transmission technology to meet the project need. 

 

21 Transmission line and substation costs are based on Frontier Line Transmission Subcommittee, Northwest 

Transmission Assessment Committee (NTAC), and ERCOT Competitive Renewable Energy Zones (CREZ) unit 

cost data.
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Figure 26-1. Comparison of costs to deliver 6,000 MW over various distances and voltages at 

75% utilization 

Source: Bahrman 2009 

“Series Comp” refers to series compensated AC lines where capacitance is added to 

balance the inductance of the overhead transmission line as transmission distance 

increases. 

An economic analysis that takes into account capital costs—including converter stations, line 

lengths, voltage levels, and power transfer capability—would be considered to determine the 

most economical transmission solution. In general, the break-even point for deciding to use a DC 

system instead of an AC system for a transmission project (not considering such factors as 

multiple converter stations and changes in operating voltages over time) is in the vicinity of 300 

to 600 miles for overhead lines. 

DC transmission systems have significant benefits when transmitting large amounts of power 

long distances and can do so between two asynchronous AC systems. Additional benefits 

include, but are not limited to, power flow control and enhanced system stability. For example, 

the high-capacity contingency rating of an HVDC overlay could accommodate the loss of a large 

conventional generator and be stable. Regarding land use, DC transmission systems require less 

right-of-way for similar amounts of transfer capability (see Figure 26-2). 
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Figure 26-2. Comparison of general right-of-way requirements for various transmission types 

Right-of-way is a term that can have different meanings. As used in this volume, it means 

the path taken by a transmission line and the property impacted by that transmission line. 

It can also imply an easement or right to reasonable use of the property over which the 

transmission line runs. The owner of the transmission line may own the property or have 

an easement or “rights” for its use. 
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26.1.3 Higher Voltages

Although the highest voltage transmission lines in use in North America are 765-kV AC, 

transmission voltages continue to increase worldwide.22 As shown in Table 26-1, both 1,000-kV 

AC and DC lines are being constructed in China. 

Table 26-1. Ongoing Ultra-High-Voltage Projects in China, 2009

Location Technology Capacity Distance

Jindongnan-Nanyang-Jingmen Ultra-High-Voltage AC, 1,000KV 6,000 MW 654 km

Yunnan-Guangdong Ultra-High-Voltage DC, ±800KV

12 pulses, bipole

5,000 MW 1,438 km

Xianjiaba-Shanghai Ultra-High-Voltage DC, ±800KV

12 pulses, bipole

6,400 MW 1,907 km

Source: Li 2009

The advantage of using higher voltages is the decline in per unit costs; the disadvantage is the 

risk of losing a larger portion of transmission capacity in a single contingency failure. More 

detailed studies will be needed to conceptualize, design, and evaluate the merits for a highvoltage “overlay.” 

26.1.4 Superconducting Cables

When long-distance overhead transmission lines approach major population and load centers, the 

availability of right-of-way for overhead lines can become limited. Similarly, overhead lines may 

be undesirable in environmentally sensitive areas. Political and institutional issues can 

completely block construction of an overhead line. New high-temperature, superconductor-based 

transmission cable technology may offer an alternative in the longer term, not just for short 

distances in urban areas but also for long-distance transmission (EPRI 2009) where pipeenclosed DC superconducting transmission cables can either be buried underground or placed in 

tunnels. These cables use high-temperature superconductor materials instead of copper or 

aluminum and have substantially higher power handling capabilities at lower voltages than 

conventional cables. This additional power-carrying capacity allows this technology to address 

reliability concerns associated with long-term load growth in densely populated urban areas. 

When operating in DC systems, these cables exhibit zero resistance, hence zero electrical losses; 

however, there are parasitic refrigeration losses. The commercial competitiveness remains to be 

fully demonstrated in the market. As this technology is not commercial, it was not included in 

RE Futures transmission modeling. 

Regarding right-of-way, the superconductor electricity pipeline (EPRI 2009) requires little land 

and it can be buried, which offers potential benefits to siting and security (Reddy 2010).

 

22 ABB (n.d.a); ABB (n.d.b); ABB (n.d.c) 
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26.2 Transmission and Institutional Issues

Institutional issues related to transmission include jurisdictional complexity, permitting, siting 

and right-of-way acquisition, and cost allocation and cost recovery, among others.23 

26.2.1 State and Federal Jurisdictions 

Although the Federal Power Act puts interstate transmission rates under the jurisdiction of 

FERC, the regulatory and economic drivers affecting transmission planning are split among the 

federal government and the states. Retail electricity rates are set locally by state public utility 

commissions, cities (in the case of municipally owned utilities), or customer-elected boards (in 

the case of rural electric cooperatives). The cost of new generation (such as that from a new 

thermal plant, new wind power, or power purchased from merchant generators) is recovered 

through retail rates. 

26.2.2 Siting, Permitting, and Right-of-Way Acquisition 

Currently, the siting and permitting of transmission lines is the responsibility of individual states. 

A line serving utilities in more than one state or one connecting across several states would best 

be planned, sited, and permitted in a process coordinated across all involved jurisdictions. 

However, multi-state regulatory coordination is rare and, where federal legislation has not 

clarified the situation, can be problematic. Authority for regulation of interstate commerce rests 

with Congress. Currently, federal regulatory authority over interstate transmission lines is limited 

to those situations where the U.S. Department of Energy has declared a possible corridor as one 

of national interest, and there is not yet experience with these recent provisions of law, which 

makes the development of an interstate transmission line higher risk than the development of a 

line situated completely within one state. State policy may also create a preference for in-state 

resources, which would require shorter lines from local resources, but may not permit capturing 

the benefits of integrating generation across a larger geographic area encompassing several 

states.24

A transmission plan may seem to be technically feasible after power flow and production cost 

modeling, but can be legally or economically infeasible when attempting to select a specific 

route for a line. Siting issues that commonly delay transmission permitting include opposition by 

individual landowners or community groups to the location of the facilities; opposition to the 

exercise of eminent domain for easements across property; concerns over property values; and 

environmental concerns regarding endangered species and habitat and aesthetics. 

 

23 A white paper summarizing issues affecting siting transmission corridors is available from The National Electrical 

Manufacturers Association at http://www.nema.org/gov/upload/tC_gameboard_verticle.pdf. 24 “Section 216(a) of the Federal Power Act (created by section 1221(a) of the Energy Policy Act of

2005) directs DOE to identify transmission congestion and constraint problems. In addition, section 216(a) 

authorizes the Secretary, in his discretion, to designate geographic areas where transmission congestion or 

constraints adversely affect consumers as National Interest Electric Transmission Corridors (National Corridors). 

A National Corridor designation itself does not preempt State authority or any State actions. The designation does 

not constitute a determination that transmission must, or even should, be built; it is not a proposal to build a 

transmission facility and it does not direct anyone to make a proposal to build additional transmission facilities. 

Furthermore, a National Corridor is not a siting decision, nor does it dictate the route of a proposed transmission 

project. The National Corridor designation serves to spotlight the congestion or constraint problems adversely 

affecting consumers in the area and under certain circumstances could provide FERC with limited siting authority 

pursuant to FPA 216(b)” (DOE 2009).
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Siting is especially complicated when a major transmission project spans several states. Filing 

requirements, timelines, and even the type of authority vary by state according to statute. In some 

states, a single agency conducts centralized (“one-stop”) review and approval; in other states, 

each county conducts its own review and approval. Consequently, a transmission developer may 

face several litigation actions (each with different issues and evidentiary needs) for one major 

project.

A state can exercise eminent domain to obtain an easement on behalf of a utility but, in many 

cases, the utility can obtain landowner consent by offering financial incentives that are slightly 

more lucrative. However, regulators recognize that having eminent domain as an option 

generally provides landowners a stronger incentive to accept negotiated compensation because 

the condemnation value awarded under eminent domain would almost always be less. 

The assessment of environmental impacts is an especially common transmission siting issue. In 

2008 and 2009, the Western Governors’ Association worked with environmental 

nongovernmental organizations and other stakeholders to identify high-quality wind, solar, and 

geothermal development areas that had the least impact on sensitive habitats. Although not 

completed, this work contributed to progress toward the identification of Western Renewable 

Energy Zones (Western Governors’ Association 2009). 

Some siting and permitting issues occur at the federal level, particularly when part of a 

transmission line crosses federally owned land or areas that enjoy protection under federal law. 

Any proposed development on federal lands requires review under the National Environmental 

Protection Act, a process that can be lengthy. However, during the past few years, the U.S. 

Department of Interior has begun to implement programmatic environmental impact statement 

procedures for wind, solar, geothermal, and transmission projects. This is an effort to streamline 

the federal permit review by addressing issues that are not site-specific.

The Energy Policy Act of 2005 (EPAct 2005) gave FERC limited “backstop” siting authority. 

FERC’s current authority is limited to national interest electric transmission corridors (also 

established by EPAct 2005), and recent court rulings have established that FERC’s backstop 

authority only applies if a state siting authority fails to act in a timely manner. The court struck 

down FERC’s ability to overturn a state siting decision that was rendered in a timely manner. 
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26.2.3 Transmission Cost Allocation

Transmission cost allocation is controversial and one of the most important issues to resolve if 

significant transmission system expansion is to be realized. 

Cost allocation25 refers to how costs for new transmission are divided among different users and 

customers. The term implicitly includes discussion of the mechanisms by which costs are 

recovered. Cost allocation often raises equity issues because customers and regulators in one 

state may object to paying for benefits that accrue to customers in another state. Most costallocation conflicts have occurred over transmission, but they may also include renewable energy 

integration costs and bulk storage costs in the near future.26 FERC has ultimate jurisdiction over 

rates charged for an interstate transmission system within the United States.

27 In states served by 

a FERC-approved ISO/RTO, most transmission cost-allocation issues are resolved within the 

rules of the ISO/RTO. FERC Order 1000 contained new guiding language regarding how 

transmission cost allocation should occur as well as requirements for planning. It is too early to 

predict the impacts of this order.28 

 

25 In the context of retail electricity rates, cost allocation refers to how state regulators allocate a local utility’s 

capital costs among residential, commercial, and industrial customers. This is slightly different from how the term is 

used with respect to transmission.

