February 2,2006 

The Honorable J. Dennis Hastert 

Speaker of the House of Representatives 

Washington, D.C. 205 15 

Dear Mr. Speaker: 

Section 1839 of the Energy Policy Act of 2005 requires the Secretary of Energy 

and the Federal Energy Regulatory Commission (Commission) to study and 

report to Congress on the steps that must be taken to establish a system to make 

available to all transmission system owners and Regional Transmission 

Organizations within the Eastern and Western Interconnections real-time 

information on the functional status of all transmission lines with such 

Interconnections. Additionally, section 1839 directs the Commission to assess the 

technical means for implementing such a transmission information system and 

identify the steps the Commission or Congress must take to require the 

implementation of such a system. 

We are pleased to submit the enclosed report addressing these issues. Should you 

have questions concerning this report, we hope you will not hesitate to contact 

Mr. Kevin Kolevar, Director of the Office of Electricity Delivery and Energy 

Reliability, at (202)586-1411 and Mr. Philip Overholt at (202) 586-81 10, or the 

Commission’s Director of the Division of Reliability, Mr. Joseph McClelland, at 

(202)502-8661 or Mr. Mahmood Mirheydar at (202) 502-8034. 

Sincerely, 

Samuel W. Bodman 

Secretary 

U.S. Department of Energy 

Enclosure 

cc: The Honorable Joe Barton 

Chairman, Committee on Energy and Commerce 

U.S. House of Representataives 

The Honorable John D. Dingell 

Ranking Minority Member 
February 2,2006 

The Honorable hchard B. Cheney 

President of the Senate 

Washington, D.C. 20510 

Dear Mr. President: 

Section 1839 of the Energy Policy Act of 2005 requires the Secretary of Energy 

and the Federal Energy Regulatory Commission (Commission) to study and 

report to Congress on the steps that must be taken to establish a system to make 

available to all transmission system owners and Regional Transmission 

Organizations within the Eastern and Western Interconnections real-time 

information on the functional status of all transmission lines within such 

Interconnections. Additionally, section 1839 directs the Commission to assess the 

technical means for implementing such a transmission information system and 

identify the steps the Commission or Congress must take to require the 

implementation of such a system. 

We are pleased to submit the enclosed report addressing these issues. Should you 

have questions concerning this report, we hope you will not hesitate to contact 

Mr. Kevin Kolevar, Director of the Office of Electricity Delivery and Energy 

Reliability at (202)586-1411 and Mr. Philip Overholt at (202) 586-8 110, or the 

Commission’s Director of the Division of Reliability, Mr. Joseph McClelland at 

(202)502-8661, or Mr. Mahmood Mirheydar at (202) 502-8034. 

Samuel W 

Secretary 

U.S. Department of Energy gulatory Commission 

Enclosure 

cc: The Honorable Pete V. Domenici 

Chairman, Committee on Energy and Natural Resources 

United States Senate 

The Honorable Jeff Bingaman 

Ranlung Minority Member 
STEPS TO ESTABLISH A TRANSMISSION MONITORING SYSTEM FOR 

TRANSMISSION OWNERS AND OPERATORS WITHIN THE EASTERN 

AND WESTERN INTERCONNECTIONS 

A REPORT TO CONGRESS 

PURSUANT TO SECTION 1839 

OF THE 

ENERGY POLICY ACT OF 2005 

Prepared by 

United States Department of Energy 

& 

Federal Energy Regulatory Commission 

February2006 
STEPS TO ESTABLISH A TRANSMISSION MONITORING 

SYSTEM FOR TRANSMISSION OWNERS AND OPERATORS 

WITHIN THE EASTERN AND WESTERN INTERCONNECTIONS 

A REPORT TO CONGRESS 

PURSUANT TO SECTION 1839 

OF THE 

ENERGY POLICY ACT OF 2005 

Prepared by 

United States Department of Energy 

& 

Federal Energy Regulatory Commission 

February 2006 
TABLE OF CONTENTS 

Executive Summary 

Section I: Introduction 

Section 11: Assessment of Technical Means and Steps to Establish a Transmission 

Monitoring System 

Define What a Real-Time Monitoring System is, What it Should Accomplish, and How 

to Accomplish it 

Evaluate Existing Real-Time Monitoring Technologies and their Limitations 

Identify Required Communications and Related Security and Operating Issues 

Define Data Requirements 

Identify Promising Emerging Technologies 

Decide what Data Should be Shared, with Whom, and When 

Decide Who Should Operate, Use, and Maintain the System 

Identify Potential Participants Involved in Establishing a Real-Time Monitoring System 

Consider Cost and Funding Issues 

Section 111: Steps to Implement an Interconnection-Wide Real-Time Monitoring 

System 

Research and Study Efforts 

Possible Development of Real-Time Information Monitoring Reliability Standards 

Section IV: Conclusion and Recommendations 

Appendix A Acronyms 

Appendix B Glossary of Terms 

Appendix C Geographical Boundaries of Interconnections 

Appendix D Functional Status Matrix 

Appendix E SCADA and EMS Communications 

Appendix F Proposed Transmission System Monitoring Data Communication 

Infrastructure 

Appendix G Map of NERC Regional Reliability Councils 
Report to Congress 

Joint Report by the Department of Energy and Federal Energy Regulatory 

Commission on 

Steps to Establish a Transmission Monitoring System for 

Transmission Owners and Operators 

within the Eastern and Western Interconnections 

February 2006 

Executive Summary 

In August 2003, an electrical outage in one state precipitated a cascading blackout across 

seven other states and as far north as a province in Canada, leaving more than 50 million 

people without power.’ The 2003 event was the largest blackout in the history of the 

United States, the eighth large-scale blackout experienced by North America since 1965; 

and the fourth U.S. blackout caused in part by deficiencies in the system that monitors the 

electric grid and by a lack of awareness of deteriorating conditions by the operators who 

monitor the system? 

Section 1839 of the Energy Policy Act of 2005 (EPAct 2005)4 directs the Secretary of 

Energy (DOE) and the Federal Energy Regulatory Commission (Commission) to study 

and report to Congress on the steps that must be taken to establish a system to make 

available to all transmission owners and Regional Transmission Organizations (RTOs)’ 

U.S. Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in 

the United States and Canada: Causes and Recommendations, April 2004, at 1 (Final Blackout Report). 

The Task Force investigated the causes of the 2003 blackout and recommended actions be taken to prevent 

future widespread outages. 

1 

* Id. at 104-07. The other seven blackouts include the 1965 Northeast blackout, the 1977 New 

York City blackout, the 1982 and the July and August of 1996 West Coast blackouts, the 1998 Upper 

Midwest blackout, and the 1999 Northeast U.S. outages and non-outage disturbances. 

Id. at 104-06. The other instances in which monitoring system failures or lack of situational 

awareness contributed to blackouts include the November 1965 Northeast blackout, the July 1977 New 

York City blackout, and the July 1996 West Coast blackout. 

Energy Policy Act of 2005, Pub. L. No. 109-58, 0 1839, 119 Stat. 594, 1142 (2005) (hereinafter 

“EPAct 2005”). 

’ EPAct 2005 defines an RTO as an entity of sufficient regional scope approved by the 

Commission: (a) to exercise operational or hctional control of facilities used for the transmission of 

electric energy in interstate commerce; and (b) to ensure nondiscriminatory access to the facilities. See 

1 
within the Eastern and Western Interconnections real-time information on the functional 

status of all transmission lines within such Interconnections.6 The study is to assess 

technical means for implementing a transmission information system and identify the steps 

the Commission or Congress would need to take to require implementation of such 

system. This Joint Report responds to Congress’ directive and addresses whether 

technology provides a means to address deficiencies in the transmission monitoring 

system and to provide better information to all system operators. The report focuses not 

on whether such a system should be deployed but offers a technical evaluation of how 

such a system could be established if one is to be pursued. This joint report merely 

describes the steps necessary to establish and implement an interconnection-wide 

monitoring system and does not require the Commission to implement such a system. 

Finally, this report acknowledges that a feasibility determination is necessary prior to any 

action to implement a real-time monitoring system and that the implementation of such a 

system is beyond the scope of Congress’ direction in section 1839 of EPAct 2005. 

7 

This report finds that: 

technology currently exists that could be used to establish a real-time transmission 

monitoring system to improve the reliability of the nation’s bulk power system; and 

emerging technologies hold the promise of greatly enhancing transmission system 

integrity and operator situational awareness, thereby reducing the possibility of 

regional and inter-regional blackouts. 

The analysis herein identifies nine steps that could be taken to establish, and two steps that 

could be taken to implement, an interconnection-wide real-time monitoring system that 

could give a near-instant picture of the transmission system’s health. Specifically, the 

report identifies a real-time transmission monitoring system that could provide the 

following primary and secondary benefits to enhance the situational awareness of system 

~ 

EPAct 2005 tj 1291, 119 Stat. 594,984 (to be codified as amended at 16 U.S.C. 9 796 in the Federal Power 

Act (FPA)). Commission-approved RTOs are those that have filed for and received approval fiom the 

Commission for RTO status pursuant to Order No. 2000. Regional Transmission Organizations, Order No. 

2000, 1996-2000 FERC Stats. & Regs., Regs. Preambles f 3 1,089 (1999), order on reh‘g, Order No. 2000- 

A, 1996-2000 FERC Stats. & Regs., Regs. Preambles f 3 1,092 (2000), petitions for review dismissed sub 

nom. Public Utility District No. I of Snohomish County, Washington v. FERC, 272 F.3d 607 @.C. Cir. 

200 1). 

