Acknowledgements

This work was conducted under subcontract to the National Renewable Energy Laboratory. The NREL 

project managers, Jeff Hein, Lynn Coles, and Kara Clark made major contributions to improve the quality 

of the report and bring it to final publication. The NREL Communications Group and its subcontractor,

PWT Communications, LLC, provided editing support for final production. The authors are solely 

responsible for any omissions or errors contained herein.

NOTICE

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makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, 

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that its use would not infringe privately owned rights. Reference herein to any specific commercial 

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constitute or imply its endorsement, recommendation, or favoring by the United States government or any 

agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect 

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iii

Abbreviations

°C degrees Celsius

AC alternating current

ACCC aluminum conductor carbon composite 

ACCR aluminum conductor composite reinforced

ACSR aluminum conductor steel reinforced

ACSS aluminum conductor steel supported

AEP American Electric Power

ATC available transfer capability

BPA Bonneville Power Administration 

CAES compressed air energy storage

CAISO California Independent System Operator

CBM Capacity Benefit Margin

CFT conditional firm transmission

CSC convertible static compensator

DC direct current

DOE U. S. Department of Energy

EPAct Energy Policy Act

EPRI Electric Power Research Institute

ERCOT Electric Reliability Council of Texas 

ERO Electric Reliability Organization

FACTS flexible alternating current transmission system

FERC Federal Energy Regulatory Commission

FPA Federal Power Administration

FRCC Florida Reliability Coordinating Council 

HTLS high-temperature low-sag 

HVDC high-voltage direct current

Hz hertz

IDC Interchange Distribution Calculator

IEEE Institute of Electrical and Electronics Engineers

IGBT insulated gate bipolar transistor 

IPFC interline power flow controller 
iv

ISO Independent System Operator

ISO-NE New England Independent System Operator

kWh kilowatt-hours

kV kilovolts

LMP locational marginal price

m meters

m/s meters per second

mph miles per hour

MISO Midwest Independent System Operator

MRO Midwest Reliability Organization

MVA megavolt amperes

MVAR megavolt-ampere reactive

MW megawatts

NAESB North American Energy Standard Board

NAPSIC North American Power Systems Interconnection Committee

NERC North American Electric Reliability Council (prior to January 1, 2007)

NERC National Electric Reliability Corporation (after January 1, 2007)

NPCC Northeast Power Coordinating Council

NYISO New York Independent System Operator

NYPA New York Power Authority

NYSRC New York State Reliability Council

OASIS Open Access Same-Time Information Systems

OATT open access transmission tariff 

PMU phasor measurement unit

PUC public utility commission

PURPA Public Utility Regulatory Policy Act 

PST phase shifting transformer

RFC Reliability First Corporation

RTO Regional Transmission Organization

SIL surge impedance loading

SPP Southwest Power Pool

SSSC series static synchronous compensator

STATCOM static synchronous compensator
v

STEP SPP Transmission Expansion Plan

SVC static VAR compensator

TCSC thyristor controlled series capacitor

TLR Transmission Loading Relief

TOP Transmission Operator

TPSC thyristor protected series capacitor

TRM Transmission Reliability Margin

TTC total transfer capability

UPFC unified power factor controller

VAR volt-ampere reactive

WAPA Western Area Power Administration

WECC Western Electricity Coordinating Council

Wh watt-hour
vi

Executive Summary

In order to more fully integrate renewable resources, such as wind and solar, into the 

transmission system, additional capacity must be realized in the short term using the installed 

transmission capacity that exists today. The U.S. Department of Energy (DOE) and the National 

Renewable Energy Laboratory Transmission and Grid Integration Group supported this study to 

assemble the history of regulations and status of transmission technology to expand existing grid 

capacity.

This report compiles data on various transmission technology methods and upgrades for 

increased capacity utilization of the existing transmission system and transmission corridors. The 

report discusses the technical merit of each method and explains how the method could be 

applied within the current regulatory structure to increase existing transmission conductor and/or 

corridor capacity. 

The history and current state of alternatives to new construction is presented for regulators, 

legislators, and other policy makers wrestling with issues surrounding integration of variable 

generation. Current regulations are assessed for opportunities to change them to promote grid 

expansion. To support consideration of these alternatives for expanding grid capacity, the report 

lists relevant rules, standards, and policy changes. 

Background

Integrating significant levels of variable renewable generation into the nation’s transmission 

system will require changes to utility operating procedures, energy market structures, and the 

conventional generation portfolio. It may require expansion of the existing transmission system, 

which is also strained by continued load growth. However, expanding the grid is no simple task. 

Lead times of 7–10 years are required to secure new rights-of-way and to permit, design, and 

construct new transmission. As a result, it will be very useful in the short run to improve

transmission capability of the current transmission grid and develop methods for incremental 

capacity additions on existing rights-of-way.

U.S. Grid Interconnection Structure

The U.S. power grid is not a monolithic structure. It is a complex assembly of interconnections, 

regional entities, and balancing authorities. The electric power grid of the continental United 

States is divided into three asynchronous interconnections commonly known as the Eastern 

Interconnection, Western Interconnection, and Electric Reliability Council of Texas (ERCOT) 

Interconnection. To maintain reliability of the U.S. electrical system, eight regional entities as 

shown in Figure 1 work with the National Electric Reliability Corporation (NERC)1

— the 

electric reliability organization approved by the Federal Energy Regulatory Commission 

(FERC).2 The regional entities are permitted to enact standards that are more stringent than those 

enacted by NERC, but they are not permitted to relax or enact standards less stringent than 

NERC standards.

 1

NERC website: http://www.nerc.com/; NERC glossary: 

http://www.nerc.com/files/Glossary_of_Terms_2010April20.pdf 2

FERC information: http://www.ferc.gov/about/about.asp;

http://www.ferc.gov/legal/maj-ord-reg.asp
vii

Figure 1. NERC interconnection3

Trends and Current Situation

A long history (detailed in Chapter 1) has brought the U.S. power system to its current set of 

operating procedures and regulations. Restructuring of the electricity market, mandatory 

reliability standards, replacing existing generation with renewable resources, and introducing 

competition have all served to change the way transmission is developed and operated in the 

United States. When conventional, dispatchable generation resources, such as coal and gas, are 

replaced by renewable resources, such as wind and solar energy, utilization of transmission 

capacity becomes more complicated. Often, these new generation resources are not at the same 

location as retired resources. Presently, transmission networks are fully or nearly fully subscribed 

in some parts of the grid, and are not fully subscribed in others. The variability of renewable 

resources further suggests that real-time dispatch of transmission capacity would be more 

efficient.4

Research has been conducted on methods to increase utilization of transmission resources by the 

Electric Power Research Institute5 (EPRI), Western Area Power Administration (WAPA), 

Western Governors Association,6 the State of Wyoming,7 west-wide Seams Steering Group –

Western Interconnection,

8 and the National Wind Coordinating Collaborative. 

 3 This image from the North American Electric Reliability Corporation’s website is the property of the North 

American Electric Reliability Corporation and is available at 

http://www.nerc.com/fileUploads/File/AboutNERC/maps/NERC_Interconnections_Color_072512.jpg. This content 

may not be reproduced in whole or any part without the prior express written permission of the North American 

Electric Reliability Corporation. Accessed August 2012. 4 Independent Electricity System Operators (2010) “Integrating Renewable Resources – Design Principals,” Ontario, 

Canada, http://www.ieso.ca/imoweb/pubs/consult/se91/se91-20101209-

Renewables_Integration_Design_Principles.pdf. Accessed August 2012. 5 “Efficient Transmission Systems Program 172.” (2012). 2012 Research Portfolio. Electric Power Research 

Institute, Palo Alto, CA. http://portfolio.epri.com/ProgramTab.aspx?sId=PDU&rId=201&pId=6310. Accessed 

August 2012.

6 Western Governors Association. (2006). “Clean Energy, a Strong Economy, and a Healthy Environment.” 

http://www.swenergy.org/news/news/documents/file/CDEAC06.pdf. Accessed August 2012.
viii

The results of these and other work discussed in this report lead to the following key findings.

Key Findings

Changes in Policy and Standards

• A relaxation of the separation distance that results in reduced ratings for parallel lines 

could increase the ratings of existing circuits. The Western Electricity Coordinating 

Council (WECC) that represents the Western Interconnect of North America has 

extended the NERC standards for multiple circuits to include those that are not on a 

common structure but are within a span length of each other.

• Replacing physical transmission rights with financial transmission rights could ensure 

efficient use of the transmission system during times of constraint due to congestion. 

FERC Order 2000 required Regional Transmission Organizations (RTOs) to establish 

market-based congestion management to improve the utilization of the grid and to 

allocate the cost of congestion to those users who were willing to pay the price. 

• Implementing conditional firm transmission (CFT) and redispatch as a bridge between 

physical firm transmission and market-based transmission congestion management could 

increase utilization of the grid during certain periods. CFT provides transmission users 

access to selected transmission paths on a firm basis except during periodic constrained 

periods. Extending this practice allows increased use of the transmission system when 

conventional firm transmission is not available, but when the system is not actually 

constrained.

• Allowing redispatch (at some defined cost) when transmission paths are constrained

could allow transmission customers to pay the cost of redispatch or forgo use of the 

transmission. Redispatch also provides a price signal that can be used to make economic 

decisions regarding the value of increasing transmission capability on selected paths.

Redispatch provides many of the same benefits as market-based congestion management 

without having a formal congestion management system in place.

• Offering to redispatch the output of generators could provide long-term firm service to 

transmission customers and allow for new renewable energy projects to be financed. 

Providers could publish dynamic, real-time values for what they would charge to provide 

redispatch service, at specified congested locations within the transmission provider’s 

system, and at specified flowgates at the border of the transmission provider’s system.9

The flow is at a maximum level during a very small percentage of the time and varies 

over the course of a year. 

 7 State of Wyoming. (2004). “Rocky Mountain Area Transmission Study.” http://psc.state.wy.us/rmats/rmats.htm. 

Accessed August 2012. 8 Western Governors Association. (2002). “Scope of SSG-WI Working Group.”

http://www.westgov.org/wieb/meetings/crepcsprg2002/briefing%20materials/ssg-wi_031902_scope.htm. Accessed 

August 2012.

9 Furman, Don and McIntire, Natalie. (undated). “New Transmission Projects Can Benefit Wind.” National Wind 

Coordinating Collaborative. http://old.nationalwind.org/events/webinar/Webinar_Presentation.pdf. Accessed August 

2012.
ix

• Implementing transmission redispatch can increase transmission sales by reducing 

congestion, which otherwise would limit sales. Transmission redispatch resolves

transmission congestion by changing generator output levels to reduce congestion. 

Redispatch is included as part of market-based congestion management, but in areas 

without markets, redispatch is often not implemented because it results in the reduction of 

selected generators that may impact revenue.

• Incorporating a redispatch process that includes a locational imbalance price reflects a 

congestion component that addresses the real-time imbalance market. An energy 

imbalance system would bridge the gap between a simple redispatch process and a full 

market-based congestion management system.

• Expanding the use of incentive rates to accommodate alternatives to building new 

transmission could be an important next step for FERC’s incentive-based rate treatments 

for transmission of electric energy in interstate commerce. Including new technologies 

could also increase transmission capability without building new facilities.

• Establishing parity between generation resources and demand response would reduce 

energy costs and provide potential benefits to transmission. The magnitude of these 

benefits depends on the location of the demand response. 

• Recognizing the benefits of new technologies in regulations could increase the capability 

of the existing grid without adding additional transmission lines. These technologies 

include energy storage, which could benefit the grid, including generation, transmission, 

and distribution. Incentives would require rule changes that recognize the unique 

operating characteristics and potential benefits of the new technologies. For example, a 

proposed rule recognizes the benefits of fast regulation services and allows for 

compensation of facilities capable of providing fast regulation service. Energy storage 

facilities can provide fast regulation as well as damping and stability, issues that often 

require transmission additions to mitigate.

Technology Innovations

The introduction of new technologies, particularly technologies with the advances in power 

electronics, has produced a variety of devices that can be used to overcome limitations in 

transmission capability. Some of these devices can be used to improve system damping and 

voltage support, which can limit the total transfer capability. Other technologies and enhanced 

engineering designs increase the power carrying capability of individual transmission lines.

• Replacing the use of static seasonal thermal ratings on critical constrained transmission 

lines with either real-time or dynamic monitoring of ambient conditions could increase 

line rating and therefore transmission capacity.10

• Replacing conventional transmission line conductors with high-temperature low-sag 

(HTLS) conductors on existing transmission lines could increase the thermal rating by up 

to 50%. The HTLS conductor imposes less physical loading than equivalent larger 

conductors that can require reinforcement of transmission tower structures. 

 10 Douglass, Dale A. (1998). “Uprating Transmission Lines and Reducing Risk: Incremental uprating methods can 

be used to increase thermal line ratings.” Transmission and Distribution World, March 1, 1998.
x

• Increasing the operating voltage of the line and adopting compact line design principals 

can, under some conditions, mitigate thermal limits on transmission lines and help offset 

the added clearance requirements when the operating voltage is increased. Compact line 

design principles could offer some benefits during redesign, but overall costs to increase 

the operating voltage on a transmission line would be substantial. This option may be 

particularly attractive where compact line design principles could be applied to allow 

reconductoring of an existing line with minimal tower changes and within the existing 

right-of-way.

Increasing the capability of individual transmission lines can overcome thermal properties that 

limit power flow on individual circuits, but often the limitations are related more to system 

performance. These limitations are more effectively mitigated by adding devices to the system 

that enhance system damping and provide more effective voltage support through the use of 

power electronics. These devices are called flexible alternating current transmission system 

(FACTS) devices and are currently being used across the United States.

• Using static volt-ampere reactive (VAR) compensators (SVCs) can achieve more precise 

and quicker voltage support for both the steady-state and transient voltage stability of the 

transmission system than conventional methods. By controlling the reactive elements, 

system voltage profiles can be enhanced, and power transfer capabilities over individual 

lines, as well as groups of lines, can be accurately controlled, allowing better system 

performance and increased power transfer.

• Using static synchronous compensator (STATCOM) devices provides shunt-connected 

reactive-power compensation equipment capable of generating and/or absorbing reactive 

power. Both SVC and STATCOM devices provide voltage control (through reactive 

power support), allowing better system performance and increased power transfer.

• Employing series static synchronous compensators (SSSCs) provides an adjustable 

synchronous component series connected with a transmission line to vary the effective 

impedance of the transmission line. This increases power transmission capability, 

improves system stability, reduces system losses, reduces voltage drop, and optimizes 

(balanced) power flow along parallel lines.

• Using the unified power flow controller (UPFC) controls power flow for a single line. By 

directly controlling power flow, these devices increase line power transfer, improve 

voltage stability, and enhance rotor angle/system frequency stability.

• Using the interline power flow controller (IPFC) compensates and controls true power 

flow for multiple lines. These devices provide three of the system benefits including line 

increased power transfer, improved voltage stability, and enhanced rotor angle/system 

frequency stability.

• Using thyristor controlled series capacitor (TCSC) devices provides continuous and 

rapidly variable series compensation. Series compensation increases the power flow on a 

circuit by reducing the series impedance between the sending end and the receiving end. 

TCSCs also provide power flow control by altering the series impedance.
xi

High-voltage direct current (HVDC), which can enhance the capability of existing transmission, 

has gained broad acceptance and is used in multiple locations in the United States and Canada. 11

• Using HVDC overhead transmission lines requires less right-of-way for the corridor than 

an alternating current (AC) transmission system of the same power transfer level. In some 

cases, it is feasible to convert an existing transmission line to HVDC to realize increased 

power flow for the same amount of right-of-way. 

• Using HVDC in terminal equipment can overcome system stability issues to interconnect 

two AC systems. These back-to-back HVDC links can provide the required system 

damping to improve performance of the transmission system and allow higher levels of 

transfer between the two systems.

• Using HVDC lines for interconnecting two AC grids allows power to be scheduled over 

HVDC lines in much the same way that power can be scheduled from a generator. HVDC 

interties also can act as shock absorbers by injecting and extracting energy quickly from 

the connected AC grids, improving system performance and potentially allowing higher 

levels of power transfer over the grid.

Mechanical power devices have a history of providing improved system performance:

• Phase shifters, also known as phase shifting transformers (PSTs),12 mechanically

switched electromagnetic devices similar to conventional transformers, are introduced in 

an existing transmission line to allow the transmission operator to control the power flow 

through the line. The flow through heavily congested lines can be reduced and shifted to 

transmission lines with spare capacity. PSTs are less expensive than new transmission

lines. They can often be placed in an existing substation, making them easier to permit. 

• The maximum power transfer through an overhead transmission line is dependent on the 

line impedance, among other parameters. The impedance is inductive and can be reduced 

by connecting a capacitor in series. The capacitor can be installed in an existing 

substation or may be installed at a discreet point along the line. The localized nature of 

series capacitors and their modest cost is often preferred over building additional 

transmission.

Opportunities to increase overall utilization of the transmission system can result from better 

monitoring and control. Much of this could be categorized under the Smart Grid banner. Realtime monitoring provides a clearer picture of the state of the grid and allows operators to increase 

transfer across critical interfaces when stability and voltage margins are not compromised. This 

allows dynamic ratings for lines that are stability or voltage limited. While dynamic rating of the 

line may not increase firm transmission capacity, it may allow operators to schedule transmission 

circuits for non-firm transfer that might otherwise be subject to static limits.

Current efforts at real-time monitoring include the following:

 11 Bahrman, Michael. (2006). “Rapid City DC Tie,” IEEE PSCE Atlanta. December 10, 2006. 

http://www.ieee.org/portal/cms_docs_pes/pes/subpages/meetings-folder/PSCE/PSCE06/panel18/Panel-18-

6_The_Rapid_City_Tie.pdf. Accessed August 2012. 12 “Power Flow Control with Phase Shifting Transformers.” (2010). ABB. 

http://www05.abb.com/global/scot/scot252.nsf/veritydisplay/023c7e3532a30cb885257776004a6992/$File/1ZDEAB

B1619_en_Phase_shifting_transformers.pdf. Accessed August 2012.
xii

• Real-time transmission temperature/sag to implement dynamic line rating

• Phasor measurement units (PMUs) to provide direct state measurements

• Improved supervisory control and data acquisition systems to accept and process realtime information flow from remote monitors.

Real-time monitoring provides system operators with an important tool to optimally dispatch the 

system and maximize the available transmission capacity. By using real-time system 

information, operators can balance the non-dispatchable nature of wind and solar resources with 

dispatchable resources to maximize the available transmission capacity.

Energy storage devices offer the potential to increase individual transmission capability; 

although, their primary emphasis has been to provide overall system benefits either through 

improved system dynamic performance or through energy price arbitrage. The range of 

capabilities and applications for energy storage facilities are based on their power rating and 

energy discharge capabilities.13,14

Summary of Techniques

The techniques for effective grid utilization highlighted in this report are presented in Table 1. 

The top row of the table identifies the typical transmission limitation issues. The potential 

solutions are listed in the left column. The X marks potential approaches to address the 

limitation. The table can be used as a checklist for investigating the latest advances aimed at a 

particular issue.

 13 “2020 Strategic Analysis of Energy Storage in California.” (2011) Public Interest Energy Research Program Final 

Project Report. Work performed by University of California, Berkeley School of Law; University of California, Los 

Angeles; University of California, San Diego. California Energy Commission: Sacramento, CA. 

http://www.energy.ca.gov/2011publications/CEC-500-2011-047/CEC-500-2011-047.pdf accessed August 2012. 14 Schainker, Robert. (2008). “Emerging Technologies to Increase the Penetration and Availability of Renewables.” 

Electric Power Research Institute: Palo Alto, CA http://www.energy.ca.gov/2008_energypolicy/documents/2008-07-

31_workshop/presentations/Energy_Storage-Schainker.pdf. Accessed August 2012.
xiii

Table 1. Techniques for Improving Utilization of the Grid

RIGHT OF 

WAY

UTILIZATION

UNUSED 

CAPACITY

THERMAL VOLTAGE STABILITY

POLICIES

Changes to WECC Reliability Criteria X X

Financial Congestion Management X

Conditional Firm Transmission (CFT) X

Transmission Investment Rule X X

Demand Resources (redispatch) X X X

Dynamic/Real Time Rating X

TECHNOLOGIES

High-Temp, Low-Sag (HTLS) 

Conductor X

Static VAR Compensator (SVC) X X

STATCOM X X

Series Static Synchronous 

Compensators (SSSC) X X

Unified Power Factor Control (UPFC) X X X

Independent Power Factor Controller 

(IPFC) X X X

Thyristor Controlled Series Capacitor 

(TCSC) X

High Voltage Direct Current 

Transmission (HVDC) X X

Back to Back HVDC Link X

System “shock absorbers” X

Phase shifting transformer (PST) X X

Series capacitors X X

Real-time monitoring X X X X

Energy Storage X X X X
xiv

Table of Contents

Executive Summary..................................................................................................................... vi

Background................................................................................................................................ vi

U.S. Grid Interconnection Structure ...................................................................................... vi

Trends and Current Situation................................................................................................ vii

Key Findings............................................................................................................................ viii

Changes in Policy and Standards......................................................................................... viii

Technology Innovations......................................................................................................... ix

Summary of Techniques....................................................................................................... xii

1.0 Introduction........................................................................................................................... 1

1.1 Background......................................................................................................................... 1

1.1.1 Regulation and Vertically Integrated Utilities ............................................................. 1

1.1.2 1937–1964: Technology Improvements and Regional Interconnection ...................... 2

1.1.3 1965–1969 Northeast Blackout and Regional Reliability............................................ 2

1.1.4 1970–1977: Environmental and Conservation Concerns; Department of Energy 

Organization Act..................................................................................................................... 3

1.1.5 1978: Public Utility Regulatory Policies Act............................................................... 4

1.1.6 1992: Energy Policies Act............................................................................................ 5

1.2 Deregulation and Restructuring.......................................................................................... 6

1.2.1 EPAct ........................................................................................................................... 6

1.2.2 FERC Order 888 (1996)............................................................................................... 6

1.2.3 FERC Order 889 (1996)............................................................................................... 7

1.2.4 FERC Order 2000 (2000)............................................................................................. 7

1.2.5 FERC Order 890 (2007)............................................................................................. 10

1.2.6 FERC Order 717 (2008)............................................................................................. 11

1.2.7 FERC Order 1000 (2011)........................................................................................... 12

1.3 Mandatory Reliability Standards...................................................................................... 12

1.4 Trends and Current Situation............................................................................................ 14

2.0 Expanding Existing Transmission Capacity – Operations, Policy, Rules..................... 15

2.1 Transmission Capability ................................................................................................... 15

2.1.1 Total Transfer Capability ........................................................................................... 15

2.1.2 Available Transfer Capability.................................................................................... 17

2.1.2.1 Transmission Reliability Margin .......................................................................... 18

2.1.3 Capacity Benefit Margin ............................................................................................ 18

2.1.3.1 Other Adjustments................................................................................................ 19

2.1.4 Planning Versus Operating Horizon .......................................................................... 19

2.2 Thermal Ratings and Estimated Capacity......................................................................... 20

2.3 Common Corridor Definitions.......................................................................................... 21

2.4 Congestion Management .................................................................................................. 22

2.4.1 Market-Based Congestion Management .................................................................... 22

2.4.2 Conditional Firm Transmission.................................................................................. 26

2.4.3 Redispatch .................................................................................................................. 26
xv

2.4.3.1 Operation of Redispatch ....................................................................................... 27

2.4.3.2 Cost of Redispatch................................................................................................ 27

2.5 FERC Transmission Investment Rule .............................................................................. 28

2.6 Demand Response ............................................................................................................ 29

2.7 Regulatory and Other Incentives to New Technologies................................................... 30

2.8 Opportunities .................................................................................................................... 30

3.0 Expanding Existing Transmission Capacity – Technology ............................................ 32

3.1 Fundamentals of Power Transfer Limits .......................................................................... 33

3.1.1 Surge Impedance Loading.......................................................................................... 33

3.1.2 Thermal Limits........................................................................................................... 34

3.1.3 System Limits............................................................................................................. 34

3.2 Increasing Thermal Limits................................................................................................ 35

3.2.1 Improved Transmission Structures ............................................................................ 35

3.2.2 Reconductoring .......................................................................................................... 36

3.2.3 Dynamic Circuit Ratings............................................................................................ 39

3.2.4 Voltage Uprating........................................................................................................ 40

4.0 Increasing System Limits................................................................................................... 42

4.1 Voltage and Stability Control ........................................................................................... 42

4.1.1 Stability Constraints................................................................................................... 42

4.1.2 FACTS Devices.......................................................................................................... 43

4.1.2.1 Static VAR Compensator ..................................................................................... 43

4.1.2.2 Static Synchronous Compensator......................................................................... 45

4.1.2.3 Series Static Synchronous Compensator .............................................................. 46

4.1.2.4 Unified Power Flow Controller / Interline Power Flow Controller...................... 48

4.1.2.5 Thyristor Controlled Series Capacitors ................................................................ 48

4.1.2.6 Comparing FACTS Devices................................................................................. 50

4.2 Power Flow Control.......................................................................................................... 50

4.2.1 FACTS Devices.......................................................................................................... 51

4.2.2 High-Voltage Direct Current Lines............................................................................ 51

4.2.2.1 HVDC Back-to Back Systems.............................................................................. 52

4.2.2.2 Segmentation and Grid Shock Absorbers............................................................. 53

4.2.3 Improved Real-Time Monitoring and Dispatch......................................................... 54

4.2.4 Phase Shifting Transformer........................................................................................ 55

4.2.5 Fixed Series Capacitors.............................................................................................. 56

4.3 Energy Storage.................................................................................................................. 56

4.3.1 Battery Systems.......................................................................................................... 58

4.3.2 Pumped Storage Hydro .............................................................................................. 59

4.3.3 Flywheel Energy Storage ........................................................................................... 59

4.3.4 Compressed Air Energy Storage ................................................................................ 60

4.3.5 Energy Storage Devices for Transmission Constraint Relief..................................... 60

4.4 Conceptual Benefits and Constraints of Increasing Transmission Capability.................. 61

4.4.1 Right-of-Way Widths................................................................................................. 61

4.4.2 Transmission Line Capacity and Cost........................................................................ 62

5.0 Research Efforts.................................................................................................................. 63
xvi

5.1 EPRI Transmission Efficiency Initiative .......................................................................... 63

5.2 Western Area Power Administration................................................................................ 63

5.3 Western Governors Clean and Diversified Energy Advisory Committee........................ 64

5.4 Rocky Mountain Area Transmission Study...................................................................... 66

6.0 Implementing Increased Line Ratings.............................................................................. 67

6.1 ISO/RTO Rating Process.................................................................................................. 67

6.2 Non-ISO/RTO Rating Processes ...................................................................................... 68

7.0 Summary of Results............................................................................................................ 71

7.1 Changes in Policy and Standards...................................................................................... 71

7.2 Technology ....................................................................................................................... 72

7.3 Overview of Techniques................................................................................................... 75

Appendix A: U.S. Electric Power Grid Structure.................................................................... 77

Interconnection and Regulatory Structures............................................................................... 77

NERC and Regional Entities .................................................................................................... 78

NERC.................................................................................................................................... 78

NERC History....................................................................................................................... 78

NERC Structure .................................................................................................................... 82

NERC Rules and Standards.................................................................................................. 83

Eastern Interconnection Transmission Loading Relief..................................................... 84

WECC Unscheduled Flow Mitigation.............................................................................. 84

Regional Entities....................................................................................................................... 85

Eastern Interconnection ........................................................................................................ 85

Northeast Power Coordinating Council................................................................................ 85

Midwest Reliability Organization......................................................................................... 86

Reliability First Corporation................................................................................................. 86

SERC Reliability Corporation .............................................................................................. 87

Florida Reliability Coordinating Council ............................................................................. 87

Southwest Power Pool .......................................................................................................... 87

Western Electricity Coordinating Council............................................................................ 87

Texas Regional Entity........................................................................................................... 88

Enforcement...................................................................................................................... 88

Enforcement of NERC Reliability Standards................................................................... 89

Enforcement of ERCOT Protocols................................................................................... 89

Redispatch ISOs and RTOs ...................................................................................................... 89

New York Independent System Operator............................................................................. 89

PJM Interconnection ............................................................................................................. 90

New England Independent System Operator........................................................................ 90

Midwest Independent Transmission System Operator ......................................................... 91

Southwest Power Pool .......................................................................................................... 91

California Independent System Operator.............................................................................. 92

Renewable Integration and Planning .................................................................................... 92

Interconnection of Renewables............................................................................................. 93

Transmission Access............................................................................................................. 93

Available Transfer Capacity Rating Methodology................................................................... 94
xvii

Balancing Authorities Not Under RTO/ISO Jurisdiction ......................................................... 94

Methods to Utilize Current Capacity ........................................................................................ 95

Comparison of ISO/RTO .......................................................................................................... 95

Appendix B: Additional Policy Details ..................................................................................... 97

Congestion Management .......................................................................................................... 97

System Assessment and Transmission Planning ...................................................................... 97

Long-Term System Assessment 10-year view ..................................................................... 97

Transmission Planning Process............................................................................................. 98

Available Transfer Capability................................................................................................... 98

Creditworthiness....................................................................................................................... 98

Energy and Generator Imbalances............................................................................................ 98

Transmission Credits for Integrated Facilities.......................................................................... 99

Transmission Capacity Reassignment ...................................................................................... 99

Changes to Long-Term Firm Point-to-Point Service – Redispatch and Conditional Firm....... 99

Rollovers................................................................................................................................. 100

Network Resources / Secondary Network Service ................................................................. 100

Integration of NERC and NAESB Standards ......................................................................... 101

Enforcement............................................................................................................................ 101

FERC Order 1000 ................................................................................................................... 101

FERC and the States ............................................................................................................... 103

ERCOT Protocols and Guides................................................................................................ 104

Additional Resources................................................................................................................ 105

List of Figures

Figure 1. NERC interconnection................................................................................................... vii

Figure 2. Interconnections of the U.S. Power Grid....................................................................... 13

Figure 3. Regional entities and balancing authorities................................................................... 13

Figure 4. Path rating and contingencies........................................................................................ 16

Figure 5. Total Transfer Capability changes with time ................................................................ 19

Figure 6. Available Transfer Capability operating versus planning horizon................................ 20

Figure 7. Dispatch and flows before congestion relief ................................................................. 23

Figure 8. Dispatch and transmission flows after redispatch to relieve congestion....................... 23

Figure 9. Post redispatch locational marginal prices.................................................................... 26

Figure 10. FACTS devices............................................................................................................ 44

Figure 11. SCCC electrical diagram............................................................................................. 47

Figure 12. TCSC and TPSC.......................................................................................................... 49

Figure 13. Back-to-back HVDC system configuration................................................................. 52

Figure 14. HVDC systems in North America............................................................................... 52

Figure 15. Maturity of energy storage technologies..................................................................... 58

Figure 16. PJM Interconnection planning process........................................................................ 68

Figure 17. WECC rating process.................................................................................................. 70

Figure 18. Regional entities and balancing authorities................................................................. 77
xviii

List of Tables

Table 1. Techniques for Improving Utilization of the Grid......................................................... xiii

Table 2. Impact of Assumptions on Thermal Line Rating............................................................ 21

Table 3. Locational Marginal Price Calculations ......................................................................... 25

Table 4. Cost of Congestion to Loads........................................................................................... 25

Table 5. Cost of Redispatch.......................................................................................................... 28

Table 6. Relative Cost of Reconductoring.................................................................................... 38

Table 7. EPRI-sponsored FACTS installations ............................................................................ 43

Table 8. SVCs versus STATCOMs.............................................................................................. 46

Table 9. Comparison of FACTS Devices..................................................................................... 50

Table 10. Relative Comparison of Benefits.................................................................................. 50

Table 11. Present Worth of 10-year Operation in Year 1 ($/kW) ................................................ 57

Table 12. Right-of-Way Width..................................................................................................... 62

Table 13. Typical Single Circuit Transmission Costs .................................................................. 62

Table 14. Summary of Benefits.................................................................................................... 76

Table 15. NERC History............................................................................................................... 79

Table 16. Comparison of Transmission Scheduling..................................................................... 84

Table 17. WECC Actions under Unscheduled Flow Mitigation .................................................. 85

Table 18. ISO/RTO Comparison .................................................................................................. 96

Table 19. Federal Regulation and State Regulation for the Electricity Industry........................ 103
1

1.0 Introduction

Continuing load growth and the integration of renewable energy sources is straining the U.S. 

transmission grid. Expanding the grid is costly and involves 7–10 years to secure new rights-ofway and to permit, design, and construct new transmission. Focused efforts toward improved 

utilization of the current transmission grid are under way and methods for incremental additions 

of capacity on existing rights-of-way are being explored.

This report presents information compiled from published reports, company and organizational 

websites, online seminars (i.e., webinars), conference proceedings, corporate operating manuals, 

and journal articles.

This chapter describes the regulatory history of the utility industry from 1910 through 2012. 

Chapter 2 lists rules, standards, and policy changes relevant to expanding existing transmission 

capacity. Chapter 3 explains the features of currently available technologies that offer 

alternatives to constructing new transmission. Chapter 4 presents some fundamental concepts 

about increase line capacity. Chapter 5 lists the results of recent analyses of the costs and 

benefits of policies and technologies to expand capacity on the existing grid. Chapter 6 lists 

organizations and projects exploring ways to expand grid capacity. Chapter 7 estimates the 

potential impact of various approaches. Appendices A and B provide detail on the U.S. power 

grid, its structure, and management. 

1.1 Background

1.1.1 Regulation and Vertically Integrated Utilities

During the first three decades of the 20th century, utilities saw tremendous growth and were able 

to charge their expanding customer base for all of the services they provided. Utility generation 

and transmission expanded dramatically from 5.9 million kWh in 1907 to 75.4 million kWh in 

1927. During this period, the delivered costs of electricity declined 55%. During the 1920s, 

utilities began to form holding companies that owned and controlled operating companies over 

large geographic regions. During this time, three holding companies controlled 45% of the U.S. 

electric utility industry. Under this interstate operating structure, holding companies were not 

subject to state-based regulatory commissions or federal oversight.15

In the 1930s, the federal government began to provide regulatory oversight and promote 

extending electricity to rural areas. The Public Utility Holding Company Act and the Federal 

Power Act were both passed in 1935 to regulate the industry at the state and federal level.16

Operating in a regulated, cost-based environment, utilities planned and built infrastructure to 

meet the needs of the customers they were obligated to serve. States regulated these companies 

because it was perceived as a lower cost approach to delivering electricity to customers than 

through market competition.