26 For a discussion of cost allocation, see PJM (2010). 27 ERCOT, which has a footprint entirely within the state of Texas, is under the ratemaking jurisdiction of the Public 

Utility Commission of Texas, not FERC. http://www.ferc.gov/industries/electric.asp. 28 For the complete Order 1000 text, see: http://www.ferc.gov/whats-new/comm-meet/2011/072111/E-6.pdf. 
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Chapter 27. Power System Considerations for High Levels

of Renewable Generation 

There will be many changes in the power system before 2050. Many changes are already 

underway as new technologies are adopted that improve system operations and 

economics and as higher levels of renewable generation are deployed. Significant 

changes in the power system will come from both the demand and supply sides, including 

both technical and institutional changes. 

Likely changes on the demand or load side include vehicle electrification; load-shifting 

encouragement through time-of-use rates; and increased flexibility in loads driven by 

utility demand-response programs addressing both load modification and provision of 

ancillary services. The latter two changes include institutional as well as technical 

components. Other likely institutional changes include evolution and expansion of 

markets for energy and ancillary services; evolution of operating strategies to allow 

wider-area coordination in generation commitment, scheduling and dispatch decisions; 

and enhanced regional coordination in planning, siting, and permitting new transmission. 

Transmission changes driven by technical considerations are likely to include 

transmission additions to allow enhanced access to remote resources such as wind and 

solar, as well as expanded cooperation among neighboring balancing authorities; 

operation at higher AC voltages with broader adoption of flexible AC technologies that 

increase controllability of AC power flows; new HVDC transmission for long-distance 

delivery of remote resources; and new underground transmission technologies to address 

congestion in crowded urban and suburban load centers. 

On the supply or generation side, changes are likely to include efficient use of variablegeneration forecasting in standard grid operating procedures; generation-fleet additions 

that are designed with flexible operating characteristics, such as high tolerance to 

frequent ramping and high part-load efficiencies; modifications to base-load units, if 

possible, to allow more flexibility, and retirement of some inflexible base-load units; new 

hydroelectric-generation control practices and capabilities, including changes in 

hydropower priorities and constraints; and possibly development of new nuclear units 

with increased operating flexibility.

Utility planners are developing new approaches to planning and operations to 

successfully manage the challenges of high-penetration variable generation integration 

and consider how to put renewable generation to the best use (NERC 2009). In addition, 

a number of recent studies have investigated the impacts and implications of integrating 

higher levels of wind on the grid. Several of the most significant issues that have been 

identified and need study are: 
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• Planning to meet system capacity and energy needs:

29 This involves 

changing from a focus on the capacity to meet the system peak load to 

planning to meet system energy and capacity needs: 

o Non-dispatchable variable generators, such as wind and photovoltaics 

(PV), are primarily energy sources rather than capacity sources. They 

will contribute some capacity value, thus contributing to system 

planning reserves, but that value will generally be substantially less 

than the plant nameplate capacity—particularly in the case of wind.

o This change includes a focus on net load and the correlation between 

load and the variable supply. 

o Additional attention on estimating the requirement for planning 

reserves (capacity in excess of peak load) is needed to accommodate 

the increased uncertainty of a variable supply.30

• Detailed study of variable generation operating impacts: Studies need to 

model the magnitude and frequency of changes in load, changes in variable 

renewable resource production, and the coincident changes in both. Changes 

across seconds, minutes, and hours will indicate system needs for regulation, 

load following, and unit commitment. Studies should also test the sensitivity 

of findings to forecast accuracy. 

• Assurance that sufficient flexibility exists in the generation portfolio: The 

additional variability of supply places additional demands on the balance of 

the generation mix. Higher ramp rates and lower minimum generation levels 

may be necessary as well as additional regulation capabilities. 

• Upgrading and expanding transmission systems: Traditional resource 

planning focuses on the adequacy of generation resources or generation 

capacity at peak load because resources are almost always more than 

sufficient at other times. The transmission system must ensure dynamic 

transfer capacity (i.e., the ability—on an instantaneous basis—to share 

reserves and average out local variability over large regions, as well as 

transfer blocks of energy—renewable and conventional energy) is adequate to 

meet system needs. Decision makers are also considering innovative policies 

at the state level that would support building transmission to wind resource 

areas—in some cases, in advance of commitments to build the wind 

generation capacity. For example, a substantial effort has been undertaken in 

Texas to identify regions where future wind development is highly likely 

(called Competitive Renewable Energy Zones or CREZ) and then facilitate 

transmission additions to access these regions. Through this process, 

transmission, which takes substantially longer to approve and build than a 

wind plant, can be in service when or shortly after the new renewable 

 

29 Traditional resource planning focuses on the adequacy of generation resources or generation capacity at 

peak load because resources are almost always more than sufficient at other times.

30 NERC (2009) discusses this issue in considerable detail.
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generation comes on line. Similar processes have been initiated in California 

and other western states.

• Cooperation in siting and permitting across multiple jurisdictions: 

Delivering the most cost-effective renewable energy resources to load centers

may require coordination across multiple jurisdictions. Such coordination will 

require an unprecedented level of cooperation among states and federal 

agencies that often have conflicting missions and little experience in 

cooperation. 

Within RE Futures, the above issues have been addressed in part within ReEDS and 

GridView modeling as described in Chapter 28. 

The following sections describe the specific challenges posed by variable generation to 

grid planning and operations, and identify general solutions, or characteristics of 

solutions, that will be useful in meeting these challenges.

27.1 Technical Challenge of Variable Generation

The renewable resources and technologies assessed in RE Futures analysis include 

hydropower, geothermal power, biopower, concentrating solar thermal power plants 

(CSP), wind turbines, and PV, among others. It is important to distinguish variable 

generation sources from renewable energy sources more generally. Hydropower, 

geothermal power, biopower, and CSP with sufficient thermal storage are “dispatchable” 

on a timescale of relevance to power system operations.31 Wind and PV are not 

completely dispatchable because if there is no wind or sun, they cannot generate 

electricity; if there is wind and sun available, their output can, however, be curtailed.32 In 

scenarios with high levels of renewable generation, it is the variable generation, mainly 

from wind and PV, along with the limited flexibility in the remaining fossil and nuclear 

units, which creates the main technical challenges for the grid. 

Variability and uncertainty are different properties of variable generation. For example, 

even if wind energy could be perfectly predicted, there would be a significant impact on 

power system operation and planning because wind energy’s output changes over the key 

time and geographic scales for power system operation. This variability implies a need 

for an increase in regulating capability (unless supplied by the wind plants themselves) 

and an increase in load following. Other generation resources could be scheduled with 

certainty; however, the remaining generation fleet would be called upon to meet an 

increasingly variable net load.

Uncertainty exacerbates these impacts. Because variable generation cannot be forecast 

with certainty, its variability in key time frames (unit commitment and load following) 

are partially unknown at the time during which system operational decisions are made 

concerning plant commitment and dispatch. This implies that operating reserves must be 

increased to accommodate the uncertainty of variability. Much is known about wind 

 

31 For RE Futures scenarios in 2050, CSP was generally built with substantial thermal storage, which 

buffers its output and permits CSP to operate as if it were dispatchable.

32 Current research into methods for wind-provided regulation, both up and down, is underway.
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variability, uncertainty, and integration impacts.33 Less is known about solar energy 

variability because of a relative lack of operational solar plant data and few integration 

studies. 

As there is relatively little installed solar capacity in the United States, the characteristics 

of solar technology (PV and CSP) power output are not well established. It is anticipated 

that CSP with substantial thermal storage will be dispatchable, offering considerable 

control of output. Initial experience with PV indicates that output can vary more 

rapidly than wind unless aggregated over a large footprint. Further, PV installed at the 

distribution level (e.g., residential and commercial rooftop systems) can create challenges 

in management of distribution voltage. CSP with storage mitigates both the variability 

and uncertainty of the output of this technology through the ability to store thermal 

energy and provide power during periods—6 hours or more depending on the amount of 

thermal storage and the prior availability of solar energy to charge it—of cloudy weather 

or at night; further, thermal inertia within the CSP system allows the system to “ride

through” short periods (a few minutes) of cloud coverage, such as when individual clouds 

pass by. 

The inability to precisely predict the output of variable generation over various time 

frames is not unlike what is currently experienced with load forecasting, but the 

prediction of variable generation delivery is currently more difficult per unit than is load 

prediction. The ability to predict variable generation output varies among the various 

renewable technologies and is expected to mature over time, but, as with load, will never 

be perfect. Both variability and uncertainty increase the power system’s need for 

reserves. Both variability and uncertainty can be reduced through aggregation of 

generation over larger geographic areas. 

27.2 Institutional Challenges of Variable Generation

Institutional challenges can be viewed, in part, as operational, market, or regulatory 

barriers to economically efficient operation of the bulk power system. These challenges 

are not new, nor are they unique to the integration of variable generation. As an example, 

hourly scheduling and dispatch is a well-known institutional constraint to efficient power 

system operation. Although coordinated or consolidated balancing authorities have 

enabled sub-hourly scheduling to be largely implemented in the Eastern Interconnection 

and in Texas, sub-hourly scheduling has not been widely implemented in other parts of 

the United States.

34 These developments, largely independent of the increases in variable 

generation on the grid, demonstrate that the increased efficiency of power system 

operation is a goal worthy of pursuit in and of itself and can drive changes in system 

operations that will also benefit renewable energy integration.

A significant institutional challenge related to integration of renewable generation is the 

development of mechanisms that enable the market emergence of flexible technology 

solutions. More specifically, when such technical solutions have been demonstrated, an 

institutional framework (e.g., rules and markets) is required that allows the power system 

 

33 See GE Energy (2010), EWITS (2010), and EnerNex (2006). 34 For more discussion on activities in the West, see Milligan and Kirby (2010a). 
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operator to tap the physically available flexibility to help integrate large amounts of 

variable generation. Each system is different, but fundamental principles that have 

already been identified in prior integration work on wind energy will apply. 