There are three distinct power grids or “interconnections” in North America. The Eastern 

Interconnection includes the eastern two-thirds of the continental United States and Canada fiom 

Saskatchewan east to the Maritime Provinces. The Western Interconnection includes the western third of 

the continental United States (excluding Alaska), the Canadian provinces of Alberta and British Columbia, 

and a portion of Baja-Califomia-Norte-Mexico. The third interconnection comprises most of the state of 

Texas. Appendix C provides a map detailing the geographical boundaries of these interconnections. 

EPAct 2005 9 1839, 1 19 Stat. 594, 1142. I 

2 
operators, should such a system be implemented. 

The primary benefits of a real-time transmission monitoring system could be to: 

0 provide early warning of deteriorating system conditions, so operators can take 

corrective actions; 

0 limit the cascading effect of disturbances (by providing wide-area system 

visibility); and 

0 improve transmission reliability planning and allow for immediate post-disturbance 

analysis and visualization through the use of archived monitoring system data. 

The secondary benefits of a real-time transmission monitoring system could be to: 

0 provide more diagnostic tools than are currently available; 

0 allow for the more effective use of automatic controls for self-correction such as 

automatic switching or controlling the flow of power; and 

improve computer models of the power system. 

This report concludes that if an interconnection-wide transmission monitoring system is 

pursued: 

0 implementation of the system could occur in two phases, with the first phase 

focusing on upgrading the current Supervisory Control and Data Acquisition' 

(SCADA)-based real-time monitoring system (Phase I) and the second phase 

focusing on developing a better real-time monitoring system based on emerging 

technologies (Phase 11); 

other technical features of a real-time transmission monitoring system require that 

uniform data and common data storage be used across the system so that all system 

operators can share and use each other's data with ease; and 

0 the system will need to have common visualization features so that all users will 

view the real-time information in a similar fashion. 

The design process for Phase I could be started without delay since it would be based on 

the existing SCADA system and require data collection from a limited number of SCADA 

data sources, collected every few seconds. Phase I1 would be based on advanced 

technology and require data collection from thousands of data sources collected many 

times per second. If an interconnection-wide transmission monitoring system is to be 

installed, it is recommended that planning for Phase I1 begin at the same time Phase I is 

being designed. 

This Joint Report recommends that if an interconnection-wide transmission monitoring 

system is pursued: 

' A system of remote control and telemetry used to monitor and control the electric system. 

3 
the Commission, in consultation with DOE, engage the soon-to-be established 

Electric Reliability Organization (ERO) that is certified by the Commission 

pursuant to section 21 5 of the FPA, to investigate and report on the feasibility, cost, 

and timeline to establish such a system; and 

the ERO develop its report using technical conferences, industry meetings, and 

independent studies. 

The analysis from the ERO report is expected to provide critical information that could be 

used to develop mandatory reliability standards necessary for the implementation of a realtime monitoring system. Implementation of an interconnection-wide real-time monitoring 

system, as assessed in this analysis, could enhance the situational awareness of 

transmission system operators, as recommended in the Final Blackout Report, thereby 

addressing one of the “principal causes”9 of the blackout. 

Section I: Introduction 

The United States’ electric transmission system is so intricately connected and 

interdependent that an electrical outage in just one state can cause cascading blackouts 

throughout many states, even through a neighboring country. Just such an event occurred 

on August 14,2003, when an electrical outage that began in Ohio caused a widespread 

blackout affecting 50 million people in Ohio, Michigan, Pennsylvania, New York, 

Vermont, Massachusetts, Connecticut, New Jersey, and the Canadian province of 

Ontario.” 

On August 15,2003, President George W. Bush and then-Prime Minister Jean Chrktien 

directed that a joint US-Canada Power System Outage Task Force be established to 

investigate the causes of this blackout. The Final Blackout Report identified, among other 

things, failures in the system that monitors the electric grid and the operators’ lack of 

situational awareness, which “was in turn the result of inadequate reliability tools and 

backup capabilities.”” Some of the monitoring failures identified in the Final Blackout 

Report were: 

9. Final Blackout Report, supra note 1, at 159, Recommendation Number 22. 

lo Id. at 1. According to the report, this outage cost the United States between $4 billion and $10 

billion and some parts of the United States were without power for up to four days. 

l1 Id. at 159, Recommendation Number 22. In addition to the deficiencies in tools for better 

visualization, the Final Blackout Report identified ineffective vegetation management practices (which 

allowed trees to interfere with energized lines) and inadequate operator training (personnel failed to declare 

an emergency and take timely and appropriate action) as contributing factors to the blackout. Id. at 59, 

157. 

4 
the failure of operators to detect the loss of transmission lines, to recognize or 

understand the deteriorating condition of the system, and to recognize the need for 

action due to insufficient information;’2 

0 the failure of operators to assess and understand the inadequacies of the system, 

particularly in regard to voltage ~tability;’~ and 

0 the failure of the interconnected grid’s reliability organizations to provide effective 

real-time diagnostic ~upport.’~ 

The above inadequacies (which highlight the lack of situational awareness), coupled with 

the interdependencies and the interconnected nature of the nation’s electric grid, 

demonstrate the need to establish an interconnection-wide monitoring system that could be 

used by owners and operators to provide an early warning so that preemptive actions can 

be taken to limit or prevent cascading outages. 

The Final Blackout Report also provided the following recommendations for avoiding 

future blackouts: 

the Commission and appropriate authorities in Canada should establish 

requirements for collecting and reporting of data needed for post-blackout 

ana~yses;’~ 

0 DOE should expand its research programs on reliability-related tools and 

technologies;16 

0 the North American Electric Reliability Council (NERC)” should evaluate and 

adopt better real-time tools for operators and Reliability Coordinators (RC);18 

l2 Id. 

Id. Voltage stability is defined as the condition of an electric system in which the sustained 13 

voltage level is controllable and within predetermined limits. 

l4 Id. 

l5 Id. at 148, Recommendation Number 1 1. 

l6 Id. at 149, Recommendation Number 13. 

l7 NERC is a not-for-profit organization formed by the electric utility industry in 1968 to promote 

the reliability of the electricity supply in North America through, among other things, the development of 

reliability standards. Appendix G provides a map illustrating the 10 regional reliability councils that 

comprise NERC to date. 

l8 Id. at 159, Recommendation Number 22. An RC is an individual or organization responsible for 

the safe and reliable operation of the interconnected transmission system for its defined area, which is 

comprised of a combination of several balancing entities who are responsible for “balancing” generation 

and load in real time. The RC facilitates the sharing of data and information about the status of the 

Balancing Authorities for which it is responsible, establishes a security policy for these Balancing 

Authorities and its interconnections, and coordinates emergency operating procedures that rely on common 

5 
0 NERC should improve the quality of system modeling data and data exchange 

practices; 

NERC, the Commission, and appropriate Canadian authorities should require the 

use of time-synchronized data recorders;20 and 

corporations should establish clear authority and ownership for physical and cyber 

security.*’ 

19 

0 

These monitoring system failures that occurred during the 2003 blackout and the 

recommendations in the Final Blackout Report informed DOE and the Commission in 

preparing this report, which responds to the Congressional directives in section 1839 of 

EPAct 2005: 

Within six months after the date of enactment of this Act, the Secretary [of Energy] 

and the Federal Energy Regulatory Commission shall study and report to Congress 

on the steps which must be taken to establish a system to make available to all 

transmission system owners and Regional Transmission Organizations (as defined 

in the [FPA]) within the Eastern and Western Interconnections real-time 

information on the functional status of all transmission lines within such 

Interconnections. In such study, the Commission shall assess technical means for 

implementing such transmission information system and identi@ the steps the 

Commission or Congress must take to require implementation of such system.22 

Specifically, section I1 of this report identifies, through a technical analysis, nine steps that 

could be taken to establish an interconnection-wide real-time transmission monitoring 

system. It begins with defining the terms “real-time information” and “functional status of 

all transmission lines in the interconnection.” Next, it evaluates existing real-time 

monitoring technologies, namely the SCADA systems and the Energy Management 

System (EMS),23 which supervise, control, optimize, and manage electric generation and 

~ ~~ 

operating technology, criteria, and standards. 

Id. at 160, Recommendation Number 24. System modeling data are used in power system 19 

computer models for simulating steady state and transient state of the power system. 

2o Id. at 162, Recommendation Number 28. Time-synchronized data recorders sample data 

synchronously at selected locations throughout the power system through the use of GPS (Global 

Positioning System). The internal GPS satellite receiverclock coordinates the sampling process to ensure 

that data is sampled at the same instant in time by the devices installed at remote locations throughout the 

power system. 

21 Id. at 169, Recommendation Number 43. 

’* EPAct 2005 6 1839, 119 Stat. 594, 1142 (2005). 

23 EMS is a computer control system used by electric utility dispatchers to monitor the real-time 

6 
transmission. Finally, this section identifies an advanced real-time monitoring and 

visualization system now under development and prototype deployment. 

Section 111 articulates, per the direction in section 1839 of EPAct 2005, and with the 

assumption that an interconnection-wide real-time transmission monitoring system is 

feasible and will be pursued, the steps the Commission would have to take to implement 

such a system. These steps address institutional, planning, and financial issues. Section 

IV offers conclusions and recommendations. The report also contains a number of 

appendices, offering a list of acronyms, a glossary of terms, a functional status matrix, a 

map detailing the geographical boundaries of the interconnections, a map of NERC 

regional reliability councils, and other relevant technical information. 