17 Electric utilities were under state public utility commission (PUC) 

 15 “Powering a Generation of Change 1997-2012.” (2012). National Museum of American History, Smithsonian 

Institution. http://www.americanhistory.si.edu/powering. Accessed August 2012. 16 National Library for the Environment. (1999). “RS20015: Electricity Restructuring Background: Public Utility 

Holding Company Act of 1935 (PUHCA).” CRS Report for Congress, January 7, 1999.

http://www.cnie.org/nle/crsreports/energy/eng-47.cfm. Accessed August 2012. 17 Concerning electric industry restructuring, see: Michaels, Robert J. (2006). “Vertical Integration and the 

Restructuring of the U. S. Electricity Industry.” CATO Institute, July 13, 2006.
2

oversight. They recovered their operating costs plus regulated profits (approximately 10%) 

through their approved service rates. As the demand for electricity grew, utilities could add to 

their system infrastructure with a guaranteed return on their investment. Utilities constructed 

generation facilities close to their customers to reduce costly system losses. 

Electric utilities were primarily under state PUC control since their activities remained 

predominantly intrastate in nature. PUCs reviewed every aspect of utility operation, from siting 

to service requirements, through final rate development. Each utility operated a control area for 

the area of the country it served (i.e., Commonwealth Edison’s control area was Chicago). 

Control areas matched electrical generation to load requirements and use.

1.1.2 1937–1964: Technology Improvements and Regional Interconnection

Improved technology allowed for larger, more efficient generating units. At the same time, 

transmission voltages increased to reduce system losses. Larger generating stations, located near 

their fuel supplies, were connected to high-voltage transmission lines and began replacing 

smaller generating stations connected to lower-voltage power sub-transmission/distribution lines.

The U.S. electric system changed from having many geographically small, locally operated grids 

to having interstate transmission lines interconnected to many different utility systems. This

increased interconnectivity at much higher voltages offered higher reliability and improved 

system economics continuing to reduce the cost of electricity. Each utility served its customers 

either with its own generation or through purchases with neighboring utilities. The practice was 

called wheeling and used contract path pricing. The individual control areas still played an 

important role in electricity sales to neighboring utilities. 

The Federal Power Act and individual state laws provided regulatory oversight. Reliability of the 

electric system was now both a regional and local concern.

1.1.3 1965–1969 Northeast Blackout and Regional Reliability

The great Northeast Blackout of 1965 uncovered a weakness in the U.S. and Canadian 

interconnected electric grid. One disturbance in one section of the grid caused a cascading effect 

that interrupted service over 80,000 square miles (eight states) in the Northeastern United States 

and in large parts of Canada. This blackout started with a single 345-kV transmission line

relaying failure near Toronto, Canada. As a result, the NERC was formed under the Electric 

Power Reliability Act in 1967.18

Today, NERC is responsible for overall reliability, planning, and coordination of electricity 

supply in North America. NERC is a non-profit agency comprised of 10 regional councils. The 

regional councils represented smaller regions of North America. Through this model, the North 

 

http://www.cato.org/pubs/pas/pa572.pdf. accessed August 2012. See also: 

http://www.eia.gov/cneaf/electricity/page/fact_sheets/restructuring.html

http://www1.eere.energy.gov/femp/pdfs/primer.pdf

18 For a discussion of the impact of blackouts on reliability regulations see: Hilt, David W. (2003). “Northeast 

Blackout Impacts and Actions and the Energy Policy Act of 2005.” 

http://www.nerc.com/docs/docs/blackout/ISPE%20Annual%20Conf%20-

%20August%2014%20Blackout%20EPA%20of%202005.pdf. Accessed August 2012.
3 

American interconnected electric power system became the most reliable system of its kind in 

the world. This is essentially how utilities operated before deregulation legislation began.19

1.1.4 1970–1977: Environmental and Conservation Concerns; Department of 

Energy Organization Act

The electric utility industry experienced difficult times in the 1970s. Utilities owned and 

operated large, central-station generating plants and high-voltage or extra-high-voltage 

transmission lines to deliver reliable electricity. However, prices of electricity quadrupled 

between 1970 and 1985. The causes for this increase included operational responses to 

environmental and conservation concerns, poor U.S. economic performance, inflation, and 

response to occupational safety concerns.

20 In 1970, the Clean Air Act21 forced substantial 

reductions in allowable emission levels (sulfur dioxide) from coal-fired power plants because of 

acid rain concerns. This was followed by the Water Pollution Control Act of 1972.22 Utilities 

responded to the requirements of these acts by reducing the output of the existing generating 

stations, thereby reducing the generation reserve capacity available to the interconnected power 

system. 

The Organization of the Petroleum Exporting Countries oil embargo of 1973 raised prices for oil 

used to generate electricity. The ensuing energy crisis also increased public awareness of 

conservation and energy efficiency issues in the United States. The Energy Supply & 

Environmental Coordination Act of 197423 required utilities to stop using natural gas or other 

petroleum-based products to generate electricity. The Resource Conservation & Recovery Act of 

1976,24 amendments to the 1970 Clean Air Act issued in 1977,25 the Power Plant & Industrial 

Fuel Use Act of 1978,26 and the National Energy Conservation Policy Act of 197827 all had the 

effect of reducing generating capacity at large power plants. 

 

19 “NERC Operating Manual.” (2010). North American Electricity Reliability Corporation. New Jersey. 

http://www.nerc.com/files/opman_12-13Mar08.pdf. Accessed August 2012. 20 “Powering a Generation of Change 1997-2012.” (2012). National Museum of American History, Smithsonian 

Institution. http://www.americanhistory.si.edu/powering. Accessed August 2012. 21 “History of the Clean Air Act, U. S. Environmental Protection Agency.” (2012). Environmental Protection 

Agency. http://www.epa.gov/air/caa/caa_history.html. Accessed August 2012. 22 “Water.” (undated). Environmental Protection Agency. 

http://www.epa.gov/aboutepa/history/topics/fwpca/05.html. Accessed August 2012. 23 “Method of Collecting Energy Information ESECA.” (2011). U.S. Government Printing Office. 

http://www.gpo.gov/fdsys/search/pagedetails.action;jsessionid=mNHyP6yDVQhgD40qTCvwkXq8zHkZ27fyvkpY

YCBsLJNwJW1pRbTV!1599065783!258410883?browsePath=Title+10%2FChapter+II%2FSubchapter+A%2FPart

+207%2FSubpart+A%2FSection+207.3&granuleId=CFR-2011-title10-vol3-sec207-3&packageId=CFR-2011-

title10-vol3&collapse=true&fromBrowse=true accessed. August 2012. 24 “Summary of the Resource Conservation and Recovery Act.” (1976). Environmental Protection Agency.

http://www.epa.gov/lawsregs/laws/rcra.html. Accessed August 2012. 25 “History of the Clean Air Act, U. S. Environmental Protection Agency.” (2012). Environmental Protection 

Agency. http://www.epa.gov/air/caa/caa_history.html. Accessed August 2012. 26 Kubiszewski, Ida. (2006). “Power Plant and Industrial Fuel Use Act of 1978, United States.” The Encyclopedia of 

Earth. http://www.eoearth.org/article/Powerplant_and_Industrial_Fuel_Use_Act_of_1978,_United_States. Accessed 

August 2012.

27 “Power Plant and Industrial Fuel Use Act.” (undated). U.S. Office of Electricity Delivery and Energy Reliability. 

U.S. Department of Energy. http://energy.gov/oe/electricity-policy-coordination-and-implementation/otherregulatory-efforts/power-plant-and. Accessed August 2012. 
4

In this environment, several federal agencies were created by the Department of Energy 

Organization Act in 1977,28 including the DOE and FERC. FERC was given the jurisdictional 

authority assigned to the Federal Power Commission.

High inflation and economic recession resulted in very low or zero load growth for the utility 

sector. However, in response to earlier load growth projections, many large, central-station 

power plants were under construction. These coal and nuclear power plants were very costly and 

took years to build. The plant costs rose due to inflation, extended construction time due to 

occupational safety concerns, and meeting environmental regulatory requirements caused plant 

costs to rise. Once the plants were built, there was excess generation capacity reserve margins 

because loads had not increased as expected. The price of electricity increased dramatically 

between 1970 and 1985.29

1.1.5 1978: Public Utility Regulatory Policies Act30

The Public Utility Regulatory Policy Act31 (PURPA) was, in part, a response to high electric 

rates and perceived inefficiencies in the generation system. PURPA expanded participation of 

non-utility generators in the electricity market and demonstrated that electricity from non-utility 

generators could be integrated successfully with a utility’s own supply. PURPA introduced 

FERC-approved, non-utility generation called qualifying facilities. Utilities were required to 

purchase generation from the qualifying facilities. The Fuel Use Act of 1978 (repealed in 1987)32

also helped qualifying facilities become established. Under the Fuel Use Act of 1978, utilities 

were not allowed to use natural gas to fuel new generating technologies, but qualifying facilities,

which were by definition not utilities, were able to take advantage of abundant natural gas and 

abundant new technologies (such as combined-cycle). The new technologies lowered the 

financial threshold for entrance into the electricity generation business as well as shortened the 

lead time for constructing new plants. The additional capacity that the qualifying facilities 

supplied was relatively small due to limitations imposed upon them. Other PURPA provisions 

included the addition of sections 210, 211, and 212 to the Federal Power Administration (FPA),

which gave FERC authority over qualifying facilities interconnections and transmission 

wheeling.

The PURPA provisions stimulated development of cheaper and cleaner generation technology 

and made it possible to add them to the power system via qualifying facilities and independent 

power producers. PURPA began the process of deregulating the highly regulated, monopoly 

generation sector. The natural gas sector was being deregulated under FERC’s oversight, and 

some believed that the same deregulation could be applied to the generation sector. PURPA 

opened the wholesale power markets to non-utility producers of electricity, an activity which 

previous to that time was largely reserved for vertically integrated utilities. This allowed a 

certain degree of competition at the supply end of the electric power generation and delivery 

chain.

 28 “Department of Energy Organization Act.” (1977). U.S. Department of the Interior, Bureau of Reclamation. 

http://www.usbr.gov/power/legislation/doeorg.pdf. Accessed August 2012. 29 “History of the U.S. Electric Power Industry.” (2000). U.S. Energy Information Administration.

http://www.eia.gov/cneaf/electricity/chg_stru_update/appa.html. Accessed August 2012. 30 PURPA and Amendments: http://www.naruc.org/Publications/PURPA_Manual_webversion.pdf. 31 Holy Cross Energy. (undated). “PURPA.” http://www.holycross.com/member-services/purpa. Accessed August 

2012.

32 “Repeal of the Powerplant and Industrial Fuel Act.” (1987). U.S. Energy Information Administration. 

http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngmajorleg/repeal.html. Accessed August 2012.
5

Responding to regulatory uncertainty, utilities began to reduce costs related to generation, 

transmission, and distribution infrastructure. They reduced the labor force through layoffs and 

early retirements. As a result, generation reserve margins and transmission capacity reserves 

began to decline.

Between 1978 and 1987, other regulated industries in the United States began to be deregulated. 

These other industries included the airline industry in 197833 and telecommunications (e.g., 

AT&T) in 1984.34 Further deregulation efforts in the natural gas industry opened access to the 

pipelines and the spot market for price in 1986 and 1987. 

1.1.6 1992: Energy Policies Act35

The primary intent of the Energy Policies Act (EPAct) was to create open access to the 

transmission system for all generating companies, both utility and non-utility (qualifying 

facilities and independent power producers). While the act gave the FERC the power to order 

utilities to grant access to the transmission system, progress and the anticipated benefits were 

slow to be realized.36 EPAct provided FERC with approval of exempt wholesale generators37 and 

added Section 213 to the FPA.38 Exempt wholesale generators were allowed to sell electricity to 

the bulk power market, and Section 213 extended FERC oversight to transmission access issues. 

As a result, transmission tariff structures changed and open access tariffs had to be filed (with 

FERC) before access to wheeling contracts would be granted by FERC. In 1992, for the first 

time, generation added by non-utility generators exceeded that added by traditional utilities.

FERC received reports through 1995 of discrimination by vertically integrated utilities for access 

to the transmission system.39 In response, FERC issued several policy statements that 

transmission remained a natural monopoly and should be treated as such. These policy 

statements were the Comparability Standard,40 Stranded Cost Notice of Proposed Rulemaking,41

 33 “Airline Deregulation.” (undated). Avjobs, Inc. http://www.avjobs.com/history/airline-deregulation.asp. Accessed

August 2012.

34 “Powering a Generation: Understanding Deregulation.” (undated). Smithsonian Institution. 

http://americanhistory.si.edu/powering/dereg/dereg3.htm 35 “Energy Policy Act 1992.” (2009). U.S. Department of Energy, Energy Efficiency and Renewable Energy.

http://www1.eere.energy.gov/femp/regulations/epact1992.html. Accessed August 2012. 36 “Evolution of Markets and the Open Access Transmission Tariff.” (2011). Edison Electric Institute. 

http://www.eei.org/meetings/Meeting%20Documents/2011-08-01-TransmissionWholesaleMarketsSchool-Matt.pdf. 

Accessed August 2012. 37 “Examining the Impacts of the Energy Policy Act of 1992.” (1994). National Rural Electric Cooperative 

Association. http://www.thefreelibrary.com/Examining+the+impacts+of+the+Energy+Policy+Act+of+1992.-

a016497478. Accessed August 2012. 38 “Order No. 889.” (2010). Federal Energy Regulatory Commission. http://www.ferc.gov/legal/maj-ord-reg/landdocs/order889.asp. Accessed August 2012. 39 Ibid. 40 “Inquiry Concerning the Commission’s Pricing Policy for Transmission Services Provided by Public Utilities 

under the Federal Power Act, Docket No. RM93-19-001.” (1995). Federal Energy Regulatory Commission.

http://www.ferc.gov/legal/maj-ord-reg/land-docs/71_FERC_61195.pdf. Accessed August 2012. 41 “Order No. 888 Final Rule.” (1996). Federal Energy Regulatory Commission. https://www.ferc.gov/legal/majord-reg/land-docs/rm95-8-00w.txt. Accessed August 2012. 
6

Transmission Pricing Policy Statement, Pooling Notice of Inquiry,42 Regional Transmission 

Group Policy Statement,43 and Merger Policy.44

1.2 Deregulation and Restructuring

In 2012, the utility sector consists of a diverse group of entities. Some have preserved their 

identities as vertically integrated utilities, while other new players offer products and services 

that address parts of the electric power supply chain. Two primary factors for the move towards 

deregulation were large differences in the retail price of electricity and the need for technological 

advancement.45 Deregulation efforts apply to the generation sector at the national level. The 

transmission sector will still be regulated, while the distribution sector will be deregulated on a 

state-by-state basis.

1.2.1 EPAct 

The EPAct of 1992 opened the door for individual states to begin the process of deregulation, 

according to their own circumstances. Implementation guidelines were provided by FERC in 

Orders 88846 and 889.47 EPAct 2005 established the concept of a National Interest Electric 

Transmission Corridor in an effort to maintain momentum for siting new transmission. The act 

gave FERC limited siting authority for electric transmission facilities located in specific 

corridors designated by DOE.48 These were sites where a state has either denied or delayed, for 

at least 1 year, an application to construct a transmission facility within the corridor. 

1.2.2 FERC Order 888 (1996)

After passage of EPAct, FERC established rules by which open transmission would be achieved. 

Order 888 established standards of conduct concerning transmission access and treatment of 

transmission customers and rules to be followed to achieve open transmission objectives: 

• Require all jurisdictional utilities (within the United States) to file an open access 

transmission tariff (OATT)

• Require investor-owned utilities to functionally unbundle wholesale generation and 

power marketing from transmission services

• Create non-profit Independent System Operators (ISOs) and operating guidelines

 42 Hogan, William. (1995). “Electricity Transmission and Emerging Competition.” Harvard University, Florida. 

http://www.hks.harvard.edu/fs/whogan/purc0495.pdf. Accessed August 2012. 43 “FERC Laws and Orders.” (undated). Basin Electric Power Cooperative, North Dakota. 

http://www.basinelectric.com/Electricity/Transmission/Regulation/FERC_Laws_and_Orders/index.html. Accessed 

August 2012. 

44 “Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement ORDER 

NO. 592.” (1996). Federal Energy Regulatory Commission. http://www.ferc.gov/industries/electric/geninfo/mergers/rm96-6.pdf. Accessed August 2012. 45 “The Changing Structure of the Electric Power Industry: an Update” (1996). Energy Information Administration. 

http://www.eia.gov/FTPROOT/electricity/056296.pdf. Accessed August 2012. 46 “Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public 

Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities.” (2006). Federal Energy 

Regulatory Commission. http://www.ferc.gov/legal/maj-ord-reg/land-docs/order888.asp. Accessed August 2012. 47 “Open Access Same-Time Information System (formerly Real-Time Information Networks) and Standards of 

Conduct” (2005). Federal Energy Regulatory Commission. http://www.ferc.gov/legal/maj-ord-reg/landdocs/order889.asp. Accessed August 2012. 48 “National Interest Electric Transmission Corridors and Congestion Study Documents.” (undated). U.S. 

Department of Energy. http://nietc.anl.gov/documents/index.cfm. Accessed August 2012.
7

• Encourage reciprocity for non-jurisdictional (Canadian and Mexican) utilities

• Allow utilities to recover stranded costs

• Identify ancillary services and comparable services to properly operate the bulk power 

system

• Initiate Standards of Conduct

To meet these points, FERC required the functional separation of power schedulers and 

marketers and the transmission operations within vertically integrated utilities. 

EPAct created a new category of electricity producer, the exempt wholesale generator, and 

mandated that FERC open up the national electricity transmission system to wholesale suppliers 

on a case-by-case basis. The EPAct created a competitive wholesale framework that opened

transmission access to wholesale generators of power. Wholesale buyers of electricity, such as 

electric utilities, buy electricity at wholesale prices to sell it on a retail basis. Order 888 assured 

the exempt wholesale generators a way to transmit their power to their purchasers.

To support the deregulated operation of the generation sector, the transmission sector was 

restructured. Order 888 outlined 11 operational principles and guidelines for newly established, 

non-profit ISOs. Order 888 made ISOs responsible for operating the transmission system, Open 

Access Same-Time Information System (OASIS), generation dispatch (and queue), and certain 

control area power markets (generation and transmission). FERC asserted authority (upheld by 

the U.S. Supreme Court) over retail transmission service, including wholesale transmission 

(wheeling) and unbundled transmission as defined within Order 888.

1.2.3 FERC Order 889 (1996)

Order 889 further defined the independence of transmission by detailing how the newly 

emerging electricity markets should interact with transmission providers. Order 889 addressed 

the issue of access to transmission system information by all interested parties. It obliged 

transmission operators to implement OASIS, an internet-based system for obtaining 

transmission-related services, including the availability of transfer capacity on specific 

transmission paths in nearly real time. Order 889 made transmission system information

previously held exclusively by vertically integrated utilities available to all interested parties. 

1.2.4 FERC Order 2000 (2000)49

After operating under the provisions of Order 888 for several years, barriers to functional 

deregulation were addressed by Order 2000. Order 2000 was issued primarily to improve 

transmission operational efficiency, expand the transmission system, and open access to the 

transmission system. Other goals were to lower electricity prices and reduce regulation. FERC 

addressed transmission on a regional, multi-state scale because all states within an 

interconnection are impacted by disturbances within it, as evidenced by the Western 

interconnection disturbances in the summer of 1996.

50

To ensure that ISOs extend beyond state boundaries, FERC created RTOs. RTOs operate the 

transmission facilities for the transmission owners in RTO control areas, but they are larger than 

their ISO predecessors. The RTO guidelines were designed to prevent transmission system 

 49 FERC Order 2000. http://www.ferc.gov/legal/maj-ord-reg/land-docs/RM99-2A.pdf 50 “Disturbance Report” (1996). North American Energy Reliability Company.

http://www.nerc.com/docs/docs/pubs/AUG10FIN.pdf. Accessed August 2012.
8

discrimination. FERC-approved RTOs must meet at least the four characteristics and eight 

functions FERC identifies as required for proper RTO operation.

1. Independence: The RTO must be independent of market participants. An RTO’s 

independence is assured when none of its employees or non-stakeholder directors have a 

financial interest in any market participant.

2. Sufficient Scope and Regional Footprint: The RTO’s region must be large enough to 

support efficient and nondiscriminatory power markets. This requirement is demonstrated 

when the organization meets nine criteria:

• Has the ability to perform essential RTO functions

• Operates with a footprint that is one contiguous geographic area

• Operates a grid that is highly interconnected

• Has the ability to deter market power

• Recognizes existing trading patterns

• Accommodates existing regional boundaries, such as the NERC regions

• Encompasses existing regional transmission entities

• Encompasses existing control areas

• Respects international boundaries

3. Operational Authority: The RTO must have the authority to operate all of the 

transmission facilities under its control and must act as the security coordinator for the 

region.

4. Near-term Reliability: The RTO must have exclusive authority for maintaining the 

reliability of the transmission grid under its control up to the planning horizon.

In addition, the RTO must include the following services:

1. Tariff Administration and Design: The RTO will have sole responsibility over its own 

tariff and be the sole decision-making authority with respect to transmission services 

including new interconnections.

2. Congestion Management: The RTO will establish market mechanisms to manage 

transmission congestion. These mechanisms should provide price signals to transmission 

customers that reflect their transmission usage decisions.

3. Parallel Path Flow: The RTO must implement procedures to recognize and address the 

fact that power flows according to the laws of physics and power dispatched in one 

region may flow over the transmission grid into another region, potentially impacting the 

transmission capacity in the second region.

4. Ancillary Services: The RTO must ensure that the grid has sufficient ancillary services 

and must act as the provider of last resort, if necessary.

5. OASIS and Capability Calculations: The RTO should act as a single OASIS node in 

order to provide the necessary data so that transmission capability, whether calculated by 

the RTO or verified by the RTO, can be available to the transmission customers.
9

6. Market Monitoring: The RTO will submit to FERC a plan to ensure that the market is 

operating in a competitive fashion, that there are opportunities for efficiency 

improvements, and that there is sufficient oversight of the market participants.

7. Planning and Expansion: The RTO must develop a planning organization to oversee the 

grid development to ensure adequate capability and relieve congestion.

8. Interregional Coordination: The RTO will work with its neighbors to ensure reliable 

operating practices and efficient market interface among regions.

The ISOs already in operation also were required to prove they met the criteria to receive FERC 

approval. RTOs could be operated to earn a regulated profit for financing infrastructure 

expansion. FERC outlined a voluntary approach for transmission owners to hand over control of 

their facilities to an RTO of which they were a member. At or near this time, independent 

transmission companies began to appear. An independent transmission company is a collection 

of transmission owners combining to form one large transmission company (e.g., TRANSLink). 

FERC specified that independent transmission companies could participate within an RTO or 

form their own RTO. Therefore, an RTO could be a non-profit organization that was previously 

an ISO or it could be a regulated, for-profit transmission company. 

Order 2000 requires transmission owners to state whether they belong to an RTO or if they 

intend to join an RTO. If they are not planning to join an RTO, they must explain why they are 

not participating and present plans and a timetable for future efforts. The order requires each 

public utility that is a member of a transmission entity and meets the requirements under FERC 

Order 888 to explain the extent to which the entity meets the minimum requirements and how it 

functions as an RTO. If the entity is not an RTO, the utility must explain how the entity plans to 

become an RTO or explain why that is not reasonable. 

Under this scenario, FERC envisioned five RTOs for the entire U.S. transmission system—

Northeast, Southeast, Midwest, Texas, and the entire Western Interconnection. Nine proposed 

RTOs were approved, each with its own operating rules. The result was a problem referred to as

RTO boundaries or seams. Seams have problems, due to their different operating rules, related to 

scheduling and paying for electrical service between RTOs. As reported to FERC, seams issues 

allowed continued discrimination for open access and impediments to wholesale power 

competition. To correct this, FERC issued the Standard Market Design Notice of Proposed 

Rulemaking51 on July 31, 2002. Standard market design would eliminate seams issues by 

standardizing the way generation and transmission markets work and create a larger geographic 

region. 

Standard market designs called for the introduction of independent transmission providers to 

replace RTOs. Independent transmission providers would retain many RTO responsibilities and 

add others. Under the standard market design proposal, jurisdictional utilities must file new 

transmission tariffs. Non-jurisdictional utilities would follow reciprocity guidelines established 

under Order 888. Locational marginal pricing and congestion revenue rights were introduced as 

new transmission pricing policies. FERC continued to assert its jurisdictional authority over 

bundled transmission, to oversee market power and, if required, to mitigate abuses of market 

 51 Woods, McGuire. (2008). “Detailed Summary of FERC’s Standard Market Design NOPR.” Thomson Reuters. 

http://library.findlaw.com/2002/Jun/25/132372.html. Accessed August 2012.
10

power. Finally, FERC proposed to develop resource adequacy guidelines and a regional planning 

process to sustain a viable electrical power system. 

1.2.5 FERC Order 890 (2007)

To rectify continuing issues of effective planning and coordination, FERC issued Order 890,52

which required a more open, transparent, and inclusive planning process. It required all 

transmission providers to file a new attachment to their OATT that contained their transmission 

planning process. The planning process must follow nine transmission planning principles.

1. Coordination: The transmission provider must meet with all of its transmission 

customers and interconnect neighbors to develop a transmission plan. FERC did not 

specify the details of how that coordination was achieved (e.g., number and structure of 

meetings). It did suggest formation of permanent planning committees that included 

transmission providers as well as state authorities, customers, and other stakeholders.

2. Openness: The coordination process should include meetings that are open to all affected 

parties. That does not imply that the public is invited, but only direct stakeholders are part 

of the process. The size of the group is dependent on the nature of the agenda.

3. Transparency: The transmission provider is required to fully disclose to all stakeholders 

the basic criteria, assumptions, and data that form the foundation for its planning process. 

FERC expressed its expectation that even those transmission providers not under FERC 

jurisdiction would also follow the principles in Order 890. The clear methodology for 

available transmission (transfer) capability (ATC) and OASIS posting is an important 

component of transparency. FERC anticipated that NERC would play a role in 

developing the ATC methodologies.

4. Information Exchange: Order 890 also places requirements on transmission customers to 

submit information on projected loads, resources, and anticipated transmission 

requirements to better assist in the planning process. The transmission provider must 

allow market participants the opportunity to review and comment on draft transmission 

plans.

5. Comparability: The transmission plan should meet the needs of transmission customers 

by accommodating their specific service requests and treating similar situations 

comparably. While this principle had been previously stated by FERC, there were 

continued concerns so that FERC felt it necessary to re-emphasize the requirement.

6. Dispute Resolution: There must be an established venue for dispute resolution to address 

both substantive and procedural planning disputes. FERC was careful to add that this 

requirement did not cover non-jurisdictional issues such as state siting issues.

7. Regional Participation: Transmission providers are required to coordinate with 

neighboring interconnected systems to share plans. Neighboring systems are to work 

together to ensure that plans are simultaneously feasible and to ensure that they address 

significant and persistent transmission congestion.

8. Economic Planning: Traditionally, planning primarily addressed reliability needs but 

FERC has added the requirement that “significant and recurring” congestion be 

 52 “Preventing Undue Discrimination and Preference in Transmission Service.” (2007). Federal Energy Regulatory 

Commission. http://www.ferc.gov/whats-new/comm-meet/2007/021507/E-1.pdf. Accessed August 2012.
11

addressed. While suboptimal dispatch and other economic transactions could be curtailed 

to maintain reliability, FERC requires that economic transmission expansion be part of 

the planning process.

9. Cost Allocation: Transmission providers and customers must develop a cost allocation 

method for new projects that represents a fair and equitable cost sharing based on benefit 

received. The cost allocation mechanism should provide incentives for new transmission 

and be supported by state authorities and regional participants.

In order to address perceived deficiencies in the way requests for firm point-to-point 

transmission service may be denied, FERC modified the pro forma OATT to include the 

“conditional firm” component. Specifically, FERC included the following in Order 890:

• FERC adopted the “conditional firm” component to provide additional long-term firm 

point-to-point service, requiring that transmission providers identify either defined 

system conditions or an annual number of hours during which service will be conditional, 

allowing transmission customers a choice.

• Transmission providers have an obligation to evaluate the provisions of redispatch from 

their own resources and provide customers with information on the capabilities of other 

generators to provide redispatch.

• The duration of both service options is limited to a time period during which service can 

be reasonably provided without impairing reliability.

• Transmission providers must post certain information monthly on the actual cost of 

redispatch services provided during that month.

Order 890 also addressed energy and generator imbalance penalties and rollover rights for 

transmission customers by increasing the minimum term of transmission contracts from 1–5 

years.

1.2.6 FERC Order 717 (2008)

FERC issued Order 71753 to clarify the rules previously promulgated under Order 200454

Standards of Conduct, which were widely perceived as interfering with efficient utility 

operations. Order 717 established a revised Standard of Conduct for employees of entities having 

both a “transmission function” and a “market function” by focusing on the day-to-day activities 

of employees. The order sought to more narrowly identify the scope of activities that constituted 

transmission activities and the scope of activities that constituted marketing activities. 

Traditionally, transmission planning relied on information related to load growth, reliability, and 

generation expansion. Under the Standard of Conduct, however, generation planning is 

considered a market function. In that context, transmission planning has shortened its horizon to 

accommodate short-term needs because transmission planners no longer have a “window” into 

generation expansion. 

 53 “Standards of Conduct for Transmission Providers.” (2008). Federal Energy Regulatory Commission. 

http://www.ferc.gov/whats-new/comm-meet/2008/101608/M-1.pdf. Accessed August 2012. 54 “FERC Commission Orders” (2012). Federal Energy Regulatory Commission. http://www.ferc.gov/legal/maj-ordreg/stand-conduct/orders.asp. Accessed August 2012.
12

1.2.7 FERC Order 1000 (2011)

FERC Order 100055 was adopted on July 21, 2011 to reform the transmission planning process to 

achieve the following outcomes:

• Require a regional transmission planning process

• Include procedures for the consideration of public policy requirements (e.g., renewable 

portfolio standards and other state clean energy requirements)

• Modify the right of first refusal for certain new transmission facilities

• Provide for additional coordination for planning and cost allocation, both within and 

among regions.

One of the key motivations was to enhance support for renewable project development and new 

transmission development by entities other than current public utility transmission owners.

1.3 Mandatory Reliability Standards

Reliability requirements for electric power systems have evolved from a voluntary agreement 

among utilities to mandates for minimum standards, with compliance audits to ensure 

enforcement. The history of reliability to a large extent mirrors the evolution of NERC. In 

response to the EPAct of 2005, FERC established the concept of a national Electric Reliability 

Organization (ERO) to develop and enforce mandatory reliability rules. As a result, NERCs role 

transformed from a voluntary organization to one that is certified by FERC to establish and 

enforce reliability standards for the bulk power system, including audit and financial penalty 

authority. NERC develops and enforces reliability standards; annually assesses adequacy; 

monitors the bulk power system; and is engaged in education, training, and certification of 

industry operating personnel.

The electric power grid of the continental United States is divided into three asynchronous 

interconnections commonly known as the Eastern Interconnection, Western Interconnection, and 

ERCOT Interconnection (see Figure 2). The eight regional entities are shown in Figure 3 work 

with NERC, the national electric reliability organization approved by FERC. The regional 

entities are permitted to enact standards that are more stringent than those enacted by NERC but 

are not permitted to relax or enact standards less stringent than NERC standards.

 55 “Order No. 1000 – Transmission Planning and Cost Allocation.” (2012). Federal Energy Regulatory Commission.

http://www.ferc.gov/industries/electric/indus-act/trans-plan.asp. Accessed August 2012.
13

Figure 2. Interconnections of the U.S. Power Grid56

Figure 3. Regional entities and balancing authorities57

 56 This image from the North American Electric Reliability Corporation’s website is the property of the North 

American Electric Reliability Corporation and is available at 

http://www.nerc.com/fileUploads/File/AboutNERC/maps/NERC_Interconnections_Color_072512.jpg. This content 

may not be reproduced in whole or any part without the prior express written permission of the North American 

Electric Reliability Corporation. Accessed August 2012. 57 This image from the North American Electric Reliability Corporation’s website is the property of the North 

American Electric Reliability Corporation and is available at http://www.nerc.com/docs/oc/rs/BubbleMap_2011-04-

12.jpg.This content may not be reproduced in whole or any part without the prior express written permission of the 

North American Electric Reliability Corporation. Accessed August 2012.
14

1.4 Trends and Current Situation

To a large extent, the need for increased transmission capacity is being driven not by an increase 

in demand, but more by a redistribution of generation. Replacing conventional dispatchable 

generation resources, such as coal and gas, with more efficient and/or cleaner renewable 

resources requires access to the transmission system. However, these new resources are often not 

at the same location as retired resources. Further complicating the issue of transmission capacity, 

the procedures and rules for accessing transmission service are being redefined by FERC. These 

orders are aimed at providing non-discriminatory service to potential users at a level comparable 

with that of the incumbent utility. FERC is also redefining the way transmission costs are 

allocated as they have in Order 1000.

For a more details on the current electric power grid structure in the United States, please refer to 

Appendix A: U.S. Electric Power Grid Structure.
15 

2.0 Expanding Existing Transmission Capacity – Operations, Policy, 

Rules

Exploring opportunities to increase the transmission capacity of the existing systems requires 

understanding basic terminology and the structural operation of the grid. This chapter explains 

the features of the grid and its operation and outlines relevant policies and rules. 

The carrying capacity of the transmission and distribution system is inextricably tied to 

reliability requirements. As outlined in Chapter 1, FERC has designated NERC as the ERO 

under EPAct 2005. NERC develops the minimum standards by which electric power 

transmission systems must be planned and operated. While other organizations may offer more 

stringent reliability rules, they may not set them below NERC standards. Activities to enhance 

the capabilities of existing transmission must be consistent with NERC standards. 

2.1 Transmission Capability

When thinking about adding renewable generation to existing transmission lines, the concept of 

transmission capabilities is crucial. These transmission values are called capabilities

(differentiating them from capacities) because they are dependent on the generation, customer 

demand, and transmission system conditions assumed during the analyzed time period. The 

electric industry generally uses the term capacity as a specific limit or rating of power system 

equipment. In transmission, capacity usually refers to the thermal limit or rating of a particular 

transmission element or component. 

2.1.1 Total Transfer Capability

The ability of the interconnected electric systems to reliably move or transfer power from one 

area to another over all transmission lines (or paths) under specified system conditions is known 

as the total transfer capability (TTC). The units of transfer capability are defined in terms of 

electric power, generally expressed in megawatts. In this context, the area may be an individual 

electric system, an operating area, sub region, NERC region, or a portion of any of these. 