More generally, the U.S. grid operates as a large interconnected system spanning the 

contiguous United States, Canada, and part of Mexico, yet the governing institutions of 

the grid do not always interact in the most effective ways. While FERC has regulatory 

authority over interstate sale of electricity and the operation of regional markets, states 

have authority over siting and permitting of generation and transmission facilities. This 

local control over infrastructure has an important impact on new transmission 

construction and other modifications to the grid. For example, state and regional 

institutions determine how to allocate costs, subject to FERC orders, which affects the 

market risks for a range of stakeholders, including project developers. These institutional 

impacts result in a complex mix of legal issues and political dynamics that impact plans 

to deploy renewable electricity technologies. Consequently, expanding the use of 

renewable electricity poses institutional challenges that are often more formidable, and 

less studied, than the technical challenges. 

This brief overview broadly describes some of the institutional challenges associated with 

high renewable generation futures. Detailed exploration of these issues will require 

additional study. 

27.3 Impact of Variable Generation on Power System Operations

Increasing the amount of variable renewable resources on the grid adds additional supply 

variations and uncertainty, complicating the task of keeping production matched to load. 

Given that much more is known about wind generation and its impact on power system 

operations and flexibility requirements than for other variable resources, the following 

discussion focuses on that technology; the impacts of other forms of variable generation 

are expected to be qualitatively similar (Mills and Wiser 2010). 

Figure 27-1 illustrates the impact of a high level of wind generation for a particular case. 

The figure shows that the net load, which is what the system operator must manage with 

conventional units, has a steeper ramp characteristic than the load alone does. This 

implies that the conventional generation fleet will sometimes be required to ramp faster 

with wind than without it. Figure 27-1 also shows that during low-load and high-wind 

periods, the net load to be served by the conventional fleet is significantly less than it is in 

the no-wind case. This implies that, to avoid curtailment,35 conventional base-load 

generation must be able to achieve lower turndown levels, or that base-load generation 

must be replaced by or augmented with more flexible generation technologies over time 

as the variable generation increases.

 

35 Curtailment refers to shutting down a plant or reducing its output at a time when its energy is not needed, 

or when the transmission system is operating at maximum capacity and thus cannot accept the plant’s 

energy. Substantial incentive exists to limit curtailment of wind and PV plants because their energy is 

provided at essentially zero operating costs and because the economic justification for these plants 

generally assumes that all energy available will be sold.
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Short-term solutions to the minimum-generation issue include use of out-of-merit36

dispatch (or more sophisticated dispatch and commitment algorithms that take minimumgeneration levels into account), curtailment of wind generation, or increasing exports to 

neighboring systems.

Figure 27-1. Impact of high level of wind generation 

Although there is sufficient controllability in modern wind plants to allow for partial or 

total curtailment, it is not economic to curtail an energy source with near-zero marginal 

cost and generate power with more costly generation. 

Recent analyses have improved the understanding of the impact of high levels of wind 

generation (e.g., 30%) over broad geographic footprints; however, much remains to be 

learned. The Eastern Wind Integration and Transmission Study (EWITS) and the Western 

Wind and Solar Integration Study (WWSIS) examined up to 30% wind energy 

penetration in large portions of the Eastern Interconnection and the Western 

Interconnection, respectively. In addition, up to 5% solar penetration in the WestConnect 

region of the Western Interconnection was also studied. Results can be found in Milligan 

et al. (2009b), EWITS (2010), and GE Energy (2010). 

A key finding of WWSIS was that over large footprints, the per-unit variability of wind 

energy declines significantly. Figure 27-2, taken from WWSIS (GE Energy 2010), shows 

 

36 Merit order is the ordering of generation in order from the lowest marginal cost to the highest. Using a 

generator “out-of-merit” means it is used out of order of its cost, most often being more expensive than an 

available generator that cannot be used at the time because of an operating constraint. 
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two examples of such smoothing. Each graph shows a scatter of the 1-hour changes 

(deltas) in wind power. The top panels show data for individual transmission zones, 

whereas the bottom panels show the respective data from larger supersets of the 

transmission zones. The flattening of the scatter pattern seen in the bottom panels is a 

powerful indicator of the smoothing impact that can be seen over broad regions. A very 

high level of variable generation should exhibit similar smoothing over broad geographic 

footprints. On a per-unit basis, this mitigates variability and uncertainty. 

Figure 27-2. Data from Western Wind and Solar Integration Study: Per-unit variability of 

wind power for four transmission zones

Source: GE Energy 2010

New Mexico (2006)
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These characteristics are not restricted to the West. Figure 27-3 is based on 10-minute 

wind power data that were simulated for EWITS. The parabolic shapes each represent 

alternative collections of wind plants, aggregated up to 85,000 MW of wind capacity. As 

more wind power is added, the per-unit variability, as indicated by the normalized 

standard deviation (sigma) of 10-minute wind deltas, declines significantly. 

It is clear from these analyses that very high levels of wind (and presumably solar PV) 

generation will exhibit similar smoothing impacts, helping to alleviate the challenge of 

achieving system balance.

Figure 27-3. Data from Eastern Wind Integration and Transmission Study:

Normalized 10-minute variability for five regional groups37

Source: EWITS 2010

Large penetrations of variable generation will have significant impacts on how 

scheduling is optimized to balance generation. Economically efficient unit commitment 

and dispatch methods have been in use for many decades, and although specific methods 

to achieve this efficiency may be needed with high levels of variable generation, the 

target of operating a reliable system economically will continue. Emerging work from

large-scale integration studies indicates, however, that the existing resource mix and 

characteristics may not be optimal for high levels of variable generation. Given a 

generation mix that is similar to that of today, along with higher levels of wind energy 

and other variable generation, this work indicates that: 

• Base-load generation cycling will increase.

 

37 Normalized sigma is the ratio of standard deviation to wind power. It is a measure of normalized 

variability. A high number denotes more variability than a low number. The graph shows the largest 

variability is in the mid-range of the wind plant output. Thus, more operating reserve (i.e., flexibility 

reserve) is needed mid-range than anywhere else. At the upper range, there is no need to carry down 

reserve because the wind cannot increase. The graph provides an indication of how much, and which 

direction, reserve is needed.
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• More flexibility is needed to throughput the system, from lower minimum 

operating levels for baseload plants, to faster ramp rates for load following 

generation, to controlled curtailment of wind and PV. 

• The net load that must be supplied from conventional (non-variable 

generation) generation is significantly different from the reasonably 

predictable diurnal and seasonal load patterns.

Within RE Futures, the GridView hourly modeling, in particular, examined issues of 

base-load generation cycling and system flexibility. Because the variations of load and 

wind tend to be uncorrelated in short timescales (EnerNex 2006), most U.S. analyses 

(EnerNex 2006; EWITS 2010; GE Energy 2010) have found that only modest amounts of 

additional regulation are necessary with more wind, with potentially significant impacts 

on longer time frames that span from tens of minutes to a few hours. The impacts of PV 

and CSP without storage are expected to be qualitatively similar to wind’s impacts, 

although the impacts may be quantitatively somewhat different, particularly in such cases 

as fast discrete clouds passing over an area with a high penetration of solar PV on a local 

feeder. Electric distribution systems and their protection equipment are generally not 

designed to handle two-directional power flow, so residential and commercial rooftop PV 

systems may present local integration challenges in some cases.

The remaining discussion in this chapter summarizes the roles of advanced unit

commitment scheduling approaches, improved wind and solar forecasting, and potential 

sources of additional flexibility in the power system evolution to high levels of variable 

renewable generation.

27.3.1 Advanced Unit Commitment Scheduling

In most locations, unit commitment schedules are currently developed one day in 

advance. More broadly implementing an approach that updates unit commitment more 

than once a day, while honoring generation commitment constraints, could improve the 

efficiency of electricity markets and lower costs. If new information becomes available

after a unit commitment decision is made that shows that some generation is not needed 

(such as by a new net-load forecast that is significantly lower than the one used in the 

hours-earlier decision), units could be de-committed, according to their economic merit 

and physical constraints. 

Because the unit commitment decision is typically the only binding decision that requires 

significant lead time (compared to dispatch decisions), advanced methods that can carry 

out commitment schedules that are robust against alternative scenario realizations have 

received substantial interest.

38 These stochastic unit commitment methods use alternative 

characterizations of the operating day, applying probabilistic methods to take these 

alternatives into account so that the commitment stack can respond to unforeseen 

variability and uncertainty. If the generation mix is changed to have fewer baseload units 

and more variable generation, then it will be helpful to reduce the ramp-up times for 

dispatchable systems (both generation and, potentially, demand response) to contribute to 

the system flexibility needed to serve net load. The unit commitment challenge may then 

 

38 See Risoe National Laboratory (2008) for a wind integration study for Ireland that used WilMar’s rolling 

and stochastic unit commitment program.
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be less of an issue or could be done closer to real-time with predictions that are more 

accurate. 

27.3.2 Improved Wind and Solar Forecasting 

A GE Energy study assessing the potential grid impacts of 10% wind penetration (GE 

Energy 2005) determined that variable operating cost savings increased from $335 

million to $430 million when state-of-the-art wind forecasting was used, with another 

$25 million in benefits accruing when perfect wind forecasting was used. The 

Intermittency Analysis Project conducted by GE Energy for the California Energy 

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

and another $0.95/MWh for perfect wind forecasting (GE Energy 2007). Moreover, it is 

not only important to implement wind forecasting, but to incorporate it into standard 

control room operations for scheduling and dispatch decisions. Wind forecasting systems 

will need to advance to be able to successfully predict large wind ramps, allowing 

utilities and RTOs to prepare for those events when they occur. 

California Independent System Operator implemented the United States’ first central 

wind forecasting system in 2002, and it is now expanding and improving its system. The 

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

implemented central wind forecasting systems in 2008. And, PJM and the Midwest ISO 

implemented a central wind forecasting system in 2009. In addition, Xcel Energy is 

collaborating with the National Center for Atmospheric Research and the National 

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

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

Wyoming. 

