The History of theNorth American
Electric Reliability
Corporation
Helping Owners, Operators,
and Users of the Bulk Power System
Assure Reliability and Securityfor More Than 50 Years

By David Nevius
Senior Vice President 1979–2012

The History of the North American Electric
Reliability Corporation
Helping Owners, Operators, and Users of the Bulk Power
System Assure Reliability and Security for More Than 50 Years

Second Edition

First edition published January 2020
Second edition published March 2020

Table of Contents
Foreword.............................................................................................................. v
Preface ................................................................................................................vii
1965 Northeast Blackout and its Immediate Aftermath ...................................... 3
Call for Legislation ........................................................................................... 4
NERC Is Formed ............................................................................................... 5
FPC Initial Appraisal of NERC ........................................................................... 7
The Next 10 Years (1968–1978) ........................................................................... 9
Further Development of the NERC Organization ............................................ 9
Expanding the Organization ............................................................................ 9
Early TAC Activities ........................................................................................ 11Interregional Review Subcommittee ............................................................. 13
Creating the Study Model ............................................................................. 15Power Transfer Capability Studies ................................................................. 15
Evaluation of Generation Delays ................................................................... 16
Special Reports and Activities ....................................................................... 17
Future Course of NERC (1979) ........................................................................... 19
Swidler Assessment of the Impact of PURPA on NERC.................................. 19
Board Actions in Response to Swidler Recommendations ............................ 21
NERC’s Second Decade: A Period of Expansion (1980–1990) ............................ 23
Strategies for NERC ....................................................................................... 23
National Electric Security Committee ........................................................... 24
Introduction of Competitive Electricity Markets ................................................ 29
Significant Activities Related to the Energy Policy Act of 1992 ..................... 29
Future Role of NERC Task Force II .................................................................. 33
NERC Reliability Compliance Team ................................................................ 38
NERC’s First Official Planning Standards........................................................ 41
Outages Prompt Creation of WSCC Reliability Management System ........... 41
Changes to NERC Bylaws ............................................................................... 42
NERC Forms the Electric Reliability Panel .......................................................... 43
Panel Members ............................................................................................. 43
History of the North American Electric Reliability CorporationiPanel’s Report and Recommendations.......................................................... 44
NERC Board Action on Panel Report ............................................................. 46
Critical Steps in the Transition from NERC to NAERO ......................................... 49
NERC Efforts Continue in 1999 ...................................................................... 50
NERC Elects Independent Board Members ................................................... 50
Other Significant Actions in 1999 .................................................................. 52
NERC to NAERO: Continuing Transformation ..................................................... 55
Legislation Stalls: Contingency Plan Considered ........................................... 55
Reliability Legislation: Status and Plan B ....................................................... 56
Other Year 2000 Activities ............................................................................. 57
NERC Reliability Functional Model ................................................................ 58
2001 Arrives Without Reliability Legislation: Plan B Developed ................... 60
9/11 Attack on World Trade Center............................................................... 62
Reorganization despite No Legislation ............................................................... 65
NERC–NAESB Resolution ............................................................................... 65
Organization and Personnel Certification...................................................... 66
Reliability Coordinator Audits ....................................................................... 66
Synchro-Phasor Measurement System ......................................................... 67
FERC NOPR on Standardization of Generator Interconnections ................... 67
NERC Standards Process ................................................................................ 67
NERC Strategic Plan ....................................................................................... 67
NERC Responds to 2003 Blackout ...................................................................... 69
A Constructive Partnership with Government .............................................. 71
Follow-up on Blackout Recommendations .................................................... 73
Compliance Reviews and Reliability Readiness Audits .................................. 74
Revamping Reliability Standards and the Standards Development Process . 75
Event Analysis and System Protection Initiative ............................................ 78
Critical Infrastructure Security Initiatives ...................................................... 79
NERC Strategic Plan ....................................................................................... 81
Reorganization of NERC Standing Committees ............................................. 81
Natural Gas/Electricity Interdependency ...................................................... 81
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History of the North American Electric Reliability Corporation