Section 11: Assessment of Technical Means and Steps to Establish a 

Transmission Monitoring System 

Study Assumptions and Approach 

Section 1839 of EPAct 2005 directed DOE and the Commission to study and report to 

Congress on the steps that must be taken to establish a system to make available real-time 

information on the functional status of all transmission lines within the Eastern and 

Western Interconnections. The steps identified in the report are based on technical 

evaluations of the relevant literature and the technical expertise of the Commission and 

DOE staff electrical engineers with extensive experience in power system operations. The 

study’s analysis considers systems with voltage levels of 69,000 volts (69 kilovolts or 

69kV) and higher, which generally match current transmission system models.24 This 

section of the report focuses on how, rather than whether, an interconnection-wide realtime monitoring system should be deployed. 

The following nine steps should be taken if an interconnection-wide real-time monitoring 

system is to be pursued: 

Step 1. Define what a real-time monitoring system is, what it should accomplish, and 

how to accomplish this goal, including an explanation of the terms “real-time 

information” and “functional status.” 

performance of various elements of an electric system and to control generation and transmission facilities. 

The transmission system is divided into the following categories based on voltage levels as 24 

defined by the American National Standards Institute (ANSI) and the Institute of Electrical and Electronics 

Engineers (IEEE) standards: Extra High Voltage (EHY) of 240 kV and higher (ANSI/IEEE Std. 49); High 

Voltage (HV) which includes 100 kV to 230 kV (ANSVIEEE Std. 260); and Medium Voltage, which is 

less than 1 kV to 72.5 kV (ANSVIEEE Std. 49). 

7 
Step 2. Evaluate existing real-time monitoring technologies and their limitations. 

Step 3. Identify the communications infrastructure required and related security and 

operating issues. 

Step 4. Define data requirements. 

Step 5. Identify promising emerging technologies. 

Step 6. Decide what data should be shared, with whom, and when. 

Step 7. Decide who should operate, use, and maintain the system. 

Step 8. Identifj potential participants involved in establishing a real-time monitoring 

system. 

Step 9. Consider cost and funding issues. 

Step 1. Define What a Real-Time Monitoring System is, What it Should Accomplish, 

and Howto Accomplish it 

A real-time monitoring system collects “real-time information” of the transmission system 

that consists of measurements of selected system elements that are collected by SCADA 

and/or Intelligent Electronic Devices (IEDs)~~ at various time intervals. These 

measurements are taken at generators, 

system, and could be used, stored in local computer databases, or sent by 

telecommunication lines to remote computer databases. 

and at selected other points on the 

A real-time monitoring system should provide operators with real-time information about 

the transmission system’s “functional status,” (i.e., real-time information about the 

operational status of the transmission system and its components). This information 

includes direct measurements such as switching status of the transmission line (i.e., in 

service/out of service), amount of sag on the line, power flow in the line, and 

interconnection frequency. Other information is calculated from measurements such as 

whether equipment is being overloaded. 

25 An ED monitors grid operational parameters and is capable of independent protective action at 

a substation. A more detailed definition can be found in Appendix B, Glossary. 

26 A substation is a facility, generally including a small building, with a fenced-in gravel yard 

containing switches, transformers, and other equipment used to adjust voltages and monitor circuits. 

8 
Operators could run the transmission system more reliably than is possible today if they 

know the functional status of all transmission lines. For example, by monitoring current 

flow, an operator could perceive system problems such as transmission line overloading. 

Thus, a real-time monitoring system would capture the real-time measurement of the 

functional status of the transmission system and should provide critical information such 

as low voltage condition2’ or low reactive power reserve margin” in a manner that can be 

quickly and easily ascertained by an operator, such as colors and alarms. Appendix D 

presents a comprehensive list of what constitutes “functional status.” 

Step 2. Evaluate Existing Real-Time Monitoring Technologies and their Limitations 

The next step in evaluating how a real-time monitoring system could be established is to 

identify the different types of available monitoring technologies that could provide a nearterm monitoring system. While there are some advanced technologies that show promise 

for establishing a more advanced real-time information system for use throughout the 

interconnections, most of these technologies are in the development phase or in an early 

stage of implementation. Therefore, an initial approach would be to utilize the existing 

technology until advanced technologies could be developed and integrated into a more 

sophisticated system. 

By far the most commonly used monitoring system throughout the energy utility industry 

is the SCADA and EMS structure that monitors, controls, optimizes, and manages 

generation and transmission systems. SCADA and EMS are used by transmission entities, 

including Independent System Operators (ISOS)?~ RTOs, transmission owners, and 

operators. These systems perform a number of functions, including: 

collecting, storing, and analyzing data from hundreds of thousands of data 

points in national or regional computer networks; 

modeling networks; 

simulating power operation; 

analyzing faults; 

studying outages; and 

interfacing with energy trading markets. 

27 A low voltage condition occurs when the voltage level falls below a nominal value. A sustained 

low voltage condition could lead to voltage collapse and a possible blackout. 

28 Reactive power reserve margin refers to the amount of reactive power available to the system. 

Reactive power is used locally to boost the system voltage. 

29 EPAct 2005 Q 1291(b)( l), 119 Stat. 594,984. An IS0 is an entity approved by the Commission 

to (a) exercise operational or functional control of facilities used for the transmission of electric energy in 

interstate commerce, and (b) ensure nondiscriminatory access to the facilities. 

9 
SCADA systems are also used in industrial applications to control distributed systems 

from a master location, such as a control center.30 SCADA acts in two ways; it provides 

data such as meter readings and equipment status to operators, and it allows operators to 

control the equipment in the field. A SCADA system collects real-time transmission 

system measurements every two to four seconds. 

Today, data from SCADA and EMS systems are available throughout the Western and 

Eastern Interconnections from ISOs, RTOs, and Balancing Authorities (BAS)?’ SCADA 

and EMS therefore are a viable platform if one were interested in establishing a real-time 

monitoring system that would be easily accessible in the near term to all users.32 The 

majority - but not all33 - of the SCADA data is transmitted from the regional BAS to the 

ISOs and RTOs and will be available to the real-time monitoring system. Some of the 

data that are not transmitted to the ISOs and RTOs could be collected from the appropriate 

BA’s SCADA system and then transmitted throughout the interconnections. 

SCADA systems, however, have a number of limitations that hinder their use for carrying 

out the functions of a more technologically sophisticated real-time monitoring system for 

the Eastern and Western Interconnections. SCADA systems generally are based on closed 

and proprietary software and hardware architectures. The data is stored in proprietary 

databases with specific structures that are unique to the ar~hitecture.~~ As a result, it is 

cumbersome to exchange data openly and freely. Currently, the amount and format of 

data exchanged between SCADA and EMS systems is covered through bilateral 

agreements between the parties. While this process may work for several entities, a 

30 For instance, SCADA systems are used in the water, oil, and natural gas inhstructures to 

monitor product flows, allow controllers to turn on or off valves, and to keep track of product sales. 

31 A Balancing Authority is the entity responsible for making certain that the area’s power 

requirements are scheduled and developed by dynamically balancing load and generation in its area. For 

example, the New York Independent System Operator is the Balancing Authority for the state of New 

York. A Balancing Authority area is an electric system bounded by interconnection metering and 

telemetry, which measures the current, voltage, power flow, and status of transmission equipment. 

32 The current SCADA and EMS systems can provide a SCADA-based real-time monitoring 

system until such time that emerging technologies move from the development to the deployment stage. 

These emerging technologies are discussed later in hs report. 

33 Not all the real-time measurements are transmitted to SCADA/EMS due to the communications 

and performance limitations inherent in these systems. 

34 Proprietary architecture is a closed form of architecture that is privately owned and controlled by 

a company. It implies that the company has not disclosed specifications that would allow other companies 

to duplicate the architecture. 

10 
standardized data format is required if a common visualization system is to be developed. 

Therefore, if a real-time monitoring system for both the Eastern and Western 

Interconnections is to be pursued, adoption of a common format for use in data exchange 

among all entities would be critical. One possible solution could be to adopt Common 

Information Model (CIM) Standards. CIM provides a common definition of management 

information for systems, networks, applications, and services, and allows for vendor 

extensions. CIM’s common definitions enable vendors to exchange semantically rich 

management information between systems throughout the network. 

Step 3. Identifi Required Communications and Related Security and Operating Issues 

The sharing of such vast amounts of data among a large number of users requires the 

establishment of a communications infrastructure. If an interconnection-wide real-time 

monitoring system is to be established, the next step would be to identify the 

communications equipment needed to facilitate data sharing. In addition, other related 

factors should also be considered, such as security (confidentiality, cyber, and physical), 

ownership, and maintenance of the communications system. 

Data collection process used throughout the transmission system relies on a variety of 

metering devices. In SCADA systems, metering devices communicate with a control 

center using Remote Telemetry Units (RTUs). An RTU electronically collects data from 

metering devices, formats the data, and sends it to a central data collector. 

Communications between RTUs and the SCADA and EMS have traditionally used 

combinations of radio, microwave, and modem connections. While this is a convenient 

way to communicate data, it poses security risks, including the compromise of data 

confidentiality that may be accessed and viewed by unauthorized entities. This issue has 

been investigated and addressed in a project sponsored by DOE’S Office of Energy 

Assurance that utilized encryption and authenticated communications from the substation 

to the SCADA control center.35 

Communication between the SCADA systems of different EMS control centers and 

among utilities and all other electricity users is typically provided by Inter-Control Center 

Communications Protocol (ICCP).36 ICCP operates across a wide range of connections, 

using dedicated routing devices for the exchange of real-time and historical power system 

data. A graphic representation of a SCADA and EMS communications system is shown in 

Appendix E. 

35 U.S. Department of Energy, Cyber Security for Utility Operations, available ut http://www.sand 

ia.gov/scada/documents/inalReport~M63SNL,34~1 SAprO5 .pdf. 