As with load forecasting, wind forecasts of larger aggregations of wind generators are 

generally more accurate than forecasts for individual plants (see Milligan et al. 2009a and 

NERC 2010); this will likely also be true for PV and CSP. As discussed earlier, new and 

improved methods to produce reliable probabilistic forecasts for wind, solar, and load 

must be developed. This will give operators better information compared to deterministic 

point forecasts and enable better preparation and better strategies for mitigation of 

unexpected events. 

PV forecasting is not as mature a field as wind forecasting is, and statistics on geographic 

dispersion are not well developed. However, PV forecasting will likely use a combination 

of numerical weather prediction models, along with methods that perturbate the clearskies estimate of solar insolation to simulate and forecast the impact of cloud cover. 
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27.3.3 Flexibility Needs: Ramping and Minimum Generation Levels

Today’s power system has been designed to manage current levels of variability and 

uncertainty; these are not new challenges. Morning and evening load ramps can be 

significant, and system operators have established procedures to ensure sufficient 

ramping capability is available. During the night and other low-load periods, baseload 

generators can be backed down and intermediate units can either ramp down or possibly 

cycle off, depending on the technology, generation mix, and load characteristics. 

Variable generation adds to the ramping requirements in at least two ways. First, variable 

generation can increase the ramping requirements already imposed by loads. Even with 

perfect foresight, ramping requirements for systems with significant amounts of variable 

generation will increase some of the time. This may be even more pronounced during the 

high load-ramping periods when wind generation moves in the opposite direction as the 

load moves. One possible approach to addressing this requirement is for wind to operate 

in a curtailed mode to address regulation needs and allow dispatchable resources to pick 

up load. Second, the ramping characteristics of variable generators are typically not as 

well understood as load, having a more random pattern than the predictable daily load 

cycle. However, forecasts for large wind ramps are available and will likely be 

significantly improved. Aggregation also significantly reduces the wind ramping impacts 

and improves the per-unit forecasting errors.

A significant body of analysis of geographically dispersed wind generation shows that, 

although there may be times that large unforeseen ramps may pose a challenge to system 

operations, these ramp events occur over many tens of minutes or a few hours as seen in 

Figure 27-4. Many different resources could have assisted in the power balance during 

the slow event. It is likely that solar generation will exhibit similar characteristics; 

however, short-term changes in PV plant output resulting from variation in cloud cover 

may prove challenging within small areas and must be analyzed more.
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Figure 27-4. Wind ramp event, Electric Reliability Council of Texas, February 26, 2008

Source: Ela et al. 2011

The wind ramp down starts at 3:00 p.m. and continues until approximately 6:30

p.m., giving a 3-hour ramp period. Many different resources could have assisted 

in the power balance during the slow event. The wind forecast (green) was 

actually very accurate; however, the updated resource plans were used during 

this event, exacerbating the wind ramp.

If ramping requirements exceed the capability of the generators to follow the ramps, a 

separate load-following ramping product might be needed. Figure 27-5 illustrates a 

simplified example for load alone (Kirby and Milligan 2008a). Extrapolating the example 

to a case of high variable generation is a straightforward process. Figure 27-5 shows there 

is sufficient baseload generation to meet the load. However, the baseload unit is not 

capable of meeting the sharp ramp requirement that begins at 8:00 a.m. Because the 

baseload unit cannot meet the ramp, a peaking unit is necessary. Had the baseload unit 

been able to supply the load ramp, the energy price would have been set at $10/MWh, the 

price of the base unit. However, because the peaking unit has a cost of $90/MWh, in a 

simple energy-only market, the peaking unit sets the price for the period that the peaking 

unit is used. Without a ramp product, the energy price will be distorted. In this simplified 

case, a market for ramping could have paid the peaking unit, but the energy price would 

not increase to $90/MWh. The development of specific ancillary services markets could 

address such variable generation-related or other ramp events. 
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Figure 27-5. Simplified example for load alone

Source: Kirby and Milligan 2008a

27.3.4 Sources of Flexibility

High levels of variable generation clearly require additional grid flexibility, which is the 

ability to respond to variations in the need for generation. In the context of this 

discussion, additional flexibility can be obtained by changes to: operational practices and 

procedures, including scheduling practices; various types of load shifting, demand 

response, or load management; generation mix and characteristics; market practices; 

management of balancing authority areas (including through cooperation among 

balancing authorities); and the use of centralized or decentralized storage. Sources of 

flexibility can be broadly separated into two categories that are not always clearly 

delineated: technical sources (e.g., specific types of generation or load technology) and 

institutional sources (e.g., markets and scheduling practice).

27.3.4.1 Flexible Load

Responsive load includes both technical elements and institutional elements. Responsive 

loads have the potential to help balance the power system over all timeframes, including 

sub-cycle stability, minute-to-minute regulation, spinning and non-spinning reserve, peak 

shaving, and increasing minimum loads. Several types of loads, either under direct utility 

control or in response to a price signal, can respond to the availability of “surplus” 

generation, significantly alleviating the minimum load problem at night in systems with 

high penetrations of wind. In addition to electric vehicle charging, such flexible load may 

include aluminum production in the industrial sector and pre-cooling of large commercial 

buildings and storage water heaters. Appropriately designed loads could profitably use 

wind energy that might otherwise be curtailed while simultaneously providing reserves 

for that wind generation. An accurate forecast of the amount of energy that might be 

available seasonally or annually through responsive load is necessary in order to enable
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industry to design and invest in processes that can take advantage of this low-cost but 

uncertain resource.

Responsive loads can also include such new approaches as “smart grid;” other automated 

metering infrastructure; and, in the future, similar but more advanced interactive 

technologies operating between consumers and producers. The grid and load 

management potential of these technologies hold promise in the future, such as when 

coupled with electric vehicles or decentralized or community electrical storage.

Responsive load supplies half of the contingency reserves for ERCOT, the maximum 

ERCOT currently allows. Providing contingency reserves using responsive loads is 

attractive in many cases because they are available at lower cost than generation reserves. 

Typical responsive loads range from residential air conditioning to large industrial loads. 

Rapid response is often needed, but advances in communications and control technology 

speed are making this possible. Technology also allows loads to sense changes in the 

system, enabling autonomous responses to large imbalances between generation and 

load—as with generators. Price-responsive load, because of the additional system 

flexibility it provides, is likely to aid substantially in the integration of variable renewable 

generation. The two examples of price-responsive load below (electric vehicles and 

industrial load) illustrate the potential benefit. 

Electric vehicles may be charged under utility control or in response to a price signal 

largely at night when surpluses of wind generation contribute to minimum load problems 

for conventional generators (Markel et al. 2009). This benefits the electric vehicle owners 

because the energy price will be low. Though electric vehicles will require charging even 

on nights when there is no wind, the average price for charging energy will be lowered in 

the presence of high wind generation levels. Perhaps equally important, there will be some 

flexibility in charging the vehicles. A typical vehicle may require a nightly 20-kWh charge. 

Though the full charge must be delivered before the morning commute, chargers can be 

built to allow controlled charging that can be ramped up or down or interrupted to provide 

fast reserves for wind generation. Even if the wind decreases at night, flexibility in the 

charging will provide sufficient time for other generation to complete the charge.

Aluminum smelting provides another example of a potentially symbiotic load for high 

penetration of wind energy. Aluminum production is electricity–intensive, and it is 

declining in the United States in response to increased electricity prices. Smelters are 

designed to operate at essentially constant load to maximize their efficiency. Recent 

efforts have demonstrated the ability of a 400-MW aluminum smelter to provide 20 MW 

of regulation (Kirby et al. 2009; Todd et al. 2009). It is possible that an aluminum smelter 

could be designed with greatly increased flexibility to make use of excess nightly wind 

power, helping alleviate minimum load problems while also providing reserves and 

regulation, and at a potentially lower electricity price for the smelter. Designing a 

potline39 with this much flexibility would be a significant undertaking, but doing so could 

provide both an economic benefit and a strategic benefit for the United States. An 

aluminum plant investor would need a solid forecast of long-term energy availability and 

 

39 A potline is a row of electrolytic cells used in the production of aluminum.
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prices to make the investment viable. This potential opportunity was not explicitly 

included in RE Futures as it was not commercial as of 2010. 

27.3.4.2 Flexible Generation

Adding significant quantities of variable generation will increase the variability and 

uncertainty in the power system. Any conventional generation that is used in a system 

with significant variability and uncertainty will be more valuable if it is more flexible

(i.e., able to respond quickly to changes in variable supply). Adding significant variable 

generation will increase the current value of flexible contractual obligations. The value of 

being able to change the output of combined or simple cycle plants has been shown to be 

a significant portion of the overall value of investing in a new plant, even with the level 

of flexibility required under existing market conditions (Roques et al. 2008; Bush et al. 

2012). For example, a CSP resource with storage is also a potential source of flexible 

generation that is in service in Spain,40 and under further development within the United 

States.41

Similarly, increasing physical flexibility can increase the value of new plants as demand 

for flexibility increases. A perfectly flexible plant is able to run at its full operating point 

in any interval where the market price exceeds its full-load marginal cost, and to turn off 

in any interval in which the price is below its marginal cost. Some generators now 

commercially available have characteristics that approach the ideal of a perfectly flexible 

unit. Examples include fast starting reciprocating engines and simple cycle gas turbines 

that can start in 10 minutes or less, and more flexible combined cycle plants with faster 

start and greater cycling range. (Heikkinen et al. 2008, GE n.d., GE Energy n.d.). 

Manufacturers are recognizing the need for, and the value of, generator flexibility, and 

they are offering products to meet that need. These plants can earn more short-run profits 

in a market than a plant with the same fuel and efficiency level, but less flexibility.42

27.3.4.3 Hydropower

Hydropower generation offers the potential to help integrate variable generation 

resources. Generally, hydropower generation can be divided into run-of–river with 

limited water storage (output closely follows river flows), controllable hydropower (with 

a reservoir or pondage), and pumped-storage hydropower (see Chapter 8 [Volume 2] for 

more information). Run-of-river generation with limited water storage has similar 

characteristics to wind in some respects: the amount of energy available depends on river 

flows and there is limited control. Conventional hydropower generation from reservoirs is 

capable of quick response and provides substantial flexibility needed to help manage 

variable generation from wind and solar PV. 