When calculating TTC, the following features must be kept in mind: 

• A transmission path (circuit) can be an individual transmission element or a combination 

of elements. 

• TTC is directional. The transfer capability from Area A to Area B is not generally equal 

to the transfer capability from Area B to Area A. 

• The ability of a single transmission line to transfer electric power, when operated as part 

of the interconnected network, is a function of the physical relationship of that line to the 

other elements of the transmission network. 

• Individual transmission line capacities or ratings cannot be added to determine the 

transmission capability of a circuit or interface (transmission circuits between two or 

more areas within an electric system or between two or more systems). 

• The actual transfer capability of a specific transmission interface between two areas of 

the network is less than the aggregated (added) capacity of the individual circuits of that 

interface. This is illustrated in Figure 4 where the sum of the individual line capacities 

that make up the only path between Area 1 and Area 2 is 700 MW. However, the 
16

interface path capability is limited to 200 MW because the capability of the path must be 

maintained to meet the largest single contingency—the loss of the 500-MW line.

Figure 4. Path rating and contingencies

Operating limits are also considered when estimating TTC. These limits are established based on 

a system’s physical and electrical characteristics. The types of limits are as follows:

• Thermal Limits: Thermal limits establish the maximum amount of electric current that a 

transmission line or electrical facility can conduct over a specified time period before it 

sustains permanent damage by overheating or before it violates public safety 

requirements. 

• Voltage Limits: System voltages and changes in voltages must be maintained within 

acceptable minimum and maximum limits. For example, voltage limits can establish the 

maximum amount of electric power that can be transferred without causing damage to the 

electric system or customer facilities. A widespread collapse of system voltage can result 

in a partial or complete blackout of the interconnected network. 

• Stability Limits: The transmission network must survive disturbances through transient 

(milliseconds) and dynamic (several minutes) time periods following the disturbance. All 

generators are connected to the AC (AC interconnected transmission systems are 

synchronized to operate at the same frequency, nominally 60 Hz). Immediately following 

a system disturbance, generators begin to oscillate relative to each other, causing 
17

fluctuations in system frequency, line loadings, and system voltages. For the system to be 

stable, the oscillations must diminish as an electric system attains a new, stable operating 

point. If a new, stable operating point is not quickly established, the generators will likely 

lose synchronism with one another, and all or a portion of the interconnected electric 

system may become unstable. Generator instability may damage equipment and cause 

uncontrolled, widespread interruption of electric supply to customers. 

Operating limits are developed based on thermal, voltage, and stability concerns according to 

industry reliability criteria (NERC and regional entities)

58 for transmission paths. All transfer 

capabilities ensure that power flows are within their respective operating limits, both precontingency and post-contingency. Different regional entities have various definitions. 

Operating limits are typically calculated for the peak condition, which may occur only once 

during the year. In some cases, a separate TTC may be calculated for the peak condition for 

winter and summer. By calculating the rating under the most severe condition, the TTC for a 

particular path is lower than necessary for the remaining periods because system conditions 

would permit a higher capability. Even when the ATC is calculated hourly, the TTC remains 

constant for a particular series of calculations within the same season.

Recent evidence indicates that the NERC standards for calculating TTC (i.e., MOD-029-1a59) 

could lead to unnecessarily low TTC values. Certain lines when modeled under the standard may 

cause the TTC to be limited by the modeling and not by historical evidence of TTC. This is 

particularly true when wind or other intermittent resources are being modeled.

60

The TTC could be expanded in at least two ways, thereby increasing the estimated transmission 

capacity available for new generation:

1. Calculating a path TTC under a wider range of conditions could lead to greater overall 

utilization of the path.

2. Evaluation and revision of NERC MOD-029-1a for calculating TTC could include 

historical evidence of TTC and avoid limits based on modeling artifacts.

2.1.2 Available Transfer Capability

ATC is less than TTC. It is the estimated or designated transmission capability remaining in the 

network over and above already committed uses. A complex mathematical calculation of ATC is 

made by each planning authority, using its own methodology. ATC is calculated by taking 

account of factors that reduce TTC such as the transmission reliability margin, existing 

transmission commitments, the capacity benefit margin, and other adjustments such as postbacks 

and counterflows. 

 58 “NERC TPL and Top Standards.” (2012). North American Electric Reliability Company. 

http://www.nerc.com/page.php?cid=2|20/. Accessed August 2012. 59 “Standard MOD-029-1a – Rated System Path Methodology.” (undated). North American Electric Reliability 

Company United States. http://www.nerc.com/files/MOD-029-1a.pdf. Accessed August 2012. 60 Lew, Debbie and Milligan, Michael. (2007). “New Approaches to Deliver Wind Energy.” National Renewable 

Energy Laboratory: Boulder, CO. http://www.nrel.gov/wind/systemsintegration/pdfs/2007/lew_delivering_wind.pdf. 
18 

NERC requires that each transmission operator select one of the following three methodologies 

for calculating ATC:

1. The Area Interchange Methodology, MOD-02861

2. The Rated System Path Methodology, MOD-029 

3. The Flowgate Methodology, MOD-03062

While NERC defines all of these terms, each planning authority determines the exact 

methodology that it will use. The detailed calculation of ATC, particularly in the daily operation 

of the system, determines the ultimate utilization of the various transmission paths (circuits) on 

the grid. 

2.1.2.1 Transmission Reliability Margin

The Transmission Reliability Margin (TRM) is a factor in the calculation of ATC that accounts 

for uncertainties and reduces ATC. NERC Standard MOD-00863 lists the various factors that 

should be taken into consideration when calculating TRM: 

• Aggregate load forecast

• Load distribution uncertainty 

• Forecast uncertainty in transmission system topology (including, but not limited to, 

forced or unplanned outages and maintenance outages) 

• Allowances for parallel path (loop flow) impacts

• Allowances for simultaneous path interactions 

• Variations in generation dispatch (including, but not limited to, forced or unplanned 

outages, maintenance outages, and location of future generation) 

• Short-term system operator response (operating reserve actions) 

• Reserve-sharing requirements

• Inertial response and frequency bias

Uncertainties associated with TRM serve to reduce the ATC and therefore the capacity available 

for new generation. A more accurate estimate of each factor would reduce uncertainties and 

allow a more accurate (and potentially less conservative) estimate of ATC. Many transmission 

operators use a TRM of 0 (no effect) when calculating ATC, which results in a higher ATC than 

if these uncertainties were taken into account. 

2.1.3 Capacity Benefit Margin

Another factor in the calculation of ATC, Capacity Benefit Margin (CBM) is the amount of firm 

transmission capability set aside by the transmission operator for use by the load serving entities. 

 

61 “Standard MOD-028-2 – Area Interchange Methodology.” (2010). North American Electric Reliability Company. 

http://www.nerc.com/files/MOD-028-2.pdf. Accessed August 2012. 62 “Standard MOD-030-02 – Flowgate Methodology.” (2009). North American Electric Reliability Company. 

http://www.nerc.com/files/MOD-030-2.pdf. Accessed August 2012. 63 “NERC Standard MOD-008-1 TRM Calculation Methodology” (2008). North American Electric Reliability 

Company. http://www.nerc.com/files/MOD-008-1.pdf. Accessed August 2012.
19

It is ignored in areas where load serving entities are required to secure their capacity 

requirements, including deliverability.

2.1.3.1 Other Adjustments

Each transmission provider may have adjustments specific to its system that would increase or 

decrease the ATC. NERC rules for calculating ATC permit these adjustments, as long as they are 

documented and applied consistently. The California Independent System Operator (CAISO), 

operating within the Western Interconnect of North America, for example, uses postbacks, which 

are temporary changes in transmission service for the particular period covered by the ATC 

calculation. The CAISO also uses counterflows, which are registered flows in opposition to the 

calculated ATC flow. These particular adjustments may actually increase the ATC.

2.1.4 Planning Versus Operating Horizon

Projected transmission needs are determined by planning studies. However, TTC can change 

over time as system conditions change and may be limited by either thermal limitations on 

individual facilities, voltage constraints, or stability limits, depending on existing conditions (see 

Figure 5). To gain maximum utilization of the grid, TTC calculations must be updated in real 

time to account for current conditions on the grid.

Figure 5. Total Transfer Capability changes with time64

Calculation of ATC takes account of the current TTC as well as the actual flows on the lines and 

not just the “reserved” flows, which may or may not materialize in real time. This is the 

difference between the prospective system, as used in planning systems, and the real-time 

conditions during actual operations, as illustrated in Figure 6. The figure introduces the concept 

of recallable and non-recallable capability. These are analogous to firm and non-firm capability. 

The figure shows the additional capability that could be available by utilizing unscheduled, nonrecallable capability. The unused (unscheduled) capability in the Operating Horizon could be 

made available in real time to increase overall transfer capability. Market-based congestion 

provides an opportunity to use all of the available capability and not unnecessarily reserving 

capability.

 64 Adapted from NERC website: www.NREC.com.
20

Figure 6. Available Transfer Capability operating versus planning horizon65

2.2 Thermal Ratings and Estimated Capacity

Estimated transmission capacity is affected by ratings of lines and other equipment. Individual 

transmission owners may develop the rating of transmission lines (and other equipment) 

provided they follow certain general guidelines as noted in the excerpt from NERC standard 

FAC-08-366 below.

The methodology used to establish the equipment ratings that comprise the facility shall be 

consistent with at least one of the following67:

• Ratings provided by equipment manufacturers or obtained from equipment manufacturer 

specifications such as nameplate rating

• One or more industry standards developed through an open process such as Institute of 

Electrical and Electronics Engineers (IEEE) or International Council on Large Electric 

Systems

• A practice that has been verified by testing, performance history, or engineering analysis

The effect of the assumptions used for thermal ratings is shown in the example below. A utility 

in the northeastern United States has calculated summer and winter ratings based on a set of 

conservative assumptions as follows:

• A summer maximum ambient temperature of 35°C and an average daily maximum of 

30°C 

• A winter maximum ambient temperature of 10°C and an average daily maximum of 5°C

 65 Adapted from NERC website: www.NREC.com. 66 “NERC Facility Ratings.” (undated) North American Electric Reliability Company. 

http://www.nerc.com/files/FAC-008-3.pdf. Accessed August 2012. 67 Ibid Section 2.1
21

• Ambient wind speed of 3 feet per second for summer and winter 

• All local thermodynamic equilibrium ratings are established assuming a maximum time 

period of 4 hours, but total no more than 300 hours over the life of the line 

• All system thermodynamic equilibrium ratings are established assuming a maximum time 

period of 15 minutes, but total no more than 12.5 hours over the life of the line; a normal 

preload is also used in establishing the short-term emergency rating

• 40-year life is assumed for each line 

The assumed ambient temperature plays an important role in determining the capacity of an 

individual line and presents an opportunity to increase utilization of line capacity. In the 

example, the actual average maximum monthly temperature in the utility’s core area is 25.6oC, 

which is 4.4oC less than the assumption. Using the higher assumed temperature results in a 

reduced capacity for the line. Reducing the average maximum assumption closer to the recorded 

average could increase TTC and allow for added transfer of renewable generation.

Fine-tuning the timing of ratings could also increase TTC. The maximum temperature applies for 

a particular time period. This means that the line would be underutilized for all but the time when 

the ambient temperature was at its maximum. Dynamic line rating or real-time line rating can be 

used to reduce the conservatism built into the seasonal static ratings. By using actual conditions 

rather than assuming a static set of “worst case” conditions, the available transmission could be 

increased in real time for operational purposes.

Table 2 shows the relative sensitivities of the thermal line rating associated with the assumptions 

used in the calculations. This is based on IEEE Standard 738-1993.68

Table 2. Impact of Assumptions on Thermal Line Rating69

ASSUMPTIONS IMPACT ON CALCULATED RATING

Solar heating during the day <5%

Ambient air temperature 10% for a 10oC difference

Wind speed 10% - 20% within the range of 0 to 3 ft/sec

Wind direction 10 degree angle to conductor vs. perpendicular 

2.8% reduction

NERC Standard FAC-08-370 permits a methodology that can be “verified by testing, 

performance history or engineering analysis.” If implemented properly, dynamic line rating or 

adjustment of ratings criteria would increase TTC while maintaining reliability. 

2.3 Common Corridor Definitions

A factor in the calculation of ATC is the reliability requirement adjustments for lines on a 

common corridor that share rights-of-way. NERC considers the reliability impact of lines on a 

common structure, whereas WECC has required that lines on a common corridor be evaluated 

 68 “IEEE Standard for Calculating the Current-Temperature of Bare Conductors.” (1993). IEEE. 

http://standards.ieee.org/findstds/standard/738-1993.html/. Accessed August 2012. 69 Source: Increased Power Flow through Transmission Circuits: Overhead Line Case Studies and Quasi-Dynamic 

Rating. (2006). EPRI: Palo Alto, CA 2006.

70 “NERC Facility Ratings.” (undated) North American Electric Reliability Company. 

http://www.nerc.com/files/FAC-008-3.pdf. Accessed August 2012.
22

together when assessing the reliability of a transmission path. Revisions to the WECC reliability 

requirements for transmission lines that share a common corridor take effect April 2012. This 

change could allow for increased use of transmission corridors, improve the siting and permitting 

process for transmission expansion, and ensure that the current reliability levels of the Western 

Interconnection are not compromised.

A technical drafting team within WECC proposed refining the definition for Adjacent 

Transmission Circuits to incorporate separation language that was contained previously in the 

Common Corridor definition. It should be noted that the drafting team modified the distance 

between the structure center line separation from “less than the longest span length of the two 

transmission circuits at the point of separation or 500 feet” to “separation between their center 

lines less than or equal to 250 feet at the point of separation.” The 250-feet distance was selected 

because it is approximately the maximum height of a 500-kV tower with some margin. The 

changes were approved by the WECC Board of Directors and will take effect in April 2012.71

With this change, future transmission circuits may be placed in closer proximity, thereby 

potentially increasing the utilization of existing rights-of-way. 

2.4 Congestion Management

2.4.1 Market-Based Congestion Management

Transmission is affected by allocation decisions of the line operators. Market-based congestion 

management allocates transmission either a day ahead or in real time to the highest bidders for 

transmission rights. Rather than holding physical transmission rights, participants hold financial 

transmission rights that form a hedge against congestion. FERC Order 2000 required RTOs to 

establish market-based congestion management.

With financial transmission rights, all market participants have access to the transmission

capacity and are under constrained conditions. Those willing to pay the highest price for access 

to the limited capacity may use it. The holder of the financial transmission rights realizes the 

financial premium from the scarcity price of the transmission. This provides an efficient use of 

constrained transmission systems, minimizing unused capacity since all market participants have 

access to the grid.

Under a market-based congestion management system, generation is redispatched to relieve the 

congestion. The initial dispatch is determined by utilizing the most efficient generation to serve 

the load. The following figures and tables from a PJM Interconnection training manual72

illustrate how the process can work. Figure 7 shows a dispatch using the lowest cost generation 

to serve the load. In doing so, however, the maximum capacity of the indicated line is exceeded 

(253 MW of flow with a capacity of 230 MW). Note that the three most efficient generators are 

fully dispatched (Brighton, Alta, and Park City) and the balance of the load requirement is met 

 71 “WECC-0071 System Performance Criteria Approved.” (2012). Western Electricity Coordinating Council. 

http://www.wecc.biz/Standards/Development/WECC-0071/Lists/SiteNews/DispForm.aspx?ID=4. Accessed August 

2012.

72 PJM Interconnection is an RTO that coordinates the movement of wholesale electricity in all or parts of 13 

states and the District of Columbia. Source for Figures 8, 9, and 10: “LMP FTR Training Manual.” (2011). PJM. 

PJM makes no representation, warranty or guarantee as to the accuracy or completeness of the information provided 

herein. http://www.pjm.com/~/media/training/core-curriculum/ip-lmp-101/lmp-ftr-101-training.ashx/. Accessed 

August 2012.
23

by the fourth most efficient generator (Solitude). The least efficient generator (Sundance) is not 

dispatched at all. 

Figure 7. Dispatch and flows before congestion relief

To relieve the congestion on the overloaded line, redispatch of the generation from the lowest 

cost configuration is necessary, as shown in Figure 8. The redispatch reduces the output from

Brighton (most efficient generator) by 90 MW and increases the output from Solitude (fourth 

most efficient generator) by 90 MW to compensate. This redispatch lowers the flow on the 

overloaded line to within its limit of 230 MW, but causes the overall cost of supplying the load 

to increase. In a market-based system, this is reflected in an increase in the locational marginal 

price and results in a higher cost of power. The difference in cost between the optimal dispatch 

and the redispatch is the congestion component of locational marginal price and is paid by 

customers.

Figure 8. Dispatch and transmission flows after redispatch to relieve congestion
24

However, transmission customers can hedge against these congestion costs by securing the 

congestion revenue rights. Two primary methods are available for hedging congestion: the 

transmission congestion contract as used by the New York Independent System Operator 

(NYISO), a balancing area and electric power market operator for the state of New York within 

the Northeast Power Coordinating Council (NPCC) and the financial transmission rights as used 

by PJM Interconnection. PJM is an RTO with responsibility for all or a portion of 13 states and 

the District of Columbia. PJM manages the electric power grid and the wholesale electricity 

market within its footprint and is a balancing area within the regional entity Reliability First 

Corporation in the Eastern Interconnection. PJM began as a power pool and transitioned to an 

ISO in 1997 and became an RTO in 2001.

Both transmission congestion contracts and financial transmission rights provide a market-based, 

efficient method for allocating transmission capacity and minimizing unused capacity, 

particularly during periods of transmission shortage. 

In areas without markets, it is not feasible to use redispatch as a means of congestion 

management. These areas must rely on physical transmission rights, which can leave unused 

capacity even during times of perceived transmission shortage. In the example above, 

transmission customers could only serve the load up to the limit of the line (230 MW) based on a 

preset dispatch. There would be no mechanism to allocate the cost of redispatch. Approximately 

23 MW (253 MW minus 230 MW) would not be served because the capacity of the transmission 

could not be increased. If market-based congestion management were used, the cost of adding 

transmission would be weighed against the cost of redispatch.

When viewing the redispatch in terms of locational marginal price, as calculated in a marketbased system (Table 3), the post redispatched and associated locational marginal prices are given 

in Figure 9. Prior to congestion, however, the locational marginal price in the system would have 

been the same and set by the marginal unit, which is Solitude’s at $30/MWh. Table 4 shows the 

impact on total cost to load, as a result of the congestion and redispatch. The cost of congestion 

to the loads is $1,920.
25

Table 3. Locational Marginal Price Calculations

Table 4. Cost of Congestion to Loads

LOAD MW

PRE-DISPATCH POST DISPATCH CONGESTION

LMP COST LMP COST COST/MW COST

B 300 30 $9,000.00 26.4 $7,920.00 ($3.60) ($1,080.00)

C 300 30 $9,000.00 30 $9,000.00 $0.00 $0.00 

D 300 30 $9,000.00 40 $12,000.00 $10.00 $3,000.00 

TOTAL $27,000.00 $28,920.00 $1,920.00 
26

Figure 9. Post redispatch locational marginal prices

2.4.2 Conditional Firm Transmission

More of the existing transmission capacity has been made available, subject to voluntary risk of 

curtailment, through CFT. FERC provided for CFT in Order 89073 to bridge the gap between 

management of the physical firm transmission and market-based transmission congestion. In 

situations where long-term firm transmission is not available because of periodic constraints, 

FERC recommended the issuing of CFTs to allow a limited number of users during constrained 

situations, but still provide transmission service at other times. Widespread use of CFTs would 

serve to increase the use of existing transmission capacity. 

Transmission service providers have requested approval and implemented CFT service, as 

required in November 2007 under FERC Order 890.74 These include: Bonneville Power 

Administration, Maine Public Service Company, PacifiCorp, Northwestern Energy, Western 

Area Power Administration, Southwest Power Pool, Nevada Power, and Florida Reliability 

Coordinating Council.

2.4.3 Redispatch

Another means to resolve transmission congestion is transmission redispatch, the changing of 

generator output levels. Redispatch can be used to enable additional transmission sales by 

reducing the congestion that otherwise would limit sales. Redispatch is included as part of 

market-based congestion management, but in areas without markets, redispatch is often not 

implemented because it results in the reduction of selected generators, which may impact their 

revenue.

 73 “Preventing Undue Discrimination and Preference in Transmission Service.” (2007). Federal Energy Regulatory 

Commission. http://www.ferc.gov/whats-new/comm-meet/2007/021507/E-1.pdf. Accessed August 2012. 74 “FERC Order 890: What Does it Mean for the West?” (2007). National Wind Coordinating Collaborative.

http://www.nationalwind.org/assets/publications/ferc890.pdf. Accessed August 2012.
27 

Where transmission lines are congested, adjusting the output of generators that produce 

congestion could be a lower-cost, faster solution to new transmission service than building new 

lines. It makes sense to use the lowest cost methods to resolve transmission congestion before 

turning to higher-cost methods. 

2.4.3.1 Operation of Redispatch

Transmission providers could offer to redispatch generators to provide long-term firm service to 

transmission customers, which in turn would allow for new renewable energy projects to be 

financed. Providers could publish dynamic, real-time values for what they would charge to 

provide redispatch service, at specified congested locations within the transmission provider’s 

system, and at specified flowgates at the border of the transmission provider’s system. In nonmarket environments, these values can and will be cost-based. These costs are known to the 

entity performing dispatch. By making these costs more transparent, customers can assess 

redispatch options. As a result, participants might voluntarily offer redispatch solutions and be 

properly compensated for their efforts. The benefits are more renewable energy integrated onto 

the grid and lower total costs for consumers if transmission constraints are handled by redispatch 

instead of more costly measures. 

The process of redispatch is very similar to that followed under market-based congestion 

management. Figure 7 shows the dispatch before adjusting for the overload on the line between 

Brighton and Sundance. The line is rated as 230 MW and the flow is 253 MW. To relieve the 

overload, the Brighton plant output is reduced 90 MW, and the Solitude Plant compensates by 

increasing output 90 MW, which reduces the flow to 230 MW, as shown in Figure 8. 

2.4.3.2 Cost of Redispatch

All transmission providers regularly redispatch their systems to relieve congestion. The 

challenge is predicting future redispatch costs and providing cost certainty to customers. 

Redispatch service can be effective only where actual costs are assigned to customers requiring 

the service, and where such costs can be known with reasonable certainty at the time the 

customer decides whether or not to accept transmission service. 

Costs are determined by the increased cost of output from one generator, and the decrease in 

output from another generator. Costs of redispatch must be determined and allocated to the 

customers requiring such service. Providing transparency of costs over time will help providers 

and market participants assess and predict redispatch costs. Table 5 shows the cost increase 

associated with redispatching the system shown in Figure 7 and Figure 8. The cost to 

accommodate the additional flow of 23 MW (253 MW minus 230 MW) between buses E and D 

without overloading any lines is $1,800. The transmission customer must decide if it is willing to 

pay $1,800 for redispatch to gain the additional 23 MW of transmission service. 
28

Table 5. Cost of Redispatch

WECC, the organization representing the western Interconnect of North America is evaluating 

an energy imbalance system and associated toolkit75 that would incorporate a redispatch process 

to relieve congestion and allocate the cost according to a locational imbalance price. The 

locational imbalance price includes a congestion component similar to locational marginal price, 

but it only addresses the real-time imbalance market. The energy imbalance system would bridge 

the gap between a simple redispatch process as described above and a full market-based 

congestion management system. 

CAISO currently uses a market-based congestion management system employing locational 

marginal price and follows congestion management processes similar to other RTO/ISOs.

2.5 FERC Transmission Investment Rule

To help increase transmission capacity, the development of incentive-based rate treatments for 

the transmission of electric energy was ordered by EPAct 2005.

76 As a result, FERC issued 

Order 679,

77 which implemented the following incentive-based rate treatments: 

• Incentive rates of return on equity for new investment by public utilities (both traditional 

utilities and stand-alone transmission companies)

• Full recovery of prudently incurred construction work in progress

• Full recovery of prudently incurred pre-operations costs

• Full recovery of prudently incurred costs of abandoned facilities

• Use of hypothetical capital structures

 75 Western Electricity Coordinating Council. (2009). “Congestion and Balancing Toolkit.”

http://www.wecc.biz/committees/BOD/120909/Technical%20Session/1/Congestion%20and%20Balancing%20Tool

%20Kit.pdf. Accessed August 2012. 76 “Energy Policy Act of 2005.” (2005). U.S. Department of Energy, Energy Efficiency and Renewable Energy. 

http://www.afdc.energy.gov/afdc/laws/epact_2005/. Accessed August 2012. 77 Stevens, George. (2007). “Transmission Infrastructure Investments FERC Order 679.” Indiana Utility Regulatory 

Commission. http://www.narucpartnerships.org/Documents/Transmission_Infrastructure_Investments_eng_George_

Stevens.pdf. Accesssed August 2012.

UNIT

RATING 

(MW) COST

PRE-REDISPATCH POST REDISPATCH

OUTPUT 

(MW) COST

OUTPUT 

(MW) COST

Brighton 600 $10 600 $6,000 510 $5,100 

Alta 110 $14 110 $1,540 110 $1,540 

Park City 100 $15 100 $1,500 100 $1,500 

Sundance 200 $40 0 $0 0 $0

Solitude 520 $30 90 $2,700 180 $5,400 

TOTAL 900 $11,740 900 $13,540

TOTAL COST 

INCREASE

$1,800
29

• Accumulated deferred income taxes for stand-alone transmission companies

• Adjustments to book value for stand-alone transmission company sales/purchases

• Accelerated depreciation 

• Deferred cost recovery for utilities with retail rate freezes

• A higher rate of return on equity for utilities that join and/or continue to be members of 

transmission organizations, such as (but not limited to) RTOs and ISOs. 

All rates approved under the rules are subject to Federal Power Act rate filing standards. The rule 

allows transmission owners, on a case-by-case basis, to select and justify the package of 

incentives needed to support new investment. Additionally, the rule provides expedited 

procedures for the approval of incentives to provide owners with greater regulatory certainty and 

facilitate the financing of projects. The rule became effective on September 29, 2006. FERC has 

made minor adjustments to the rule and issued a Notice of Inquiry on May 19, 201178 seeking 

comments to questions designed to determine the effectiveness of the rule.

Much of the rule was focused on new transmission; however, the incentive could also be applied 

to incremental improvement of existing transmission facilities. This was clearly stated in FERC’s 

responses to the Notice of Inquiry as provided in Section 180 of the FERC discussion of the final 

rule.79 FERC has not yet implemented any changes to the order in response to the Notice of 

Inquiry.

Since the issuance of Order 679, FERC has received more than 75 applications for transmission80

incentives associated with more than an estimated $50 billion in proposed investments from a 

variety of transmission developers. In one case, FERC granted incentive rates for transmission in 

Potomac Electric Power Company’s (PEPCO’s) Mid Atlantic Power Pathway. In another case, 

FERC granted incentive rates for the delivery of renewable energy in the Tehachapi Project to 

load centers in California. 

A possible next step for FERC would be to expand the use of incentive rates to accommodate 

alternatives to building new transmission, including new technologies that increase transmission 

capability on existing lines.

2.6 Demand Response

Some benefits to transmission capacity have been attributed to demand response, the balancing 

of customers’ need for electricity with the power company’s output. Table 5 identifies qualitative 

benefits that demand response offers to transmission and distribution. Quantitative benefits are 

difficult to assess because demand response is spread across a large portion of the system. Any 

benefits to individual transmission facilities are dependent on the distribution of demand 

resources and the resulting flow changes on the transmission system brought about by reduced 

demand. 

 78 Troutman Sanders, LLP. (2012). “FERC Releases NOI on Transmission Investment,” Washington Energy Report. 

http://www.troutmansandersenergyreport.com/2011/05/ferc-releases-noi-on-transmission-investment/. Accessed 

August 2012. 79 “Promoting Transmission Investment Through Pricing Reform: Final Rule” (2006). Federal Energy Regulatory 

Commission. http://regulations.vlex.com/vid/part-ii-22122747/. Accessed August 2012. 80 Campbell, Richard. (2011). “Regulatory Incentives for Electricity Transmissions – Issues and Cost Concerns.” 

Energy Legislation, United States, 2011. http://energylegislation.blogspot.com/2011/11/regulatory-incentives-forelectricity.html. Accessed August 2012.
30

Although the main benefit of demand response is reduced energy costs, there are also potential 

benefits to transmission. According to a presentation by Battle Group to U.S. DRCC Webinar, 

March 16, 2007, demand response can help avoid or defer costs although the benefits may be 

larger for distribution than for transmission. 

In cases where specific and significant blocks of localized demand resources exist, FERC’s effort 

to establish parity between generation resources and demand response suggests that demand 

response could schedule negative transmission reservations. To the extent that a particular load 

block has a corresponding resource and flow path with a transmission reservation, the load’s 

willingness to curtail during specific peak times, would have the same effect as scheduling a 

negative transmission reservation. This could reduce peak demand on specific transmission paths 

and, therefore, be the equivalent of increasing the capability of the path for a non-curtailed load 

by the same amount. Future OATT could address this potential as a means of reducing peak 

transmission congestion.

2.7 Regulatory and Other Incentives to New Technologies

New technologies can increase the capability of the existing grid without adding additional 

transmission lines. Technologies, such as energy storage, offer benefits to multiple facets of the 

grid from generation to transmission and distribution. 

Incentives and market rules can be designed to encourage and accommodate these technologies. 

FERC and the RTO/ISOs would need to implement rule changes that recognize the unique 

operating characteristics of the new technologies. For example, FERC’s Notice of Proposed Rule 

Making RM 11-7 and AD10-11 recognized the benefits of fast transmission regulation services 

that have previously required additions to the transmission system. The rule will compensate 

storage facilities that can provide fast regulation, and other benefits to the grid related to 

damping and stability.81

2.8 Opportunities

As discussed in the previous sections of this chapter, changes in standards and policies can 

“stretch” the existing grid. The following list summarizes suggested changes in primary policies, 

rules, and procedures for determining transmission capabilities and some opportunities for 

modification to enhance transmission capabilities:

• Replace the practice of using static seasonal ratings on critical constrained transmission 

lines, with either real-time or dynamic monitoring of ambient conditions. Transmission 

capability that is currently restricted could be increased during much of the year because 

the line rating is fixed for the worst ambient conditions that rarely occur.

• Extend the NERC standards for multiple circuits to include those that are not on a 

common structure, but are within a span length of each other. This action by the WECC 

could increase utilization of existing rights-of-way.

• Establish market-based congestion management to improve the utilization of the grid and 

to allocate the cost of congestion to those users who were willing to pay the price.

Extending this practice of replacing physical transmission rights with financial 

 81 Brown Rudnick LLP. (2011). “Comments of the Electricity Storage Association.” 

http://www.electricitystorage.org/images/uploads/static_content/advocacy/regulation/ESAFERCPFPNOPR.pdf. 

Accessed August 2012.
31

transmission rights ensures that the actual cost of using the transmission system is done in 

the most efficient and equitable use of the transmission system during times of constraint.

• Implement CFT and redispatch as a bridge between physical firm transmission and 

market-based transmission congestion management. CFT provides a mechanism for 

transmission users to have access to selected transmission paths on a firm basis except 

during periodic constrained periods. Extending this practice allows increased use of the 

transmission system when conventional firm transmission is not available, but when the 

system is not actually constrained. During periods when transmission paths are 

constrained, redispatch may relieve the constraints at some defined cost and allow 

transmission customers to decide whether to pay the cost of redispatch or forgo use of the 

transmission. Redispatch also provides a price signal, which can be used to make 

economic decisions regarding the value of increasing transmission capability on selected 

paths. Redispatch provides many of the same benefits as market-based congestion 

management with having a formal congestion management system in place.
32

3.0 Expanding Existing Transmission Capacity – Technology

Complex technology is necessary to increase the power flow capacity on existing power 

equipment (overhead lines and power transformers), power circuits (multiple power equipment 

elements in series), and power system interfaces (multiple parallel power circuits connecting 

power system regions). The following three issues are basic to all approaches:

1. For overhead lines, increase in power flow capacity is dependent on length, original 

design assumptions, environmental regulations, the condition of structures, and the type 

of conductors. Increase in a line’s thermal rating could range from between 5% and 

100%.

2. Overhead lines are only part of the transmission path (circuit). The lines are terminated at 

substations by air disconnects, circuit breakers, and line traps. The power flow through all 

of the circuit elements must be limited to avoid damaging the line or the terminating 

equipment. The maximum allowable power flow over this circuit may be limited by any 

one of the circuit elements. According to the current NERC rating methodology,

82 a

facility rating must be the minimum of all ratings between substations.

3. Increase in maximum allowable power flow through a component circuit or circuit 

element does not necessarily yield a higher rating for the complex interface, or from 

source to sink, when considered as part of a power system interface. This is because

increased flow on an improved element may bump into another element’s limits.

Transmission circuit ratings are often developed on a system basis, rather than on an individual 

line basis.83 This is because the maximum power flow on the transmission system is a function of 

the overall system topology (transmission lines, transformers, generation, series and shunt 

compensation, and load). Many non-thermal system considerations (such as sag and voltage) can 

also limit the maximum power flow on a specific transmission circuit. The overall limit may be 

set between operating areas, irrespective of ownership or individual lines, and may change 

during a day based on system conditions. Increasing the capacity on a single line by 100% would 

not necessarily increase the system capacity by this amount. A separate, parallel facility may 

have a constraint after the flow increases by only 25%.

A variety of technologies is available to more fully leverage and expand the physical capability 

of an existing transmission system infrastructure and its assets (i.e., rights-of-way). These

include the following:

• FACTS-based devices

• HVDC converters and transmission

• Enhanced system and equipment monitoring

• “Mature” (i.e., well-established, non-power electronics-based) technologies (e.g., phase 

shifting transformers, series capacitor line compensation)

• Next-generation conductors (i.e., high-capacity or superconductor cable)

 82 “NERC FAC-008-1 Rating Methodology.” (2006). North American Electricity Reliability Company. 

http://www.nerc.com/files/FAC-008-1.pdf. Accessed August 2012. 83 “Western Interconnection Path Flow Study.” (2007). Western Electricity Coordinating Council. 

http://www.wecc.biz/committees/BOD/TEPPC/External/070917_07_Report.doc. Accessed August 2012.
33

Although each of these technologies employs different methods to affect the operating 

parameters of the transmission system, they all facilitate a more stable and fully utilized electric 

power network. As with most technologies, however, there are tradeoffs between device 

size/capability and cost. In addition, a technology may work well to address one issue, but it may 

raise other issues. Accordingly, the selection of a technology is based on competing, though 

generally collaborative, interests (e.g., technical feasibility and applicability, cost, operations and 

maintenance, and proven commercial history). 