System Operator Training and Certification .................................................. 81
GADS Services ............................................................................................... 82
Legislation Finally Passes: New NERC Begins! .................................................... 85
Preparing for ERO Certification ..................................................................... 85
NERC Application Filed with FERC ................................................................. 88
NERC Certified by FERC as the ERO ............................................................... 88
NERC’s 40th Anniversary Ushers in the Next Decade ........................................ 91
Overview ....................................................................................................... 91
NERC Program Area Developments and Activities: Fifth Decade....................... 97Standards ...................................................................................................... 97
Compliance.................................................................................................. 102
Infrastructure Protection and Cyber Security Initiatives ............................. 109
Reliability Assessment Activities ................................................................. 121
Event Analysis and Trends ........................................................................... 130
Risk-Based Strategies and Initiatives ........................................................... 136
Collaboration with Canada, Mexico, and International Entities .................. 140
System Operator Training and Certification and Human Performance ....... 142
Final Thoughts .................................................................................................. 145
Appendix .......................................................................................................... 146
Evolution of the Electric Utility Industry (1882–1970) ................................ 147
Regulation of Electricity in North America .................................................. 153
North American Power Systems Interconnection Committee .................... 155
Number of Major Interconnected Systems in North America ..................... 160
NERC Special Reliability Assessments: 1972–1978 ..................................... 161
Significant NERC Milestones in the 1980s ................................................... 162

History of the North American Electric Reliability Corporationiii

History of the North American Electric Reliability Corporationiv

Foreword
History can easily be lost as time passes; people
move on, and memories fade. This project wasundertaken to be sure that we preserve thehistory of the key events of NERC’s first 50 years
and recognize the individuals responsible for
NERC’s many accomplishments during thisperiod. The story records how NERC evolved
from a voluntary international organization thatwas formed by electric utilities across North
America and dedicated to the maintaining andenhancing the reliability of the interconnected
Bulk Electric System to the Electric Reliability
Organization today. NERC is now responsible for developing, adopting, andenforcing Reliability Standards under U.S. law and assessing the reliability ofthe bulk power system and for developing reliability standards andmonitoring compliance and performing assessments of the interconnected
system in Canada and the northern portion of Baja, Mexico.
This history illustrates how NERC has met the challenges presented by the
many changes that have occurred over this 50-year period in technology andindustry structure while maintaining a steady, laser-like focus on its
fundamental public interest mission. As this history illustrates, it can be said
with certainty that the reliability and security of the North American grid has
been protected and significantly enhanced through the hard work of NERC,
its Regional Entities, and many stakeholders. This highly reliable system isessential to the health, safety, and economic well-being of North America.
Many thanks to former NERC senior vice president David Nevius, the lead
writer and researcher for this project. His 35 years of service to NERC, his
prodigious memory, and the many relationships he formed while at NERC
have been crucial to the success of this project. It is impossible to recognize
here everyone else who has contributed. They are many. A special thanks
though to Earl Nye, Mike Greene, Don Hodel, and Paul Barber, who provided
Dave with many insights and memories. Thanks also to NERC’s staff who
worked on this project, including Mark Lauby, Andy Rodriquez, Kimberly
Mielcarek, Amy Desselle, Terry Campbell, and Alex Carlson.
Roy Thilly
NERC Board of Trustees Chair

History of the North American Electric Reliability Corporationv

vi

History of the North American Electric Reliability Corporation

Preface
The North American Electric Reliability Corporation (NERC) was formedon June 1, 1968, as the National Electric Reliability Council. While NERC’s
formation was the direct result of the 1965 northeast blackout, it was also
an important step in the progression of increasing industry coordinationand cooperation that has been the hallmark of the electric industry andNERC.
Since its formation, NERC has continued to adapt to industry and market
changes, including the introduction of wholesale and retail electricity
competition and the changing economics and policies that are driving thecurrent shift to natural gas, renewable, and distributed energy resources.
In the face of these many changes, NERC’s constant mission has been toassure that the North American bulk power system (BPS) remains highly
reliable. Over time, NERC has transformed itself into the world-classorganization for electric reliability that it is today.
While the various chapters in this document cover different time periods
and milestones in NERC’s history, it is helpful to think of NERC’s evolution
in the following three key stages:
Stage One started with NERC’s original formation and earlyorganizational developments. Rather than creating a new
government-based regulatory structure, NERC was formed toaddress the obvious reliability issues stemming from the 1965
blackout and the much greater utility interdependence that
resulted from further integration of the grid while maintaining
the responsibility for reliability in the industry itself where theoperational and planning expertise resides.