Water flows are subject to a large number of constraints that honor competing uses of the 

river. It is not unusual for hydropower generation to be a relatively low priority compared 

to navigation, flood control, or wildlife management. In addition, hydropower generation 

 

40 Andesol Units 1, 2, and 3. 41 Abengoa Solana, Arizona. 42 The flexibility of these resources can be limited based on air emissions permits issued with the 

operational approval of these units. However, air permits might be relaxed if other types of generation (e.g., 

coal) are decommissioned. 
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occupies an unusual niche in the power supply portfolio because of its low (marginal) 

cost but high value to customers with access to this resource. Given the historical 

allocation of hydropower to specified preference customers and the large body of water 

law, much of the value potential for using hydropower to integrate large penetrations of 

variable generation may not be realized without significant changes in the institutions that 

regulate this part of the power industry. 

In large river-based hydropower systems such as the Columbia River system, the parties 

who receive allocations from the system have coordination agreements with each other. 

Some experts believe existing, untapped flexibility could potentially be identified by 

more consistent river-basin analysis and modeling, so that both water and energy needs 

are fully considered while also honoring other competing uses. The power system’s need 

for fast, short response, for example, may be compatible with environmental constraints 

that typically have somewhat longer time constants. 43

27.3.4.4 Energy Storage Technologies

Storage technologies—both the existing large-scale commercial technologies of pumpedstorage hydropower and compressed air energy storage, and the emerging technologies of 

batteries and flywheels—offer significant flexibility in operations with rapid start and 

ramp capabilities as discussed in Chapter 12 (Volume 2).44

High penetration of variable generation may result in curtailment during periods when the 

amount of available generation exceeds load or exceeds the carrying capacity of the 

transmission system to deliver to load. Curtailment can also occur when total variable 

generation throughout the region might require conventional units to operate below their 

minimum operating capacities. In addition, strategically curtailing some variable 

generation provides a source of operating reserves, and doing so could reduce the need to 

retain aged, high-cost, high-emission thermal units (CAISO 2010). 

As the amount of “wasted” or dumped generation increases, storage becomes more 

desirable, if it is cost-effective.

45 Studies suggest that curtailment may be more costeffective than storage at variable generation levels of 20%–35%, mostly wind (EWITS

2010; GE Energy 2010). While curtailment of renewable generation appears undesirable, 

using variable generation to charge storage results in round-trip losses of approximately 

20%–25% and effectively “curtails” this amount of generation while also incurring the 

additional cost of the storage system (Denholm et al. 2010a). At very high generation 

levels, low-cost flexibility options such as demand response and larger balancing 

authorities may be limited in capability; long-term storage technologies may then be 

more competitive. 

 

43 Hydropower in the Northwest has pondage, and it is partially controllable and operates under certain 

environmental restrictions. 

44 For additional information on storage, see Denholm et al. (2010b). 45 Levels of variable renewable generation that result in curtailment create an opportunity as the marginal 

generation is then “wasted” and might be considered “free.” If cost-effective energy storage were available, 

this energy could be saved for use when loads are again in excess of the variable renewable generation.
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27.3.4.5 Potential Sources of Institutional Flexibility

Institutional constraints can be reduced or eliminated so that a system operator has the 

tools that allow access to the physical flexibility that exists on the power system. 

Examples such as balancing authority consolidation and inter-area coordination, reserve 

sharing, use of fast markets, storage charging and dispatching protocols, and load and 

variable generation forecast improvements are notable as areas where substantial 

improvements may occur in the future. These concepts and their impacts are discussed 

below. 

27.3.4.5.1 New Types of Reserves: Flexibility Reserves

Flexibility reserves refer to scheduling methods and reserve categories, and as such, do 

not constitute a technological source of flexibility. Considerable work in recent wind 

integration studies, such as EWITS, has been done to ensure sufficient flexibility is 

available when needed to manage ramp events. There is no standard definition or term for 

this system capability, so this discussion uses the term flexibility reserves, or reserves that 

can meet unexpected need for additional system flexibility. In addition to the physical 

need for flexibility and the operational practices that may need to be changed, certain 

market implications could also facilitate the development of new reserve types.

27.3.4.5.2 Balancing Authority Area Size and Inter-Balancing Authority

Consolidation 

Within the last several years, many wind and grid integration studies46 have found that 

large balancing authorities are beneficial to integration. This is because the per-unit 

variability of load and variable generation both decline with aggregation, whereas the 

capability of the system to manage variability (e.g., ramp capability) increases linearly 

with aggregation. Therefore, a large balancing authority results in having a deep pool of 

flexible generation that can respond to variations in variable generation output, helping 

the system operator maintain balance, and reducing the cost of system balancing. Larger 

balancing authorities have larger generation pools. Greater flexibility is a function of the 

generation mix, but larger pools always provide greater flexibility than smaller pools of 

the same generation mix.

The balancing authority is the basic operating unit within the interconnected power 

system. As such, the balancing authority has a large impact on power system reliability 

because it is responsible for maintaining load and generation balance. Increasing the 

balancing authority size provides economies of scale because aggregating larger amounts 

of load reduces the effective load variability. Similarly, aggregating larger amounts of 

variable generation also reduces the effective variability and uncertainty of the 

generation. The net effect reduces the required regulating reserves. At the same time, the 

ramping capability of the larger balancing authority increases. 

Contingency reserves exhibit similar economies of scale. Many balancing authorities join 

reserve sharing groups to take advantage of these economies. More recently, balancing 

authorities in the Western Interconnection have been exploring ways to take advantage of 

the diversity in the variability of their loads and generation with the variability of their 

 

46 See EWITS (2010), GE Energy (2010), and EnerNex (2006).
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neighboring balancing authorities’ loads and generation. Advances in communications 

and control allow sub-hourly trading of energy and ancillary services and virtual 

consolidation of balancing authorities. 

The Midwest ISO (MISO) recently consolidated the operation of 27 balancing 

authorities, and the Southwest Power Pool is considering moving in the same direction. 

Even though MISO and PJM have large electrical and geographic footprints, significant 

seams47 remain between them, and between New York ISO and ISO New England. In 

some areas, there is a move towards tighter coordination across operating footprints; for 

example, New York ISO and Hydro Quebec are moving toward the ability to schedule 

hydropower transactions sub-hourly, which would significantly increase the flexibility 

available to both balancing authorities. 

To illustrate these benefits, Figure 27-6 shows the hourly ramping that could be 

eliminated, based on an analysis by Kirby and Milligan (2008b). The teal trace shows the 

total up-ramp requirements if balancing authorities operate separately, and the dark green 

trace similarly shows the down-ramping requirements. Because there are many hours 

when some balancing authorities must ramp up and others must ramp down, netting these 

movements can save ramping and wear and tear on thermal units. The light green trace 

shows the net required ramping, and the blue trace shows the bi-directional ramping 

reduction that can be achieved. 

Figure 27-6. Elimination of hourly ramping

Source: Milligan and Kirby 2008b

 

47 Seams are the boundaries that exist between balancing authorities. Ideally these boundaries would be 

“seamless” and not limit cooperation between neighbors. Differences in technology and institutions 

between neighbors create “seams” that can create operating challenges.
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Inter-balancing authority coordination is also critical. Fast (5–10-minute) dispatch can 

improve a balancing authority’s ability to integrate variable generation within the 

balancing authority; coordination of schedules between balancing authorities can have a 

similar effect. In a high renewable electricity future, large quantities of variable 

generation will likely be located in areas that are distant from load centers; in some cases, 

this distance could span multiple balancing authorities, as currently configured. Ensuring 

that balancing authorities have the ability to make schedule adjustments several times 

during the hour will improve the operating efficiency of all the areas involved. Longer 

term, this coordination can reduce both the amount of installed capacity and types of 

reserves that are necessary to meet system reliability needs, and export requirements 

between utilities.48

RE Futures modeling and analysis inherently reflects fluid markets. Such markets are 

assisted through the adoption of sub-hourly energy markets and trading, and sub-hourly 

generation scheduling across the United States. However, sub-hourly modeling itself was 

not done in RE Futures, and it is an important issue to be addressed. The modeling and 

analysis also reflects that voluntary balancing authority coordination would eliminate the 

technical distinctions associated with balancing authority size. In the absence of actual 

balancing authority consolidation, it was assumed that inter- balancing authority 

communication and sub-hourly scheduling effectively accomplishes the same outcome as 

full consolidation. However, because RE Futures relied on system-wide, least-cost 

optimizations for capacity expansion and dispatch, markets and trading were not 

explicitly modeled in the study. 

27.3.4.5.3 Future Markets

In the future, market and policy changes will be an aspect of accessing greater flexibility 

from either new or existing generation units, and might include a combination of 

expanded ancillary service markets, incentives, and market requirements. In Texas, the 

GE Energy–ERCOT study made an overarching recommendation that both day-ahead 

and shorter-term forecasts be used as the basis for ancillary service procurement (GE 

Energy 2008). With respect to specific services, the study recommended that ERCOT 

consider introducing a new, non-spinning reserve service with a startup time of 10–15 

minutes, representing a new future ancillary service. This service has the potential to 

reduce the amount of responsive reserves needed for identified periods of risk from 

reduced wind generation. 

Additional market or policy changes may be necessary to better manage large-scale wind 

ramps, which are relatively infrequent and slow—occurring over several hours—as 

compared to a sudden generator trip. As such, wind ramps more closely resemble large 

load ramps than sudden unscheduled generator outages or trips. The ancillary service 

requirements from large wind ramps are more closely aligned with non-spinning reserves 

and supplemental operating reserves that are provided by generators and responsive loads 

that can respond within 10–30 minutes. Current rules may require operators to make 

available or use very expensive rapid response resources even though wind ramps are 

 

48 For additional information, see Kirby and Milligan (2009).
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slow, and, as noted, limit the response period of reserves to less than the wind ramp 

period. 