36 ICCP is an international standard for real-time data communication among control centers, 

utilities, power pools, regional control centers, and non-utility generators. ICCP defines a set of objectives 

and services for data exchanges. ICCP was developed largely by the Electric Power Research Institute 

(EPRI) in the 1990s in collaboration with energy companies, energy company consultants, protocol 

providers, and energy management system vendors. 

11 
Today’s communication infrastructure, however, has a number of limitations that hinder 

the transfer of data from substation RTUs to other monitoring systems. For instance, due 

to the low-bandwidth3’ of existing communications protocols, SCADA communications 

protocols are designed to be very compact and most are designed to send information to 

the master SCADA station only when the master station polls the RTU. If, for example, 

the master station polls the RTU every four seconds, the data in the SCADA system is not 

truly real-time - it is as much as four seconds old. During transient events (e.g., power 

oscillations due to an equipment trip caused by a protection relay as a response to an 

overload condition), measured data could change as quickly as 60 times per second. 

Compact SCADA protocols limit the amount of infomation that can be transmitted, and 

require use of abbreviations, which could make data difficult to interpret. 

Another limitation of current systems is that the grid’s communications between different 

EMS control centers could be inadequate, causing operators to be unaware of disturbances 

in neighboring BAS. As occurred in the August 14,2003 blackout, operators in 

neighboring BAS missed opportunities to limit the spread of trouble because they relied on 

manually initiated telephone conversations for information about transmission lines 

outside their own area rather than on a real-time visualization system?8 

As more computer processing power is embedded within new SCADA equipment, there is 

a demand for more information to be transferred, requiring higher data-transfer rates. The 

challenge lies in having SCADA equipment and protocols work together with modem 

networks and increased computer power. 

As for communications requirements of owners and operators, most control center 

operators and transmission operators only need information about transmission lines in 

their area and neighboring areas. Data from local meters are collected at a local data 

center, and any calculations needed for the operators are done on the local data. However, 

a distributed communication network allows for a more efficient way to share data. To 

achieve such efficiency, local data centers could be interconnected to share information 

among areas as specified by Recommendation Number 24 of the Final Blackout Rep0rt.3~ 

Security issues must also be addressed when developing an interconnection-wide real-time 

transmission monitoring system. Many levels of security need to be achieved in a 

communications infiastructure. For communication protocols and the equipment that read 

37 Bandwidth is a measure of the capacity of a communication’s channel. The higher a channel’s 

bandwidth, the more information it can carry. 

38 Final Blackout Report, supra note 1, at 1 6 1. 

39 Id. at 160, Recommendation Number 24. 

12 
these protocols, the available security technologies include encryption, authorization, 

authentication, intrusion detection, and filtering of communications and network traffic.40 

These security technologies require more bandwidth, memory, and processing power than 

most SCADA components have. 

Although ICCP was developed with built-in security measures, today’s interconnected 

environment and large-scale exchange of confidential information appear to require 

additional security measures to ensure uninterrupted transmission and generation system 

operations. 

Cyber security is most effective in conjunction with physical security measures, such as 

secure physical access to all computers, and locks, fences, guards, and surveillance 

cameras around communications facilities. One step toward ensuring physical security 

would be to evaluate all connections to the SCADA system, disconnecting those that are 

unnecessary and strengthening the security of those that are necessary. Remote sites 

connected to the SCADA system are especially vulnerable because they are often 

unmanned. SCADA network owners could take steps to ensure that any communication 

links from those sites are secure (e.g., communications cables cannot be tapped, radio or 

microwave links are not exploitable, and there is no unauthorized access through computer 

terminals or wireless network^).^' 

The bulk electric power grid, with its geographically dispersed assets and data flows, may 

lend itself to a “publish-and-subscribe” communication architecture. In this type of 

networked system, some intelligent devices “publish” information that is of value to other 

“subscribers.” A publisher might be a residential watt-hour meter, and a subscriber might 

be a utility’s billing software system. In this case the billing software would subscribe to 

the output of the homeowner’s meter for monthly readings. 

One such application currently being developed for electric power “publish-and-subscribe” 

systems is called “middle~are.”~~ Middleware is a communications layer that allows 

applications to interact across hardware and network environments, using uniform 

protocols to ease communications compared to what is possible in current systems. It is 

unclear whether industry will adopt an architecture that involves middleware, but an 

40 General Accouting Office (GAO) Report, Critical Infrastructure Protection Challenges in 

Securing Control Systems, GAO 04 140T, October 1,2003 at 12, available at http://www.gao.gov/new.ite 

ddO4 140t.pdf. 

41 U.S. Department of Energy, 21 Steps to Improve Cyber Security of SCADA Networks, 

September 9,2002, at 3-5. 

42 C. Hauser, D. Bakken A. Bose, A Failure to Communicate, IEEE POWER & ENERGY MAG., 

MarcWApril2005, at 47. 

13 
interconnection-wide transmission monitoring network may be a good application for this 

technology. 

The communications equipment between local utilities and a central monitoring system 

could be owned by a central entity such as the ERO, especially if the monitoring system 

relies on a centralized communication architecture. Alternatively, there could be one set 

of central communication equipment for each region, owned by the regional entity or the 

TOs in the region. This approach would work if the monitoring system uses a distributed 

communications architecture, as described above. 

Much of the metering and communications equipment needed to implement an 

interconnection-wide transmission monitoring system is already in place and owned by 

local utilities or transmission operators. Each local utility could purchase and maintain its 

own equipment for communicating between its system and an interconnection-wide 

monitoring system. NERC Monitoring System Conditions Standard (TOP-006-0) requires 

RCs, TOs, and BAS to monitor specific equipment status and system conditions in real 

time.43 

Step 4. Define Data Requirements 

Once the existing real-time monitoring technologies and their limitations are evaluated, it 

would be necessary to identify the required data for use in a real-time transmission 

monitoring system. At the minimum, it would be necessary to know the following: (1) 

the data available; (2) what data are being archived to support post-disturbance analysis; 

and (3) and the level of standard formats being used for storing real-time data. 

Currently, there is a limitation on the amount and type of available data as it often depends 

on what the transmission operator considers necessary to collect. Some of these 

measurements include generator output quantities (ie., power, voltage, status) and tie-line 

flow information (i.e., power flow, frequency). This information would have to be 

collected at least every four seconds to meet the performance standards of automatic 

generation control (AGC).44 Although transmission operators are not required by FERC 

regulations to retain real-time data, a number of Commission regulations exist that govern 

the retention of operational data.45 Data being collected at a substation will likely be 

43 Available at http://www.nerc .com/pub/sys/all~upd~standardslrsiTOP-OO6-O.pdf. 

44 A stand-alone subsystem that regulates the power output of electric generators within a 

prescribed area in response to changes in system frequency, tie-line loading, and the relation of these to 

each other. This maintains the scheduled system frequency and established interchange with other areas 

within predetermined limits. 

45 See 18 C.F.R. 0 37.7 (requires that audit data must remain available upon request for download 

14 
different from data being collected at a control center. Further, there are differences in the 

applications of, and calculations being done with, the data. The goal is to determine the 

common level of data needed for reliable operation of the grid while taking into 

consideration that, as technology advances, faster rates of compiling and measuring data 

will be increasingly available in the near future. 

A common description of required data must be established for the whole interconnection 

so that the same data are available at the same rates and at the same time from all 

substations and the EMS control centers. The main criteria for determining what data are 

required should be such data that support grid reliability and adherence to reliability 

standards. 46 

Because substations are continually employing new measurement technologies to gather 

more accurate data at faster sampling rates, the uniform data requirements must 

continually be updated to keep pace. For example, faster sampling of currents and 

voltages with satellite-synchronized time stamping - in which both the value and the exact 

time of measurement are recorded - are being used increasingly to measure important 

system conditions such as phase angles, fault conditions, and switching ~equences.4~ 

Similarly, improved communication is making these data rapidly available to distant 

computers. Faster computers are calculating more sophisticated measures of reliability 

than have been an option in the past. Combined, these features could enhance the level of 

real-time data available to the whole interconnection. 

It is also important to understand which real-time data are currently archived by each 

transmission owner or operator and to determine the minimum data that must be stored to 

allow significant events affecting the power grid to be analyzed. This entails determining 

which data need to be stored and at what rates. For instance, it may not always be 

necessary to archive all of the data at the same rate as they are measured, especially when 

some quantities are being sampled many times a second, and others are sampled less 

frequently. 

for three years from the date they were first posted on OASIS (Open Access Same-Time Information 

System)); 18 CFR 0 125.3 Item 13.1 (d) and (e) require generating high-tension and low-tension load 

records and load curves, temperature logs, coal and water logs to be retained for three years; and 18 CFR 0 

125.3 Item 14 (a) and (b) require substation and transmission line logs and system operator’s daily logs and 

reports of operation to be retained for three years. 

46 NERC, Approved Reliability Standards, available at http://www .nerc.com/-filedstandardslrelia 

bility-standards.html. 

47 Voltage and current magnitudes are recorded as well as the time of measurement accurate to a 

millionth of a second. Fault conditions and switching sequence data can be used to reconstruct power 

system events in postdisturbance studies. 