The following sections discuss technologies available to enhance the existing transmission 

system infrastructure. Brief histories are provided for context and clarification. To achieve a 

structure for comparison, the grid parameter(s) affected by each technology are broadly 

classified into three categories: 

1. Increased power transfer

2. Improved voltage stability

3. Enhanced system frequency stability

As with any system (defined in Webster’s Dictionary as “a regularly interacting or 

interdependent group of items forming a unified whole”), these three specified categories of grid 

parameters are not isolated. Targeted improvements to one grid parameter can have ancillary and 

indirect benefits on another parameter. The three categories are used to identify the targeted 

system improvements provided by a particular technology.

3.1 Fundamentals of Power Transfer Limits

The following sections describe technical aspects of electric power transfer that will help those 

evaluating alternative strategies for increasing the transfer capability of the grid.

3.1.1 Surge Impedance Loading

The surge impedance loading (SIL) of a power transmission line is the nominal power flow 

capacity based on the design characteristics for the line and its operating voltage. SIL is 

governed more by the overall geometry of the line and its operating voltage and less by the 

conductor size. SIL is independent of the line length. SIL is not the maximum that a particular 

line can carry, but rather a benchmark that can be used to compare lines of different designs and 

voltage rating. SIL is a useful concept to compare different transmission lines. 

For an overhead transmission line, typical surge impedance is around 300 ohms, compared to a 

cable, which may be 50 ohms or less. At 345 kV, the SIL of an overhead line is on the order of 

400 MW. Short lines may be able to carry 800 MW or more. Long lines of the same construction 

may be limited to less than 400 MW by system considerations. Underground transmission cables 

always operate very far below SIL because of limitations on heat dissipation. As a result, 

underground transmission cables are a net source of reactive power (vars) to the system.

Reactive loading and losses can become a limiting problem if a significant number of the lines 

are loaded above their SIL. As loading increases appreciably above SIL for many lines in the 

system, the reactive losses will increase in relation to the square of the current and the line 

reactance. Adding high-capacity lines, instead of improving the power transfer capability of the 

system, could further increase the reactive losses and, consequently, further hamper power 

transfers.
34

3.1.2 Thermal Limits

Thermal limits are the maximum flows that can be permitted through a transmission circuit, 

either on a continuous basis or for a short duration, based on the circuit design. The design 

parameters include the conductor type, conductor bundles, ambient temperature, wind speed, ice 

loading, and span length. The thermal limitation is critical primarily in cases of lower voltage 

lines of 50 miles or less.

At extra-high voltage (345 kV and above), environmental considerations, such as corona 

discharge and field effects, dictate line designs and usually result in high thermal capabilities, 

which can exceed the realistic power transfer. For extra-high voltage transmission, line 

terminating equipment, such as wave traps and substations, impose a thermal limit rather than the 

line itself. Consequently, thermal limits are significant only for short lines at 138 kV and below.

The process of selecting a thermal rating for an overhead line can be fairly complex or simple. 

Ratings are published by conductor manufacturers for a range of conservative weather 

assumptions and conductor temperature limits. Ratings can also be determined from field 

measurements of sag, wind direction and strength, solar insolation, and other variables.

As power flow increases in a bare overhead power line, the conductors, connectors, and 

associated hardware are heated because of the ohmic losses. Typically, lines that are thermally 

limited are the shorter lines in the system and the economic cost of electrical losses may be 

tolerable. However, potential damage to conductor systems or safety concerns occasioned by 

violation of minimum clearances remains a concern. 

Thermal ratings for overhead lines are defined in amperes or megavolt amperes (MVA) with an 

associated duration and, possibly, by frequency of occurrence. Consequently, one line may have 

a continuous thermal rating of 100 MVA; a 4-hour, long-time emergency rating of 115 MVA;

and a 15-minute, short-time emergency rating of 130 MVA. The system operator would 

understand these ratings to mean that the power flow on this line could reach but not exceed 

100 MVA indefinitely. Also, if the flow exceeds 100 MVA, but is less than 115 MVA, the 

operator must reduce the flow to below 100 MVA within the next 4 hours. If the flow exceeds 

115 MVA, the operator must reduce it to below 100 MVA within 15 minutes. The temperature 

limits on these lines typically serve to limit the loss of conductor tensile strength to less than 

10% over the life of the line. It may be possible to exceed the thermal limits of lines and accept 

some loss of life provided safe clearances are maintained especially for lines that are scheduled 

for replacement or upgrade in the near future. 

3.1.3 System Limits

System limits are functions of transmission line reactance in relation to the overall power system. 

Series reactance, shunt admittance, and their combination can alter system transfer limits. 

System planners have long recognized this relationship, particularly where there are prospects of 

changing the line surge impedance, either by adding equipment (e.g., series capacitors) or by 

modifying the line itself (e.g., reconductoring, voltage uprating). Transmission line series 

inductive reactance is determined by conductor size, phase spacing, number of conductors, 

relative phasing (double-circuit lines), and line configuration. In long high-voltage overhead 

transmission lines, the series reactance is larger than the series resistance and is dominant in a 

first-order explanation of system behavior. For this reason, simple reconductoring of many long 

transmission lines, with no change to structure geometry, results in only minor changes in system 

power flows.
35 

However, for shorter lines, the thermal capacity of the conductors or the characteristics of the 

system in which the line operates impose the power limits of that line. System limits can result 

from factors such as voltage drop, possibility of voltage collapse, and system stability, both 

steady state and transient. 

3.2 Increasing Thermal Limits

The thermal limits of the conductor are a key limiting factor in the capabilities of transmission 

lines. As electricity flows through a transmission line, heat is produced due to the flow of current 

through the resistance of the conductor. As the current flowing through the conductor increases, 

additional heat is produced, which causes the temperature of the conductor to increase. The 

temperature is a function of the electrical current and the environmental conditions (temperature, 

humidity, and windspeed). If the conductor becomes too hot, one of two problems may result. 

1. First, excessive heat may permanently damage the conductor. Each transmission line has 

a maximum amount of power that can flow over it without damage. 

2. Second, the increasing temperature may cause the line to physically sag below design 

levels, resulting in increased risk of injury and damage, as well as line outages. The line 

must not touch anything including the ground. Physical sag of the line can be reduced by 

using certain conductors. 

Other important constraints are the level of electric and magnetic fields produced (e.g., electric 

fields increase as the conductor gets closer to the ground), the maximum structure loads during 

occasional high wind and ice loads, and the maximum temperature at which the energized 

conductors are allowed to operate. 

Given standard worst-case weather conditions, the thermal rating of an existing line is 

determined by the maximum allowable conductor temperature. Thus, uprating (pushing more 

electricity) such lines, without reconductoring, normally requires finding ways to maintain 

electrical clearances above the ground while operating at a higher conductor temperature.

To protect against problems resulting from thermal overloads on transmission lines, utilities 

install relays. A relay senses the amount of power flowing through a transmission line, and 

operates a circuit breaker to interrupt the power flow on the line, if it exceeds the thermal limit of 

the line. The power will then flow through parallel paths. The increased loading along the 

parallel paths creates the potential for an overload condition on other transmission lines. If the 

system is not properly designed, operated, and maintained, thermal overloads can lead to 

cascading outages of transmission lines and system breakup. 

Transmission line capacity can be increased through improvements in transmission tower design 

(to compensate for physical sag) and increases to conductor current capabilities (to withstand 

more heat). The ability to accurately determine the conductor thermal condition at any point in 

time is also helpful in maintaining the line.

3.2.1 Improved Transmission Structures

Adaptations can be made to accommodate physical sag resulting from increased transmission 

capacity on existing lines. Ground clearance on specific spans can be increased by installing 

additional structures mid-span, if the ground contours and permitting restrictions allow.

Clearance can also be increased by modifying the existing structures to raise the conductor 

attachment points. Alternatively, existing structures can be replaced with taller structures. These 

methods do not increase conductor tension, minimizing the need to replace angle and dead-end 
36

structures. Increasing ground clearance typically results in only modest increases in allowable 

ampacity (electricity through the line) before cost becomes prohibitive.

3.2.2 Reconductoring

To increase the current capability of lines, a thermal balance calculation must be performed to 

determine if the conductor, as well as all the connectors and hardware, can withstand the 

resulting higher temperatures. The rating of the line is limited by the following:

• The properties of the conductor material 

• The environmental conditions surrounding the conductor

• The ground clearance of the line

Today, most overhead transmission lines are aluminum conductor steel reinforced (ACSR) 

transmission. Steel can withstand temperatures up to 200°C with no changes in its properties. 

Aluminum, however, experiences deterioration in mechanical properties when the temperature is 

higher than 90°C. The temperature is a function of the electrical current and the environmental 

conditions. On a continuous basis, ACSR may be operated at temperatures up to 100°C and, for 

limited time emergencies, at temperatures as high as 125°C without any significant change in the 

physical properties. 

To increase the nation’s transmission capability to handle new generation, transmission systems 

could achieve higher current densities in existing transmission lines. Several approaches have 

been proposed to achieve this increase: 

• Increase the maximum allowable operating temperature of the conductor to 100°C. For 

example, if the line is limited to a modest temperature of 50°C to 75°C and the electrical 

clearance above the ground is sufficient to allow an increase in physical sag for operation 

at a higher temperature, then the thermal rating of the line can be increased. If sufficient 

clearance does not exist in all spans, then conductor attachment points on tower structures 

may be raised, the conductor tension increased, or other mechanical methods applied to 

obtain the necessary clearance at the higher temperature.

• Use dynamic ratings or less-conservative weather conditions relating to wind speed and 

ambient temperatures. For example, if the existing line is already rated at a temperature 

near 100°C, and a modest increase of 5% to 15% is desired, then condition monitors can 

be installed and the higher ratings used when wind speed is higher than the standard 

0.6 m/s and the ambient temperature is lower than 40°C.

• Replace the conductor with a larger one or with one capable of continuous operation 

above 100°C (reconductoring). 

Reconductoring, the replacement of transmission lines with conductors that withstand more 

electricity transfer, is the most common method of attaining significant increases in allowable 

ampacity. Although the physical characteristics of the new line may allow more electricity to be 

transferred, it imposes more weight on support structures. Horizontal wind pressure on wires 

causes most of the stress on tangent structures. Because most transmission structures are already 

near their structural limit, just replacing wires with larger diameter wires is usually not 

economically viable. 
37

Traditional conductors (e.g., ACSR, all-aluminum) used on most transmission lines are 

composed of aluminum strands or a steel core surrounded by aluminum strands. Aluminum 

expands faster than steel does when it is heated; therefore, conductors with high proportions of 

aluminum sag more than those with low proportions of aluminum. The strength of aluminum 

starts to degrade under sustained usage above 95°C, thereby limiting the maximum operating 

temperature of traditional conductors.

Aluminum conductor steel supported (ACSS) conductors have been used for reconductoring. 

The aluminum strands that surround the steel core on an ACSS conductor are fully annealed so

that they are too soft to carry wire tension. Because the steel carries all the tension, ACSS 

conductors do not sag as much as comparatively sized traditional conductors. Additionally, 

ACSS conductors can operate at much higher temperatures than traditional conductors without a 

loss of strength. The sag and tension characteristics of ACSS conductors can usually be matched 

to existing structure capacities such that a significant ampacity increase is realized with few or 

no structural modifications. 

Composite conductors are a relatively new option in the industry, but have generally been used 

with great success. The two primary options are the aluminum conductor composite reinforced

(ACCR) cable and the aluminum conductor carbon composite (ACCC). Each cable uses a special 

lightweight, high-strength core to carry the tension, surrounded by aluminum wire to carry the 

current. The ACCR cable uses a fiber reinforced aluminum matrix core surrounded by 

aluminum-zirconium strands. The ACCC cable uses a high-strength carbon and glass fiber core, 

embedded in a high-performance thermoset resin matrix, surrounded by fully annealed aluminum 

wire. When compared to the ACSS conductor, the primary advantage of each cable is the low 

thermal expansion characteristics of its core, which allows the cable temperature to increase 

greatly with little increase in sag. Although the material cost of these products can be high, 

structure modifications are minimized, resulting in cost-effective installation.

The thermal rating of an existing line can be increased by approximately 50% by using a 

replacement conductor that has twice the aluminum area of the original conductor. The larger 

conductors can double the original strain structure tension loads and increases transverse 

wind/ice conductor loads on suspension structures by approximately 40%. Such large load 

increases typically would require structure reinforcement or replacement. This drawback to the 

use of a larger conductor may be avoided by using the HTLS conductor, which can be operated 

at temperatures above 100°C while exhibiting stable tensile strength and creep elongation 

properties.

Practical temperature limits of up to 200°C have been specified for some conductors. Using the 

HTLS conductor, which has the same diameter as the original, at 180°C can increase the line 

rating by 50%, often without any significant change in structure loads. If the replacement 

conductor has a lower thermal elongation rate than the original, then the structures will not have 

to be raised. Although the use of a larger conductor provides a reduction in losses over the life of 

the line while operating temperatures remain at a modest level, the use of the HTLS conductor 

reduces capital investment by minimizing structure modifications. 

Conductors are constructed from helically stranded combinations of individual wires. Galvanized 

steel wires are used for mechanical reinforcement, aluminum wires for the conduction of 

electricity, and hard-drawn aluminum for both mechanical and electrical purposes.
38

Desirable properties for reinforcing core-wire material include a high elastic modulus, a high 

ratio of tensile strength to weight, the retention of tensile strength at high temperatures, a low 

plastic and thermal elongation, a low corrosion rate in the presence of aluminum, and a relatively 

high electrical conductivity. The material must be easy to fabricate into wire for stranding.

Choices available for HTLS conductors include the following:

• ACSS and ACSS/twisted annealed aluminum strands over a conventional steel stranded 

core; operation to 200°C

• Gap type heat resistant aluminum alloy conductor steel reinforced high-temperature 

aluminum, grease-filled gap between core/inner layer; operation to 150°C; gap type super 

heat resistant aluminum alloy conductor steel reinforced

• ACCR high-temperature alloy aluminum over a composite core made from alumina 

fibers embedded in a matrix of pure aluminum; operation to 210°C

• Composite reinforced aluminum conductor annealed aluminum over 

fiberglass/thermoplastic composite segmented core; probable operation to 150°C

• Aluminum conductor composite carbon fiber reinforced annealed or high-temperature 

aluminum alloy over a core of strands with carbon fiber material in a matrix of 

aluminum; probable operation to 210°C

Table 6 illustrates the capacity increases and relative cost of reconductoring an existing ACSR 

transmission line with various conductors of equal diameter.

Table 6. Relative Cost of Reconductoring 

CONDUCTOR

DIAMETER

(IN)

ALUM 

AREA

(KCMIL)

WEIGHT

(LB/KFT)

AC RESISTANCE -

75°C AMPACITY RATINGS RELATIVE 

COST

(ohm/kft) ∆% 75[°C] 100[°C] 200[°C] (APPROX.)

Drake ACSR 1.108 795 1093 0.0266 905 1115 - - - 1

Drake ACSS 1.108 795 1093 0.0258 -3.0% 919 1132 1660 1.2

Suwannee 

ACSS/TW 1.108 960 1317 0.0216 -18.8% 1010 1245 1831 1.3

Suwannee 

ACCR/TW 1.108 958 1075 0.0211 -20.5% 1812 5

Drake 

ACCC/TW 1.108 1020 1043 0.0206 -22.6% 1029 1267 1861 2.5

Suwannee 

ACSR/TW 1.108 960 1317 0.0218 -18.0% 1000 1233 - - - 1.1

Note:

1. Conductors with an overall diameter equal to the standard ACSR conductor allow reconductoring without major 

structure reinforcement.

2. Ambient Temperature 25°C, wind speed 2 ft/sec., full sun.

3. Costs are relative estimates and costs for newer composite core conductor may decrease with higher volume.

Superconductors have received press coverage over the last several years and may be applicable 

in very specific applications.84

 84 American Superconductor, “New Transmission Options – Case Study Super Conductor Cables,” Transmission 

Policy Institute, Colorado, 2011. http://www.narucmeetings.org/Presentations/MCCALL%20NARUC%204-

2011.pdf. Accessed August 2012.
39

3.2.3 Dynamic Circuit Ratings

The actual thermal capacity of a transmission circuit is determined by the conductor temperature 

at each point in time. This conductor temperature is dependent on the magnitude of current flow, 

conductor resistance, and ambient weather conditions (temperature, humidity, wind). While the 

current flow can be accurately measured and the conductor resistance is known, the ambient 

weather conditions along the length of the transmission line are difficult to monitor. To be on the 

safe side, thermal ratings of lines are calculated assuming the most adverse seasonal weather 

condition. If actual conditions were known, the line could be allowed to carry more power than 

the worst case ambient conditions allow.

Various schemes are available to more accurately determine the true thermal limits of a 

transmission circuit based on real-time monitoring. With these measurements, thermal limits of 

the line could be calculated on a real-time basis. While systems that employ remote 

measurements may hold the most promise to accurately determine conductor temperature, they 

require power and communications, which can limit their effectiveness and increase their cost. 

The EPRI has developed the Dynamic Thermal Circuit Rating program85 for dynamic rating of 

transmission line equipment and various manufacturers offer systems as well. Four types of realtime monitors have been used in the industry for this purpose:

1. Weather data monitors measure ambient temperature, wind speed, wind direction, and 

solar heating. When combined with line current data, the conductor temperature and sag 

can be calculated and compared to the allowable sag.

2. Conductor temperature monitors consist of a thermocouple clamped to the conductor. 

The sag in the conductor can then be calculated and compared to the allowable sag.

3. Tension monitors consist of a load cell placed between a dead-end insulator string and the 

structure. The sag in the conductor can then be calculated and compared to the allowable 

sag.

4. Sag monitors use laser surveying technology to measure sag directly. They can be 

configured to take measurements at preset intervals or on demand.

Monitors are installed at multiple locations because conductor temperature can vary when the 

geographical orientation of the line (e.g., N-S or E-W) changes significantly. Some segments are 

more prone to the effects of wind and sun than are others. 

The data from each monitor is relayed to the utility’s operations center where software calculates 

a dynamic circuit rating. The benefits of dynamic rating are dependent on the level of 

conservatism used in the original static circuit rating. Under peak loading conditions, the 

increased rating of the circuit through the use of real-time monitors is typically low when 

compared to increases achieved through other means. However, the cost is lower as well. Realtime monitoring can also be an appropriate solution when reconductoring and/or structure 

upgrades are not practical due to permitting or outage concerns. Typical of these types of system 

is the one employed in ERCOT.86

 85 Electric Power Research Institute. (2007). “DTCR 4.1.” 

http://mydocs.epri.com/docs/ApplyingResults/Ready_Now/PDU/2007_Application_Plan_for_P164-001_DTCR_4-

1.pdf. Accessed August 2012. 86 Johnson, Justin “Smart Grid Demonstration Project – Dynamic Line Rating,” Oncor Electric Delivery Company, 

2010.
40

In some cases, the capacity of existing transmission circuits is limited by the thermal rating of 

terminal equipment. In some cases, involving equipment such as switches, wave traps, and other 

relatively inexpensive devices, direct replacement is sometimes possible. For more expensive 

equipment, such as transformers, dynamic rating may be possible using software to calculate 

internal temperatures that allow increased power flow at certain times. EPRI has released Power 

Transformer Loading software designed to calculate real-time ratings of transformers.

87

3.2.4 Voltage Uprating

Thermal limits on transmission lines are determined by the current flow and not directly by the 

power transfer. Power flow is proportional to the product of the voltage and current. By 

increasing the applied voltage (voltage uprating), power transfer can be increased without a 

corresponding increase in current. Unfortunately, voltage uprating introduces other issues, such 

as insulation strength and clearances, corona, electromagnetic fields, and radio frequency 

interference. 

Increasing the applied voltage on a transmission circuit will require replacement of the 

insulators, possible modification to the tower design to maintain adequate clearances, and /or 

changes to terminal equipment. It may also impact conductor selection to mitigate the issues 

created at the higher voltages. While small temporary voltage increases could be tolerated on 

transmission lines (a few percent), significant increases in voltage will require redesign of the 

line. Voltage increases could also require widening the right-of-way. Voltage uprating may be 

attractive where compact line design principles can be applied. These allow reconductoring of an 

existing line with minimal tower changes and within the existing right-of-way.

Transmission line conductors are rated by ampacity, not voltage. Uprating the voltage on an 

existing transmission line results in a proportional increase in its transfer MVA capacity. The 

required replacement of the insulators with longer ones can create clearance problems as follows: 

• Conductors supported by insulators that hang vertically (e.g., I-Strings and V-Strings) 

have reduced ground clearance and may have reduced clearance between phases. When 

subjected to wind, the insulators swing further horizontally, which can result in clearance 

violations to the structure or come close to facilities at the edge of the right-of-way.

• Insulators mounted horizontally (e.g., Line Posts) put higher stresses on the structures 

and may result in inadequate clearance between phases or to come to close to facilities at 

the edge of the right-of-way. 

If these issues can be overcome without the need for extensive structure modifications, then 

uprating the voltage on a transmission line may be a viable option. However, the substation 

facilities at each end must be expanded, if not completely rebuilt, and construction for voltage 

improvements typically requires extended outages and may result in unacceptable impacts to 

other entities. 

 

http://www.ercot.com/content/meetings/ros/keydocs/2010/0625/05._OncorDynamicLineRatingProject06252010_.pp

t#363,1,Smart. Accessed August 2012. 87 Electric Power Research Institute. (2008). “Development of Algorithms to Include New Research Data on Loss of 

Life.”

http://mydocs.epri.com/docs/ApplyingResults/Ready_Now/PDU/2008/2008%20Application%20Plan%20for%20P3

7-002%20PTLOAD-%20Development%20of%20algorithms%20to.pdf. Accessed August 2012.
41

As long as those issues can be mitigated, voltage uprating can provide a substantial increase to 

the transfer capacity of a transmission line. Live line uprating offers a means of reducing outage 

time on critical transmission lines.
42

4.0 Increasing System Limits

4.1 Voltage and Stability Control

Voltages throughout the system must remain within an acceptable range at all times for system 

reliability. When power flows through a transmission line, the voltage drops. Voltage at the 

receiving end of a line is lower than at the sending end. If large amounts of power are transferred 

over long distances, the bulk transmission system must maintain adequate voltage at the 

receiving end. Voltage can also drop as a result of outages of critical facilities. If a sudden outage 

of a transmission line occurs, power will continue to flow at the same level, but on less efficient, 

alternative parallel paths. As a result, the voltage drop in the transmission system increases, and 

there will be an abrupt change in the voltage at the receiving end. Voltage drops or voltage 

fluctuations at the customer end reflect reduced system reliability.

4.1.1 Stability Constraints

Normally, all generators on an interconnected system operate in synchronism. That is, each 

generator operates at precisely the same frequency (60 Hz in North America). System 

disturbances, such as load changes or facility outages, will cause the speed (frequency) of one or 

more generators to change relative to other generators. In addition, the magnitude of other 

frequency-dependent items, such as the load, also changes and causes imbalances in the system. 

Generator controls sense such changes and change the power output of the affected generators to 

synchronize the system.

This stability is compromised under two types of conditions: steady-state instability and transient 

instability. 

• Steady-state instability occurs when the system cannot return to synchronous operation 

because of excessive power flows. The speed of some generators changes relative to 

others, causing system separation, a break-up of the transmission system, or a blackout.

• Transient instability occurs when a major disturbance (such as a short circuit on a 

transmission line or the loss of a large generating unit) is experienced, causing generators 

to oscillate relative to each other. If the system cannot damp the oscillations quickly, for 

example, by changing the output of generators, the oscillations will increase, causing 

large fluctuations in line loadings and system voltages. The result is the same as for 

steady-state instability: system separation, a break-up of the transmission system, or a 

blackout. 

These events are not common in modern transmission networks, primarily because of the 

planning and coordinated operations.

If power flows exceed dynamic limits over wide areas, the grid can exhibit unstable behavior. If 

not controlled, this can trigger large-scale outages. Dynamic grid stability is a critical issue for 

power system management. To maintain reliability, potential instabilities must be sensed and 

responded to quickly. 

While transmission lines have a designed power handling capacity based on thermal limits, 

instabilities frequently limit maximum transmitted power to levels significantly less. In 

particular, this limits both the amount of power that can be imported from outside a region and 

amounts that can be transferred from one region to another. The addition of significant remote 
43

generating facilities, much of it with low inertia, may have undesirable effects by reducing the 

overall system damping under sudden energy imbalance, such as generation trips.

Addressing stability limits requires study to identify the source of the problem. Operating 

procedures or altered protective systems may be implemented to eliminate or mitigate stability 

problems and increase the power transfer capability of the existing grid.

4.1.2 FACTS Devices

FACTS technology refers to power electronic devices used to enhance the operation and control 

of the electric power grid. FACTS devices use power electronic components and conventional 

equipment in different configurations for switching or controlling reactive power for active 

power conversion or control. 

FACTS technology increases the value of the transmission system by facilitating a greater 

utilization of the system’s assets. FACTS technology increases the steady-state or transient 

stability (or both) operating regions of the system. To do this, FACTS devices apply strategies to 

influence the operating parameters of the transmission system. These methods are categorized as 

follows:

• Voltage controller

• Line impedance controller

• Power flow controller

Several FACTS devices are currently in operation in United States, and they are applied in 

various configurations. Table 7 lists the EPRI sponsored FACTS devices installed in United 

States.

Table 7. EPRI-sponsored FACTS installations88

EPRI SPONSORED FACTS INSTALLATIONS

DEVICE DESCRIPTION LOCATION HOST 

UTILITY

Unified Power Flow 

Controller (UPFC)

+/- 160 MVA Shunt; +/-160 

MVA Series'

Inez Substation, 

Kentucky AEP

Thyristor Controlled Series 

Capacitor (TCSC)

Line Impedance Controller 

208 MVAR 

Slatt Substation; 

Oregon BPA

Back-to-Back HVDC Tie 36 MW Eagle Pass, Texas CSW

Static Synchronous 

Compensator (STATCOM) Voltage Controller +/- MVAR Sullivan Substation, Tennessee TVA

Convertible Static 

Compensator (CSC)

Flexible Multifunctional 

Compensator +/- 200 MVAR

Marcy Substation, 

New York NYPA

4.1.2.1 Static VAR Compensator

An important type of FACTS in use today is the static VAR compensator (SVC). An SVC is a 

shunt-connected, static generator and/or absorber of reactive power, in which the output is varied 

 88 “Efficient Transmission Systems Program 172.” (2012). 2012 Research Portfolio. Electric Power Research 

Institute, Palo Alto, CA. http://portfolio.epri.com/ProgramTab.aspx?sId=PDU&rId=201&pId=6310/. Accessed 

August 2012.
44

to maintain or control specific parameters of an electrical power system.89 SVCs are used mainly 

to regulate system voltages; these devices combine thyristor-based power electronics with 

inductors and/or capacitors to rapidly and accurately produce or consume reactive power. 

Producing (out of the SVC) reactive power at a bus will raise the bus voltage; similarly, 

consuming (into the SVC) reactive power will lower the bus voltage. 

SVCs were one of the first technologies classified as a FACTS device, shown in Figure 10 as a 

second-generation controlled device.

Figure 10. FACTS devices90

SVCs have several features that require attention. Due to the nature of power electronic 

switching, SVCs (and FACTS equipment in general) generate harmonics (i.e., multiples of the 

fundamental voltage/current frequency), which can have adverse affects on power system 

quality. To counter these effects, filters must be employed. In addition, SVCs experience a 

marked decrease in their capacity to generate/absorb reactive power when system voltages are 

low (in the same manner as conventionally switched reactor or capacitor banks). Finally, because 

SVCs use conventional AC reactors and capacitors, the overall footprint of the equipment is 

larger than a comparatively capable STATCOM device (from a reactive power 

generation/absorption perspective).

SVCs are voltage control devices and can enhance both the steady-state and transient voltage 

stability of the transmission system. Improved system voltage profiles can enhance power 

 89 Mathur, R., Mohan, and Varma, Rajiv K.(2002). “Thyristor-Based FACTS Controllers and Electrical 

Transmission Systems,” New York, NY: Wiley-IEEE Press. 90 Adapted from Siemens “Discover the World of FACTS Technology Technical Compendium.” (2011). 

http://www.energy.siemens.com/hq/pool/hq/power-transmission/FACTS/FACTS_Technology_.pdf. Accessed 

August 2012.
45

transfer capabilities, and the absorption/generation of reactive power can improve rotor 

angle/system frequency transient stability (via power system damping). These improvements are 

not always directly controllable by an SVC device, and thus are indirect system benefits.

Hundreds of SVCs have been installed all over the world. One of the largest SVCs in the United 

States is in Devers, California. Southern California Edison and CAISO identified voltage 

stability constraints from increasing the power imported into California from Arizona.91 Southern 

California Edison installed a 440-MVAR SVC at Devers in 2006, which subsequently increased 

the California import. Similarly, Entergy installed a 300-MVAR SVC in Porter near New

Orleans to increase the power import capability into New Orleans area.

4.1.2.2 Static Synchronous Compensator

Like SVCs, STATCOM devices are also shunt-connected, reactive-power compensation 

equipment capable of generating and/or absorbing reactive power. The output can be varied to 

control the specific parameters of an electric power system. Unlike SVCs, STATCOM devices 

use voltage source converters—generally comprised of gate turn off thyristors or Insulated Gate 

Bipolar Transistors (IGBTs)—and a direct current (DC) voltage source to generate a set of threephase AC output voltages. Because of this, STATCOMs appear as an adjustable voltage source 

behind a reactance, and as such do not require capacitor or reactor banks to generate/absorb 

reactive power. As a result, a STATCOM is more compact, has a smaller footprint, and generates 

less noise/magnetic impact (as compared to an SVC).

As with SVCs, STATCOMs produce harmonics as a result of power electronic switching. To 

resolve these undesired effects, STATCOMs can employ filters. However, their robust switching 

capability also enables them to employ strategies to simply mitigate (as much as possible) 

harmonic production. Although STATCOM devices provide a measure of capability beyond 

SVCs, the fundamental intent of these devices is to provide voltage control (through reactive 

power support) to the system. A summary of the characteristics of SVCs versus STATCOMs is 

provided in Table 8.

 91 Kowalski, J et.al. “Application of Static VAR Compensation on the SCE System,” IEEE PES PSCE, 2006.
46

Table 8. SVCs versus STATCOMs92

ISSUE STATCOM SVC

V/I characteristic Good undervoltage performance 

Current Source

Good overvoltage performance 

Impedance

Control range Symmetrical otherwise 

Hybrid solutions

Freely adjustable to any range by 

TCR/TSR/TSC branches

Modularity

Same converter usable for various 

applications (STATCOM, UPFC, 

CSC, B2B etc.) 

Redundancy no degraded mode

TCR/TSR/TSC branches used in SVC 

and TCSC/TPSC 

Redundancy

Degraded mode operation

Response time 1 to 2 cycle 2 to 3 cycle

Transient behavior Self protecting at critical system faults Available before, during, and after 

critical system conditions

Space requirement 40% to 50% 100%

Availability 96% to 98% >99%

Investment costs 120% to 150% 100%

Similar to an SVC, the STATCOM can be classified as a voltage controller and it is used

primarily to improve the voltage stability of the transmission system. Here again, indirect system 

benefits are also applicable, as with the SVC. However, these improvements are not necessarily 

directly attributable to the STATCOM device. Unlike the SVC, the voltage source converter 

technology used in STATCOM devices allows independent control of output current over the 

entire inductive/capacitive range, irrespective of the system voltage. This means that the 

STATCOM can provide voltage support during periods of low system voltage (i.e., faults), and 

in other situations where system voltage collapse is of concern.

Several STATCOMs are installed in United States. An early project sponsored by EPRI at 

Sullivan substation in Tennessee began operation in 1995. The STATCOM enabled Tennessee 

Valley Authority to defer capital expenditures for an additional substation transformer, or an 

additional 161-kV line. A recent installation at Stony Hill, Connecticut, employed an 8-MVAR 

STATCOM together with switched capacitors to increase the power import into Southwest 

Connecticut by 100 MW.

93 Another recent STATCOM installation at Essex, Vermont, provided

voltage stability in response to significant load growth. The 7-MVAR STATCOM provided the 

needed stability control and was compact. 

4.1.2.3 Series Static Synchronous Compensator

Like the STATCOM, the SSSC appears (to the system) as an adjustable synchronous voltage 

source; unlike the STATCOM (and as the name implies), the SSSC is connected in series with a 

transmission line (see Figure 11). This connection enables the device to vary the effective

impedance of the transmission line (by injecting a voltage containing an appropriate phase angle 

in relation to the line current). The system enhancements available from an SSSC mirror those 

offered by a conventional series capacitor used to compensate transmission lines, including 

 92 Adapted from: Tyll, H.K. (2004). “FACTS Technology for Reactive Power Compensation and System Control,” 

Transmission and Distribution Conference and Exposition: Latin America, 2004 IEEE/PES, Sao Paulo.

93 M. Henderson, et.al. (2010). “Planning HVDC and FACTS in New England.” 

http://ieeexplore.ieee.org/xpl/mostRecentIssue.jsp?punumber=5479080.
47

increased power transmission capability, improved system stability, reduced system losses, 

reduced voltage drop, and optimized (balanced) power flow along parallel lines.

Figure 11. SCCC electrical diagram94

As with SVCs/STATCOMS, SSSC devices can introduce harmonics due to the nature of the 

power electronic switching. Compensation techniques are similar to those previously identified 

for the STATCOM.

The manner in which the SSSC performs (particularly improvements to system stability) 

provides the transmission system with a powerful device capable of quickly responding to a 

variety of abnormal conditions and performing as a line impedance controller. 

When the power system is disturbed (e.g., during a fault), the connected synchronous machines 

may accelerate or decelerate, and system frequency may rise or fall above the nominal value 

(60 Hz). While these occurrences are not unexpected, they are not desired. Rather, it is 

advantageous to return the system to a steady state condition (generally as quickly as possible). 

In these situations, the line impedance controller enables the SSSC device to either increase or 

decrease the amount of power transmitted from a generator (helping to counter the machine 

acceleration or deceleration) by increasing or decreasing the inductive/capacitive reactance of the 

line; this helps to damp the power swing oscillations and facilitates a quicker return of the system 

to steady state.