Many market-based power system services are priced based on their incremental 

opportunity costs in the energy market. Energy itself is priced based on the marginal cost 

of producing it. Suppliers are either profitable or not, based on their ability to recover 

capital costs from market payments that are based on these relative marginal costs. 

Ancillary services are priced based on the suppliers’ lost opportunity for leaving the 

energy market to instead supply these services. This system works well and encourages 

suppliers to bid their actual marginal cost. The system also works well because most 

suppliers (conventional generators) have significant marginal fuel costs. However, this

system for selling energy or ancillary services based on the marginal cost of producing 

them breaks down when resources with no marginal cost, but non-zero capital costs, 

dominate the supply of energy or any of the ancillary services. For example, once wind or 

solar PV systems are installed, there is little or no additional cost to provide power 

whenever the wind or solar resource is available—the capital cost of these systems has 

already been sunk. Thus, for high levels of wind or solar PV generation, the marginal cost 

of power can be near zero over long periods. This situation is in sharp contrast to 

conventional power systems for which there is always a significant cost for fuel to 

generate power. Further, for conventional systems, marginal cost pricing can lead to 

higher prices during periods of peak demand. During peak summer periods when air 

conditioning demand is high, for example, marginal costs for power may be determined 

by very expensive gas turbines providing peaking power, and all the generators, low cost 

coal as well, are then paid for power at the high marginal price for gas turbine power. 

High levels of renewable generation may turn this cost structure on its head. In this case, 

during these peak summer periods, the marginal cost of power may instead be set by solar 

PV, which would be near zero. 
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Text Box 27-1. Locational Marginal Prices 

Locational marginal prices (LMPs) are a method used to set the price of electric energy at a specific location and at the 

time it is delivered. If the lowest-priced electricity can be delivered to all locations, prices are the same across the entire 

region and generators are selected or dispatched, in order of lowest to highest offer price or cost (merit order) until 

demand is met. When there is transmission congestion, energy flow to some locations is limited by physical or reliability 

constraints. In that case, more expensive energy is dispatched (out of merit order) to meet demand at that location. As 

a result, the LMP is higher in those locations. The methods for calculating LMPs differ among the markets but they are 

generally based on a security constrained economic dispatch where the economic dispatch is modified from strict merit 

order to meet operation, transmission, and reliability constraints. 

Wholesale energy markets for electricity use supplier offers and demand bids in an auction environment. Traditionally, 

regulated utilities use cost-based rather than offer-based economic dispatch for the determination of LMPs. Economic 

theories suggest that in a competitive market, generators will offer at their incremental costs. Market imperfections and 

complexities, or the exercise of market power, can subvert economic theory in a system as complex as the grid. 

The LMP can then be defined in terms of the incremental generation price (or production cost) to optimally deliver the 

next increment of energy-to-load at the specified location, or node, while satisfying all the system operating, 

transmission, and reliability constraints. Specifically, the LMP is the ratio of the cost increment to the energy increment 

($/MWh).

More generally, LMP is a method for managing transmission congestion through pricing in a wholesale market for 

electricity and was originally proposed by Schweppe et al. (1988) and further developed by Hogan (1992). The 

organized wholesale markets in the United States are operated by the ISO and RTO organizations under FERC 

oversight. The ISOs/RTOs coordinate the buying, selling, and delivery of wholesale electricity throughput their footprint 

or region. In their role as system and wholesale market operators, the ISOs/RTOs balance the needs of generators, 

wholesale customers (generally load-serving entities), and other market participants and monitor market activities to 

ensure open, fair, and equitable access, all under FERC oversight. The specific methods used by the different markets 

vary in detail, as described in Litvinov (2010).

In this current marginal cost-based pricing environment, responsive loads,49 storage, and 

renewables will likely be “price takers” as long as conventional units are on the margin. 

During periods when zero-marginal-cost units are on the margin, prices collapse and 

there is no ability to recover capital costs. Therefore, cost recovery for installed 

equipment that is based primarily on selling energy at its marginal price would be 

difficult in such a system where energy prices could be near zero for much of the year—

such a market would not be sustainable because the average price would be less than 

average total cost. As such, high levels of renewable electricity generation may require 

re-examination of market structures for energy and consideration of a broader range of 

factors, such as capacity or others, for cost recovery.

Research, particularly on market design, is needed to address this issue. The current LMP 

market structure was developed during deregulation. This relatively new market may 

need to evolve to a different market structure to address this issue of near-zero LMPs. A 

proactive approach to identifying potential market problems could help enable the public 

and private sectors to construct an appropriate market structure in a pragmatic approach. 

Potential market solutions include capacity markets or sufficient up-lift for energy prices 

 

49 For additional information on responsive loads, see Milligan and Kirby (2010b). 
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so that prices enable capital recovery. Other options are also possible. Ancillary services, 

such as frequency response, regulation, and ramping must be assured. Although these 

issues are beyond the scope of RE Futures, an understanding of the operational 

characteristics of the required system can be informed, in part, by this analysis. Future 

reforms needed to enable markets to efficiently provide all of the needed physical 

characteristics for operating the system with high levels of renewable generation can then 

be explored. 

27.4 Impact of Variable Generation on Transmission 

For renewables, the tradeoff between nearby, but lower-quality resources, versus distant, 

but higher-quality resources, with the additional cost of the transmission system, is a 

particularly important consideration. 

The WWSIS and EWITS both developed conceptual transmission overlays to test the 

viability of increasing the penetration of variable renewable generation in each 

interconnection. Although no optimization study was performed, both studies concluded 

that it may often be more economic to build transmission from sites with high-quality 

renewable resources (or similarly, use nearby, existing lines more efficiently), than to site 

wind or solar installations in locations with lower-quality resources that are nearer to 

load. The cost of the additional transmission is often a small fraction of the cost of 

additional generation equipment at the lower-quality site needed to provide equivalent 

amounts of electrical energy. Hence, the delivered cost of energy produced at the higherquality site is lower than the energy cost from the lower-quality site, even though the 

former requires additional transmission. Neither study—WWSIS nor EWITS—addressed 

the feasibility of siting and permitting new transmission, nor did they investigate the cost 

allocation of new transmission. 

Exploring the most economic solution to locating renewable generation requires detailed 

analysis of such issues as reliability, congestion relief, economic tradeoffs of various 

resource and transmission scenarios, and long-term planning. Building a wind energy 

plant can be done in 1–2 years, but negotiating the siting and permits for the rights-ofway for transmission that crosses multiple jurisdictions can require a decade. Many 

detailed alternatives need to be examined, including alternative transmission 

technologies. Because transmission losses increase with distance and because long 

transmission lines require reactive compensation, it may be more economical to use 

HVDC for distances greater than approximately 300–500 miles, as discussed earlier in 

this chapter. HVDC provides the ability to fully control the power flows and results in 

lower losses. However, HVDC requires conversion of AC to DC—and back again—and 

converter stations are relatively expensive. Technology innovation and research could 

lower the costs of conversion and make DC more attractive. Within RE Futures, HVDC 

lines were considered for increased capacity for asynchronous interconnects but they 

were not considered for linking distant renewable generation sources to main 

transmission lines.

Underground transmission systems could also be used to avoid barriers to siting overhead 

lines, but the state of the technology, higher costs of “undergrounding,” and increased 

repair time limit its application. 
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Chapter 28. Modeling of System Expansion and Operations for 

RE Futures Scenarios 

Electric system planners and operators employ a variety of modeling tools, each with a specific 

temporal and regional focus, to ensure the continuous and reliable delivery of electricity to the 

customer. These tools include system expansion planning tools, day-ahead unit commitment 

scheduling tools, hourly economic dispatch models, DC and AC power flow models, and tools 

for simulation of transient events that occur in seconds as well as market operation models and 

simulations. Some of these models are continually run and updated as the system or system 

conditions change. The models used by electric system operators have proven to be very 

effective; however, they are generally limited to the regional footprint of the system, are focused 

on near-term operation, and do not include detailed treatment of renewable generation. In other 

words, a full analysis of the operational and market impacts of all of the high-variable generation 

penetration scenarios described in Volume 1 is not yet possible, due to the long temporal 

(40-year) and the large spatial (contiguous United States) scope of RE Futures and the associated 

uncertainties. However, the modeling tools used in RE Futures address, at a basic level, the 

major planning and operation aspects introduced in previous chapters of this volume. 

The analytic backbone of RE Futures includes two electric sector models: the Regional Energy 

Deployment Systems (ReEDS) model and the GridView model. ReEDS was used to provide a 

high level of spatial resolution in order to effectively represent the geographic diversity of 

renewables and to step through, in 2-year intervals, the evolution of the power system over time. 

This represents the capacity expansion or planning process described in Chapters 23 and 24. 

GridView is an hourly chronological production cost model that is used to support and 

complement the ReEDS analysis. GridView captures some, but not all of the reliability and 

operational issues described in Chapters 24 and 25. For RE Futures, the generation and 

transmission capacity as projected in 2050 by ReEDS was imported into GridView, with its 

hourly resolution, which was then run to provide insights into how an electric system in 2050 

might operate. Both models consider the deployment and use of a variety of flexibility options 

needed to effectively integrate large amounts of variable generation as described in Chapter 27. 

The following briefly describes how the framework of both models ensures balance between 

electricity supply and demand. Details of the modeled scenarios, inputs, and results are provided 

in Volume 1. Additional details on the approaches and assumptions related to the modeling of 

variable generation are also provided in Volume 1 (Appendix B in particular) and Short et al. 