15 
Another consideration is where the data should be archived. Two options are to store the 

data where they are generated or to store all of the data for the entire interconnection at 

one location. The goal is to have a data set available for analysis to answer reliability 

questions, such as whether a grid disturbance was caused by a single misoperation of 

equipment, by a series of events over a large area, or something in between. Having this 

data set available will address Recommendation Number 14 in the Final Blackout Report, 

which calls for establishing a standing framework for conducting future blackout and 

disturbance investigations. Archiving data in this manner will allow analysts to expedite a 

time-synchronized reconstruction of an event and facilitate investigations as proposed in 

Final Blackout Report Recommendation Number 1 4.48 

Finally, it is necessary to address the extent to which common or standard formats and 

data base definitions are used for storing real-time data. Real-time data are often collected 

and stored in different formats by the numerous SCADNEMS vendors. This situation 

creates a major obstacle to automatically collecting and utilizing data fiom different parts 

of the interconnection, a critical function necessary for establishing an effective real-time 

transmission monitoring system.49 Therefore, it is necessary to determine the 

commonality of all data outlined earlier in terms of format and exchange protocols and to 

determine the need for further development of standards for data conversion, collection, 

and sharing.” 

Step 5. Identifi Promising Emerging Technologies 

While the SCADA and EMS systems are a useful foundation for a SCADA-based realtime monitoring system, advanced technologies show promise for establishing a more 

sophisticated system that could serve the future needs of users within the interconnections. 

Several such technologies are already being explored by the industry, while some 

technologies already exist but must be networked together to provide the technological 

sophistication required for an interconnection-wide real-time monitoring system. 

Therefore, the next step in the process should identify promising emerging technologies. 

DOE has been funding research in Phasor Measurement Unit (PMU)” technology for 

48 Final Blackout Report, supra note 1, at 149. 

49 EPG Company, SCALIA System Assessment, available at http:Nwww.epgco.comlscada-systemassessment.html. 

An ANSI standard now exists for a common format for control center data, but not for all 

available substation and generation data. See Common Information Model (CIM) Standards, available at 

http:llwww .dmtf.orglstandards/cim. 

51 A PMU, which is considered an ED is a modem fast transducer that provides synchronized 

phasor measurements of voltages and currents fiom widely dispersed locations in an electric power grid. 

16 
more than 10 years.52 PMUs are unique voltage and current transducerss3 that take timesynchronized measurements, which are important to the electric utility industry. PMUs 

use timing signals from the Department of Defense’s Global Positioning System (GPS)54 

to precisely time-stamp voltages and currents at any geographic location on the power 

grid. The accuracy of PMUs is unparalleled, compared, for example, with that of 

traditional SCADA data, in which two voltage measurements taken from different points 

on the bulk power grid may be “skewed” (or off) by as much as several seconds. SCADA 

would inaccurately record these two data points as one “scan” and log them into the 

database at one instant in time. 

With a PMU, however, the time “skew” is never more than one-millionth of a second. 

PMU data sampling rates of as much as 60 times a second allow the calculation of voltage 

and current phase angles” along with power flows. The technical benefits of this 

technology include more accurate state-of-the-system estimates (which use metered data to 

estimate the status of the system in better situational awareness and wide-area 

visibility for transmission system operators, and better post-disturbance 

which contribute to better planning. 

all of 

Currently, PMU technology is the basis for the Eastern Interconnection Phasor Project 

(EIPP), a DOE technology-transfer effort in which more’than 40 system operators and 

reliability organizations across North America are participating. The purpose of this 

project is to install and network time-synchronized measurement units to make 

fundamental data widely available to grid operators for use in monitoring and visualizing 

system operations. 

See Appendix B, Glossary, for the definition of phasor measurement. 

52 See, e.g., Eastern Interconnect Phasor Project, available at http://phasors.pnl.gov. 

53 A device which converts a measurement into a signal that can be monitored by the SCADA 

system. 

54 A satellite-based global navigation system that allows users to determine their exact location, 

velocity, and time, anywhere in the world, and in all types of weather. 

’’ The measure of the progression of a periodic wave in time or space from a chosen reference or 

position. 

56 A state estimator is a computer software package that takes redundant measurements of system 

values and provides an estimate of system status. It is used to confm that the monitored electric power 

system is operating in a secure state. A more comprehensive definition can be found in Appendix B, 

Glossary. 

57 Final Blackout Report, supra note 1, at 162, Recommendation Number 28. 

17 
The Consortium for Electric Reliability Technology Solutions (CERTS)” has integrated 

and delivered three software applications based on phasor measurements. Operation 

support engineers at the California Independent System Operator Corporation (CAISO) 

are using these applications to study grid disturbances and calibrate system models that are 

used to develop guidelines for real-time operations, in coordination with the Western 

Electricity Coordinating Council.59 

CAISO is also pioneering the first-ever, real-time application of phasor technology in 

which phasor data collected by the Bonneville Power Administration, Southern California 

Edison, and Pacific Gas and Electric Company are being transferred to a CAISO data 

concentrator for use in prototype real-time monitoring workstations that are being built by 

CERTS. 

While PMU technology is still in the development phase, many of the existing IEDs being 

used in today’s utility substations could be networked together, using digital electronics, to 

form a fast (IED-based) real-time monitoring system to provide a complete picture of the 

power system “health.” Such an IED-based system, therefore, could provide wide-area 

visibility necessary for real-time monitoring.60 

Some existing IEDs that could be used for this purpose include the Digital Fault Recorder 

(DFR), which records a snapshot of voltages and currents at a substation during an 

abnormal event, such as a transmission line or a generator trip. The information from the 

DFR is used to examine and correct the performance of substation equipment. Many 

DFRs are now capable of streaming PMU data to data concentrators. A recorder records 

“what happened when” from hundreds of independent devices in a substation.6’ It is used 

to determine whether protection devices are triggered in the proper order to protect 

personnel and equipment. Another recorder, referred to as Dynamic Swing Recorder 

(DSR), is used to examine how power oscillations affect the system during periods of 

stress; the results are incorporated into planning studies and operating procedures to avoid 

excessive grid stress. Relays automatically perform protective action by switching 

equipment out of service in the event of serious abnormalities such as faults (i.e., short 

” Consortium for Electric Reliability Technology Solutions, available at http://certs.lbl.gov. 

59 One of the 10 electric reliability councils in North America, encompassing a geographic area 

equivalent to half of the United States. It is responsible for promoting electric system reliability and 

providing a forum for coordinating the operating and planning activities of its 145 member systems. The 

members, representing all segments of the electric industry, provide electricity to 7 1 million people in 14 

Western states, two Canadian provinces, and portions of one Mexican state. 

Electric Power Research Institute, Distribution Design to Integrate New Intelligent Electronic D 

evices, available at http://www.epri.codportfolio/product.aspx?id= 1499&area=3 8&type= 10. 

Referred to by industry as a Sequence of Events Recorder. 61 

18 
circuits). Some transmission line relays are now capable of streaming PMU data to 

concentrators. 

Today there are a variety of electronic devices6* that could be utilized in an 

interconnection-wide real-time monitoring system. However, there is no need to rely on a 

single technology to provide all of the information required to adequately monitor realtime information on the hnctional status of all transmission lines. In fact, multiple 

monitors are actually desirable, as they could provide redundancy to enhance reliability. 

Currently, the phasor projects in both the Eastern and Western Interconnections are using 

concentrators that collect and store data from PMUs in a database at each utility. These 

data are archived at a central concentrator. Software at the central concentrator 

continuously processes the data streaming in from across the interconnection and creates a 

graphic visualization of grid status, which is available to NERC RCs and grid operators 

via secure internet communications. However, future use of these data to control the grid 

flexibly in real time would require a communication network structure that can move the 

data in a timely, secure manner. 

The number of phasor measurements could increase dramatically in the fbture as more 

PMUs are added. Use of phasor data in real time across an interconnection will challenge 

any communication architecture, but the ability to use these data in real time will greatly 

enhance operators’ ability to run the grid reliably and securely. 

Step 6. Decide what Data Should be Shared, with Whom, and When 

Should an interconnection-wide real-time monitoring system be pursued, the next step in 

the process could be identifying what information should be shared, at what frequency, 

and among which entities. 

The majority of real-time data is private and contains sensitive operational information 

(e.g., generator and transmission line status). From a security perspective, it is important 

that the monitoring system ensure that the private data is only shared among entities with 

legitimate credentials. This would include the entities that have signed a data 

confidentiality agreement. Another important security measure is to ensure that the data 

cannot be manipulated and that any remote control functions cannot be exercised by 

unauthorized users. Further, frequency of updates and a hierarchy of needs for specific 

information should be addressed, as these requirements vary for different users. For 

instance, entities such as BAS, RCs and the ERO would likely require more detailed 

Other options include condition monitors that detect various special circumstances such as 

circuit breaker failure, over-temperature, and oil contamination, as well as meters that monitor and record 

billing and accounting quantities. 

19 
information and more frequent updates on day-to-day operations than government entities 

such as the Commission or DOE. However, government entities would likely require that 

historical data be available to government entities63 to facilitate investigation and 

assessment of conditions as necessary, such as those that result in reliability violations, or 

crisis situations64 as part of post-disturbance analysis as identified by Recommendation 

Number 14 of the Final Blackout Report.65 

Further, a technical process for identifying critical transmission paths and equipment 

would be a necessary component of this step. In both the Eastern and Western 

Interconnections, certain generators, transmission paths, substations, and/or regions are 

known to be critical for the reliability of the interconnections. However, critical facilities 

change over time as new generation, transmission or other equipment is added and power 

flow patterns change. 

Once a system is established where real-time information can be gathered, archived, and 

shared, the next logical step is to determine who should have access to this data. The 

criterion for access should be an entity’s “need to know” for the purpose of ensuring 

monitoring, assessing, investigating, and/or enforcing reliability. For example, the 

Commission and the ERO will likely need access to all data while a transmission owner 

may only need data from its nearest neighbors or from those that may have an impact on 

its service. 

In addition to resolving the data-sharing issues addressed above, system designers must 

also determine the amount of monitoring necessary for real-time functional status 

reporting. The level of monitoring will depend upon the number and location of 

measurements needed to cover key corridors and system sites in order to perform 

reliability functions and to provide all users with sufficient information to monitor the 

functional status of all transmission lines within the interconnections. 