SSSC devices can also be used to increase (or decrease) current flow on a line, and even balance 

the current flows in parallel lines. In both instances, the effective line impedance is varied 

according to the implemented control scheme (and its desired outcomes). The result is a change 

in flow corresponding to the increase or decrease of the effective line impedance. While the 

SSSC is able to control power flows indirectly (by varying the line impedance), it does not 

provide complete power flow control capability (provided by devices offering phase angle 

shifting capability).

An SSSC device does not introduce a physical capacitor into the transmission line and hence it 

does not cause sub-synchronous resonance.

 94 Adapted from: Chow, Joe H. “Voltage-Sourced Converter Based FACTS Controller Seminar,” NSF US-Africa 

Research and Education Collaboration Workshop, December 15, 2004.
48

4.1.2.4 Unified Power Flow Controller / Interline Power Flow Controller

The UPFC and IPFC are the most versatile FACTS-based devices thus far developed. The key 

distinction between the UPFC and IPFC is that the UPFC is designed to perform its control 

functions on only one line, whereas the IPFC is intended to compensate and manage power flows 

for multiple lines. The methods and control strategies implemented by each device, however, are 

quite similar.

Both the UPFC and IPFC are combinations of the STATCOM and SSSC devices. Accordingly, 

both offer all three FACTS controller capabilities (i.e., voltage controller, line impedance 

controller, and power flow controller).

Of particular note is the true power flow control nature of the UPFC/IPFC, as compared to the 

SSSC. Whereas the SSSC affects power flow by modifying the effective line impedance, the 

UPFC/IPFC can control power flow quantity and direction by regulating bus voltage phase 

angles (i.e., phase angle shifting). By facilitating the control of each of the aforementioned 

parameters, these devices directly provide all three of the system benefits identified (i.e. 

increased power transfer, improved voltage stability, and enhanced rotor angle/system frequency 

stability). These increased capabilities are accompanied by increased cost, but the overall 

contribution of the UPFC or IPFC device to the transmission system can be of significant value.

Two EPRI-sponsored UPFC projects are operating in the United States. The Inez UPFC was the 

first of its kind in the world and was placed into service in 1998. The other UPFC project in the 

United States is the convertible static compensator (CSC) at the Marcy substation on the New 

York Power Authority (NYPA) transmission system. Two of the New York State system’s major 

interfaces are the Total East interface and the Central East interface. Before application of the 

CSC device, the transfer across these interfaces was limited to 6150 MW and 2880 MW, 

respectively. These limits were imposed due to voltage collapse and power system damping 

concerns that could occur under critical contingencies.

Extensive studies performed by NYPA and EPRI identified the need for both voltage support and 

power flow management capabilities.95 The CSC device provides a readily customizable 

FACTS-based solution, which can be adjusted depending upon the needs of the system. As such, 

it provides all of the following capabilities: STATCOM, SSSC, UPFC, and IPFC. These various 

capabilities are available in two +/- 100 MVAR rated units.

Results from system operations demonstrated increased power transfers of 114 MW on the Total 

East interface, and 65 MW on the Central East interface.96 In addition to a greater utilization of 

the existing transmission infrastructure, other benefits provided by this equipment include 

relieved power transfer bottlenecks, improved voltage control, and reduced system losses.

4.1.2.5 Thyristor Controlled Series Capacitors

A TCSC is an extension of conventional series capacitors by adding a thyristor controlled 

reactor. Placing a controlled reactor in parallel to the series capacitor provides a continuous and 

rapidly variable series compensation system. In some applications, thyristors are used just to 

protect the series capacitor, rather than controlling the series compensation, and they are called 

thyristor protected series capacitors (TPSCs). Figure 12 compares the two devices.

 95 Edris, A. (1999). “FACTS Technology Development: An Update.” IEEE Power Tech Conference, Budapest, 

Hungary.

96 Fradanesh, B. and Schuff, A. (2003). “Dynamic Studies of the NYS Transmission System With the Marcy CSC in 

the UPFC and IPFC Configurations.” Transmission and Distribution Conference and Exposition, IEEE PES.
49

Thyristor Controlled Series Capacitor

Thryristor Protected Series Capacitor

Figure 12. TCSC and TPSC97

Series compensation increases the power flow on a circuit by reducing the series impedance 

between the sending end and the receiving end. The TCSC, in addition to providing the benefit 

of a fixed series capacitor, offers the advantage of power flow control by altering the series 

impedance. Power flow control helps either increase the flow when the load requires it or reduce 

when transmission congestion occurs.

 97Adapted from http://www.energy.siemens.com/co/en/power-transmission/facts/series-capacitor/ -

content=Applications
50

The first-ever TCSC was installed in WAPA system at Kayenta, Arizona, in 1992. This was 

installed to increase the power transfer capacity between Shiprock substation in New Mexico and 

Glen Canyon substation in Arizona.

98 Another TCSC is in operation at Slatt substation in 

Oregon.

4.1.2.6 Comparing FACTS Devices

Table 9 summarizes how each of the FACTS devices provides benefits. Some devices provide 

indirect benefits to system parameters as a result of their direct (i.e., targeted) improvements. 

Accordingly, the table below indicates which system improvements (generally) are directly 

attributable to the capabilities offered by each device. 

Table 9. Comparison of FACTS Devices

FACTS DEVICE

INCREASED 

POWER 

TRANSFER

IMPROVED 

VOLTAGE 

STABILITY

ENHANCED 

ROTOR 

ANGLE/SYSTEM 

FREQUENCY 

STABILITY

SVC Indirect Direct Indirect

STATCOM Indirect Direct Indirect

TCSC / SSSC Direct Indirect Direct

UPFC/IPFC Direct Direct Direct

Table 10 provides a relative comparison of the benefits for different applications for each of the 

FACTS devices.

Table 10. Relative Comparison of Benefits

FACTS DEVICE LOAD FLOW 

CONTROL

VOLTAGE 

CONTROL

TRANSIENT 

STABILITY

DYNAMIC 

STABILITY

SVC X XXX X XX

STATCOM X XXX XX XX

TCSC XX X XXX XX

UPFC XXX XXX XX XX

Installation cost of a particular FACTS device depends on various factors such as redundancy, 

ambient conditions, and location. Voltage stability can be enhanced using the FACTS devices 

listed, and their application can often be used in place of building additional transmission.

4.2 Power Flow Control

In addition to the described technologies, power flow controlling devices can increase the 

transfer capacity of lines. In contrast to the situation described in the previous examples, these 

devices allow for active control of the flow in the line. A well-known technology for controlling 

line flow are PSTs.

 98 Christi, N., Hedin, R., Johnson, R., Krause, P., Montoya, A. (1991). “Power System Studies and Modelling for the 

Kayenta 230 kV Substation Advanced Series Compensation.” IEEE 5th International Conference on AC and DC 

Transmission.
51

4.2.1 FACTS Devices

In addition to controlling voltage and stability, FACTS devices can directly control power flow.

By controlling power flow, localized overloads can be mitigated by diverting power from the 

over loaded circuit to other parallel paths. A more detailed discussion of FACTS devices is 

presented in the previous sections.

4.2.2 High-Voltage Direct Current Lines

HVDC devices have a long (and evolving) history of application in electrical power systems. 

Although most transmission is provided via AC, DC applications can provide economic and 

technical benefits to more fully utilize the existing transmission system infrastructure. In addition 

to the classic application of long distance, point-to-point transmission or long lengths of cable, 

HVDC can provide important technical benefits when interconnecting large AC networks where 

only weak AC interconnections exist. The three major U. S. interconnections use HVDC links.

In an HVDC transmission system, AC voltage is converted to high-voltage DC using power 

electronic devices, such as thyristors or high power transistors. The systems that use thyristors 

are known as classic HVDC / Line Commutated Converters / Current Source Converters. The 

DC systems that use high-power transistors, such as IGBTs, are called Voltage Source 

Converters as well as specific manufacturer trade names. 

HVDC transmission systems are used in long-distance overhead transmission applications, 

primarily for economic reasons and stability considerations, and in underground/underwater 

applications, as the only technically viable alternative in certain instances. HVDC cables do not 

have a charging current effect like AC cables, which make DC cable transmission superior to AC 

beyond a certain length.

Since the first HVDC system was placed in service in Gotland, Sweden, in 1954,99 HVDC 

technology has progressed in both size and implementation. The Gotland project connected two 

AC systems via a submarine cable link, utilizing mercury arc valves to convert AC to DC. The 

project was rated at 20 MW and 100 kV. Today, depending on the selected converter technology 

(i.e., line commutated or voltage-source), the ratings of HVDC systems can reach 2000 MW and 

800 kV, for line-commutated or thyristor-based converters, and 400 MW and 300 kV, for 

voltage-source or IGBT-based converters. Accordingly, a variety of proven HVDC technologies 

can be designed and implemented to help improve an assortment of transmission system 

limitations and constraints. 

Generally, HVDC overhead line towers are much more compact than equivalent AC 

transmission line towers. Therefore, HVDC transmission systems require less right-of-way, as 

compared to an AC transmission system of the same power transfer level. In other words, HVDC 

transmission systems can deliver more power than an AC transmission system for the same 

amount of right-of-way. For example, an 8000-kV AC line has a capacity of 2000 MW and 

requires 75-m right-of-way. In contrast, a 500-kV DC line has a capacity of 3000 MW and only 

requires 50-m right-of-way.100 By using advanced control techniques, HVDC lines can provide 

 99 “The Gotland HVDC Link” (2012). ABB Power Technologies. 

http://www.abb.com/industries/ap/db0003db004333/8e63373c2cdc1cdac125774a0032c5ed.aspx. Accessed August 

2012.

100 Weimers, Lars. (undated). “Bulk Power Transmission at Extra High Voltages, a Comparison Between 

Transmission Lines for HVDC at Voltages Above 600 kv dc and 800 kv ac,” ABB Power Technologies. 

http://www05.abb.com/global/scot/scot221.nsf/veritydisplay/56aef360ec16ff59c1256fda004aeaec/$file/04mp0274%

20rev.%2000.pdf. Accessed August 2012.
52

system damping, which can help to improve stability and potentially improve overall system 

transfer capability in the connected system.

4.2.2.1 HVDC Back-to Back Systems

In back-to-back applications, the fundamental building blocks for all HVDC systems, the power 

converters, are co-located and separated by a short run of interconnecting DC bus work (see 

Figure 13). These devices have a solid history of use in interconnecting asynchronous AC 

transmission systems throughout the world.

Figure 13. Back-to-back HVDC system configuration101

Back-to-back HVDC systems are particularly suited to connect two asynchronous AC systems, 

such as between WECC and the Eastern Interconnect or between ERCOT and the Eastern 

Interconnect. Figure 14 shows the back-to-back and the long-distance HVDC transmission

systems that are currently in operation in North America. By using appropriate control strategies, 

a back-to-back HVDC link can provide the required system damping that improves the overall 

performance of both the transmission systems to which it is connected and allow higher levels of 

transfer between the two systems.

Figure 14. HVDC systems in North America102

 101 Adapted from Siemens “HVDC Classic,” United States. http://www.energy.siemens.com/hq/en/powertransmission/hvdc/hvdc-classic/. Accessed August 2012.
53

HVDC systems are customized for each application, and the technology is changing rapidly so it 

is difficult to find general cost data.103

4.2.2.2 Segmentation and Grid Shock Absorbers

HVDC is particularly effective for interconnecting two AC grids when conventional AC 

interconnection is not feasible for technical reasons. The current grid configuration consists of a 

tight network of AC lines with some HVDC links employed for special conditions. Advances in 

HVDC technologies have presented other opportunities for the application of HVDC 

technologies in an overall structural way. The grid in the United States has pockets of AC that 

would benefit from having the weak AC interties replaced with HVDC interties. 

The advantage of HVDC interties is that power can be scheduled over the HVDC lines in much 

the same way that power can be scheduled from a generator. Another advantage of HVDC 

interties is their control capabilities to act as shock absorbers, by injecting and extracting energy 

more quickly and precisely from the connected AC grids than conventional AC controls. Typical 

HVDC response to a disturbance includes the following:

• During normal conditions, each HVDC tie is operated in a conventional manner with 

power flow held at scheduled levels on each tie until a disturbance is sensed on either 

side of the HVDC link.

• The disturbance is indicated by changes in frequency beyond a small threshold. Power 

transfer is automatically changed to support a falling frequency or limit a rising 

frequency.

• Power flows can be increased up to the ratings of the HVDC ties or to the thermal or 

voltage limits imposed by adjacent ac systems on either side of the HVDC ties.

• Without the protection assured by grid segmentation, disturbances can propagate without 

bounds, causing tie power flows to increase to levels exceeding thermal limits, and 

eventually violating voltage and angular stability limits, triggering cascading.

• With HVDC ties, power transfers are limited to safe levels that will often be beyond the 

stability limits of AC ties.

• Unlike unsegmented grids where the possibility of any one AC tie reaching a thermal or 

voltage limit requires constraining the loading of other parallel ties to levels substantially 

below their thermal capabilities, and which are thus underutilized, each HVDC tie can 

operate up to its local thermal or voltage limit.

• The ability to control power flows at the perimeter of an area (AC sector) allows 

adjustment of power flows to counter disturbances and internal problems that could 

otherwise result in intra-area cascading.

• Centralized control and coordination of power flows over the HVDC ties will be limited 

to normal dispatching of inter-area power flows and remedial adjustments to limit or 

reduce power flow in weakened areas within a sector. (The latter capability is generally 

 102 Adapted from Bahrman, Mike “Overview of HVDC Transmission,” IEEE PSEC Conference, Georgia, 

November 1, 2006. http://www.ieee.org/portal/cms_docs_pes/pes/subpages/meetingsfolder/PSCE/PSCE06/panel2/Panel-02-1_Overview_of_HVDC_Transmission.pdf. Accessed August 2012. 103 For a discussion of cost data available in 2006, see the presentation of Mike Bahrman (referenced above).
54

available for today’s grids only from phase angle regulators in AC ties.) This degree of 

flow controllability is much faster and more manageable with HVDC ties.

• Inter-area support (traditionally provided by synchronizing power with its problematic 

lack of control) is provided by what is effectively a governor control on each HVDC tie 

that responds to frequency differences between asynchronous areas. When a disturbance 

in one area triggers increased power flow from adjacent AC systems via these controls, 

the frequency change in the adjacent systems will cause increased support from more 

remote AC systems.

• A major disturbance that causes frequency to drop in an area may load HVDC ties to 

their local power transfer limits. The first result is cascading avoidance. The second result 

is the activation of the spinning reserve in the affected system, as frequency is allowed to 

drop. Between increased tie flows and greater intra-area generator production from 

spinning reserve, the frequency drop may be arrested. If it is not, under-frequency load 

shedding that normally responds after a grid breakup will occur and arrest the frequency 

decay with a relatively lesser loss of customers.

4.2.3 Improved Real-Time Monitoring and Dispatch

Real-time monitoring within power systems is being actively pursued in the United States. Much 

of this activity could be categorized under the Smart Grid banner. Real-time monitoring provides 

a clearer picture of the state of the grid and allows operators to increase transfer across critical 

interfaces when stability and voltage margins are not compromised. This allows dynamic ratings 

for lines that are stability or voltage limited. While dynamic rating of the line may not increase 

firm transmission capacity, it may allow operators to schedule transmission circuits for non-firm 

transfer that have static limits.

Current efforts at real-time monitoring include the following.

• Real-time transmission temperature/sag to implement dynamic line rating

• PMUs to provide direct state measurements—a number of utilities have implemented 

programs to equip their systems with advanced real-time monitoring systems, including 

PMUs. The NYISO has recently announced installation of 39 PMUs as part of its Smart 

Grid initiative,104 and WAPA has initiated a similar project totaling $108 million.105 DOE 

funded approximately 50% of the Western synchrophaser project.

• Improved supervisory control and data acquisition systems to accept and process realtime information flow from remote monitors

Real-time monitoring requires real-time communications consistent with the speed of the 

monitoring equipment. The Power Line Carrier has been used for many years for relaying 

purposes. Increased data rates require more robust systems with higher capacity, such as fiber 

optic links. Fiber optic communication channels are commonly embedded in transmission 

ground wires and retrofitting existing transmission lines that do not have optical ground wire 

 104 Electric Power Research Institute. (2010). “Synchrophasor Enabled Smart Applications.” 

http://www.nyiso.com/public/webdocs/Issues_and_Trends/smart_grid/EPRI_Presentation_2010.pdf. Accessed 

August 2012.

105 IEEE, “Phasor Measurements: Systems and Applications.” 

http://www.ieee.org/portal/cms_docs_pes/pes/subpages/meetingsfolder/T_D_2005_2006/wedndesday/pn22/05TD0297.pdf. Accessed August 2012.
55

provides an economic method for using existing transmission facilities to enhance real-time 

monitoring.

Expansion and improvement of communication channels for transmission of real-time data 

includes fiber optic and improved Power Line Carrier. 

Real-time monitoring provides system operators with an important tool to optimally dispatch the 

system to maximize the available transmission capacity. By using real-time system information, 

operators can balance the non-dispatchable nature of wind and solar resources with dispatchable 

resources to maximize the available transmission capacity.

4.2.4 Phase Shifting Transformer

PSTs are electro-magnetic devices, similar to conventional transformers that are introduced in an 

existing transmission line. A PST contains two sets of windings, one in series and the other in 

parallel. It controls the power flow by adjusting the phase angle between the sending and the 

receiving ends of the PST and injecting voltage through the series windings.

A PST allows the transmission operator to control the power flow through a transmission line. 

Using this device, the flow through heavily congested lines can be reduced and shifted to 

transmission lines with spare capacity. This means that the transfer capacities rise as congestion 

diminishes. Furthermore, PSTs are relatively inexpensive devices, when compared to new 

transmission lines, and can often be placed in an existing substation. They have been less subject 

to public opposition due to environmental, political, or other concerns. As a result, the permitting 

process for a PST may be relatively problem free.

A PST, however, has some drawbacks. First, it adds an extra series element in the grid, which is 

subject to failure. Second, it generally increases the losses in the system as it distorts the natural 

flows in the power system. Third, the effects of power flow control are not necessarily positive 

for all parties involved. The effect of shifting the power flow is not local, and an increase in one 

place can induce a decrease in the other. A final disadvantage is that, in the case of multiple 

power flow controlling devices, they must be used in a coordinated way to avoid inefficient grid 

use. When multiple power flow controlling devices are installed in the transmission grid, local 

control can cause suboptimal or inefficient use of the available power system. 

When employing PSTs, analysis is often performed to develop strategies and circuit 

configurations that minimize the frequency of operation of the phase shifting mechanism since 

this leads to higher maintenance and potentially shortened life of the unit. Strategies such as the 

following have been investigated by at least one western utility: 

1. Control by power flow: Set power flow on the 230-kV circuit at a predefined level for 

overall system economic operation. During contingent situations or other changes in the 

system, adjust the phase shifter to maintain the predefined power flow on the circuit. This 

form of control implies automatic and continuous control.

2. Control by phase angle: Set the phase shifter at a fixed tap (angle) position during normal 

conditions. Change the tap position according to some predefined setting for contingent 

cases. This form of control implies non-continuous control by remote supervision.

3. Bypass control: The phase shifter is bypassed for maintenance or for specific conditions 

such as loss of 500-kV supply, or for economic operation under suitable system 

conditions.
56

4. Control for remedial action: A few remedial action schemes address events such as cable 

overload protection, over-voltage protection and under-frequency load shedding. The 

phase shifter control needs to be coordinated with the existing remedial action schemes 

and new remedial action schemes to be added in future.

4.2.5 Fixed Series Capacitors

Fixed series capacitors reduce the line impedance in long lines, increasing maximum power 

transfer. Greater the line impedance means lower the power transfer capability of the line. Unlike 

the shunt (parallel) capacitors, these series capacitors are not meant to supply reactive power. 

Hence, their power rating is relatively small. However, their voltage rating is higher than a shunt 

capacitor, and they are installed on elevated insulated platforms.

The cost of installing a series capacitor is approximately 10% of the cost of the overhead line on

which it is applied. The increase in power transfer capacity could be approximately 10% to 30% 

depending on the network topology.

Many series capacitors are in operation in United States, and many more are in planning stages. 

One of the recent projects was the replacement of older series capacitors at Eldorado substation 

in Nevada.

106 New series capacitors were placed in service in 2006 on 500-kV lines at Eldorado 

substation by Southern California Edison to increase the power transfer between Arizona/Nevada 

and Southern California.

4.3 Energy Storage

Energy storage devices offer the potential to increase individual transmission path transfer 

capability, although their primary emphasis has been to provide overall system benefits either 

through improved system dynamic performance or through energy price arbitrage. One of the 

primary distinguishing characteristics between the various types of energy storage devices is 

their energy storage capacity, which is the key determinant for whether a device can be effective 

in increasing transmission path transfer capability. Other features include cost, location, and 

efficiency. 

Table 11 lists the most common types of energy storage devices and a comparison of their cost.

 106 Siemens Power Transmission and Distribution. (2006). “Eldorado Series Capacitor Upgrade Project,” Highlights 

& Innovations in Transmission and Distribution. HVDC/FACTS Highlights. 

http://www.ptd.siemens.de/artikel0602.pdf. Accessed August 2012.
57

Table 11. Present Worth of 10-year Operation in Year 1 ($/kW)107

TECHNOLOGY/

USE

ADVANCED

LEAD-ACID

BATTERY

Na/S

(7.2 hr) Zn/Br VREDOX

LEAD-ACID 

BATTER 

WITH 

CARBONENHANCED 

ELECTRODES

Li-ION CAES

(8 hrs)

PUMPED 

HYDRO

(8 hrs)

HIGHSPEED 

FLYWHEEL

(15 min)

SUPERCAP

(1 MIN)

Long-duration 

storage, 

frequent 

discharge

2839.26 2527.97 2518.03 3279.34 2017.87 2899.41 1470.10 2399.90

Long-duration 

storage, 

infrequent 

discharge

1620.37 2438.97 1817.82 2701.41 1559.57 2442.79

Short-duration 

storage, 

frequent 

discharge

1299.70 905.53 1459.85 669.85 1409.99 965.73 834.62

Short-duration 

storage, 

infrequent 

discharge

704.18 697.78 999.78 625.57 960.48 922.87 793.02

Applying storage technologies to transmission systems requires sufficient energy and power capacity to be meaningful. 

 107Schoenung, Susan. (2011). Energy Storage Systems Cost Update a Study for the DOE Energy Storage Systems Program, Sandia Laboratory Report: 

Albuquerque, NM, SAND2011-2730. http://prod.sandia.gov/techlib/access-control.cgi/2011/112730.pdf. Accessed September 2012.
58

Figure 15. Maturity of energy storage technologies108

While a variety of energy storage technologies are under development, only a few have reached 

the stage where efficiency and cycling life time are viable.109

4.3.1 Battery Systems

Significant development is underway in storage technologies, including batteries and battery 

technologies. Some of these technologies are being used commercially, including for grid 

support. They provide many benefits for electric power utilities, transmission companies, 

electricity generators, and consumers. Some of the benefits are load leveling, spinning reserve, 

absence of emissions, and deferral of investment for new generation and transmission 

equipment. Some of the batteries used in grid applications are as follows:

• Lead Acid Batteries: Lead acid is one of the oldest and most developed battery 

technologies. These batteries are much cheaper when compared to other battery 

technologies. The major disadvantage is that they use lead, which is toxic and needs to be 

recycled. 

• Sodium Sulphur Batteries: Sodium sulphur batteries are high temperature batteries. They 

have operating temperatures of 300 °C to 350°C. They have relatively high energy and 

power density, high electrical efficiency, long life, a small footprint, instantaneous 

response, and reliable operation. The sodium sulphur batteries are the most commercially 

advanced of several emerging energy storage devices for peak shaving and power quality 

solutions. 

 108 Adapted from Ibid. 109 Electricity Storage Association. (2003). “Technologies & Applications, Technology Comparisons,” ESA: Morgan 

Hill, CA. http://energystorage.org/tech/technologies_comparisons_lifeefficiency.htm/. Accessed August 2012.
59

• Zinc Bromine Batteries: The Zinc Bromine flow battery is an attractive technology for 

utility-energy storage. The battery has high specific energy and energy efficiency. 100% 

depth of discharge does not damage the battery but improves it. Zinc/bromine batteries 

are attractive candidates for load-leveling applications because they offer two to three 

times the specific energy of lead-acid batteries, have sufficient power, operate at near 

room temperature, are recyclable, are low cost to build, and have the potential for long 

life.

• Vanadium Redox Batteries: Vanadium Redox Batteries are a particularly clean 

technology, with high availability and a long lifecycle. Their energy density is rather low,

approximately 40 Wh per kilogram. The role for vanadium redox is high-level power 

storage. Vanadium Redox Batteries can be fully discharged without reducing life 

expectancy. Some applications are for utility supply energy levels, which can be as high 

as 350 MW and more. 

• Lithium Ion Batteries: The lithium ion battery market has grown tremendously in the last 

two decades. They have a high specific energy,

110 high energy density and high 

charge/discharge efficiencies. Larger-scale production due to emerging electric vehicle 

applications is expected to bring down their cost significantly.

While batteries offer the potential for relieving transmission congestion, applications have 

typically centered on on-peak and off-peak energy price arbitrage.

4.3.2 Pumped Storage Hydro

Pumped storage hydro is a mature technology with many installations in the United States and 

around the world. A pumped storage facility consists of an upper reservoir and lower reservoir 

and a generator/pump in between. During periods of high electricity demand, water is allowed to 

flow from the upper reservoir to the lower reservoir passing through the turbine/generator and 

generating electricity. During periods of low demand, the process is reversed and the water is 

pumped from the lower reservoir to the upper reservoir where it is stored until the next period of 

high demand. 

Similar to batteries, pumped storage hydro facilities offer the potential to be used to reduce 

transmission congestion, but their primary application is to hedge on- and off-peak energy price 

arbitrage. Pumped storage hydro facilities are limited by the geography suitable for building the 

two reservoirs, which limits their application in relieving transmission constraints.

4.3.3 Flywheel Energy Storage

Flywheels are devices capable of storing energy in a rotating mass driven by a motor/generator 

arrangement. They allow electrical energy to be removed from the connected electrical grid and 

stored in the rotating mass of the flywheel and then removed from the rotating mass of the 

flywheel and returned to the electrical grid as electrical energy. Solid state electronic converters 

and controls permit this process of removal, storage, and retrieval to occur very rapidly within 

the operating range of the device.

Current applications of flywheels for grid size installations have been limited to providing 

frequency regulation services with installations rated in the 20-MW/5-MW-hr size in operation. 

Typical size of a single unit is 100 kW; a 20-MW plant would require 200 individual flywheels. 

 110 National Renewable Energy Laboratory. (2009). “Energy Storage,” NREL: Golden, CO. 

http://www.nrel.gov/vehiclesandfuels/energystorage/battery_types.html/. Accessed August 2012.
60

While the current application has been restricted to frequency regulation, technical papers have 

been written that demonstrate the potential for large flywheel installations (50 MW)111 to provide 

stability damping on grids, one of the limiting factors for power transfers across transmission 

paths and interfaces. Installed costs for flywheels can be relatively expensive per kilowatt-hour. 

However, because of their high efficiency, they compare favorably to other forms of energy 

storage but over a longer operating period, as noted in Table 12. 

4.3.4 Compressed Air Energy Storage

Compressed air energy storage (CAES) uses compressed air as the storage medium. It is released 

during periods of high electricity demand to power turbine/generators, and replenished during 

periods of low electricity demand using pumps. Different configurations have been developed to 

achieve better efficiencies and lower costs, and one early configuration is in commercial 

operation in Alabama. CAES installations depend on the availability of a suitable storage cavern 

and, therefore, their application for relieving transmission constraints is also somewhat limited.

4.3.5 Energy Storage Devices for Transmission Constraint Relief

Energy storage devices have the potential to alter transmission flow patterns that may relieve 

transmission constraints under some conditions. Energy storage devices have been used on 

transmission systems to arbitrage energy prices between peak and off-peak. They store energy 

during periods when energy prices are low and release energy during periods when energy prices 

are high. Cost recovery is dependent on the price differential between peak and off-peak periods. 

Additional revenue can sometimes be realized in earning capacity payments and supplying 

ancillary services.

One study has quantified the potential benefit of locating energy storage facilities in such a way 

that transmission utilization is increased.112 The National Electric Transmission Congestion 

Study, published by DOE in December 2009, concludes that this benefit may be limited for 

energy storage technologies with particular geographic requirements. However, there may be 

instances where energy storage can be located to impact transmission capability. For example, 

locating an energy storage facility coincident with wind generation could reduce the peak 

loading on the transmission facility. During periods of high wind generation, a portion of the 

energy is stored to reduce the peak loading on the transmission facility. During periods of 

reduced wind generation, energy is released to take advantage of available transmission capacity. 

However, by coordinating the energy storage with the wind generation rather than with the price 

of energy, the overall economics of energy storage is potentially reduced. The question is 

whether the reduced cost of increasing the transmission capacity is sufficient to compensate for 

the potential loss of energy revenue. Determining whether the economics favor co-locating 

energy storage with wind or other non-dispatchable resources is very dependent on a number of 

factors. Critical parameters include the following:

• Price differential between peak and off-peak energy

• Time correlation between generation production and energy prices

 111 Rici, M.R. and Fiske, O.J. (2006). “Third Generation Flywheels for High Power Electricity Storage,” 

LaunchPoint Technologies, Inc, CA. http://www.launchpnt.com/portals/53140/docs/002_Fiske_PowerRing.pdf.

Accessed August 2012. 112 U.S. Department of Energy, (2009). “National Electric Transmission Congestion Study”

http://energy.gov/sites/prod/files/Congestion_Study_2009.pdf. Accessed August 2012.
61

• Amount of reduced transmission capacity and cost savings

• Relative size of energy storage compared to peak generation capacity

• Potential for realizing additional revenue from an energy storage facility, in capacity 

payments, ancillary services, and non-dispatchable resource integration services

The congestion study lays out many of the considerations and issues and includes sample 

analyses for three different geographic locations and energy markets. As the paper points out, the 

potential benefits of using the energy storage to benefit transmission capability is very much 

location-specific and it is difficult to generalize the results.

4.4 Conceptual Benefits and Constraints of Increasing Transmission Capability

The cost to upgrade the capacity of an existing transmission line is difficult to estimate without a 

full understanding of all the constraints. Constraints that need to be considered are as follows:

• Right-of-way constraints including the width of the right-of-way, easement restrictions, 

permitting restrictions, and physical constraints along the corridor

• Capacity, age, condition, and degree of structural data available for existing structures

• Ability of the system to handle the increased capacity

• Outage constraints, including the ability of the system to withstand the short or long 

outages needed to accomplish the upgrade

4.4.1 Right-of-Way Widths

The right of way widths for transmission lines are difficult to increase and desirable to decrease. 

Line characteristics that affect transfer capacity also potentially affect right-of-way widths that 

must accommodate increased say or electromagnetic fields. The National Electrical Safety 

Code113 does not dictate the required width of a right-of-way, only that transmission lines must 

be constructed to keep the public safe. The most common method of determining right-of-way 

width assumes that a tall building could (some day) be built just outside the right-of-way at midspan between two structures. The National Electrical Safety Code requires that all wires maintain 

a set clearance from said building during 48-mph wind. Additionally, many utilities maintain a 

set clearance to the edge of the right-of-way under high-wind conditions. 

In areas with very high land prices, some utilities choose much narrower right-of-way corridors 

by regularly examining land use at the edge of the right-of-way and mitigating inadequate 

clearances. As an example, a building constructed adjacent to a structure might not require any 

mitigation while a building built near mid-span might be mitigated by adding an additional 

structure. However, this level of risk is intolerable for most utilities.

Table 12 contains representative right-of-way widths for common nominal transmission 

voltages. The actual width used by a utility will vary dependent upon span length, structure 

configuration, conductor type, metrological conditions, and tolerance for risk.

 113 “National Electric Safety Code,” (2012). IEEE. http://standards.ieee.org/about/nesc/. Accessed August 2012.
62

Table 12. Right-of-Way Width

TRANSMISSION 

VOLTAGE (KV)

TYPICAL ROW 

WIDTH

(FT)

12.0 

34.5 

69.0

115.0

230.0

345.0

500.0

40 

60 

90 

110 

140 

170 

200 

4.4.2 Transmission Line Capacity and Cost

Table 13 contains representative single circuit transmission line capacities and costs by voltage. 

The actual capacities vary by conductor size, geographic location, and circuit rating 

methodology. The actual costs vary by line length, terrain, geologic conditions, access, land cost, 

structure type, structure configuration, conductor type, meteorological conditions, and span 

length. 

Table 13. Typical Single Circuit Transmission Costs

TRANSMISSION 

VOLTAGE

(KV)

TYPICAL 

CAPACITY

(MW)

TYPICAL 

COST

($/MILE)

12 

34.5

69 

115 

230 

345 

500 

10 

25

100 

175

450 

1000

1500

300,000

400,000

600,000

700,000

1,000,000

1,500,000

1,900,000

Double circuit costs are usually approximately 1.6 times the cost of a single circuit line. The cost 

of an underground transmission line varies by cable type, construction standards, line length, 

land use/congestion, terrain, and geologic conditions. The relative cost is typically 3–10 times 

the cost of an equivalent overhead line with the same capacity. Generally, this ratio increases 

with voltage.
63

5.0 Research Efforts

The industry continues to investigate technology and regulatory policies to increase the 

utilization of transmission resources. Some of the active organizations and their focus are 

presented below.

5.1 EPRI Transmission Efficiency Initiative

EPRI has initiated a program with a number of leading utility organizations to identify needs and 

gaps in technology that could lead to lower losses and more efficient utilization of transmission 

systems.114 The technologies and overall objectives are identified below.

1. Reduction of system losses

• Voltage upgrade / extra-high voltage AC / HVDC

• Coordination voltage VAR control

• Loss minimization optimization

2. Reduce line and equipment losses

• Advanced conductors and superconductors

• Low-loss leadership in energy environmental design substation equipment and 

transformers

3. Increase line and system utilization

• Dynamic rating

• SMART transmission

5.2 Western Area Power Administration

WAPA undertook a study in 2009 to examine transmission expansion options in the MontanaDakota region to accommodate development of generation options.115 As part of that effort, a 

review of methods and technologies with the potential to enhance the existing grid was 

conducted. The study identified the following potential enhancements:

• Reconductor transmission lines and replace terminal equipment

• Voltage upgrades

• Conversion of single circuit to double circuit

• Series compensation

• Shunt compensation (switched and static VAR compensators)

• PSTs

• Dynamic line rating

 114 “Efficient Transmission Systems Program 172.” (2012). 2012 Research Portfolio. Electric Power Research 

Institute, Palo Alto, CA. http://portfolio.epri.com/ProgramTab.aspx?sId=PDU&rId=201&pId=6310/. Accessed 

August 2012.