(2011)

28.1 The Regional Energy Deployment Systems Model

ReEDS is a generation and transmission capacity expansion model that projects the least-cost 

evolution, within applied constraints, for the contiguous U.S. electric sector from the present day 

until 2050 in 2-year steps.50 ReEDS represents U.S. wind and concentrating solar power 

resources by dividing the contiguous United States into 356 regions. All other resources and 

technologies are divided into 134 regions or balancing areas represented in the model. Due to 

computational constraints driven by the long time horizon and large spatial scope, each model 

 

50 For example, renewable generation levels in 2050 were prescribed in the RE Futures scenarios. In these scenarios, 

the renewable generation levels in years before 2050 were linearly increased to meet the 2050 level. ReEDS 

determined the least-cost renewable generation portfolio along with the least-cost balance of generation. 
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year is represented by 17 time slices consisting of four time slices in 1 day for each of the four 

seasons and an additional time slice to represent the summer super-peak demand. 

The ReEDS model is highly discretized and consists of multiple spatial hierarchies, including 

134 balancing areas (BAs) and 21 reserve-sharing groups (RSGs). Although the existing 133 

balancing authorities are considered in the design of the ReEDS BAs, BA boundaries do not 

correspond with existing balancing authority boundaries.51 The average generation and demand 

in each BA is balanced during each of the 17 time slices in the ReEDS optimization routine. For 

this balance, ReEDS allows transmission of power between neighboring BAs subject to 

transmission line capacity constraints. In these ways, the ReEDS BAs behave similarly to how 

existing balancing authorities behave, although there are at least four major exceptions:

1. The dispatch decision in ReEDS is based on a contiguous U.S.-wide, least-cost 

optimization compared with balancing-authority-specific optimizations, and does not 

include a separate unit commitment process. It is important to note that regional marginal 

energy costs (e.g., LMPs) are not used in the capacity expansion and dispatch decision; 

instead, the full system-wide, 20-year net present value costs of generation resources and 

transmission additions are used. ReEDS does not represent market behavior in deregulated power markets, but does find the system-wide optimal solution. 

2. The ReEDS model does not represent scheduled and contracted power transfers between 

BAs and instead simply transmits power on an as-needed basis.

3. The ReEDS model does not calculate reliability metrics specific to each BA, such as 

frequency-related metrics (e.g., area control error).

4. The balance in generation and demand is based on averages over each of the coarse time 

slices instead of for each hour. 

In addition to balancing generation with demand, ReEDS includes constraints on planning and 

operating reserves that are satisfied at the RSG level.52 In other words, ReEDS assumes 21 

reserve-sharing groups consisting of the existing ISOs and RTOs (e.g., California Independent 

System Operator, ERCOT, MISO, PJM, New York ISO, and ISO New England) and assumes 

consolidations of other regions loosely based on current and future transmission plans.53 Reserve 

requirements and curtailment calculations involve statistical calculations to address the inherent 

variability and uncertainty of some renewable resources (e.g., wind, solar PV) and the 

unpredictability of demand. 

At the longest timescale, a planning reserve (i.e., resource adequacy) requirement is applied in 

ReEDS to ensure resource adequacy for times of extreme demand.54 All (conventional and

renewable) dispatchable generators are assumed to contribute fully to the planning reserve 

requirement. However, because variable renewable resources cannot always deliver power on 

 

51 Political and jurisdictional boundaries, regional resource quality, and demographic distributions are also 

considered in the makeup of the ReEDS BAs. See Short et al. (2011) for more information. 52 Electricity curtailment is also calculated for each of the 21 RSGs. 53 Four RTOs are assumed in the Western Electricity Coordinating Council, one for ERCOT, with the remaining 16 

in the Eastern Interconnection.

54 Specifically, planning reserves are required to exceed the highest forecasted demand by approximately 12.5%–

17.2%.
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demand, including during times of system stress, their contribution to planning reserves can be 

considerably less. In ReEDS, a statistical “capacity value”55 is calculated separately for wind, 

solar PV, and CSP without storage. This calculation ensures that the LOLP does not increase 

over time. In addition, as variable generation increases, the capacity value of these resources will 

tend to decrease due to correlations between the output of nearby wind or solar plants,56 and 

because periods of high “net load” for the system (i.e., load minus variable generation) tend to 

shift to times when variable generation is more limited. In general, the average capacity value of 

wind and PV drops as renewable electricity penetration increases, both over time and with 

increasing renewable generation levels. Additionally, when high solar deployment is observed, 

the capacity value of PV drops significantly as the peak net-load shifts toward the evening hours 

when PV output is limited or zero. The capacity value of wind, on the other hand, can improve 

with this shift in peak net-load because wind output is generally higher in the evening than in the 

afternoon. This also indicates the complementarity of wind and solar resources together.

At hourly to sub-hourly timescales relevant to daily electric system operations, ReEDS requires 

sufficient flexible supply- and demand-side technologies to satisfy operating reserve 

requirements. Because ReEDS does not simulate events that occur at these short timescales, 

operating reserves are only treated on a capacity basis, although the flexibility and ability of 

resources to meet these operating demands are considered.57 The operating reserves considered 

in ReEDS include wind and solar forecast error reserves, contingency reserves, and frequency 

regulation. Because contingency reserves and frequency regulation requirements are assumed to 

be established as a fraction of demand (6% for contingency and 1.5% for frequency), they are 

independent of the amount of variable generation.58 In contrast, forecast error reserve 

requirements are estimated based on hourly persistence forecasts for wind and solar PV, and thus 

increase as variable generation increases. In addition, the different timescales involved in each of 

the operating reserve types place restrictions on the degree to which each technology can 

contribute to the reserve requirements. For example, because frequency regulation targets the 

sub-minute timescales, only generators that are spinning and synchronized to the line frequency 

can contribute to regulation. Based on existing standards,59 contingency events must be 

addressed in roughly 10 minutes with at least half of the reserve requirements to be met by 

spinning resources and the other half satisfied with non-spinning (also referred to as “quick 

start”) resources. For forecast error reserves, which occur in the roughly hourly timescale, 

 

55 Capacity value is defined and the different methods for its calculation are found in the IEA Task 25 report 

(Milligan and Porter 2005). 

56 Wind and solar output are determined by the immediate weather conditions (e.g., wind speed or solar insolation), 

so the output profiles of proximately located wind (or PV) plants are generally correlated with each other. Having 

positive correlations within a group of wind (or PV) power plants increases the likelihood that all members of the 

group will have diminished power outputs simultaneously, thereby decreasing the capacity value of the group. On 

the other hand, negative correlations, such as those that frequently exist between nearby wind and PV plants, can 

increase the capacity value of the group as a whole.

57 For example, start times and ramp rates for conventional fossil energy and nuclear energy plants are used to 

determine the extent to which a generator can provide spinning and non-spinning reserves. 58 For many existing reserve-sharing groups, contingency reserves are normally based on the largest single 

contingency, such as the loss of a large nuclear or coal plant or a large transmission line. Because ReEDS is a linear 

program and is limited by computational time, the more simplistic treatment of 6% and 1.5% of demand are 

assumed for contingency and frequency, respectively.

59 Existing standards differ regionally.
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ReEDS simply assumes that five-sixths of the reserve requirement can be met by non-spinning 

reserves.60

Though the above reserve requirements are primarily focused on ensuring a supply-demand 

balance when unforeseen or uncontrollable events lead to a reduction in electricity generation (or 

increase in load), the opposite scenario of over-generation is also important, especially from an 

economic point of view. Because wind and PV are sources of power that are generally not tightly 

constrained by minimum-output-level or ramp-down restrictions, electricity generation from 

these plants is likely first to be curtailed in over-generation conditions (e.g., high wind, low 

demand), and ReEDS estimates the level of that curtailment. Similar to forecast error reserve 

requirements and capacity values, curtailment is calculated statistically in ReEDS at the 21-RSG 

regional level. These statistically calculated curtailment values are used in the national 

investment and dispatch decision in ReEDS. Specifically, the curtailment calculation can be 

thought of structurally as the opposite of the statistical LOLP calculation (the LOLP calculation 

accounts for minimum generation requirements of thermal units, the presence or absence of 

storage, and correlations in output of resources serving each RSG).

28.2 The GridView Model

GridView is a production cost model that simulates the unit commitment and economic dispatch 

of an electric power system. For RE Futures, the electric power system as modeled by ReEDS 

for the Low-Demand Baseline and a subset of the core 80% RE scenarios in 2050 was simulated 

in GridView.61 A suite of assumptions (as described in Volume 1) was used to import the electric 

power system infrastructure modeled by ReEDS in aggregate terms into specific units for the 

production cost modeling. The GridView model captures the same electric system operational 

aspects as described above in the ReEDS model. However, primarily due to its finer temporal 

resolution (hourly), GridView is able to capture the additional features described below.

Although GridView is a nodal model with approximately 65,000 buses representing the electric 

power system, several simplifying assumptions were required in order to match the spatial 

resolution of the ReEDS model and produce reasonable run times. Demand is balanced at each 

bus, but transmission constraints are only enforced across interfaces between different ReEDS 

BAs. This keeps the ReEDS and GridView models consistent and eliminates the need to 

optimize the placement of every individual renewable generator on the transmission network. 

GridView considers DC power flow constraints, whereas ReEDS follows a more simplified 

transportation model.

For RE Futures, GridView balanced operating reserves at the same RSG-level as ReEDS did (as 

described above). Operating reserve requirements were estimated using the methodology for the 

Eastern Wind Integration and Transmission Study, described in detail by Ela et al. (2010). Thus, 

for GridView, this method takes into account the additional frequency regulation that would be 

 

60 Reserves for forecast errors have not been widely put into practice, and further work is needed to identify the 

necessary characteristics for reserve providers.

61 Conversely, walking GridView through time from the present to 2050, as was done for ReEDS, was not possible 

due to the different nature of the models and due to the computational demands this would have imposed. Thus, 

ReEDS was used to determine the least-cost evolution of the system under the various high-penetration renewable 

electricity constraints from the present to 2050 in 2-year steps, while GridView was used to conduct the detailed 

hourly simulation of the system in 2050 to determine its operation and performance.
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required with additional penetration of wind and solar energy (as opposed to the ReEDS 

treatment where frequency regulation reserves are independent of variable generation 

penetration), based on the hourly and 10-minute changes of the wind and solar input profiles. 