Another area that should be addressed involves the types of processes needed to share data 

among entities. Here, a distinction must be made between sharing the real-time data and 

sharing the historical data. For instance, SCADA real-time monitoring may be configured 

to be updated once every two minutes for overall monitoring of system integrity by an 

operating entity, whereas historical data should be available at the same rate that it was 

originally created and archived in order to accurately analyze and simulate past events. 

63 EPAct 2005 recognizes the international footprint of the North American electric transmission 

system by acknowledging Canadian and Mexican interests in the reliability of the interconnected North 

American electric grid. See EPAct 2005 5 121 1, 119 Stat. 594,941 (2005). 

64. Final Blackout Report, supra note 1, at 149, Recommendation Number 14. 

65 Id. 

20 
Because of the limitations of current monitoring technology described in Step 2 above, 

some changes would be required in existing SCADA and EMS systems to allow for 

efficient data-sharing with the real-time monitoring system. The changes will require the 

use of the Common Information Model. 

Step 7. Decide Who Should Opearte, Use, and Maintain the System 

Moving from system-related issues to organizational issues, should a real-time 

transmission monitoring system be pursued, the next step would be to categorize the roles, 

responsibilities, and tools provided to reliability desks in the EMS control centers 

throughout the interconnections. 

The roles and responsibilities of reliability desks in the control centers throughout the 

interconnections include monitoring the real-time status of bulk power system 

components in their areas, monitoring the status of communication equipment, and 

monitoring data quality. If local communication equipment that is a part of the 

transmission line monitoring system is not hnctioning properly, the control center should 

notify all other EMS control centers that use the transmission line monitoring system. 

Likewise, if data coming in from local equipment are corrupt, all transmission monitoring 

system users should be notified of the problem. This will help those using the system to 

know whether information coming from the monitoring system is based on accurate 

measurements. 

The tools provided to reliability desks in the control centers throughout the 

interconnections include visualization tools and data about neighboring systems. 

Visualization tools could show information about the entire interconnection (e.g., voltage 

and frequency) and also have dynamic zoom capability to show information about a 

specific area. A good visualization system quickly summarizes computer data for 

operator action. 

The data provided by visualization systems could also enhance grid reliability. 

Visualization systems could be integrated into state estimators and, along with other 

contingency analysis software, allow a system operator to review each critical 

contingency to determine whether each possible scenario is within reliability limits. 

Neighboring system information also could be integrated into security analysis tools, 

which help operators analyze what steps to take if different outages occur, based on the 

current system state. 

Step 8. Identifi Potential Participants Involved in Establishing a Real-Time 

Monitoring System 

If a transmission monitoring system is to be established, another step in the process would 

21 
be identifying potential participants and understanding the needs of these users. Potential 

participants in establishing a real-time transmission monitoring system include the ERO, 

regional entities, transmission entities, the Commission, DOE, Canadian and Mexican 

agencies, provincial regulators, and state regulators. Each would likely have a role in 

collaboratively maintaining andor utilizing the data infrastructure, with the goal of 

ensuring reliable operation of the electric grid. 

66 

Different participants would have different needs for transmission line monitoring 

information. The ERO and the Commission, as well as DOE, Canadian, Mexican, and 

other agencies, would likely need to see all transmission lines in the interconnections. 

State and Provincial governments may only need to see transmission lines within their 

State or Province along with the lines outside of the State or Province that may impact 

their system(s). Individual utilities may need to see an entire interconnection or just a 

small area. The entity developing visualization software would need to understand and 

address these needs. 

As new transmission lines are built, the ERO could take steps to ensure that compatible 

monitoring and communication equipment are installed in the monitoring system. 

Likewise, as technology evolves, new communication infrastructure, software, andor 

metering may need to be installed to maintain a state-of-the-art monitoring system. 

Step 9. Consider Cost and Funding Issues 

The final step prior to implementation of the real-time monitoring system would be to 

consider cost and funding issues. The system’s cost would depend on the level of 

technology and infrastructure that are currently in place for that entity. For example, an 

entity that has already installed digital equipment (Le., digital relays) could more easily 

upgrade to a better sophisticated IED at a cost less than an entity that lacks these modem 

devices. 

Further, in addition to the development and deployment of the system, the total cost would 

include maintenance and upgrades throughout the system’s life. 

The variety of choice in configurations is a positive development for the industry. While 

the first eight years of technology development in the area of time-synchronized recording 

equipment for the power industry saw few commercial product lines, there are now more 

commercial manufacturers of this type of equipment. The Institute of Electrical and 

Electronic Engineers (IEEE), a professional society representing power engineers, has 

66 In Mexico, the equivalent state regulator is called Comision Reguladora de Energia. 

22 
approved several standards ensuring compatibility of equipment and data.67 The vendor 

community now offers a variety of configurations to suit the needs of the most common 

utility environments. The time-synchronized recording device could be purchased as 

optional equipment on standard transmission line relays, as optional equipment on digital 

fault recorders, as stand-alone units, or in a number of alternative packages. 

The sources of funding and their mechanisms should also be addressed. Depending on the 

benefits accruing to the parties involved, funds for development, deployment, and 

maintenance of the monitoring system could come from Congressional appropriations, a 

supplemental tariff on transmission, and/or directly from the transmission owners, or from 

recovery of costs necessary to comply with reliability standards pursuant to the reliability 

provisions of EPAct 2005 should such standards be implemented.68 

Section 111. Steps to Implement an Interconnection-Wide Real-Time 

Monitoring System 

Section 1839 also requires that this Joint Report “. . . identify the steps the Commission or 

Congress must take to require implementation of such 

Commission have identified two steps that could be followed if an interconnection-wide 

real-time monitoring system is to be implemented. 

DOE and the 

Step 1. Research and study efforts to determine feasibility, cost, and benefits 

of a real-time transmission monitoring system for the Eastern and 

Western Interconnections. 

Step 2. Based on the findings from Step 1 above, possible development of 

real-time monitoring system reliability standards. 

Step 1. Research and Study Efforts 

The Commission, in coordination with DOE, could request that the ERO research and 

study, for review, a workable technical and financial approach to establishing a real-time 

transmission monitoring system for the Eastern and Western Interconnections. As a 

‘’ IEEE Standard 37.1 18-2005, Standard for Synchrophasors for Power Systems, approved by IEEE Board 

but not yet published. 

68 EPAct 2005 0 1241, 119 Stat. 594,961-62. New 5 219(6)(4) of the FPA requires the 

Commission to establish a role, among other things, allowing recovery of “all prudently incurred costs 

necessary to comply with mandatory reliability standards.” 

69 EPAct 2005 1839,119 Stat. 594,1142 (2005). 

23 
practical measure, it would be necessary to obtain feedback from all stakeholders. The 

ERO report would need to be developed using technical conferences, industry meetings, 

and independent studies. The ERO would coordinate the efforts involved in this task. 

Ultimately, the feasibility of implementing an interconnection-wide real-time monitoring 

system would depend on the outcome of a cost-benefit analysis. For example, one of the 

principal causes of the August 2003 blackout was a lack of situational awareness of 

operators, a problem that an interconnection-wide real-time monitoring system could 

address. Although this was not the only cause of the blackout, and its mitigation would 

not have prevented the event, the cost of that blackout was $4 billion to $10 billion. 

Step 2. Possible Development of Real-Time In formation Monitoring Reliability 

Standards 

The findings of the ERO study should provide a basis necessary for determining the next 

steps in the implementation phase of an interconnection-wide real-time monitoring system. 

This information should also be used to determine whether an interconnection-wide realtime monitoring system should be implemented. If it is determined that such a system is 

feasible, the development of mandatory reliability standards by the ERO may be the most 

effective way forward. In addition, if such standards are to be pursued, the requirements 

to be considered include but are not limited to the following: specifications of the 

monitoring equipment, type of information to be provided and to whom, communication 

specifications. 

Should such standards be developed, pursuant to EPAct 2005’s provisions, the 

Commission could either approve the proposed reliability standards or remand them for 

further consideration.” 

Section IV. Conclusion and Recommendations 

This report to Congress identifies the steps necessary to establish and implement a realtime transmission monitoring system for the Eastern and Western Interconnections, but 

does not pre-judge the feasibility of such an endeavor. In addition to the requirements set 

out by Congress, this report includes relevant findings and recommendations from the 

Final Blackout Report, and identifies steps to establish and implement an interconnectionwide real-time monitoring system. 

The analysis concludes that current technologies could provide a foundation for 

establishing a SCADA-based real-time information system, but we must look to advanced 

technologies to fully respond to recommendations in the Final Blackout Report. The 

findings fiom technical analysis in this joint report for establishing a real-time information 

”Id. at $ 1211, 119 Stat. 594, 943. 

24 

.- 
monitoring system are described in the recommendations below. 

Should such a system be implemented, a phased implementation of a combination 

SCADA-based system and a fast (IED-based) system is recommended. Further, the 

planning for Phase I1 should begin at the same time Phase I is being designed. 

The SCADA-based real-time information system could be assembled using the existing 

SCADNEMS infrastructure architecture and components with some changes in data 

communications. The issues with non-standard data structures and data exchange would 

have to be addressed by using the established standards and methods. The database 

structure for storing the SCADNEMS real-time and historical data may be completely 

different at each control center. The Common Information Model standards could be 

adopted to address this issue by ensuring data consistency and efficiency. 