115 “Transmission Enhancement Technology Report.” (2002) Power Systems Engineering Research Center. 

http://www.pserc.wisc.edu/document_search.aspx/. Accessed August 2012.
64

• Conductor replacement from ASCR to ACCR

• FACTS devices

• Improved substation monitoring

5.3 Western Governors Clean and Diversified Energy Advisory Committee

The Western Governors Clean and Diversified Advisory Committee presented a report in 2006116

that identified the following steps to enhance the utilization of transmission:

FERC actions:

• Promote conditional-firm, priority non-firm, and other transmission service products

• Encourage transparent review and assessment of ATC

• Eliminate rate pancaking across control areas

• Promote control-area consolidation, wherever possible

• Encourage congestion management systems subject to reliability security constraints

• Encourage common websites for OASIS to facilitate transmission transactions

• Clarify the code of conduct for transmission owners/operators to allow transmission 

planners and resource planners of a vertically integrated utilities to participate in joint 

transparent discussions to better coordinate transmission planning with future and 

existing resources

• Convene a technical conference to develop needed reforms of interconnection and 

transmission queuing processes

Western Governors actions:

• Ensure resources to enable state participation in regional transmission planning

• Encourage the electric power industry to make the existing proactive, transparent 

interconnection-wide, and sub-regional transmission planning process a priority

• Review state laws, and if necessary, amend state laws requiring PUCs and public power 

boards to consider regional transmission needs

• Support the goal of a regional planning capability that can yield critical information for 

stakeholders and regulators to allow rigorous evaluation of large, long-term investments 

in transmission

• Bring together stakeholders and forge solutions to regional transmission needs, cost 

allocation, and siting where RTOs or ISOs do not exist, and ensure state participation in 

such activities by existing RTOs/ISOs

• Promote use of an open season process by project developers as a means of 

demonstrating demand for, and value of, new transmission projects and expand project 

participation

 116 Western Governors Association. (2006). “Clean Energy, a Strong Economy, and a Healthy Environment.” 

http://www.swenergy.org/news/news/documents/file/CDEAC06.pdf. Accessed August 2012.
65

• Urge FERC and PUCs to form joint panels on transmission cost recovery that would 

explicitly consider risks and needs for incentives, such as forms of preapproval, higher 

rates of return on transmission investments, and quicker cost recovery of transmission 

investments

• Encourage states to consider adopting funding mechanisms to support research, 

development, and demonstration of advanced technologies in the public interest

• Urge transmission operators to develop workable agreements at seams between ISO and 

non-ISO systems to enable effective grid operations

• Ensure that there are resources and political commitments to successfully implement the 

Western Governors’ Association Transmission Permitting Protocol and the Midwest 

Electric Transmission Protocol for new interstate transmission proposals

• Evaluate the option of forming an interstate compact for the creation of a regional siting 

agency pursuant to Section 1221 of the EPAct 2005 and encourage consistent siting 

processes within their states through the use of standardized applications, joint data and 

studies, coordinated schedules and deadlines and other mechanisms, where possible.

State PUC actions:

• Establish tiered standards of review for prudency and application of transmission 

incentives for transmission expansion costs featuring a lower standard for screening 

studies and planning, a moderate standard for permitting and the acquisition of rights-ofway, and a higher standard for construction costs.

• For states with mandatory renewable portfolio standards, regulatory commissions should 

make public interest findings associated with cost-effective transmission projects that will 

enable states to attain energy policy goals.

• Expand transmission in advance of generation to enable the modular development of 

location-constrained, clean, and diversified resource areas to meet cost-effective 

Renewable Portfolio Standard, integrated resource plan, and state goals, similar to Texas 

and Minnesota legislation for new transmission and the renewable trunk line (Tehachapi 

Project) model for new transmission.

• Provide a coordinated, multi-state review of transmission projects by developing 

common principles for cost allocation and cost recovery, and adopt a common Western 

procedural process that would identify and coordinate the applications, forms, analyses, 

and deadlines.

• Promote cost-effective transmission expansion by accommodating both non-dispatchable 

and dispatchable resources.

Federal Agency actions:

• Commit state resources to participate in federal effort and identify contiguous corridors 

on adjacent state lands.

• Urge Congress to fund federal land management agency corridor planning efforts.

• Foster designation of corridors of lands not owned by the federal government or the states 

to ensure continuity in corridors.
66

Western Electric Power Industry actions:

• Synchronize regional transmission planning efforts to resource acquisition plans of loadserving entities and plans of generators

• Support and collaborate with state infrastructure authorities that have been created to 

facilitate transmission expansion

• Ensure institutional homes for regional transmission planning

5.4 Rocky Mountain Area Transmission Study

The Rocky Mountain Area Transmission Study provides a comprehensive view of the 

transmission needs covering the states of Colorado, Idaho, Montana, Utah, and Wyoming.

117 The 

charter for the study includes the following:

• Work together for effective solutions in a balanced, open, and inclusive public process 

• Conduct analysis of generation and transmission alternatives based on data, assumptions, 

and scenarios developed by participating stakeholders 

• Consider every need, generation technology, and location option that is appropriate for 

the region 

• Evaluate all potential transmission alternatives within the region 

• Identify the costs and benefits of generation and transmission options for serving the 

electricity needs of consumers that make operational, economic, and environmental sense 

for the region 

• Cooperate and coordinate with the west-wide Seams Steering Group – Western 

Interconnection planning effort118 and other sub-regional planning efforts and with 

WECC to ensure maintaining or improving system reliability. 

The report provides a range of alternatives to conventional transmission expansion, with 

comparisons of the relative effectiveness of each. 

 117 State of Wyoming. (2004). “Rocky Mountain Area Transmission Study.” http://psc.state.wy.us/rmats/rmats.htm/.

Accessed August 2012.

118 Western Governors Association. (2002). “Scope of SSG-WI Working Group.”

http://www.westgov.org/wieb/meetings/crepcsprg2002/briefing%20materials/ssg-wi_031902_scope.htm/. Accessed 

August 2012.
67

6.0 Implementing Increased Line Ratings

Implementing increased transmission ratings or expanding transfer capability with new facilities 

can be a complex and time-consuming process. Critical review includes a comprehensive series 

of technical studies to verify that proposed changes will achieve the project objectives without 

compromising the surrounding interconnected system or reducing the ratings of other facilities 

(“do no harm” philosophy). NERC sets the fundamental reliability requirements for determining 

ratings, but the specific steps are determined by other authorities. ISOs or RTOs have standard 

planning and/or an interconnection processes that govern how transmission facilities are rated 

and integrated into the existing system in their areas. Areas not under the control of an ISO or 

RTO usually have less centralized, but equally complete, processes for increasing the rating of 

existing facilities.

6.1 ISO/RTO Rating Process

ISOs and RTOs normally have a formal expansion process that reviews transmission needs on an 

annual basis and studies the impact of a group of transmission changes. The ISO/RTO 

recommends transmission changes based on the studies, and issues a formal expansion plan for 

approval by the Board of Directors. Once approved, individual transmission owners implement 

the plan. Recommendations for individual transmission additions can come either from the 

ISO/RTO based on their planning studies or from the member transmission owners themselves. 

Merchant transmission expansion follows a similar path when requesting transmission additions 

or when expanding the capabilities of existing facilities. Figure 16 is the process followed by

PJM and is representative of other ISO/RTOs.

PJM follows a three-step study process, whereby each step imposes a financial obligation on the 

requester and establishes PJM milestone responsibilities:119

1. Transmission Interconnection Feasibility Study: Project sponsor submits an 

interconnection request using the Interconnection Feasibility Study Agreement, along 

with a study deposit and preliminary project data. PJM conducts the study, and the 

sponsor is responsible for the full cost of the study. The study assesses the practicality 

and cost of incorporating the project. The project sponsor must decide whether or not to 

carry the project to the next step.

2. System Impact Study: If the project sponsor elects to pursue the project, the sponsor must 

execute a System Impact Study Agreement along with a study deposit to PJM. The 

sponsor must also provide more comprehensive project data. PJM schedules and 

performs a more comprehensive determination of the impact of the proposed project on 

both the local network and the overall system. The study refines the system upgrades 

necessary to accommodate the proposed project and the costs of the upgrades. PJM also 

estimates which party is responsible for the costs of the upgrades and the lead times for 

the upgrades. Similar to the Interconnection Feasibility Study, the project sponsor decides 

whether or not to proceed based on the more definitive costs and schedule.

3. Transmission Interconnection Facilities Study: If the project sponsor elects to proceed, 

the sponsor must execute a Transmission Interconnection Facilities Study Agreement, 

with a study deposit. When completed, the Facilities Study will document the engineering 

 119 “PJM Manual 14A, Generation and Transmission Interconnection Process.” (2012). PJM 

http://www.pjm.com/~/media/documents/manuals/m14a.ashx/. Accessed August 2012.
68

design work necessary to begin construction of any required transmission facilities to 

support the project. It will also provide a good-faith estimate of the cost to be charged to 

the applicant for attachment facilities, local and network upgrades, and an estimate of the 

time required to complete a detailed design and construction of the facilities and 

upgrades.

Details of the responsibilities for the requester and PJM are detailed in the PJM OATT120 and 

PJM Interconnection Manual M-14-B.121

Figure 16. PJM Interconnection planning process122

The PJM process described here is similar to the ones used by other ISO/RTOs. In most, if not 

all, ISO/RTO processes, the studies are conducted by the ISO/RTO and are often incorporated 

into the overall planning process and schedule that the ISO/RTO routinely conducts.

6.2 Non-ISO/RTO Rating Processes

Transmission expansion in areas not included in ISO/RTOs follow a variety of processes to 

ensure that transmission rating changes do not compromise overall system reliability. As an 

 120 “PJM Open Access Transmission Tariff.” (2012). PJM. 

http://www.pjm.com/~/media/documents/agreements/tariff.ashx/. Accessed August 2012. 121 “PJM Regional Transmission Planning Process Manual.” (2012). PJM.

http://www.pjm.com/~/media/documents/manuals/m14b.ashx/. Accessed August 2012. 122 Adapted from PJM “Manual 14 A Generation and Transmission Interconnection Process” (2012). 

http://www.pjm.com/~/media/documents/manuals/m14a.ashx/. Accessed August 2012.
69

example, WECC has a well-defined rating process that is shown in Figure 17123 Similar to the

process followed in areas within an ISO/RTO, WECC follows a three-stage study process for 

rating new transmission or changing the rating of an existing facility:

• Phase 1: Phase 1 involves a project description and results of initial studies that

demonstrate that the proposed project meets minimum reliability standards under normal 

conditions. The material is submitted either through the WECC Progress Report process 

or via letter to the WECC Technical Studies Subcommittee (TSS). WECC will grant a 

Planned Rating if the project meets the necessary requirements under Phase 1.

• Phase 2: Phase 2 includes more comprehensive studies demonstrating that the proposed 

project meets reliability requirements under stressed conditions. A Project Review Group 

comprised of interested WECC members, normally members from utilities and other 

parties, who could be impacted by the proposed project, review the results. The project 

sponsor then submits the Project Review Group Phase 2 Rating Report to WECC.124

Upon acceptance by WECC, the projected is granted an Accepted Rating.

• Phase 3: In Phase 3, final implementation and construction of the project is monitored to 

ensure that all conditions are met under the Accepted Rating. This phase is completed 

when the project is placed in service.

 123 “Overview of Policies and Procedures for Regional Planning Product Review, Project Rating Review, and 

Progress Reports.” (2012). Western Electricity Coordinating Council. 

http://www.wecc.biz/library/WECC%20Documents/Miscellaneous%20Operating%20and%20Planning%20Policies

%20and%20Procedures/Overview%20Policies%20Procedures%20RegionalPlanning%20ProjectReview%20Project

Rating%20ProgressReports_07-05.pdf. Accessed August 2012. 124 Ibid.
70

Figure 17. WECC rating process125

In addition to the studies necessary under the rating process, it may be necessary to undertake an 

interconnection process with other entities that own facilities connecting with the project. That 

process will often involve additional studies as prescribed by the impacted system owner and is 

normally governed by the OATT of the impacted system. 

 125 Adapted from “Overview of Policies and Procedures for Regional Planning Product Review, Project Rating 

Review, and Progress Reports,” (2012). WECC. 

http://www.wecc.biz/library/WECC%20Documents/Miscellaneous%20Operating%20and%20Planning%20Policies

%20and%20Procedures/Overview%20Policies%20Procedures%20RegionalPlanning%20ProjectReview%20Project

Rating%20ProgressReports_07-05.pdf. Accessed August 2012.
71

7.0 Summary of Results

New renewable generation must be integrated into the existing electric power system. The way 

this system of transmission is developed and operated in the United States today has been 

affected by restructuring, the evolution of mandatory reliability, replacement of existing 

generation to accommodate renewable resources, and the process of introducing competition. 

Because changes have come relatively recently, traditional transmission planning (10 and 20+ 

years) has been disrupted. The consequence is that short-term transmission planning (5–10 years) 

has become the norm. Construction of new transmission lines takes 7–10 years, so 10-year 

planning is not adequate for the life span of transmission facilities (40+ years). The existing 

transmission grid must be utilized to its maximum potential until new transmission is built. That

will require enhancements in operating procedures and the application of new technologies to 

enable current infrastructure to carry more power.

The research and analysis presented in the previous chapters identified the following 

opportunities to increase the available capability of the electric transmission grid.

7.1 Changes in Policy and Standards

The transfer capability of the existing grid can be increased by changes in the standards and 

policies guiding line rating, such as the following:

• Replacing the practice of using static seasonal ratings on critical constrained transmission 

lines, with either real-time or dynamic monitoring of ambient conditions that could 

increase transmission during much of the year.

• WECC has extended the NERC Transmission Planning Standards for multiple circuits to 

include those that are not on a common structure, but are within a span’s length of each 

other. WECC has approved changing the distance between two circuits from a span 

length to a tower height, thereby eliminating reduced ratings on some parallel lines due to 

their proximity to other lines. While it is not clear how many lines are affected by this, a 

number of heavily used corridors in the west have lines that are forced into close 

proximity. A relaxation of the separation distance could increase the rating of existing 

parallel circuits.

• FERC Order 2000 required RTOs to establish market-based congestion management to 

improve the utilization of the grid and to allocate the cost of congestion to those users 

who were willing to pay the price. Replacing physical transmission rights with financial 

transmission rights ensures that the transmission system is allocated in the most efficient 

and equitable manner during times of constraint.

• CFT and redispatch were provided for by FERC Order 890 as a bridge between physical 

firm transmission and market-based transmission congestion management. CFT provides 

a mechanism for transmission users to have access to selected transmission paths on a 

firm basis except during periodic constrained periods. Extending this practice allows 

increased use of the transmission system when conventional firm transmission would not 

be available, but when the system is not actually constrained. During periods where 

transmission paths are constrained, redispatch may relieve the constraints at some defined 

cost and allows transmission customers to decide whether to pay the cost of redispatch or 

forgo use of the transmission. Redispatch also provides a price signal that can be used to 

make economic decisions regarding the value of increasing transmission capability on 
72 

selected paths. Redispatch provides many of the same benefits as market-based 

congestion management without having a formal congestion management market in 

place.

• Other changes offer the potential to increase existing transmission and/or allow better 

utilization of existing rights-of-way. These include reviewing, and possibly relaxing, 

transmission capability indices, expanding transmission investment rules to include new 

technologies, and fully integrating demand resources into transmission reservation and 

operation processes. 

7.2 Technology

New technology, particularly power electronics, can help overcome limitations in transmission 

capability. Some of these devices can be used to improve system damping and voltage support. 

Other technologies and enhanced engineering designs increase the power carrying capability of 

individual transmission lines as described below: 

• Conventional transmission line conductors can be replaced by HTLS conductors on 

existing transmission line to increase the thermal rating by up to 50%. The HTLS 

conductor overcomes the increased loading and other factors that can lead to the need to 

reinforce transmission structures, if existing conductors are simply replaced by larger 

conductors. 

• Under some conditions, thermal limits on transmission lines can be mitigated by 

increasing the operating voltage of the line and adopting compact line design principals 

to help offset the added clearance requirements when the operating voltage is increased. 

Compact line design principles could offer some benefits during redesign, but overall 

costs to increase the operating voltage on a transmission line would be substantial. This 

option may be particularly attractive where compact line design principles could be 

applied to allow reconductoring of an existing line with minimal tower changes and 

within the existing right-of-way.

Increasing the capability of individual transmission lines can overcome thermal limitations, 

which limit power flow on individual circuits, but often the limitations are related more to 

system performance. These limitations are more effectively mitigated by adding devices to the 

system that enhance system damping and provide more effective voltage support through the use 

of power electronics. These devices are often lumped together under the term FACTS devices: 

• The need for more precise and quicker voltage support can be satisfied through the use of 

SVCs. SVCs are voltage control devices that directly provide benefit for both the steadystate and transient voltage stability of the transmission system by electronically switching 

shunt inductors and capacitors to achieve a highly precise amount of reactive power 

support. By controlling the reactive elements, system voltage profiles can be enhanced 

and power transfer capabilities over individual lines, as well as groups of lines, can be 

accurately controlled, allowing better system performance and increased power transfer.

• Similar to SVCs, the STATCOM devices also act as shunt-connected, reactive-power 

compensation equipment capable of generating and/or absorbing reactive power, but 

STATCOM devices utilize different power control. The technology used in the 

STATCOMs eliminates the need for capacitor or reactor banks to generate/absorb 

reactive power. As a result, a STATCOM has a more compact design, a smaller footprint, 
73

and lower noise/magnetic impact (as compared to an SVC). Although STATCOM 

devices provide a measure of capability beyond that of SVCs, the fundamental intent of 

these devices is to provide voltage control (through reactive power support) to the 

system.

• Employing similar technology to the STATCOM, the SSSC appears (to the system) as an 

adjustable synchronous component series connected in with a transmission line. This 

connection enables the device to vary the effective impedance of the transmission line, 

which leads to increased power transmission capability, improved system stability, 

reduced system losses, reduced voltage drop, and optimized (balanced) power flow along 

parallel lines.

• The UPFC and IPFC have similar technology and are one of the most versatile FACTS 

devices thus far developed. The key distinction between the UPFC and IPFC is that the 

UPFC is designed to perform its control functions on only one line, whereas the IPFC is 

intended to compensate and manage power flows for multiple lines. The methods and 

control strategies implemented by each device, however, are quite similar. Both the 

UPFC and IPFC are combinations of the STATCOM and SSSC devices with some 

important differences. In particular, the UPFC and IPFC have true power flow control, as 

compared to the SSSC. Whereas the SSSC affects power flow by modifying the effective 

line impedance, the UPFC/IPFC can directly control the magnitude and direction of 

power flow. By directly controlling power flow, these devices provide all three of the 

system benefits identified (i.e., line increased power transfer, improved voltage stability, 

and enhanced rotor angle/system frequency stability).

• The TCSC is an enhanced conventional series capacitor that uses a thyristor controlled 

reactor to provide a continuous and rapidly variable series compensation system. Series 

compensation, in general, increases the power flow on a circuit by reducing the series 

impedance between the sending end and the receiving end. In addition to providing the 

benefit of a fixed series capacitor, TCSC also provides an additional advantage of power 

flow control by altering the series impedance.

Other devices that can enhance the capability of existing transmission have a longer history of 

being used in power systems. While these employ power electronics, they are not commonly 

referred to as FACTS devices:

• HVDC transmission has a long (and evolving) history of application in electrical power 

systems. Although the overwhelming amount of transmission is provided via AC, DC 

applications can provide a variety of economical and technical benefits that may be used 

to more fully utilize the existing transmission system infrastructure. Generally, HVDC 

overhead transmission lines are much more compact than equivalent AC transmission 

lines. The HVDC transmission system requires less right-of-way as compared to an AC 

transmission system for the same power transfer level. In some cases, it is feasible to 

convert an existing transmission line to HVDC to realize increased power flow for the 

same amount of right-of-way. 

• Applying the technology employed in HVDC terminal equipment, but eliminating the 

actual transmission line, is sometimes employed to interconnect two AC systems that 

would otherwise be impossible due to system stability concerns. These applications are 

called back-to-back and use the fundamental building blocks for all HVDC systems—the 
74

power converters. However, they are co-located and separated by a very short run of 

interconnecting DC bus work. By using appropriate control strategies, a back-to-back 

HVDC link can provide the required system damping that improves the overall 

performance of both transmission systems to which it is connected and allow higher

levels of transfer between the two systems.

• Extending the application of HVDC technology, a more system-wide approach to 

improving the overall efficiency of the transmission system may be achievable. The 

current grid configuration consists of a tight network of AC lines, with some HVDC links 

employed for special conditions. Advances in HVDC technologies have presented other 

opportunities for application in an overall structural way. HVDC is particularly effective 

for interconnecting two AC grids where conventional AC interconnection is not feasible 

for technical reasons. The grid in the United States has pockets of AC that would benefit 

from having the weak AC interties replaced with HVDC interties. HVDC interties’ 

advantage is that power can be scheduled over the HVDC lines in much the same way 

that power can be scheduled from a generator. HVDC interties also have the advantage of 

using their control capabilities to act as shock absorbers, by injecting and extracting 

energy more quickly and precisely from the connected AC grids than conventional AC 

controls do. Therefore, HVDC interties improve system performance and potentially 

allow higher levels of power transfer over the grid.

While devices employing power electronics can react to system conditions much more quickly 

than mechanically controlled devices, more conventional power devices have a good history of 

providing improved system performance:

• A Phase Shifter, also known as PST, is a mechanical switch, electro-magnetic device, 

similar to a conventional transformer that is introduced in an existing transmission line. It 

allows the transmission operator to control the power flow through a transmission line. 

Using this device, the flow through heavily congested lines can be reduced and shifted to 

transmission lines with spare capacity. The transfer capacities rise as congestion 

diminishes. Furthermore, PSTs are relatively inexpensive devices, when compared to 

new transmission lines, and can often be placed in an existing substation. As a result, the 

permitting process for a PST may be relatively problem free.

• The maximum power transfer through an overhead transmission line, among other 

parameters, is dependent on the line impedance. The impedance is inductive and can be 

reduced by connecting a capacitor in series. The capacitor can be installed in an existing 

substation or may be installed at a discreet point along the line. The localized nature of 

the series capacitors and its modest cost is often preferable to building additional 

transmission.

The addition of energy storage facilities on transmission grids has received increasing interest in 

recent years, driven to a large extent by the addition of large blocks of non-dispatchable 

resources such as wind and solar. The ability to store a surplus of low cost, non-dispatchable 

resources during periods of low demand, and then release that energy during periods of high 

demand, can have both economic and technical benefits. Technology improvements have been 

particularly strong in battery storage by increasing energy storage density and 

charging/discharging rates. A number of energy storage technologies have reached the level of 

commercialization including batteries, flywheels, pumped storage hydro, and CAES.
75

In addition to the benefits of single devices, opportunities exist to increase the overall utilization 

of the current transmission system through better monitoring and subsequent control. Much of 

this could be categorized under the Smart Grid banner. Real-time monitoring provides a clear 

picture of the state of the grid and allows operators to increase transfer across critical interfaces 

when stability and voltage margins are not compromised. This allows dynamic ratings for lines 

that are stability or voltage limited. While dynamic rating of the line may not increase firm 

transmission capacity, it may allow operators to schedule transmission circuits for non-firm 

transfer that otherwise are limited by static limits.

Current efforts at real-time monitoring include the following:

• Real-time transmission temperature/sag to implement dynamic line rating

• PMUs to provide direct state measurements

• Improved supervisory control and data acquisition systems to accept and process realtime information flow from remote monitors.

Real-time monitoring provides system operators with an important tool to optimally dispatch the 

system to maximize the available transmission capacity. By utilizing real-time system 

information, operators can balance the non-dispatchable nature of wind and solar resources, with 

dispatchable resources, to maximize the available transmission capacity.

7.3 Overview of Techniques

Table 14 presents the policy and technology approaches for improved utilization of the existing 

grid.
76

Table 14. Summary of Benefits

RIGHT OF 

WAY

UTILIZATION

UNUSED 

CAPACITY THERMAL VOLTAGE STABILITY

POLICIES

Changes to WECC Reliability Criteria X X

Financial Congestion Management X

Conditional Firm Transmission (CFT) X

Transmission Investment Rule X X

Demand Resources (redispatch) X X X

Dynamic/Real Time Rating X

TECHNOLOGIES

High Temp, Low Sag (HTLS) 

Conductor X

Static VAR Compensator (SVC) X X

STATCOM X X

Series Static Synchronous 

Compensators (SSSC) X X

Unified Power Factor Control (UPFC) X X X

Independent Power Factor Controller 

(IPFC) X X X

Thyristor Controlled Series Capacitor 

(TCSC) X

High Voltage Direct Current 

Transmission (HVDC) X X

Back to Back HVDC Link X

System "shock absorbers" X

Phase shifting transformer (PST) X X

Series capacitors X X

Real-time monitoring X X X X

Energy Storage X X X X
77

Appendix A: U.S. Electric Power Grid Structure

Interconnection and Regulatory Structures

The electric power grid of the continental United States is divided into three asynchronous 

interconnections commonly known as the Eastern Interconnection, the Western Interconnection, 

and the ERCOT Interconnection. 

Eight regional entities, which work with NERC to improve reliability, overlay the three 

interconnections. The regional entities are responsible for the following tasks:

• Developing and implementing reliability standards

• Enforcing compliance with those standards

• Providing seasonal and long-term assessments of the bulk power system’s ability to meet 

demand for electricity

• Providing an appeals and dispute resolution process

The regional entities are permitted to enact standards that are more stringent than those enacted 

by NERC (e.g., the FERC-approved electricity reliability organization), but they are not 

permitted to relax nor enact standards less stringent than electricity reliability organization 

standards.

Within the three interconnections, there are also sub-groups called balancing authorities, which 

have certain operating responsibilities relative to the efficient and reliable operations of the grid. 

The balancing authority structure of the United States relative to the regional entities and 

interconnections is shown in Figure 18.

Figure 18. Regional entities and balancing authorities126

 126 This image from the North American Electric Reliability Corporation’s website is the property of the North 

American Electric Reliability Corporation and is available at http://www.nerc.com/docs/oc/rs/BubbleMap_2011-04-
78

The structure of the three interconnections is described below relative to the various balancing 

authorities and ISO/RTOs within their footprint. In regions where there are organized markets, 

there are RTOs and ISOs, which operate the generation dispatch markets, market mitigation, and 

the system, and play varying roles in transmission planning.

NERC and Regional Entities

A reliability standard defines certain requirements of entities that own, operate, plan, and use the 

bulk power systems of North America. NERC, which was certified by FERC as the ERO for 

North America, works with all stakeholder segments of the electric industry to develop standards 

for the reliable planning and operation of the bulk power systems. Since ERCOT is not currently 

under FERC’s jurisdiction, it is included separately in the discussion of standards and rules.

NERC

NERC has been certified by FERC to be the national ERO and has moved from being a 

voluntary, industry-sponsored organization to being a statutory entity with specific authority, 

compliance, and enforcement power.

NERC History

Historically, the vertically integrated utility industry used NERC, which is a bottom-up, electricutility-dominated, volunteer organization, to establish reliability rules and monitor compliance. 

NERC was formed in 1968 in the aftermath of the 1965 Northeast Blackout and in response to 

the 1967 U.S. Federal Power Commission report on that blackout recommending the formation 

of an industry-based, national reliability organization. 

While efforts were undertaken in the 1990s to require adherence to NERC reliability policies and 

guidelines, mandatory reliability standards were not adopted in the United States until Congress 

passed EPAct 2005. That act required FERC to certify an independent ERO, with the job of 

developing and enforcing mandatory reliability standards. Renewed efforts to adopt mandatory 

reliability standards came in response to the Northeastern blackout of August 14, 2003. 

Subsequently, recommendations were made in a report prepared by a joint United States and 

Canadian task force that reviewed the causes of the blackout. Based on EPAct 2005, FERC 

certified NERC as the ERO on July 20, 2006. At that time, NERC changed its name from the 

North American Electric Reliability Council to the National Electric Reliability Corporation, but 

retained the same acronym. Under the procedures adopted by FERC, NERC is permitted to 

delegate a portion of its responsibilities for enforcement and for the development of regional 

standards applicable to regional entities. NERC oversees the activities of these Regional 

Reliability Organizations. A chronology of NERC history is given in Table 15. 

 

12.jpg. This content may not be reproduced in whole or any part without the prior express written permission of the 

North American Electric Reliability Corporation. Accessed August 2012.
79

Table 15. NERC History127

HISTORY

1962–1963 The electricity industry created an informal, voluntary organization of 

operating personnel to facilitate coordination of the bulk power system in 

the United States and Canada. Four interconnected transmission 

systems were connected to three more systems, forming the largest 

electricity grid in the world.

1960s Electricity industry operations followed: (a) criteria and guides for reliable 

operations, developed by the North American Power Systems 

Interconnection Committee (NAPSIC), a utility organization; and (b) 

reliability planning guides in some regions.

November 9, 1965 The largest blackout to this date in history occurred when 30 million 

people lost power in the northeastern United States and southeastern 

Ontario, Canada. New York City and Toronto were among the affected 

cities. Some customers were without power for 13 hours.

1967 Legislation (U.S. Electric Power Reliability Act of 1967) proposed the 

creation of a council on power coordination. Although not enacted, the 

proposed legislation stimulated the development of an industry reliability 

council.

1967–1968 The Federal Power Commission (predecessor of the Federal Energy 

Regulatory Commission) recommended the formation of a council on 

power coordination made up of representatives from each of the nation’s 

regional coordinating organizations, to exchange and disseminate 

information and to review, discuss, and assist in resolving interregional 

coordination matters.

1967–1968 The Federal Power Commission (predecessor of the Federal Energy 

Regulatory Commission) recommended the formation of a council on 

power coordination made up of representatives from each of the nation’s 

regional coordinating organizations, to exchange and disseminate 

information and to review, discuss, and assist in resolving interregional 

coordination matters.

June 1, 1968 NERC was established by the electric utility industry, in response to the 

1965 blackout. Nine regional reliability organizations were formalized 

under NERC. Regional planning coordination guides, which NERC 

maintained, were also formalized. NAPSIC operations criteria and guides 

continued to be maintained and practiced voluntarily.

1975 NERC was incorporated as a non-profit corporation in New Jersey.

July 13–14, 1977 A blackout occurred in New York City. This led to the first, limited 

reliability provision in federal legislation. The legislation enabled the 

federal government to propose voluntary standards, an authority never 

exercised.

1980 NAPSIC became part of NERC, bringing the reliability roles of operations 

and planning together in one organization. NERC adopted NAPSIC 

operations criteria and guides.

1981 NERC changed its name to the North American Electric Reliability 

Council in recognition of Canada’s participation.

1987 NERC updated its operations criteria and guides, renamed them as 

operating policies, and added requirement statements (“shall do this”) 

and guideline statements (“should do this”).

 127 Source: North American Electric Reliability Corporation. “History.” (2007). 

http://www.nerc.com/page.php?cid=1%7C7%7C11/. Accessed August 2012. 
80

HISTORY

1987 NERC formed a committee to address terrorism and sabotage of the 

electricity supply system, at the urging of the U.S. National Security 

Council and DOE.

1992 NERC Board of Trustees stated for the first time that conformance to 

NERC and regional reliability policies, criteria, and guides should be 

mandatory to ensure reliability, in one of six Agreements in Principle 

adopted by the Board. (NERC still had no authority to enforce compliance 

with the policies, criteria, and guides.)

1993 Building on the Agreements in Principle, NERC published “NERC 2000,” 

a four-part action plan for the future, which recommended mandatory 

compliance with NERC policies, criteria, and guides; and a process for 

addressing violations. NERC 2000 encompassed policies for 

interconnected systems operation, planning reliable bulk electric 

systems, membership recommendations, and dispute resolution.

1995 NERC led on addressing the planning and operating reliability aspects of 

FERC’s Notice of Proposed Rulemaking on a more competitive 

wholesale electric power market.

1996 Two major blackouts in the Western United States prompted some 

Western Systems Coordinating Council members to enter into 

agreements to pay fines if they violated certain reliability standards. (The 

Western Systems Coordinating Council, a regional reliability organization, 

is now the WECC.)

1997 The Electric System Reliability Task Force established by the DOE and 

an independent “blue ribbon” panel formed by NERC determined that grid 

reliability rules must be mandatory and enforceable in an increasingly 

competitive marketplace. Both groups recommended the creation of an 

independent, self-regulatory, electric reliability organization to develop 

and enforce reliability standards throughout North America. Both groups 

concluded that federal legislation in the United States was necessary to 

accomplish this.

1997 NERC set out to implement the blue-ribbon panel’s recommendation of a 

self-regulatory reliability organization. NERC began work to convert its 

planning guides into planning standards.

1998 NERC led the effort to assess the electric industry’s readiness for Y2K, at 

the request of DOE.

1999 Nine independent directors were added to the NERC Board, joining the 

president and 37 industry stakeholder interests, in anticipation of NERC 

becoming a self-regulatory organization.

2000 NERC was appointed as the electric utility industry’s primary point of 

contact with the U.S. government for national security and critical 

infrastructure protection issues.

2001 NERC governance changed. The NERC Board was replaced with the 10-

member independent board. The Stakeholders Committee was created 

(today, the Stakeholders Committee is called the Member Representative 

Committee).

May 1, 2002 NERC operating policies and planning standards became mandatory and 

enforceable in Ontario, Canada.

August 14, 2003 North America experienced its worst blackout ever, as 50 million people 

lost power in the northeastern and Midwestern United States and 

Ontario, Canada.
81

HISTORY

April 5, 2004 The final report of the U.S.-Canada Power System Outage Task Force on 

the 2003 blackout concluded the single most important recommendation 

for preventing future blackouts, and reducing the scope of those that 

occur, is for the U.S. government to make reliability standards mandatory 

and enforceable.

Summer 2004 The Bilateral Electric Reliability Oversight Group was established as a 

forum for identifying and resolving reliability issues in an international, 

government-to-government context. The Bilateral Electric Reliability 

Oversight Group grew out of the United States – Canada Power System 

Outage Task Force.

November 12, 2004 NERC translated its operating policies, planning standards, and 

compliance requirements into an integrated and comprehensive set of 90 

measurable standards called “Version 0 Reliability Standards.”

February 8, 2005 The NERC Board of Trustees adopted the Version 0 standards. 

Stakeholders overwhelmingly supported the standards.

April 1, 2005 Version 0 Reliability Standards became effective. Voluntary compliance 

was expected as a matter of good utility practice.