GridView enforces constraints for two types of operating reserves: spinning and non-spinning 

reserves. All variability at frequency regulation timescales (e.g., less than 10 minutes) is required 

to be online (i.e., spinning). Variability in wind and solar output at timescales between 10 

minutes and 1 hour contributes equally to both the spinning and non-spinning reserve 

requirements. Contingency reserves are assumed to be 6% of demand to match the ReEDS 

assumptions, and split equally between spinning and non-spinning. 

Curtailment in GridView is based solely on minimizing production cost. There is no annual 

constraint in the hourly commitment and dispatch decisions to require any renewable generation. 

For details on GridView, see Feng et al. (2002). For more details on and the assumptions for RE 

Futures, such as application of production tax credits, see Volume 1.

A full reliability assessment of the contiguous United States in 2050 with 80% renewable 

generation was not attempted due to the detailed regional and local modeling requirements. The 

ReEDS and GridView models used for RE Futures use simplifying assumptions to balance 

demand at aggregate and hourly timescales, respectively. Although simplified model constraints 

have been applied that require RSGs to carry sufficient capacity to respond quickly to 

contingencies, future work is needed to ensure the full reliability of the electric power system at 

sub-hourly timescales in high-renewable generation scenarios.
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Summary and Conclusions

Today’s power system has evolved over the past 130 years from isolated, distributed power 

plants that serviced local load into three large regionally interconnected systems in the 

contiguous United States and Canada. Traditionally, the resource adequacy of the system has 

been based on dispatchable generation under the control of system operators. In addition, with 

the notable exception of hydroelectric generation, location-constrained resources have not been 

used. Maintaining balance between demand and generation at all times is a fundamental need. 

Additionally, system frequency and voltages must be maintained within defined, extremely tight 

tolerances. Initial studies examining the feasibility of a project are normally followed by more 

detailed, reliability-focused studies. RE Futures is an initial analysis that requires follow-up 

studies to analyze in greater detail how the power system will operate to ensure reliability of the 

bulk power system. 

Renewable electricity is available from a very diverse set of resources and technologies. Some 

are dispatchable, and others—primarily wind and solar PV technologies—are generally nondispatchable in that system operators can curtail output but cannot increase it if the wind or solar 

resource is not available. Both wind and solar PV technologies present challenges to power 

system operators, owing to variability and uncertainty of their generation output on the 

timescales relevant to the task of maintaining system reliability. However, generation from these 

variable renewable resources is being added to the electric system now. In particular, wind 

generation is expanding rapidly in some regions of the United States. As a result, significant 

operational challenges are emerging, including curtailment resulting from transmission and 

minimum generation constraints, relatively rare rapid ramps in wind generation resulting from 

passage of large footprint storm fronts, and increased need for operational reserves due to 

uncertainty of generation output. Of course, electricity demand also varies and is uncertain, but 

its behavior is generally well understood based on decades of experience and the developed 

ability to forecast load with reasonable accuracy a day in advance.

Revised operating procedures and strategies are needed—and are being adopted —to 

accommodate the characteristics of variable generation. Actual operating experience to date 

indicates that it is technically feasible to operate an electric power system with wind energy 

penetrations of 10%–20% of energy generated, albeit with changes in current operational 

practice to provide increased flexibility and expanded cooperation over longer distances.62

However, operating challenges are leading to curtailment of wind plant outputs during periods of 

low system demand or transmission congestion. In addition, in some regions, LMPs for 

electricity have sometimes fallen to values too low to sustain either variable or conventional 

generation over the mid- to longer term. It is becoming clear that not only must operating 

procedures evolve to better accommodate variable resources, but also market transformation 

must ensure appropriate payments for needed energy, capacity, and ancillary services. RE 

Futures explores some of the operational implications of very high levels of renewable 

generation (up to 80% renewable generation by 2050). 

In many cases, more cost-effective, higher-quality renewable resources are located far from 

major load centers. Expansion of the electrical transmission system is needed to access and 

 

62 See Cochran et al. (2012) for an international perspective.
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deliver location-constrained renewable resources. Typically, transmission costs averaged across 

the United States constitute only approximately 10% of the final delivered cost of electricity and 

are responsible for a relatively small portion of the investment needed to bring energy from a 

remotely sited generator to load. However, siting and permitting of transmission, particularly 

lines spanning multiple jurisdictions, is a challenging and lengthy process. 

Future transmission planning needs to be done proactively, looking many (20–40) years into the 

future, to pursue a broad range of long-term goals, including: 

• Maintaining system reliability

• Ensuring adequate dynamic power transfer capability 

• Ensuring just and reasonable rates 

• Providing access to the most cost-effective renewable (and other) resources

• Electrifying transportation

• Supporting functional electricity markets by minimizing congestion 

• Planning for future transmission corridor capacity needs, not just those immediately 

apparent

• Considering all options, including extra-high-voltage AC and DC, and technology 

advances such as superconductors and “undergrounding” 

• Ensuring non-wire options are fully considered (e.g., efficiency and local distributed 

generation) 

• Minimizing local, regional, and global environmental impacts, including reduced 

emissions of greenhouse gases, criteria pollutants, mercury, and other harmful 

pollutants. 

All of these goals are driven by the need to optimize societal benefits of the power system 

relative to costs incurred.

In addition to transmission, greater operational flexibility will be needed to support high levels of 

renewable generation. Means to provide this include the following options, some of which are 

already emerging in practice:

• Enhanced balancing authority cooperation, coordination, or consolidation (as has 

occurred in Texas, PJM, and MISO) 

• More efficient markets with shorter clearing periods, down to 5–10 minutes (as is the 

case already in MISO, PJM, and other regions) 

• New ancillary service markets covering a wider range of needs (e.g., flexibility—

faster ramp rates) beyond regulation and reserves markets already operating in much 

of the United States

• Unit commitment adjustments within the day

• New conventional generation technologies or modifications to existing generators 

that allow faster ramp rates, lower minimum output levels, quicker start times and 

shorter minimum-off times
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• Improved wind and solar forecasting—along with efficient use of forecasts (as is now 

occurring in many regions) 

• Increased connectivity among neighboring and distant regions 

• Expanded electricity flow across the Eastern, Western, and ERCOT Interconnections 

• Increased use of demand response (as is occurring now in PJM, ERCOT, California, 

and other regions)

• New, manageable electrical loads such as electric vehicle charging

• Increased use of storage options. 

As described in Volume 1, RE Futures has found that at the hourly simulation level and for the 

cases examined, the system can meet projected loads with high levels of renewable electricity, 

including high levels of variable renewable generation. However, the investigation of system 

reliability—which requires detailed analysis down through the level of a few minutes to a few 

seconds and the investigation of system security (e.g., through stability and AC power flow 

analysis) for these high levels of renewable generation—remains to be done. As indicated in this 

volume, additional studies and experience are needed to examine in more detail, particularly at 

the sub-hourly level, the quantitative impacts of high renewable generation futures and then 

validate the measures suggested for addressing the electric power system operating challenges 

arising from these impacts. 

Additional Research and Analysis Needed

RE Futures examined long-term planning issues, including transmission and generation issues 

stemming from operation of the electric power system with renewable energy penetrations of 

80% and higher. The modeling was done with a standard industry production simulation model 

that runs on an hourly time step, observing transmission constraints, minimum up-times and 

downtimes, minimum turndown levels, and unit ramp rates. The model performs economic unit 

commitment and economic dispatch, based on an optimization that meets load and reserve 

obligation at minimum cost, subject to various constraints on the system. However, more work 

must be done to ensure the reliable operation of a system, including the following activities, 

listed by category: 

• Data Development

o Acquiring more detailed data on the output of variable and renewable 

resources over large footprints and the correlation of these resources with 

load. To provide good statistics, years of data are desired, as are new 

techniques for scaling limited data

• Model Development 

o Developing true stochastic planning and operations tools and models that can 

better address the increased stochastic nature of high penetration levels of

variable generation 

o Developing detailed dynamic models of current and anticipated load to marry 

with improved and detailed models of supply technologies

o Improving understanding and developing better models of the operation of 

conventional power generation technology operating with greater demands on 
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ramp rates and minimum turndown levels; also needed are approaches to 

retrofit high ramp rates and minimum turndown levels into existing plants as 

well as develop new fossil energy and nuclear energy units with improved 

flexibility

o Developing improved models for forecasting day-ahead and hourly 

performance of weather-dependent variable renewable resources, as well as 

longer-range forecasts, and incorporation of these models into system 

operations 

• Analysis 

o Conducting sub-hourly feasibility analyses under a wide variety of conditions, 

including the impact of potential changing weather patterns. 

o Studying interconnection-wide power system dynamics and system reliability 

and stability under high renewable generation scenarios, with variable and 

renewable resource models that have frequency and inertial response built into 

their representation of control systems; the same studies need to include 

HVDC lines with full converter control capability

o Understanding the potential impacts of balancing authority consolidation 

(and/or seamless coordination) on system reliability, economics, and access to 

remote resources

o Assessing required evolution of methodology to identify appropriateness and 

accuracy of required resource reliability standards

• Market, Business Model, and Regulatory Practice Evolution 

o Addressing technical and institutional issues to permit sub-hourly scheduling 

to access the flexibility of the markets so that regulation, the most expensive 

ancillary service, does not have to be relied on to balance within the hour 

o Conducting research on market changes that may be needed to deal with 

generation that has near-zero marginal costs

o Exploring alternative business models and regulatory practices for 

transmission planning, siting, and permitting to enable necessary and 

economic development of transmission; a particularly important issue to 

explore is methods to improve collaboration for the planning, siting, 

permitting and cost allocation of transmission lines that cross multiple states.

RE Futures provides a foundation for future studies that explore further the various sensitivities 

and scenarios associated with renewable electricity that could impact the electricity sector’s 

future. This analysis of bulk power issues in high renewable electricity futures identifies the 

significant opportunities that such futures open, the challenges that they pose, potential pathways 

to addressing these challenges, and future analytical needs to better understand and address them.
Renewable Electricity Futures Study 

Volume 4: Bulk Electric Power Systems—Operations and Transmission Planning

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