In terms of data sharing, the use of a publish-and-subscribe communication architecture 

and the concept of data concentrators appear to be feasible methods in providing a 

systematic approach for organizing and sharing the massive amounts of real-time data 

among various entities. Another issue that would need to be addressed for the SCADAbased system is system security. While the existing communication has been developed 

with built-in security, in today’s interconnected environment, additional security measures 

are critical for enabling uninterrupted operations for transmission, generation, and ISOs. 

The fast IED-based real-time information system is under accelerated development in 

response to the Final Blackout Report, with operating prototype systems in the Eastern and 

Western Interconnections. Recommendation Number 28 of the Final Blackout Report 

requires the industry to use time-synchronized data recorder^.^^ All time-synchronized data 

recorders (i.e., digital fault recorders, digital events recorders, phasor measurement units, 

and power system disturbance recorders) are time-stamped at the point of observation 

using a Global Positioning System (GPS) synchronizing signal. Time-synchronized 

devices, such as phasor measurement units, could be beneficial for providing a wide-area 

view of power system conditions in real-time. The fast (IED-based) real-time information 

system would collect real time data from time-synchronized data recorders to provide 

instant transmission system visibility across the interconnection, and provide the capability 

for quick post-disturbance analysis. These systems would operate separately in parallel 

with the SCADA-based system to provide the full range of required data. 

The Final Blackout Report found that a “lack of situational awareness” was a “principal 

cause” of the interruption of power to over 50 million citizens of the United States and 

Canada, causing an estimated cost of between $4 billion and $10 billion to the nation?2 

71 Final Blackout Report, supra note 1, at 162. 

72 Id. at 1. 

25 
To address this problem, the Commission and DOE have found that the technology 

necessary to implement a real-time transmission monitoring system does exist at present 

and could be utilized to improve the reliability of the nation’s bulk power system by 

increasing the situational awareness of the transmission entities, as recommended in the 

Final Blackout Report, thereby addressing one of the “principal ca~ses’”~ of the blackout. 

In addition, new technologies hold the promise of greatly enhancing both situational 

awareness and system automation, thereby hrther reducing the possibility of regional and 

interregional blackouts . 

This report recommends that the Commission, in consultation with DOE, request the 

newly established ERO that is certified by the Commission pursuant to section 2 15 of the 

Federal Power 

establish the monitoring system. The ERO report is expected to be developed using 

technical conferences, industry meetings, and independent studies. The analysis from the 

ERO will be used to: (1) determine whether the implementation of a real-time monitoring 

system is feasible; and (2) if feasible, develop mandatory reliability standards necessary 

for the implementation of such a system. 

investigate and report on the feasibility, cost, and timeline to 

73 Id. at 159, Recommendation Number 22. 

74 EPAct 2005 fj 121 1,119 Stat. 594,941-46. 

26 
Appendix A 

Acronyms 

ACE 

AGC 

ANSI 

API 

ATC 

BA 

CAISO 

CERTS 

CIM 

Commission, the 

CRC 

DCS 

DFR 

DOE 

DSR 

EIPP 

EMS 

EPRI 

ERO 

F'ERC 

FPA 

GPS 

Hv 

ICCP 

IED 

IEEE 

IS0 

kV 

LMP 

IWRC 

PDC 

PMU 

QOS 

RC 

RTO 

RTU 

SCADA 

Area Control Error 

Automatic Generation Control 

American National Standards Institute 

Application Program Interface 

Available Transfer Capability 

Balancing Authority 

California Independent System Operator 

Consortium for Electric Reliability Technology 

Common Infrastructure Model 

Federal Energy Regulatory Commission 

Central Repository for Security Events 

Distributed Control System 

Digital Fault Recorder 

Department of Energy 

Dynamic Swing Recorder 

Eastern Interconnection Phasor Project 

Energy Management System 

Electric Power Research Institute 

Electricity Reliability Organization 

Federal Energy Regulatory Commission (Commission) 

Federal Power Act 

Global Positioning System 

High Voltage 

Inter-Control Center Communications Protocol 

Intelligent Electronic Device 

Institute of Electrical and Electronic Engineers 

Independent System Operator 

Kilo-volt 

Locational Marginal Price 

North American Electric Reliability Council 

Phasor Data Concentrator 

Phasor Measurement Unit 

Quality of Service 

Reliability Coordinator 

Regional Transmission Organization 

Remote Telemetry Unit 

Supervisory Control and Data Acquisition 

Solutions 

27 
SDX 

SER 

TCP/IP 

TLR 

TO 

System Data Exchange (NERC) 

Sequence of Events Recorder 

Transmission Control Protocol/Internet Protocol 

Transmission Loading Relief 

Transmission Operator 

28 
Appendix B 

Glossary of Terms 

Application Program Interface (API): An application program interface is the 

software interface to system services or software libraries. An API can consist of 

classes, function calls, subroutine calls, and descriptive tags. 

Area Control Error (ACE): The instantaneous difference between net actual 

and scheduled interchange, taking into account the effects of frequency bias 

including a correction for meter error. 

Automatic Generation Control (AGC): A stand-alone subsystem that regulates 

the power output of electric generators within a prescribed area in response to 

changes in system frequency, tie-line loading, and the relation of these to each 

other. This maintains the scheduled system frequency and established interchange 

with other areas within predetermined limits. 

Available Transfer Capability (ATC): A measure of the transfer capability 

remaining in the physical transmission network between a specific point of delivery 

and point of receipt over and above already committed uses. 

Balancing Authority, formerly known as Control Area (BA): The entity 

responsible for balancing load and generation in real time in its Balancing 

Authority area. For example, the New York Independent System Operator is the 

Balancing Authority for the state of New York. A Balancing Authority area is an 

electric system bounded by interconnection metering and telemetry, which measure 

the current, voltage, power flow, and status of transmission equipment. 

Capacitor: A device that stores electrical charges and can be used to maintain 

voltage levels in power lines and improve electrical-system efficiency. 

Common Information Model (CIM): A common definition of management 

information for systems, networks, applications and services, and allows for vendor 

extensions. CIM’s common definitions enable vendors to exchange semantically 

rich management information between systems throughout the network. 

Consortium for Electric Reliability Technology Solutions (CERTS): An 

organization formed in 1999 to research, develop, and disseminate new methods, 

tools, and technologies to protect and enhance the reliability of the U.S. electric 

power system and functioning of a competitive electricity market. 

29 
Control Center: The operational center for SCADA and EMS where the state of 

the system is monitored. 

Current Transducer: A device that converts a current measurement into a signal 

that can be monitored by a SCADA system. 

Cyber Security: The branch of Security dealing with digital or information 

technology. 

Data Concentrator: A collection of streamed information stored in a computer in 

a systematic way. 

Digital Fault Recorder (DFR): An intelligent electronic device that records a 

snapshot of voltages and currents at a substation during an abnormal event. The 

recording is performed at a very high sampling rate. 

Distributed Control System (DCS): A computer-based control system where 

several sections within the plants have their own processors, linked together to 

provide both information dissemination and manufacturing coordination. 

Eastern Interconnection Phasor Project (EIPP): Technology-transfer effort 

sponsored by DOE in cooperation with utilities, RTOs, ISOs, hardware and 

software vendors, and NERC to develop and deploy a real-time, wide-area 

measurement network in the Eastern Interconnection. 

Energy Management System (EMS): A computer control system used by electric 

utility dispatchers to monitor the real-time performance of various elements of an 

electric system and to control generation and transmission facilities. 

Electricity Reliability Organization (ERO): The Energy Policy Act of 2005 

contains reliability provisions that authorize the creation of a self-regulatory electric 

reliability organization (ERO) that covers the United States excluding Alaska and 

Hawaii, with FERC regulatory oversight. 

Global Positioning System (GPS): A satellite-based global navigation system that 

allows users to determine their exact location, velocity, and time, anywhere in the 

world, and in all types of weather. 

Inter-Control Center Communications Protocol (ICCP): An international 

standard for real-time data communication between the EMS control centers, 

utilities, power pools, regional control centers, and non-utility generators. ICCP 

defines a set of objects and services for data exchanging. 

30 
Intelligent Electronic Device (IED): This device monitors grid operational 

parameters and is capable of independent protective action at the substation level. 

Some examples of IEDs are Digital Fault Recorders (DFRs) and SERs Sequence of 

Events Recorders (SERs). 

Independent System Operator (ISO): An entity approved by the Commission - 

(a) to exercise operational or functional control of facilities used for the 

transmission of electric energy in interstate commerce; and (b) to ensure 

nondiscriminatory access to the facilities. 

Kilovolt (kV): Unit of electrical potential equal to 1,000 Volts. 

Middleware: A communications layer that allows applications to interact across 

hardware and network environments. 

Non-utility Generator: A power plant (or its owners) not owned by the utility to 

whose retail customers the output is sold. It is also called an Independent Power 

Producer. 

North American Electric Reliability Council (NERC): A not-for-profit company 

formed by the electric utility industry in 1968 to promote the reliability of the 

electricity supply in North America. NERC consists of nine Regional Reliability 

Councils and one Affiliate, whose members account for virtually all the electricity 

supplied in the United States, Canada, and a portion of Baja-California-NorteMexico. The members of these regional councils are from all segments of the 

electricity supply industry: investor-owned, federal, rural electric cooperative, 

state/municipal, and provincial utilities, independent power producers, and power 

marketers. The NERC Regions are: East Central Area Reliability Coordination 

Agreement (ECAR); Electric Reliability Council of Texas (ERCOT); Mid-Atlantic 

Area Council (MAAC); Mid-America Interconnected Network (MAIN); MidContinent Area Power Pool (MAPP); Northeast Power Coordinating Council 

(NPCC); Southeastern Electric Reliability Council (SERC); Southwest Power Pool 

(SPP); Western Systems Coordinating Council (WSCC); and Alaskan Systems 

Coordination Council (ASCC, Affiliate). NERC has developed the Version 0 

reliability standards. 