August 8, 2005 EPAct 2005 authorized the creation of a self-regulatory “electric reliability 

organization” that would span North America, with FERC oversight in the 

United States. The legislation stated that compliance with reliability 

standards would be mandatory and enforceable.

April 4, 2006 NERC filed an application with FERC to become the “electric reliability 

organization” in the United States. 

NERC filed with FERC 102 reliability standards, the 90 Version 0 

standards plus 12 additional standards developed in the interim.

NERC filed the same information with the Canadian provincial authorities 

in Alberta, British Columbia, Manitoba, New Brunswick, Nova Scotia, 

Ontario, Quebec, and Saskatchewan, and with the National Energy 

Board of Canada, for recognition as the “electric reliability organization” in 

Canada.

July 20, 2006 FERC certified NERC as the “electric reliability organization” for the 

United States.

September–December 2006 NERC signed Memorandums of Understanding with Ontario, Quebec, 

Nova Scotia, and the National Energy Board of Canada.

January 1, 2007 The North American Electric Reliability Council became the North 

American Electric Reliability Corporation. The new entity has a large 

membership base representing a cross-section of the industry.

March 15, 2007 FERC approved 83 NERC reliability standards, the first set of legally 

enforceable standards for the U.S. bulk power system, effective June 4, 

2007. FERC stated that voluntary compliance with NERC’s additional 

standards should continue as good utility practice.

April 19, 2007 FERC approved eight delegation agreements by which NERC will 

delegate its authority to monitor and enforce compliance with NERC 

reliability standards in the United States to eight regional entities, with 

NERC continuing in an oversight role.

June 18, 2007 Compliance with approved NERC reliability standards becomes 

mandatory and enforceable in the United States.
82

NERC Structure

NERC is funded by 10 regional councils, which adapt NERC rules to meet the needs of their 

regions. In 1994, the regional councils opened their membership to independent power 

producers, power marketers, and electricity brokers. In 1996, NERC opened its board and 

committees to voting participation by independent power producers and power marketers (NERC 

2001a). NERC and the regional councils have largely succeeded in maintaining a high degree of 

transmission-grid reliability throughout North America. However, the organization is dominated 

by representatives of the supply side (generators and transmission providers), even though the 

organization’s purpose is to ensure the reliability of supply to the consumer. NERC replaced its 

47-member combined stakeholder/independent board with a 10-member independent board in 

March 2001. Members of the independent board are selected by a stakeholder committee rather 

than being appointed or elected through a political process. NERC’s role became more 

formalized when FERC 672 selected it as the national ERO in 2006.128

NERC has provided delegated authority to eight regional entities in the United States and

Canada—each has primary authority for enforcement in the regions shown in Figure 18. The

eight regional entities operating under delegated authority from NERC are FRCC, Midwest 

Reliability Organization, NPCC, ReliabilityFirst Corporation, SERC Reliability Corporation, 

SPP, Texas Reliability Entity, and WECC.

Currently, there are more than 1900 registered entities subject to the reliability standards (a

number of entities are counted more than once because they are registered under more than one 

category). The categories of registered entities are set out in the NERC registration process.129

Registered entities are required to report the occurrence of defined bulk power system 

disturbances and unusual occurrences to the appropriate regional entity and to NERC. The 

regional entity and/or NERC, in turn, undertakes various levels of analysis to determine the 

causes of the events, assure tracking of corrective actions to prevent recurrence, gathers

information needed to assess compliance, and provides lessons learned to the industry. The event 

analysis process also provides input for training and education, reliability trend analysis efforts 

and reliability standards development, all of which support continued reliability improvement. 

Under NERC’s field trial of its event analysis program, the 2011 Southwest Cold Weather 

Events on February 2 and February 3130 were classified as Category 4 due to the overall 

significance and impact of the event (loss of more than 5,000 MW but less than 10,000 MW of 

load or generation). Based on the scope of the needed analysis, and the fact that it impacted 

multiple regions, NERC determined that the event review should be coordinated at the NERC 

level.

 128 Troutman, Sanders, “Brief History of Mandatory Reliability Standard.” (2009). 

http://www.troutmansanders.com/tmapril2009-04/. Accessed August 2012. 129 (NERC) North American Electric Reliability Corporation “Updated Request to Identify Entities Responsible for 

Implementing Version 0 Standards,” New Jersey, 2004. 

http://www.nerc.com/docs/standards/sar/Updated%20Req_to_Register_Entities_11-5-04.pdf. Accessed August 

2012.

130 (NERC) North American Electric Reliability Corporation Outages and Curtailments During the Southwest Cold 

Weather Event,” New Jersey, 2011. http://www.nerc.com/files/SW_Cold_Weather_Event_Final_Report.pdf. 

Accessed August 2012.
83

NERC Rules and Standards

The electric power grid is used and relied on by all users and owners of the system. All users 

(generators and customers/loads) share the benefits of interconnected system operation. 

Reliability rules were established to assure that the activities of one user or control area do not 

adversely impact system reliability for other users or control areas.

Reliability rules require that control areas maintain a balance between generation and load, and 

they help maintain interconnection frequency. NERC’s Control Performance Standards 1 

and 2131 establish requirements for maintaining generation and load balance under normal 

conditions. The Disturbance Control Standard requires that control areas reestablish the

generation-to-load balance within 15 minutes of the unexpected failure of a generator or 

transmission line. NERC also requires voltages to be maintained throughout the power system 

under normal and contingency conditions. For this purpose, NERC requires that control areas 

have reserves (extra generation, extra transmission capacity, and/or responsive load) ready to 

respond immediately when the need arises. These reserves can be obtained through markets, but 

they must be responsive to system operator commands.

The capacity available on the existing transmission system is governed by these reliability rules 

and the manner in which the grid is used to satisfy the growing and diverse demands placed on it.

NERC has defined two primary levels of transmission service, firm and non-firm. Firm is 

defined as the highest quality (priority) service offered to customers under a field rate schedule.

Firm customers expect to be treated on the same basis as other firm customers, including the 

native load of the transmission owner. Non-firm is defined as transmission service that is 

reserved on an as-available basis and is subject to curtailment or interruption. The designations 

and rules governing firm and non-firm transmission are contained in FERC’s pro-forma OATT. 

As the name implies, entities scheduling power under firm transmission are given priority over 

those scheduled under non-firm transmission. During system events requiring curtailment of 

power schedules, non-firm transmission schedules are curtailed before those scheduled over firm 

transmission. If curtailment must be extended to firm transmission, NERC defines the criteria for 

curtailing firm transmission. In situations where interconnection-wide events require large-scale 

curtailment, NERC standards define the process. 

To determine the priority within each category of service on the transmission system, 

transactions are identified by a tag, which uniquely identifies the transaction in terms of owner, 

time of schedule, source, and sink. These tags are used as input into NERC’s Interchange 

Distribution Calculator (IDC),132 which serves to keep track of each transaction and determine,

through sensitivity factors, effects on parallel paths from source to sink. These are used 

differently in the Eastern Interconnection, ERCOT, and WECC. Tags are initiated and processed 

in accordance with the North American Energy Standard Board (NAESB) business practice

standards. Tags in the Eastern Interconnection are delivered to the IDC where they are used to 

 131 (NERC) North American Electric Reliability Corporation “Control Performance Standards,” New Jersey. 

http://www.nerc.com/docs/oc/ps/tutorcps.pdf. Accessed August 2012. 132 (OATI) Open Access Technology International “Congestion Management.” 

http://www.oatiinc.com/transmission_congestion_management.aspx/. Accessed August 2012.
84 

implement the interconnection-wide Transmission Loading Relief (TLR) procedures specified in 

NERC’s standard IRO-006133 and the NAESB business practice WEQ-008.134

WECC, instead of using the IDC tool, uses the WECC Interchange Tool as the Tagging 

Authority Service for the Western Interconnection. The Texas Reliability Entity, areas in Texas 

use their own methodology based on ERCOT Operating Procedures.135 A comparison of 

transmission scheduling is provided in Table 16. 

Table 16. Comparison of Transmission Scheduling

TRANSMISSION SCHEDULING

East WECC Texas (TRE, ERCOT)

e-Tag e-Tag e-Tag

IDC WECC Interchange Tool ERCOT Protocols

TLR WECC Interchange Tool ERCOT Protocols

Eastern Interconnection Transmission Loading Relief

During an event requiring execution of a TLR, NERC Standard IRO-006-EAST-1136 provides for 

the following major actions:

• Inter-area redispatch of generation

• Intra-area redispatch of generation

• Reconfiguration of the transmission system 

• Voluntary load reductions (e.g., demand-side management)

• Controlled load reductions (e.g., load shedding) 

WECC Unscheduled Flow Mitigation

Similar to the TLR in the Eastern Interconnection, NERC has outlined a list of actions to be 

followed as provided in Table 17. 

 

133 (NERC) North American Electric Reliability Corporation “Standard IRO-006-3 — Reliability Coordination — 

Transmission Loading Relief,” New Jersey, 2006. http://www.nerc.com/files/IRO-006-3.pdf. Accessed August 

2012.

134 (NAESB) North American Energy Standards Board “Transmission Loading Relief – Eastern

Interconnection,” United States, 2005. http://www.naesb.org/pdf2/weq_bklet_011505_tlr_numbering.pdf. Accessed 

August 2012. 135 Texas Reliability Entity “Standards,” Texas, 2011. http://texasre.org/standards_rules/Pages/Default.aspx/. 

Accessed August 2012. 136 (NERC) North American Electric Reliability Corporation “Standard IRO-006-EAST-1 — TLR Procedure for the 

Eastern Interconnection,” New Jersey, 2010. http://www.nerc.com/files/IRO-006-EAST-1.pdf. Accessed August 

2012.
85

Table 17. WECC Actions under Unscheduled Flow Mitigation

STEP ACTION 

DESCRIPTION

UNSCHEDULED FLOW 

ACCOMMODATION 

ACROSS PATH 

(First Contract Year / 

Second Contract Year / 

Third and Subsequent 

Contract Years)

EQUIVALENT PERCENT CURTAILMENT 

REQUIRED IN CONTRIBUTING SCHEDULE 

(Based on Amount of Unscheduled Flow 

across Path)

10–

14%

15–

19%

20–

29%

30–

49% 50+%

1 Operate controllable 

devices in path N/A

2 Accommodation 50 MW or 5% of maximum 

transfer limit

3

Coordinated operation 

of qualified controllable 

devices

50 MW or 5% of maximum 

transfer limit

4 First-level curtailment 50 MW or 5% of maximum 

transfer limit 10% 20%

5 Second-level 

curtailment

50 MW or 5% of maximum 

transfer limit 10% 15% 25%

6 Accommodation 75 MW or 6% of maximum 

transfer limit 10% 15% 25%

7 Third-level curtailment 50 MW or 5% of maximum 

transfer limit 10% 15% 20% 30%

8 Accommodation 100 MW or 7% of maximum 

transfer limit 10% 15% 20% 30%

Regional Entities

The NERC structure includes eight regional entities to allow a more local focus in improving the 

reliability of the grid. Membership in the regional entities is diverse and includes a wide range of 

participation, including investor-owned utilities; federal power agencies; rural electric 

cooperatives; state, municipal, and provincial utilities; independent power producers, power 

marketers, and end-user customers. The regional entities collectively account for virtually all of 

the electricity supplied in the United States, Canada, and part of Mexico.

Eastern Interconnection

The Eastern Interconnection covers the eastern half of the United States. There are six regional 

entities within the Eastern Interconnection. Each regional entity has multiple balancing 

authorities within its jurisdiction that are responsible for maintaining local reliability within their

boundaries. In organized markets where ISO/RTOs are present, they often take on the 

responsibility of the balancing authorities, but not in all cases.

Northeast Power Coordinating Council

The NPCC covers New York and the six New England states, plus the Canadian provinces of 

Ontario, Quebec, New Brunswick, and Nova Scotia. It covers an area of nearly 1.2 million 

square miles with a population of more than 55 million people.137 Within the NPCC, there are 

five balancing authorities, including the NYISO and the New England Independent System 

Operator (ISO-NE). The remaining three balancing authorities are Canadian.

 137 (NPCC) Northeast Power Coordinating Council “About NPCC,” New York, 2011. 

https://www.npcc.org/About/default.aspx/. Accessed August 2012.
86

NPCC Directories are currently being developed to demonstrate that NPCC regional criteria and 

standards are consistent with NERC reliability standards. The Directories will provide a 

consistent and comprehensive set of reliability requirements for the NPCC region to replace the 

current system of A, B, and C documents.138 The development of the Directories will be shared 

with other regional entities that participate in an open and inclusive process for developing and 

reviewing the criteria documents. 

Midwest Reliability Organization

The Midwest Reliability Organization (MRO) covers approximately 1 million square miles and

20 million people including the states of North Dakota, Minnesota, Nebraska and the majority of 

the states of South Dakota, Iowa, and Wisconsin and the Canadian provinces of Saskatchewan 

and Manitoba.139 Within the MRO, there are 17 balancing authorities located in the United 

States, none of which are ISO/RTOs. The balancing authorities are a mix of investor-owned and 

publicly owned utilities including some regional power districts.

The MRO has approved a number of regional standards, but these standards have not yet been 

approved by NERC and FERC and are not mandatory at this point in time. Once approved by the 

regional entities, however, they are considered good utility practice and are often cited in 

contractual arrangements within the regional entities footprint. There are currently no MROapproved standards that address renewable resources specifically.

Reliability First Corporation

The Reliability First Corporation (RFC) covers the upper middle eastern part of the United States

with 13 balancing areas, including the Midwest Independent System Operator (MISO) and the

PJM RTO. It includes the service territories of the load serving entities within the states of New

Jersey; Delaware; Pennsylvania; Maryland; District of Columbia; West Virginia; Ohio; Indiana;

Lower Michigan; and portions of Upper Michigan, Wisconsin, Illinois, Kentucky, Tennessee, 

and Virginia. Similar to the MRO, the balancing areas in the RFC are a combination of investorowned and publicly owned utilities.

RFC currently has one fully approved and mandatory standard (BAL-RFC-02)140 addressing 

Resource Adequacy. BAL-RFC-02 requires that the modeling characteristics of “energy limited 

resources such as wind” are submitted to the RFC. RFC also has one standard that addresses 

renewable resources, with specific operating requirements (MOD-25-RFC-01)141 and another 

with reporting requirements (MOD-24-01_1).142

 138 (NPCC) Northeast Power Coordinating Council “Directory Development and Revision Manual,” New York, 

2011. 

https://www.npcc.org/Standards/Directories/NPCC%20Directory%20Development%20Manual%20Final%20%20N

ov%208%202011%20GJD.pdf. Accessed August 2012. 139 (MRO) Midwest Reliability Organization “MRO Manual,” United States. 

http://www.midwestreliability.org/01_about_mro/overview/mro_manual/1_Introduction.pdf. Accessed August 

2012.

140 Reliability First “Standards,” Ohio, 2011. https://rfirst.org/standards/Pages/ApprovedStandards.aspx/. Accessed 

August 2012.

141 Ibid. 142 Ibid.
87

SERC Reliability Corporation

SERC Reliability Corporation143 is responsible for promoting and improving the reliability, 

adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 

central and southeastern states. The SERC Region covers approximately 560,000 square miles 

and occupies the southeastern portion of the United States (excluding Florida), with 30 separate 

balancing authorities in its footprint. The balancing authorities represent a combination of 

investor-owned and publicly owned utilities, but no ISOs/RTOs exist within SERC.

SERC currently has one standard addressing automatic under frequency load shedding (PRC006-SERC-01)144 in the internal approval process. This draft standard does not address 

renewables specifically.

Florida Reliability Coordinating Council

The FRCC includes the regional entities for the State of Florida only and is comprised of 11 

separate balancing authorities. No ISOs/RTOs exist within the footprint of FRCC. Many of the 

balancing authorities are publicly owned, but there are a few investor-owned utilities.

FRC currently has no standards approved by NERC and FERC, and it has no standards currently 

active within the standards approval process.

Southwest Power Pool

The Soutwest Power Pool is both a regional reliability organization and an ISO, but unlike most 

ISOs, it does not act as the balancing authority for the region. There are 17 separate balancing 

authorities within the SPP footprint, representing a combination of investor-owned and publicly 

owned utilities. SPP provides reliability, tariff administration OATT, and scheduling for its 

members in Arkansas, Kansas, Louisiana, Mississippi, Missouri, Nebraska, New Mexico, 

Oklahoma, and Texas. SPP also provides transmission expansion planning and market operation 

for energy imbalance service.

SPP currently has one standard under development (PRC-006-SPP-01)145 for under frequency 

load shedding.

Western Electricity Coordinating Council

WECC is unique among NERC regions in that it is substantially larger, including all or portions 

of 14 U.S. states as well as portions of Western Canada and northern Baja del Norte, Mexico,

within the entire synchronous interconnection. This assessment considers the operation and 

interconnection processes only within in the U.S. portion of WECC, ignoring Canada and 

Mexico. While these regions are operationally a portion of WECC, the transmission 

interconnection and ratemaking processes are different that those in the United States.

Whereas in other NERC regions, policies are implemented directly by the regional entities, in 

WECC, many of the operations policies are implemented on a sub-regional basis through six 

sub-regional reliability councils. These sub-regional councils depicted in Figure 18. Within 

WECC and the sub-regional areas, most of the balancing authorities are large, vertically 

 143 (SERC) Southeast Reliability Corporation “Welcome to SERC,” United States. 

http://serc1.org/Application/HomePageView.aspx/. Accessed August 2012. 144 (SERC) Southeast Reliability Corporation “Standards,” United States, 2011. 

https://serc.centraldesktop.com/standardhomepage/doc/10285789/w-SercRegionalStandards/. Accessed August 

2012.

145 (SPP) Southwest Power Pool “Regional Standard Under Development: PRC-006-SPP-01 - Under Frequency 

Load Shedding,” United States, 2012. http://www.spp.org/section.asp?pageID=101/. Accessed August 2012.
88

integrated utilities, with only one ISO, the CAISO operating within the WECC in the United 

States.

This assessment reviews the transmission, operation, and interconnection processes for the 

WECC as a whole, with the notable exception of California. California will be considered 

independently from the WECC for several reasons. As already mentioned, California is unique 

insofar as it has an ISO controlling its transmission operation for investor-owned utilities in the 

state: Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric. The 

ISO does not extend to the publicly owned utilities in the state, primarily the Los Angeles

Department of Water and Power and the Sacramento Municipal Utility District and Imperial 

Irrigation District, which represent approximately 40% of the state’s energy demand and 

requirements.

In addition to having the only ISO in WECC, California is a major driver for transmission 

development in the WECC. It is a major load sink for both conventional and renewable 

generation, importing vast quantities of energy from throughout the Western United States. Since 

it imports much of its energy requirements, proposed transmission in the West is often geared to 

deliver energy to California. Finally, California’s demand for renewable energy has drawn a 

large number of projects seeking to interconnect to the WECC grid and deliver energy to 

California.

Texas Regional Entity

Texas Reliability Entity is authorized by NERC to develop, monitor, assess, and enforce 

compliance with NERC Reliability Standards within the geographic boundaries of the ERCOT 

region. In addition, Texas Reliability Entity has been authorized by the Public Utility 

Commission of Texas to maintain Texas State reliability requirements. Texas Reliability Entity

is independent of all users, owners, and operators of the bulk power system.

The regional entity functions and protocol compliance were previously performed by Texas 

Regional Entity, a functionally independent division of the ERCOT. Texas Reliability Entity 

took over all responsibilities of Texas Regional Entity on July 1, 2010. Texas Reliability 

Entity146 performs the regional entity functions described in Section 215 of the EPAct 2005 for 

the ERCOT region, as mandated by the FERC-approved delegation agreement with NERC.

Texas Reliability Entity is a non-profit corporation with voluntary membership consisting of 

owners, users, and operators of the Bulk Electric System. Texas Reliability Entity members have 

membership in one of six industry sectors: System Coordination and Planning, Transmission and 

Distribution, Cooperative Utility, Municipal Utility, Generation, or Load-Serving and Marketing.

Enforcement

Because the Texas Reliability Entity is authorized by NERC to enforce compliance with NERC 

reliability standards, possible NERC standard violations may be identified by the entity itself by 

self-reports, exception reports, or as part of a self-certification or periodic data submission. 

NERC standard violations may also be discovered by Texas Reliability Entity during an audit or 

spot check, or during the course of a compliance violation investigation. Others may report a 

NERC standard violation through an incident report. 

In addition, Texas Reliability Entity is permitted by NERC to investigate compliance with the 

ERCOT Protocols and Operating Guides, working with Texas PUC staff regarding any potential 

 146 Texas Reliability Entity (2012) Texas 2012. http://www.texasre.org/Pages/Default.aspx/. Accessed August 2012.
89

protocol violations. Possible violations of the ERCOT Protocols and/or Operating Guides may be 

reported by the entity itself during a self-certification or periodic data submission, discovered by

Texas Reliability Entity during an audit or investigation, or reported through a complaint. 

Texas Reliability Entity validates all alleged violations of NERC standards and/or ERCOT 

Protocols and Operating Guides. Texas Reliability Entity conducts an internal, independent 

review of the evidence before deciding on a course of action.

Enforcement of NERC Reliability Standards 

After Texas Reliability Entity issues a “Notice of Possible Violation” to a NERC-registered 

entity, the entity has 30 days to submit a mitigation plan. Submitting a mitigation plan is not 

considered to be an admittance of guilt. The entity should preserve all relevant documentation, 

and the process is considered to be confidential.

When Texas Reliability Entity issues a “Notice of Alleged Violation,” Texas Regional Entity

includes a penalty, which may be monetary or non-monetary, and which may include remedial 

actions to be taken. The entity may accept or contest the penalty; if contested, the entity may 

attempt to reach a settlement with Texas Regional Entity at any time.

A “Notice of Confirmed Violation,” or NOCV, is issued if the entity has not responded to the 

NAVAPS within 30 days, if the entity has accepted the violation and penalty, or if the entity has 

completed the appeals process with NERC. A “Notice of Penalty” is then issued, filed by NERC 

with the FERC, and posted on the NERC site.

Enforcement of ERCOT Protocols

Texas Reliability Entity has been authorized by the Texas PUC to investigate compliance with 

the ERCOT Protocols and Operating Guides, working with Texas PUC staff regarding any 

potential protocol violations. The Texas PUC oversees the enforcement process.

When Texas Reliability Entity issues an “ERCOT Protocol Compliance Violation” or an 

“ERCOT Operating Guide Compliance Violation,” a market participant has 10 days to contest, 

accept, or supply additional information, and 30 days to supply a mitigation plan to Texas 

Reliability Entity. After reviewing, Texas Reliability Entity will accept or deny the mitigation 

plan, and Texas Reliability Entity will also confirm that the mitigation plan has been completed. 

The Texas PUC determines a penalty, if necessary.

Redispatch ISOs and RTOs

In areas where there are organized markets, ISOs and RTOs have formed.

New York Independent System Operator

The NYISO147 is the balancing are and electric power market operator for the state of New York. 

It performs a central economic dispatch for New York and operates the transmission system 

within the state. The NYISO is a balancing authority within NPCC.

The NYISO is responsible for the reliable operation of the New York electric system. It does not 

issue reliability standards. Rather, regional reliability rules for New York are developed and 

maintained by the New York State Reliability Council (NYSRC). The NYSRC also monitors

compliance in conjunction with the NYISO and, when necessary, ensures compliance through a 

 147 New York Independent System Operator, “NYISO,” New York 2012. http://www.nyiso.com/public/index.jsp/. 

Accessed August 2012.
90

dispute resolution procedure as part of its agreement with the NYISO. The reliability rules 

developed by NYSRC are more stringent than NPCC and NERC standards and criteria.

The NYISO has adopted procedures for both reliability transmission planning and economic 

transmission planning.148 The NYISO Comprehensive Reliability Planning process149 begins

with input from the Local Transmission Owner Planning Process, which assesses each of the 

eight utility transmission owners in the state on a 2-year cycle and adheres to the applicable 

criteria of NERC, NPCC, and NYSRC. The economic planning process (Congestion Assessment 

and Resource Integration Study)150 issued its first report in 2010. The Congestion Assessment 

and Resource Integration Study is a two-phase process in which Phase 1 assesses the historic and 

future congestion on the New York State bulk power transmission system over a 10-year horizon 

and provides an analysis of the potential costs and benefits of relieving that congestion. In 

Phase 2, developers can propose transmission projects for evaluation of their potential economic 

benefits in relieving congestion. The NYISO analyzes each proposal to determine benefits and 

whether the proposed transmission project should proceed through a stakeholder voting process 

and have its costs recovered through the NYSIO Tariff.

PJM Interconnection

PJM is an RTO with responsibility for all or a portion of 13 states and the District of Columbia. 

PJM manages the electric power grid and the wholesale electricity market within its footprint and 

is a balancing within RFC. PJM began as a power pool and transitioned to an ISO in 1997 and 

became an RTO in 2001.

PJM has implemented a Regional Transmission Expansion Play process that identifies

transmission system upgrades and enhancements to provide for the operational, economic, and 

reliability requirements of the PJM system. The process considers generation and load response 

projects as part of the overall transmission needs over a 15-year planning horizon. Transmission 

upgrades to mitigate identified reliability criteria violations are evaluated for feasibility, impact, 

and cost over the entire PJM footprint. PJM has a separate process for evaluating Merchant 

Transmission as outlined in PJM Manual M-14C.151

New England Independent System Operator

ISO-NE152 is an RTO, but maintains its ISO name. It is responsible for a six-state area covering 

New England, with the responsibility for operation of the transmission system and wholesale 

electric power market within its footprint. ISO-NE is registered as a balancing authority under 

NERC. ISO-NE is responsible for transmission planning and issues an annual report (CELT),153

 148 New York Independent System Operator, “Planning Studies,” New York, 2012. 

http://www.nyiso.com/public/markets_operations/services/planning/planning_studies/index.jsp/. Accessed August 

2012.

149 New York Independent System Operator, “Comprehensive Reliability Planning Process Manual,” New York, 

2007. http://www.nyiso.com/public/webdocs/documents/manuals/planning/CRPPManual120707.pdf. Accessed 

August 2012.

150 New York Independent System Operator, “Initial Manual Congestion Assessment And Resource Integration 

Study,” New York, 2010. http://www.nyiso.com/public/webdocs/committees/bic/meeting_materials/2010-07-

14/Agenda_10_Initial_CARIS_Manual_07_14_2010_BIC.pdf. Accessed August 2012. 151 PJM “PJM Manual 14C Generation and Transmission Interconnection Facility Construction,” United States, 

2012. http://www.pjm.com/~/media/documents/manuals/m14c.ashx/. Accessed August 2012. 152 (ISO NE) Independent System Operator New England, 2012. http://www.iso-ne.com/. Accessed August 2012. 153 (ISO NE) Independent System Operator New England, “CELT,” New England, 2012. http://www.isone.com/trans/celt/. Accessed August 2012.
91

which identifies capacity and transmission requirements within its footprint. ISO-NE has a 

somewhat de-centralized planning process. The generation and transmission additions or changes 

are submitted to ISO-NE under a formal Proposed Plan Application for review by the ISO 

Reliability Committee. The ISO supplies the Reliability Committee with a statement of its 

recommendation or the recommendation of any applicable task force. The Reliability Committee 

may defer action, recommend approval by the ISO, or recommend disapproval by the ISO. 

Applications are to be submitted no more than 5 years prior to the in-service date, without 

mitigating circumstances.

Midwest Independent Transmission System Operator

The MISO154 is an RTO serving all or parts of 13 states and the Canadian province of Manitoba. 

The MISO operates the grid and power markets within its footprint. This includes reliability 

coordination and regional planning services. MISO handles generation interconnection, 

maintenance coordination, market monitoring, and dispute resolution. The MISO acts as the 

regional balancing authority, instructing local balancing authorities on operation of resources. 

The MISO develops an annual MISO Transmission Expansion Planning report, which identifies 

regional transmission expansion needs and operates an OASIS for long-term transmission 

reservations time. The MISO may experience a large addition in membership with the addition 

of the Entergy companies, who announced their intention to join MISO and become integrated 

by the end of 2013. If the Entergy companies join MISO, MISO may form MISO South to 

accommodate Entergy.

Southwest Power Pool

SPP155 is both a regional entity and an ISO, but unlike most ISOs, it does not act as the balancing 

authority for the region. There are 17 separate balancing authorities within the SPP footprint, 

representing a combination of investor-owned and publicly owned utilities. SPP provides 

reliability, tariff administration OATT, and scheduling for its members in Arkansas, Kansas, 

Louisiana, Mississippi, Missouri, Nebraska, New Mexico, Oklahoma, and Texas. SPP also 

provides transmission expansion planning and market operation for energy imbalance service 

and is in the process of implementing a full market structure. 

SPP currently has one standard under development (PRC-006-SPP-01)156 for under frequency 

load shedding. It does not specifically address renewable resources.

SPP has recently developed the Integrated Transmission Plan,157 which is a reliability-based plan 

for incremental transmission additions and a strategic 20-year plan. As part of the initial start of 

the plan, SPP will develop a 10-year and a near-term transmission needs assessment. The driver 

for the Integrated Transmission Plan process is the SPP Transmission Expansion Plan (STEP),158

 154 MISO Energy “Midwest Independent System Operator,” United States, 2012. 

https://www.misoenergy.org/Pages/Home.aspx/. Accessed August 2012. 155 (SPP) Southwest Power Pool, United States, 2012. http://www.spp.org/. Accessed August 2012. 156 (SPP) Southwest Power Pool “Regional Standard Under Development: PRC-006-SPP-01 Under Frequency Load 

Shedding,” United States, 2012. http://www.spp.org/section.asp?pageID=101/. Accessed August 2012. 157 (SPP) Southwest Power Pool “Integrated Transmission Planning,” United States, 2012. 

http://www.spp.org/section.asp?pageID=129/. Accessed August 2012. 158 (SPP) Southwest Power Pool “SPP Transmission Expansion Plan Report,” United States, 2012. 

http://www.spp.org/publications/2012-01-18_2012%20STEP%20Report%20Filing_07-00390-UT.pdf. Accessed 

August 2012.
92

which summarizes activities that impact future development. Core areas addressed by STEP are 

as follows:

• Regional reliability

• Tariff studies to meet Transmission Service Requests

• Sub-regional and local area planning

• Transmission congestion and the ten most constraining flowgates

• Interregional coordination

• Integrated transmission planning and priority projects

• Project tracking

The STEP process is independent of SPPs duties as a regional entity of the North American 

Electric Reliability Corporation.

California Independent System Operator

The CAISO is responsible for the reliability of the transmission grid for the transmission owners 

for the investor owned utilities within California. The CAISO controls approximately 60% of the 

total California grid, while the remaining grid and energy deliveries are managed by municipal 

balancing authorities, such as the Los Angeles Department of Water and Power and the 

Sacramento Municipal Utility District. The CAISO does not own any transmission and is not 

responsible for interconnecting into the investor-owned utility distribution system, or the 

operation of the distribution system. The CAISO is responsible for the interconnection of 

renewable resources to the transmission system within its jurisdiction.

Renewable Integration and Planning

With California having the most aggressive renewable portfolio standard in the United States, 

there are many challenges the CAISO faces with respect to the integration of renewables. Many 

of the state’s base load generation are anticipated to be replaced by renewables by 2020. 

As the tax incentives in the United States made wind and solar more affordable and created a 

policy-driven influx of interconnection resources, the CAISO has run into even more issues with 

integration. On a 33% target, only approximately 25% of the projects within the CAISO queue 

are required to meet 33%. Designing a system to facilitate more than 70,000 MW of generation 

can cause substantial issues, and changes the current nature of energy flows within the state. If 

all of the generation in the queue were to be interconnected, California would substantially 

exceed its load, and be forced to either curtail or export excess generation. 

To study and design the current transmission system for the impending influx of generation, the 

CAISO has worked with the state utilities and stakeholders to develop a transmission plan that 

would facilitate the 33% renewables goal, while maintaining reliable operation of the 

transmission system. There are currently 33 transmission network upgrades approved by the 

CAISO based on studies implemented by the Renewable Energy Transmission Initiative and the 

California Transmission Planning Group. Even with these studies, the CAISO is continuing to 

study impacts of new projects and the renewable resource mix anticipated in the future, which 

could take advantage of energy storage and co-location of renewable resources.
93

Interconnection of Renewables

FERC mandates that transmission cannot be overbuilt for anticipated generation, so every 

interconnection studied by the CAISO prior to 2008 was done serially. This resulted in a slower 

process and a backlog of projects anticipating network upgrades to allow for delivery of the 

project. In 2008, the CAISO moved forward in implementing a cluster study to study the impact 

of multiple projects within a specific area. This process would allow for the CAISO to assign the 

cost of substantial network upgrades to multiple projects to facilitate the delivery of generation 

resources within the state.

There are numerous maps in each of the investor-owned utilities depicting information on 

locating renewables more effectively due to available transmission capacity. Transmission 

ranking cost reports released by each investor-owned utility show the available transmission 

capacity at large delivery substations. These maps allow renewable resources to utilize the 

existing transmission capacity more efficiently. These maps and transmission ranking cost 

reports can be found at the following websites for the following investor-owned utilities:

• Pacific Gas & Electric

o Map:

http://www.pge.com/b2b/energysupply/wholesaleelectricsuppliersolicitation/PVRFO/pvmap/

o Transmission ranking cost reports: 

http://www.pge.com/includes/docs/pdfs/b2b/wholesaleelectricsuppliersolicitation/RPS/Rene

wablePortfolioStdsOIR-III-Admin_Other-Doc_PGE_20100120-01%5B1%5D.pdf

• Southern California Edison

o Map: http://www.sce.com/EnergyProcurement/renewables/spvp-ipp/spvp-ipp.htm

o Transmission ranking cost reports:

http://asset.sce.com/Documents/Shared/2011_SCERFPSCE_s_TransmissionRankingCostRep

ort.pdf

• San Diego Gas & Electric

o Map: http://sdge.com/builderservices/dgmap/

o Transmission ranking cost reports: http://www.sdge.com/regulatory/documents/r-06-05-

027/svcTRCRFiling.pdf

Transmission Access

To sell power to the market, there are many options for renewable resources. There are programs 

specifically for the Renewable Portfolio Standards within the investor-owned utilities to gain a 

power purchase agreement, as well as congestion revenue rights that can be purchased to gain 

transmission access in the CAISO market. 

There are multiple programs for transmission access within each of the California investorowned utilities. Each of them has Rule 21 Interconnection procedures, such as the Southern 

California Edison Crest Program159 and the Pacific Gas & Electric Solar Photovoltaic Power 

Purchase Agreement Program.160 There are also Renewable Portfolio Standard Request for 

 159 (SCE) Southern California Edison “Renewable and Alternative Power – CREST Program,” California, 2012. 

http://www.sce.com/EnergyProcurement/renewables/crest.htm/. Accessed August 2012. 160 (PG&E) Pacific Gas & Electric Program “2011 Solar Photovoltaic Program,” 2011. 

http://www.pge.com/b2b/energysupply/wholesaleelectricsuppliersolicitation/PVRFO/. Accessed August 2012.
94

Offers for wholesale generation. Each of the investor-owned utilities has a Renewable Portfolio 

Standard Request for Offers for 2011.161, 162

Available Transfer Capacity Rating Methodology

NERC requires that each Transmission Operator (TOP) select one of the following three

methodologies for calculating ATC:

• The Area Interchange Methodology, MOD-028163

• The Rated System Path Methodology, MOD-029164

• The Flowgate Methodology, MOD-030165

The CAISO uses the Rated System Path Methodology (MOD-029) for all ATC paths within its 

area. 

Balancing Authorities Not Under RTO/ISO Jurisdiction

The Western Interconnection is substantially different than the Eastern Interconnection, as it 

does not have many ISOs or RTOs. The majority of the utilities are also their own balancing 

authority. Each of these balancing authorities has its own standards and operates differently, but 

still adheres to FERC regulations.

The Los Angeles Department of Water and Power is one of the larger municipal utilities in 

California, serving customers in the Los Angeles Basin. It acts as its own balancing authority, 

and imports its power from utilities such as Southern California Edison and San Diego Gas & 

Electric. Although it is not part of the CAISO, it is directly affected by changes to transmission 

within the CAISO.

BPA is a federal utility that operates a substantial amount of wind and hydro in the Northwest 

United States. One important difference with the BPA is that it has “environmental curtailment,” 

which allows it to curtail generation (specifically wind) due to dams overflowing and hydro 

needing to be used. The policies surrounding the environmental dispatch have been debated 

recently,166 as a substantial quantity of wind generation was curtailed for this very reason. In 

times of curtailment, there may be other ways to plan system dispatch and overflowing of dams 

in heavy rain or snow melt periods, as well as enable various resource mixes to firm and shape 

intermittent generation to facilitate the full utilization of existing transmission.

 161 (PG&E) Pacific Gas & Electric Program “2011 Renewables,” 2011. 

http://www.pge.com/b2b/energysupply/wholesaleelectricsuppliersolicitation/renewables2011/index.shtml/. 

Accessed August 2012.

162 San Diego Gas and Electric Company “2011 Renewables Portfolio Standards Solicitation,” California, 2011. 

http://www.sdge.com/rfo/renewable2011/index.shtml/. Accessed August 2012. 163 (NERC) North American Energy Reliability Corporation “Standard MOD-028-2 — Area Interchange 

Methodology,” New Jersey, 2012. http://www.nerc.com/files/MOD-028-2.pdf. Accessed August 2012. 164 (NERC) North American Energy Reliability Corporation “Standard MOD-029-1a — Rated System Path 

Methodology ,” New Jersey. http://www.nerc.com/files/MOD-029-1a.pdf. Accessed August 2012. 165 (NERC) North American Energy Reliability Corporation “Standard MOD-030-02 — Flowgate Methodology,” 

New Jersey, 2009. http://www.nerc.com/files/MOD-030-2.pdf. Accessed August 2012. 166 BPA Transmission Services Business Practices “Environmental Redispatch Version 3,” 2011. 

http://transmission.bpa.gov/ts_business_practices/Content/9_Redispatch_and_Curtailment/Environmental_Redispat

ch.htm/. Accessed August 2012.
95

Methods to Utilize Current Capacity

As there are many different programs and interconnection standards across the WECC, questions 

on how to reliably utilize the existing transmission system without substantial transmission 

expansion are posed. 

First, current planning methodologies may need to be updated to fully appreciate resource 

diversity. Within the CAISO, there are many microclimates that may make it difficult to fully 

understand peak load situations. For instance, in the middle of August, it may be extremely hot 

in southern California, but temperatures remain lower in parts of Pacific Gas & Electric territory. 

To assume peak loads, at times in Pacific Gas & Electric that may see heavy fog, can be 

incorrect. Also, wind profiles and solar profiles can be extremely different at 3:00 p.m. on a hot 

summer day, as the wind does not typically blow during these times, but solar is at peak. In 

California, some wind tends to peak later in the evening, which makes co-location of resources 

extremely attractive. Is it fair then, to assume full capacity at summer peak for both of these 

resources? Is this “gold plating” the transmission system? With California being a key leader in 

renewable resource development and having aggressive Renewable Portfolio Standard targets, it 

behooves the industry to fully understand the implication. Currently, all of the investor-owned 

utilities within California have signed power purchase agreements to meet the 33% goal. To 

reach this goal, it is estimated that approximately 30 GW of renewable resources are required. 

Within the CAISO queue and investor-owned utilities wholesale distribution access generator 

interconnection queues, approximately 100 GW of generation is proposed to interconnect within 

the next 7 years. The majority of this is renewable generation. This results in more than 50% of 

these projects not getting built, but currently the transmission system is being designed to 

facilitate the full 100 GW of new generation. Looking into specific areas of the state, it may be 

pertinent to understand the amount of project failure within each area of interconnection study 

(clustering). If a multiplier, of sorts, was assigned to specific resource types based on capacity 

factors and project failure, a more realistic picture can be painted, and only imperative 

transmission projects would be proposed to offer reliability.

Second, FERC requires that transmission projects be “used and useful.” This requirement ties the 

hands of the utilities to be able to reliably interconnect generation projects. Certain projects may 

not be necessary if utilities could loop existing transmission into “trunk lines” or large generation 

tie lines to facilitate the delivery of large quantities of generation (an example of this is the 

Tehachapi Project). Doing this would allow utilities to fully utilize existing transmission and

reliably integrate renewables where there is substantial base load or even hydro to offset off-peak 

generation.

Third, there are currently no incentives to promote energy storage for generator interconnection 

projects. If there were incentives for renewable energy projects to install and utilize energy 

storage devices in times of over-generation or shoulder peak, transmission could be utilized more 

fully, and utilities could redispatch more cost-effective solutions during peak time, while also 

fully utilizing the transmission system to transmit power to serve load.

Comparison of ISO/RTO

As the various ISOs and RTOs have matured, they have tended to offer similar features and 

services. This is due in part with the fact that FERC has played a significant role in defining the 

necessary components for a reliable grid and efficient and competitive markets. Table 18

compares the various functions played by the eight ISO/RTOs with respect to transmission 

planning and NERC functionality.
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Table 18. ISO/RTO Comparison

NERC RELIABILITY ECONOMIC

Multi-state FERC Regional Regional NERC Planning Planning

ISO/RTO Jurisdictional Region Location Classifications Process Process

NYISO No Yes No NPCC BA, IA, PA, RC, RP, TP, TOP, TSP Yes Yes

PJM Yes Yes No RFC, SERC BA, IA, PA, RC, RP, TP, TOP, TSP Yes Yes

ISO-NE Yes Yes No NPCC BA, IA, PA, RC, RP, TP, TOP, TSP Yes No

MISO Yes Yes No MRO, RFC, SERC BA, IA, PA, RC, TSP, CFR Yes Yes

SPP Yes Yes Yes MRO, SERC, SPP IA, PA, RC, RSG, TP, TSP Yes No

CAISO No Yes No WECC BA, PA, TOP, TSP Yes Yes

ERCOT No No Yes ERCOT BA, IA, PA, RS, RP, TOP, TSP Yes Yes

Balancing 

Authority 

BA The responsible entity that integrates resource plans ahead of time, maintains loadinterchange-generation balance within a balancing area, and supports Interconnection 

Generator 

Operator 

GOP The entity that operates generating unit(s) and performs the functions of supplying energy and 

interconnected operations services. 

Generator 

Owner 

GO Entity that owns and maintains generating units. 

Interchange 

Authority 

IA The responsible entity that authorizes implementation of valid balanced interchange schedules 

between BA areas, and ensures communication of Interchange information for reliability 

assessment purposes

Planning 

Authority 

PA The responsible entity that coordinates and integrates transmission facility and service plans, 

resource plans, and protection systems. 

Reliability 

Coordinator 

RC The entity that is the highest level of authority who is responsible for the reliable operation of 

the bulk power system, has the wide area view of the bulk power system, and has the 

operating tools, processes, and procedures, including the authority to prevent or mitigate 

emergency operating situations in both next-day analysis.

Reserve 

Sharing 

Group 

RSG A group whose members consist of two or more Balancing Authorities that collectively 

maintain, allocate, and supply operating reserves required for each BA’s use in recovering 

from contingencies within the group. Scheduling energy from an adjacent BA to aid recovery 

need not constitute reserve sharing provided the transaction is ramped in over a period the 

supplying party could reasonably be expected to load generation in (e.g., ten minutes). If the 

transaction is ramped in quicker, (e.g., between zero and ten minutes) then, for the purposes 

of disturbance control performance, the areas become an RSG. 

Resource 

Planner 

RP The entity that develops a long-term (generally one year and beyond) plan for the resource 

adequacy of specific loads (customer demand and energy requirements) within a PA area. 

Transmission 

Owner 

TO The entity that owns and maintains transmission facilities. 

Transmission 

Operator 

TOP The entity responsible for the reliability of its local transmission system and operates or directs 

the operations of the transmission facilities. 

Transmission 

Planner 

TP The entity that develops a long-term (generally one year and beyond) plan for the reliability 

(adequacy) of the interconnected bulk electric transmission systems within its portion of the 

PA area. 

Transmission 

Service 

Provider

TSP The entity that administers the transmission tariff and provides transmission service to 

transmission customers under applicable transmission service agreements. 
97

Appendix B: Additional Policy Details

In 1992 the EPAct167 gave FERC “wheeling authority” and created a new category of electricity 

manufacturer: exempt wholesale producers. Additional details of U.S. regulations relevant to the 

transmission system are included in this appendix.

Congestion Management

NERC reliability standards168 require the establishment of operating plans, monitoring of the 

system, and mitigation of limit violations through operational actions. These may include 

implementing redispatch of system resources and facilities. The ERCOT Nodal169 electricity 

market construct provides for meeting reliability requirements through a robust system of 

operating actions that use ancillary services in dispatch actions by the ERCOT ISO. Ancillary 

services are procured and deployed through a comprehensive market system to ensure reliable 

operations in accordance with the NERC reliability standards, as well as with ERCOT’s

Protocols170 and Nodal Operating Guides.171 ERCOT uses a centralized energy dispatch process 

and applies Equipment Operating Ratings and Limits, described in the Protocols. 

ERCOT market dispatch is done using the energy dispatch process according to the Protocols. 

Market-based congestion management techniques are embedded in a Security Constrained 

Economic Dispatch process.

Situations where the market system fails to reach a solution are considered failure(s) of the 

Security Constrained Economic Dispatch process and a reason for an Emergency Notice. 

Typically, actions taken for transmission loading relief, which are subject to this standard, are 

within the context of an Emergency Notice. Such actions may include: (1) system 

reconfiguration (pre- and post-contingency); (2) non-synchronous transfer of load to other 

systems not within the ERCOT Interconnection; and (3) a reduction of interruptible or firm 

loads. 

System Assessment and Transmission Planning 

Long-Term System Assessment 10-year view

ERCOT conducts a Long-Term System Assessment that does not provide specific 

recommendations. It is intended to inform the 5-year planning process by providing a longer 

term view of system reliability and indicates system needs that require solutions that will take 

longer than 5 years to implement. The study consists of two parts: (1) an analysis of the 

reliability needs of the system based on peak load system conditions and (2) an evaluation using 

scenario analysis of the cost-effectiveness of potential economic projects to improve system 

efficiency.

 167 U.S. Department of Energy “Energy Policy Act of 1992,” United States, 2009. 

http://www1.eere.energy.gov/femp/regulations/epact1992.html/. Accessed August 2012. 168 (NERC) North American Energy Reliability Corporation “Reliability Standards,” Washington, D.C., 2012. 

http://www.nerc.com/page.php?cid=2%7C20/. Accessed August 2012. 169 (ERCOT) Electric Reliability Council of Texas “About Texas Nodal,” Texas, 2008. 

http://nodal.ercot.com/about/index.html/. Accessed August 2012. 170 (ERCOT) Electric Reliability Council of Texas “Current Protocols – Zonal,” Texas, 2010. 

http://www.ercot.com/mktrules/protocols/current/. Accessed August 2012. 171 (ERCOT) Electric Reliability Council of Texas “Nodal Operating Guides,” Texas, 2011. 

http://www.ercot.com/mktrules/guides/noperating/. Accessed August 2012.
98

Transmission Planning Process

As the transmission planning authority for the region, ERCOT works with the region’s 

transmission and distribution providers and other stakeholders to identify the need for new 

transmission facilities based on engineering analysis of operational results, load forecasting, 

generation interconnections, and transmission and system studies. As part of the planning 

process, ERCOT seeks input from all market participants and stakeholders about options and 

possible solutions through the ERCOT-led Regional Planning Group. Major projects must also 

be endorsed by the ERCOT Board of Directors.

To provide transmission customers with more information and clarity on the workings of a 

transmission provider’s system, all transmission providers must include a coordinated regional 

planning process plan as Attachment K to the revised OATT. The planning process may vary

depending on the region, but must include all nine FERC-mandated principles: coordination, 

openness, transparency, information exchange, comparability, dispute resolution, regional 

coordination, economic planning studies, and cost allocation.

Available Transfer Capability

In Order No. 888, FERC did not prescribe a calculation for ATC. Under Order No. 890, FERC 

now requires that the calculations and procedures used to determine ATC be transparent and 

consistent to reduce opportunities for undue discrimination. Transmission providers will need to 

include, as Attachment C in all OATT filings, the NERC methodology used to calculate ATC 

(i.e., contract path, network ATC, or network AFC),

172 a process flow diagram that describes the 

various steps in performing the ATC calculation, and a definition and explanation of each ATC 

component (i.e., Total Transfer / Flowgate Capabilities), Existing Transmission Commitments, 

Capacity Benefit Margin, and Transmission Reserve Margin). The algorithm used to determine 

ATC must be provided on the transmission provider’s website. 

Creditworthiness

FERC found that a transmission provider’s credit standards significantly affect transmission 

service. Therefore, each transmission provider must include the qualitative and quantitative 

criteria used to determine the level of secured and unsecured credit required from customers in a 

new OATT Attachment L.173 Attachment L must include: (1) a summary of procedures for 

determining the level of secured and unsecured credit; (2) a list of acceptable types of 

collateral/security; (3) procedures for providing customers with reasonable notice of changes in 

credit levels and collateral requirements; (4) procedures for providing upon request a written 

explanation for any change in credit levels or collateral requirements; (5) reasonable 

opportunities to contest determinations of credit levels or collateral requirements; and (6) 

reasonable opportunities to post additional collateral, including curing any non-creditworthy 

determinations. 

Energy and Generator Imbalances

Finding previous imbalance charges “excessive, too varied, and otherwise unrelated to the cost 

of providing the service,” FERC adopted the following tiered charges for energy and generator 

imbalances:

 172 (NERC) “Standard MOD-001-0 — Documentation of TTC and ATC Calculation Methodologies,” New Jersey, 

2005. http://www.nerc.com/files/MOD-001-0.pdf. Accessed August 2012. 173 (FERC) Federal Energy Regulatory Commission “FERC Order 890-A Preventing Undue Discrimination and 

Preference in Transmission Service,” United States, 2007. http://www.ferc.gov/whats-new/commmeet/2007/122007/E-1.pdf. Accessed August 2012.
99

• Tier 1 – Imbalances of less than or equal to 1.5% of scheduled transmission (or 2 MW, 

whichever is larger): 100% of transmission provider’s incremental cost for under

scheduling imbalances or decremental cost for over-scheduling imbalances

• Tier 2 – Imbalances greater than 1.5% and up to 7.5% of scheduled transmission:

Charges of 90% of a transmission provider’s decremental cost for over-scheduling 

imbalances; 110% of incremental cost for under-scheduling imbalances

• Tier 3 – Imbalances above 7.5% of scheduled transmission: Charges of 75% of a 

transmission provider’s decremental cost for over-scheduling imbalances; 125% of 

incremental cost for under-scheduling imbalances. 

FERC exempted intermittent resources from the highest deviation band (Tier 3) to not unduly 

penalize these resources. FERC declined to modify intra-hour netting procedures, but limited its 

use to Tier 1 imbalances only. FERC also declined to abrogate existing generator imbalance 

agreements, but invited any party desiring an amendment to “exercise whatever rights it may 

have under the agreement or FPA section 206.” 

In a change from Order No. 888, unreserved use and imbalance penalty revenue is to be 

distributed to all non-offending transmission customers, including affiliated customers. 

Transmission providers are to determine a nondiscriminatory payment mechanism to the extent 

the unreserved use penalty revenue accrues above the transmission provider’s base firm point-topoint transmission service charge or the imbalance penalty revenue accrues above the provider’s 

incremental cost. 

Transmission Credits for Integrated Facilities

While keeping the general transmission credits structure the same, FERC eliminated the 

requirement that transmission facilities funded by network customers must be part of a 

provider’s “joint planning” process to be eligible for credits. The joint planning requirement 

created a disincentive for transmission providers to coordinate planning of facilities. Now, 

facilities need only be integrated with a transmission provider’s system to be eligible for credits. 

Facilities are presumed integrated if they are: (1) owned by the provider and (2) eligible for rate 

recovery by such provider. This standard applies only to transmission facilities added after the 

effective date of Order 890. 

Transmission Capacity Reassignment

FERC lifted the price cap on the reassignment of point-to point service for all customers to 

eliminate what it considers an unnecessary impediment to the resale of transmission capacity. 

FERC declined to retain the price cap for a transmission provider’s merchant function and 

affiliates as originally proposed in Order 890’s Notice of Proposed Rulemaking. Any such 

reassignments must be reported on OASIS before the effective date of such assignment and 

aggregated in a quarterly report made by the transmission provider to FERC. The transmission 

assignee must execute a service agreement with the original transmission provider that will 

govern the service being assigned. 

Changes to Long-Term Firm Point-to-Point Service – Redispatch and Conditional 

Firm

FERC concluded in Order 890 that the existing methodologies for evaluating requests for longterm, firm, point-to-point services are “no longer just, reasonable and not unduly 

discriminatory.” Therefore, FERC requires that when transmission requests cannot be met with 
100

existing capacity, the transmission provider must offer customers either planning redispatch or 

conditional firm service. This is a deviation from FERC’s original position in the notice of 

proposed rulemaking that only one of these options would be required. With planning redispatch, 

FERC wanted to make redispatch “of greater use to transmission customers and more consistent 

with reliability planning and operation of the system.”

174 Although FERC declined to require 

planning redispatch for third-party resources, transmission providers must identify any thirdparty resources that could relieve system congestion in the system impact study process. Also, 

there is no requirement to cap redispatch prices over the term of the service at the costs of 

expanding the system. Redispatch pricing will be either: (1) the higher of the (a) actual 

incremental costs of redispatch or (b) applicable embedded cost transmission rate (monthly), or 

(2) a negotiated fixed rate subject to a cap representing the total fixed and variable costs of the 

resources expected to provide the redispatching service. 

Conditional, firm, point-to-point service is long-term firm service, with periods of less than firm 

service during: (1) a defined number of hours or (2) defined system conditions. This allows firm 

service when an otherwise economic agreement would be denied because the resource might not 

be deliverable for a few hours out of the entire service agreement term. Notably, network 

resource designations may still be supported by conditional firm service because conditional 

service is not interruptible for economic reasons. Neither planning, redispatch, nor conditional 

firm service is required when it would impair system reliability. 

Rollovers

Under FERC Order 890-B, the rollover term requirement of OATT § 2.2 has been extended so 

that only service agreements for 5 years and longer are eligible.

175 The notice period has also 

been extended from 60 days to 1 year, and customers must match any competing requests as to 

term and rate to retain their priority in the service request queue. All current contracts will roll 

over under previous rollover standards until the contracts are renewed following the acceptance 

of the transmission provider’s planning process. Once the transmission provider’s planning 

process is accepted by FERC, the new rollover provisions become effective and only service 

contracts of 5 years or longer in duration may roll over. Notably, customers will retain their 

rollover rights even if they redirect to other service providers. 

Network Resources / Secondary Network Service

FERC is requiring that all network customers attest in each application for network service that: 

(1) the customer owns or is committed to purchasing the designated network resource and (2) the 

network resource fulfills the requirements of a designated resource.

176 Network resources must 

 174 Stoel Rives, LLP “Energy Law Alert: Order No. 890: FERC Creates New Transmission Service Rules for Wind 

Energy; ‘Prying Open The Black Box,’” United States, 2007. http://www.stoel.com/showalert.aspx?Show=2302/. 

Accessed August 2012. 175 Troutman Sanders, LLP “Regulatory Alert Bulletin,” Washington, D.C. 2008. 

http://www.troutmansanders.com/files/FileControl/984289c3-6168-49a6-a830-48cdadbb0344/7483b893-e478-44a4-

8fed-f49aa917d8cf/Presentation/File/Troutman%20Sanders%20Order%20No.%20890-B%20Summary.pdf. 

Accessed August 2012. 176 Order No. 890 requires that all designated network resources requests be accompanied by an attestation stating 

that the request meets the requirements of section 29.2 and 30.2 of the pro forma OATT. Order No. 890-A requires 

that the attestation be provided in the customer comment section of the OASIS at the time of confirmation (or at the 

time of submittal if the request is pre-confirmed), and that the language of the pro forma OATT sections 29.2(vii) 

and 30.2 be included in the attestation. Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 919; (FERC) “Order 

Accepting Compliance Filing, Subject to Further Compliance Filing, Granting Limited Waiver Request and 
101

be undesignated as network resources to sell third-party firm service. Power purchase 

agreements with liquidated damage “make whole” provisions are the only agreements with 

liquidated damage provisions that may be considered a network resource. Agreements with fixed 

damages or damage caps are not eligible. FERC declined to limit secondary network service, and

instead retained the rule that this service may be used to deliver economy energy to network 

loads.

Integration of NERC and NAESB Standards

OASIS NERC and NAESB have been tasked by FERC to integrate a number of new 

functionalities into OASIS to increase transmission system transparency and reduce undue 

discrimination. These new functionalities include the amount of unused transfer capability 

associated with transmission reservations; underlying load forecast assumptions for all ATC 

calculations; number of rejected affiliate versus non-affiliate requests for transmission service;

and the total number of affiliate versus non-affiliate requests for transmission service and 

quarterly performance metrics for processing transmission delivery service requests.

Enforcement

FERC staff has been tasked with performing compliance audits of OATTs.

177 The most severe

consequences will be determined on a case-by-case basis and include civil penalties, a revocation 

of market-based rates (if there is a factual nexus between the violation and the market-based 

rates), and findings of market manipulation under Section 222 of the Federal Power Act. In 

general, however, operational penalties will be used to enforce OATT rules and regulations.

Examples of such operational penalties include the following unreserved use penalties (if 

included in the OATT):

• Penalties for use of transmission service that was not reserved must not be greater than 

twice the firm point-to-point rate for the period of unreserved use. In a change from 

Order 888, unreserved use penalty revenue is to be distributed to all non-offending 

transmission customers (including affiliated customers) to the extent the revenue accrues 

above the transmission provider’s base firm point-to-point transmission service charge. 

• Penalties for a failure to meet the 60-day deadline to finish system impact and facilities 

studies: After failing to meet the 60-day compliance deadline for a system impact or 

facilities study, a transmission provider must notify the FERC. In the 120 days after such 

notification, if the transmission provider does not finish 90% of its studies within each 

study’s 60-day deadline, then penalties begin accruing (assessed each quarter) of $500 

per day per late study until a quarter occurs when 90% of all studies are completed within 

60-days of receipt of the customer’s request. 

FERC Order 1000 

FERC has placed an increasing role in reliability and the rules and standards governing 

reliability. Most recently in this area is Order 1000 on transmission planning and cost 

allocation.178 Order 1000 is intended to apply to new transmission facilities. The requirements of 

 

Granting Clarification Request,” United States, 2009. https://www.ferc.gov/EventCalendar/files/20090603154917-

oa08-75-000.pdf. Accessed August 2012. 177 (FERC) Federal Energy Regulatory Commission “How Audits are Conducted,” United States, 2010. 

http://www.ferc.gov/enforcement/audits/conducted.asp/. Accessed August 2012. 178 (FERC) Federal Energy Regulatory Commission “Order No. 1000 - Transmission Planning and Cost Allocation,” 

United States, 2012. http://www.ferc.gov/industries/electric/indus-act/trans-plan.asp/. Accessed August 2012.
102

Order 1000 apply to the evaluation or reevaluation of any transmission facility that occurs after 

the effective date of the public utility transmission provider’s filing adopting the reforms 

required by Order 1000. The Commission-directed public utility transmission providers must 

explain in their compliance filings how they would determine which facilities would be subject 

to the requirements of Order 1000. Based on an initial summary, Order 1000 establishes the 

following requirements.

There are three requirements for transmission planning:

• Each public utility transmission provider must participate in a regional transmission 

planning process, which produces a single regional transmission plan and satisfies the 

principles under Order 890.

• Each transmission planning process at the local and regional level must consider 

transmission needs driven by federal or state laws or regulations.

• Public utility transmission providers in neighboring transmission planning regions must 

coordinate concerning more efficient or cost-effective solutions.

There are three requirements for transmission cost allocation:

• Each public utility transmission provider must participate in a regional transmission 

planning process, which has a regional cost allocation method for new transmission 

facilities that satisfies six regional cost allocation principles.

• Public utility transmission providers in neighboring planning regions must have a 

common interregional cost allocation method for new interregional transmission 

facilities, which satisfies six regional cost allocation principles.

• Participant funding of new transmission facilities is permitted but not as part of the 

regional or interregional cost allocation method.

Federal Rights of First Refusal must be removed from Commission-approved tariffs and 

agreements are subject to four limitations:

• The requirement would not apply to a transmission facility not selected in a regional 

transmission plan for purposes of cost allocation.

• The requirement would not apply to upgrades to transmission facilities (i.e., tower change 

outs or reconductoring).

• The rule would allow, but not require, competitive bidding to solicit transmission projects 

or developers.

• Nothing in this requirement impacts state or local laws concerning construction of 

transmission facilities, including siting or permitting.

One additional requirement is that each public utility transmission provider must add a tariff 

provision that requires the provider to reevaluate the regional transmission plan to determine if 

alternative solutions need to be evaluated when there is a delay in the development of a 

transmission facility. Such alternative solutions can include those proposed by the incumbent.
103

All public utility transmission providers are required to make a compliance filing within 12 

months of the effective date of the final rule; compliance filings for the regional planning and 

cost allocation requirements are due in 18 months.

FERC and the States

The U.S. has adopted a federalist system for regulating the electricity industry. FERC has an 

important role, and state regulators have an important role. Table 19 illustrates these roles.

179

Table 19. Federal Regulation and State Regulation for the Electricity Industry

FEDERAL REGULATION STATE REGULATION

• Wholesale transactions (sales of energy for 

resale) 

• Interstate transmission (transfers of power across 

state lines) 

• Rates charged for transmission of oil 

• Hydroelectric licenses 

• Licensing of nonfederal hydroelectric projects 

• Inspection of hydroelectric projects for safety 

issues 

• Regulating the interstate transportation of natural 

gas, oil, and electricity

• Approving the construction of interstate natural 

gas pipelines, storage facilities, and Liquefied 

Natural Gas terminals

• Monitoring energy markets and companies to 

protect customers from market manipulation and 

higher prices

• Resolving disputes between energy companies, 

other organizations, and the public

• Overseeing mergers

• Reviewing rates set by the Bonneville Power 

Administration and federal power marketing 

administrations 

• Certifying co-generators which use energy for 

both productions of electricity and industrial 

processes

• Retail sales (sales of energy to users) 

• Intrastate transmission (transfers of power within 

state boundaries) 

• Certification for new electric generation and 

electric transmission facilities 

• Certification for oil pipelines 

• Develop retail franchise areas 

• Enforce service and quality standards 

• Set retail tariffs 

• Approve planning of transmission and generation 

facilities 

• Approve construction of non-hydro generation 

and transmission facilities 

However, FERC does not regulate the following:

• The physical siting of electrical generation, transmission, or distribution facilities, except 

for hydroelectric projects and under certain circumstances transmission lines

• Activities of municipal power systems, the Tennessee Valley Authority, and most rural 

electric cooperatives

 179 (FERC) Federal Energy Regulatory Commission “What FERC Does,” United States, 2012. 

http://www.ferc.gov/about/ferc-does.asp/. Accessed August 2012.
104

ERCOT Protocols and Guides

For the ERCOT region, Texas Reliability Entity develops, through its own FERC-approved 

processes, separate regional reliability standards that go beyond, add detail to, or implement 

NERC reliability standards, or that cover matters not addressed in NERC reliability standards. 

Any entity (organization, company, government agency, individual) that is directly and 

materially affected by the reliability of the ERCOT bulk power systems may request an ERCOTspecific regional reliability standard to be developed, modified, or withdrawn by sending a 

Standard Authorization Request Form to the Reliability Standards Manager. The Reliability 

Standards Committee reviews and recommends action on ERCOT-specific reliability standards 

and regional variances to NERC standards. 

In the ERCOT region, in addition to NERC reliability standards, ERCOT Protocols and 

Operating Guides outline the procedures and processes used by the ERCOT ISO and market 

participants for the orderly functioning of the ERCOT system and market. These ERCOT market 

rules are approved through a stakeholder process that is facilitated by ERCOT staff. Texas 

Reliability Entity has been authorized by the Texas PUC and is permitted by NERC to 

investigate compliance with the ERCOT Protocols and Operating Guides. Texas Reliability 

Entity does not develop, revise, or modify the ERCOT Protocols or Operating Guides.
105

Additional Resources

Western Electric Coordinating Council (WECC) http://www.wecc.biz/Pages/Default.aspx

Northeast Power Coordinating Council (NPCC) https://www.npcc.org/default.aspx

Midwest Reliability (MRO) http://www.midwestreliability.org

Reliability First Corporation (RFC) https://rfirst.org/Pages/Rfirst.aspx

Southwest Power Pool (SPP) http://www.spp.org

SERC Reliability Corporation (SERC) http://serc1.org/Application/HomePageView.aspx

Florida Reliability Coordinating Council (FRCC) https://www.frcc.com/default.aspx

Electric Reliability Council of Texas (ERCOT) http://www.ercot.com

NERC Regional Entities (RE) http://www.nerc.com/page.php?cid=1|9|119

Transmission Capability Indices (ATC etc.) http://www.westgov.org/wieb/wind/06-

96NERCatc.pdf

WECC Common Corridor Standard 

http://www.wecc.biz/Standards/Development/Lists/Request%20Form/DispForm.aspx?ID=71&S

ource=/Standards/Development

Financial congestion management (PJM Training)

http://www.pjm.com/~/media/training/core-curriculum/ip-lmp-101/lmp-ftr-101-training.ashx

Conditional Firm Transmission 

http://old.nationalwind.org/events/webinar/Webinar_Presentation.pdf

http://www.nationalwind.org/assets/publications/ferc890.pdf

http://www.epsa.org/forms/uploadFiles/715D00000064.filename.EPSA_-

_Redispatch_and_CFS_Bare_Essentials.pdf

http://www.nationalwind.org/assets/blog/WGA_NWCC_Redispatch_Factsheet.pdf

FERC transmission incentive rates

http://www.ferc.gov/industries/electric/indus-act/trans-invest.asp

http://www.ferc.gov/industries/electric/indus-act/trans-invest/2009.asp
106

http://www.whitecase.com/files/Uploads/Documents/alert-FERC-Extends-TransmissionRate.pdf

Available Transmission Capability (ATC) definitions and methodology

http://www.nerc.com/docs/docs/pubs/atcfinal.pdf

ACCR Conductors 

http://solutions.3m.com/wps/portal/3M/en_US/EMD_ACCR/ACCR_Home/?WT.mc_id=www.3

m.com/ACCR

ACCC Conductors http://www.ctccable.com/pdf/ACCCOverview.pdf

SyncroPhasor Measurements www.naspi.org

NYPA Convertible Static Compensator (CSC) 

http://tdworld.com/mag/power_reinforcing_td_infrastructure

Uprating thermal conductor ratings 

http://tdworld.com/mag/power_uprating_transmission_lines/index.html

Conductor thermal rating 

http://www.southwire.com/transmission/OCM.htm

IEEE Standard 738

http://standards.ieee.org/findstds/standard/738-1993.html

FACTS Devices

http://www.energy.siemens.com/hq/en/power-transmission/facts

http://www.abb.com/facts

http://www.meppi.com/pages/results.aspx?k=statcom&cs=This%20Site&u=http%3A%2F%2Fw

ww.meppi.com

HVDC

http://www.energy.siemens.com/hq/en/power-transmission/hvdc

http://www.abb.com/hvdc

http://www.ebooks-freedownload.net/2011/pdf-link/hvdc-systems.html

Series Capacitors

http://www.abb.com/search.aspx?q=series%20capacitor%20banks&abbcontext=products
107

Rocky Mountain Area Transmission Study on expanding existing transmission. 

http://psc.state.wy.us/rmats/rmats.htm

EPRI report on transmission technology

http://mydocs.epri.com/docs/CorporateDocuments/SectorPages/PDU/TransmissionEfficiencyInit

iative/index.html

DOE Technology Brief

http://www.scribd.com/doc/6630240/Tech-Briefs

U. S grid structure

http://www.isorto.org/site/c.jhKQIZPBImE/b.2603295/k.BEAD/Home.htm

U. S. ISOs and RTOs

http://www.caiso.com/Pages/default.aspx

http://www.ercot.com

http://www.iso-ne.com

https://www.misoenergy.org/Pages/Home.aspx

http://www.nyiso.com/public/index.jsp

http://www.pjm.com

http://www.spp.org

NERC History

http://www.nerc.com/page.php?cid=1|7|11

NERC Regional Entities (RE)

https://www.npcc.org/default.aspx

http://www.midwestreliability.org

https://rfirst.org/Pages/Rfirst.aspx

http://serc1.org/Application/HomePageView.aspx

https://www.frcc.com/default.aspx

http://www.spp.org
108

http://www.wecc.biz/awareness/Reliability/Pages/default.aspx

NERC glossary

http://www.nerc.com/files/Glossary_of_Terms_2010April20.pdf

Additional Policy Details

http://www.ferc.gov/about/about.asp

http://www.ferc.gov/legal/maj-ord-reg.asp