NERC System Data Exchange (NERC SDX): Provides a central repository of all 

scheduled and on-going branch, generator, and transformer outages throughout the 

Eastern Interconnection. This data is made available to NERC-approved users, who 

have agreed to the terms of the NERC Data Confidentiality Agreement. 

Phase Angle: The measure of the progression of a periodic wave in time or space 

from a chosen reference or position. 

31 
Phase Shifter: A device used to control the power flow within a given network by 

creating a angle shift between its primary and secondary terminals. 

Phasor Data Concentrator (PDC): A computer database that contains data from 

several phasor measurement units (PMUs). 

Phasor Measurement: Simultaneous measurement of network voltage and current 

phasors (i.e., magnitudes and angles) at different geographical locations of the 

network through GPS time stamping. 

Phasor Measurement Unit (PMU): A modem fast transducer that provides 

synchronized phasor measurements of voltages and currents from widely dispersed 

locations in an electric power grid. 

Power Pool: Two or more electric systems that are interconnected and operated on 

a coordinated basis to promote economies of scale as well as reliability in supplying 

their combined loads. 

Quality of Service (QoS) Requirements: Require that communication for the 

power grid be delivered in a timely, reliable manner with adequate bandwidth. 

Regional Transmission Organization (RTO): An entity of sufficient regional 

scope approved by the Commission - (a) to exercise operational or functional 

control of facilities used for the transmission of electric energy in interstate 

commerce; and (b) to ensure nondiscriminatory access to the facilities. 

Reliability Coordinator (RC): An organization responsible for the safe and 

reliable operation of the interconnected transmission system for its defined area, in 

accordance with NERC reliability standards, regional criteria, and sub-regional 

criteria and practices. This entity facilitates the sharing of data and information 

about the status of the BA for which it is responsible, establishes a security policy 

for these BAS and their interconnections, and coordinates emergency operating 

procedures that rely on common operating technology, criteria, and standards. 

Remote Telemetry Unit (RTU): A device that collects data at a remote location 

and transmits it to a central station. RTUs are commonly used in SCADA systems. 

Supervisory Control and Data Acquisition (SCADA): A computer system for 

gathering and analyzing real time data. SCADA systems are used to monitor and 

control a plant or equipment. 

Security Analysis: Use of computer software to analyze system contingencies to 

32 
ensure that power can be delivered from generation to load within the operating 

limits of transmission equipment and without loss of continuity of supply or 

widespread failure for the most likely contingencies. 

Sequence of Events Recorder (SER): An intelligent microprocessor-based 

system that records remotely occurring events. 

Situational Awareness: The ability to identify, process, and comprehend 

information about what is happening in a complex system; specifically, the ability 

to understand real-time power system operation with regards to reliability. 

Stability Limit: The maximum power flow possible through a particular point in a 

system while maintaining stability in the entire system. A stability limit can also 

apply to a local area of the system. 

State Estimator: Computer software package that takes redundant measurements 

of quantities related to system state as input and provides an estimate of the system 

state. It is used to confirm that the monitored electric power system is operating in a 

secure state by simulating the system both at the present time and one step ahead, 

for a particular network topology and loading condition. With the use of a state 

estimator and its associated contingency analysis software, system operators can 

review each critical contingency to determine whether each possible future state is 

within reliability limits. 

Status Variable: Periodic sequence of time-stamped values corresponding to 

measurement, condition, or control settings in the power grid. 

Substation: Facility equipment that switches, changes, or regulates electric voltage 

and power flow. 

Supervisory Control and Data Acquisition (SCADA): A system of remote 

control and telemetry used to monitor and control the electric system. SCADA is 

also used in other industries, including chemical plants and water treatment 

facilities. 

Telemetry: Transmittal and receiving of electronic data over long-distance 

communication links. 

Time Stamp: Information added to data to indicate the time at which it was 

recorded. 

Transformer: A device used to raise or lower voltage in an electric transmission 

s ys tem . 

33 
Transmission Control Protocolflnternet Protocol (TCPDP): A protocol for 

transmitting data between computers, the basis for standard internet protocols. 

Transmission Line: Facility for transmitting electrical power at high voltages. 

For purposes of this report, transmission lines are those at 69 kV and higher. 

Transmission Loading Relief (TLR): A NERC procedure used to manage 

congestion on the electric transmission system. The TLR procedure is invoked by 

the RC to alleviate an overload condition detected on transmission lines in his 

jurisdiction. 

Transmission Operator (TO): NERC-certified party (company) responsible for 

monitoring and assessing local reliability conditions; operates the transmission 

facilities and executes switching orders in support of the Reliability Authority. 

Transmission System: An interconnected group of lines and associated equipment 

for the movement or transfer of electric energy between points of supply and points 

at which it is transformed for delivery to customers or is delivered to other electric 

systems. 

Utility: A company that provides and manages energy and is subject to state and 

government regulation. 

Visualization: Methods of displaying data, including lists, tables, charts, and 

graphics. 

Voltage: The electrical force or “pressure” that causes current to flow in a circuit, 

measured in Volts. 

Voltage Limit: A hard limit above or below which is an undesirable operating 

condition. Normal limits are between 95 and 105 percent of the nominal voltage at 

the point under discussion. 

Voltage Stability: The condition of an electric system in which the sustained 

voltage level is controllable and within predetermined limits. 

Voltage Transducer: A device that converts a voltage measurement into a signal 

that can be monitored by a SCADA system. 

34 
Appendix C 

Geographical Boundaries of Interconnections 

North American Electricity Reliability Council, available at http://www.nerc.com/regional. 

35 
Appendix D 

Functional Status Matrix 

--I 

Orga 

RTOIISC 

Information 

(den'ved in 

RTO or TO 

EMS from 

TO 

ationa 

NERC 

CRC Synchronized Electr&ic 

Data Devices 

Recorders (DFRs, SERs, 

(PMUs) DSRs) 

Source 

NERC 

SDX 

' Real-Time Information 

Derived I Time- I Intelligent SCADA Transmission 

Operator via 

ICCP from 

TO SCADA 

Functional Application for 

Data 

(Real-time applications 

emphasized) 

via ICCP 

from TO 

SCADA 

k SCADA) 

Functional 

Status 

Switching Status 

:topology) 

Used for state estimation, 

operator displays, 

confirmation of operatorinitiated switching actions, 

SCADA alarm processor 

Used for state estimation. 

operator displays, alarm 

processor 

Used to dispatch reactive 

resources, primarily 

capacitors 

May indicate system stress 

X X X ll 

X ieal/Reactive 

'ower Flow X X X 

u'oltage 

vlagnitude X 1x1 

X 

Joltage Angle 

he Sag X X 

'hase Annle 

X 

May indicate potential 

islanding or impending 

system separation 

Used for state estimation and 

for certain derived 

information calculations 

Used in ACE calculations 

resulting in AGC action. Also 

indicator of grid stress 

Some limits are determined in 

advance through planning 

studies while some are 

calculated in real time 

I 

Late-of-Change 

-aP 

:hanger/Phase 

;hitter Setting 

nterconnection 

'requency 

X X 

X 

+ 

imit Violation 

loni toring 

now, voltage, 

tability) 

36 
Organizational Source 

Functional SCADA Transmission RTOIISO NERC NERC 

Status Operator ( ( via CRC SDX 

via ICCP ICCP 

fromT0 fromTO 

SCADA) SCADA) 

ATC 

TLR Status X 

LMP 

Security Alarms 

X 

Other SCADA 

Application 

Calculation 

Results 

Analogs X X X 

Dynamic 

Disturbance Data 

Post Disturbance 

Analysis X X 

Functional Application for 

Data 

(Real-time applications 

emphasized) 

of Real-Time Information 

Derived Time- Intelligent 

Information Synchronized Electronic 

(derived in Data Devices 

RTO or TO Recorders (DFRs, SERs, 

EMS from (PMUs) DSRs) 

TO 

SCADA) 

X 

X 

X 

X 

X X 

X X X 

While not strictly an 

engineering quantity, LMP 

affects flows and system 

operation 

Primarily door switches to 

alert operators when someone 

enters a substation control 

house 

Oil temperature, wind speed, 

line sag, etc. 

Applications may include 

dynamic security assessment, 

dynamic line rating, ATC, 

LMP, TLR, etc. 

SER, DFR, DSR, etc. not 

currently used in real-time 

Requires robust archival 

capability of real-time data 

Compiled by Commission and DOE Staff 

37 
Appendix E 

SCADA and EMS Communications 

I /=I 

I I SCADNEMS 

Measurements from metering devices on transmission equipment and in substations are collected 

by an RTU, which sends data to a utility SCADARMS system. ICCP network allows different 

utilities to share SCADAEMS data. 

Compiled by Commission Staff 

38 
Appendix F 

Proposed Transmission System Monitoring 

Data Communications Infrastructure 

The figure below shows the proposed infrastructure for transmission monitoring system 

data communications using the publisherhbscriber methodology. 

SCADAIEMS 

Publisher 

Transmission Concentrator Substation RTUs 

Critical Grid Locations 

TI'. - 

\>' \/ 

Super Data Concentrator 3 

Reliability 

Coordinators 

Subscriber 

I I 

Reaulatorv 

Tranmlssion 

Operatorsl 

Owners 

Subscriber 

Eitities 

Subscriber 

Compiled by Commission Staff 

39 
Appendix G 

Map of NERC Regional Reliability Councils 

North American Electricity Reliability Council, available at http://www.nerc.com/resonal. 

40