Stage Two was often called the “advent of competition,”characterized by the introduction of new non-utility generatorsand marketers without an obligation to serve, open access totransmission service and retail deregulation, coupled with fears
that reliability rules could be used for anti-competitive purposes.
This led NERC to ask itself: “How can reliability of the BPS be
assured in this new, open-access and increasingly competitiveelectricity environment?” The answer came into focus in early
1999 and led NERC into its next stage of development.

History of the North American Electric Reliability Corporation

vii



Stage Three was marked by the passage of the Energy Policy Act
of 2005, which provided for a new form of reliability assuranceorganization—the Electric Reliability Organization (ERO). The ERO
would be responsible for mandatory, enforceable Reliability
Standards developed by industry and adopted and enforced by
NERC with oversight by its independent Board and the U.S.
Federal Energy Regulatory Commission (FERC) and Canadianprovincial regulators. The ERO would also be responsible for
conducting and reporting on periodic short- and long-term
assessments of the reliability of the grid, including analysis of
emerging risks. In 2006, NERC was approved to fill this role in the
United States and, over time, made arrangements to provide formandatory compliance with NERC Reliability Standards
throughout the Canadian provinces.

The evolution of the electric utility industry from isolated tointerconnected systems enhanced reliability and economics but broughtwith it mutual dependence—a problem on one system could affectneighboring systems. This drove the need for careful cooperation andstrong coordination in system operations and common Reliability
Standards. This eventually led to the formation of the North American
Power Systems Interconnection Committee (NAPSIC), which preceded
NERC.
In April 1962, at the invitation of the chair of the Interconnected Systems
Group, a meeting was held with the representatives of interconnected
systems throughout the United States and Eastern Canada to discuss
future coordination requirements in light of the explosive pace ofinterconnection developments. It was at that meeting that the idea of
NAPSIC was conceived. NAPSIC was created as an informal operationsorganization for the future to promulgate “operating guides” for the
reliable operation of interconnected systems. See details of NAPSIC’s
evolution in the appendix.
Former NERC Board member, Donald Paul Hodel,1 recently remarked thata number of highly significant events, and the people who responded tothem were instrumental in moving NERC from its beginnings in 1968 to
1 Mr. Hodel served on the NERC Board of Directors from 1973 to 1977 as a representativeof the federal utility sector and again as an independent director starting in 2001.
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History of the North American Electric Reliability Corporation

where it is today. Mr. Hodel was struck by the fact that the many
thousands of engineers who planned, designed, built, and operated thegrid, and their respective organizations that were part of NERC’s
formation and evolution, were dedicated to ensuring reliability of aservice essential to health, safety, and our economy. Without thisdedication, NERC’s success could not have been achieved.
The chapters that follow chronicle the many events that have shaped
NERC over its 50 years as well as how it assumed its new role as the ERO—
an entity created pursuant to United States law2 to create and enforce
mandatory Reliability Standards.
But more than the events themselves, these chapters will give the readersa sense of how the people of NERC tirelessly worked together incooperation with each other across all industry sector lines and alongsidewith state, federal, and provincial governments to promote the reliabilityof what most regard as the most complex machine ever devised by man—a machine on which so many depend for their very health, safety, andeconomic wellbeing.
Terry Boston, former NERC Board member and former CEO of PJM,
probably said it best: “What we do is not rocket science…it is more
important than that.”

2 Various regulatory and statutory arrangements in Canada provided for the ERO to

oversee reliability throughout North America.
History of the North American Electric Reliability Corporationix

x

History of the North American Electric Reliability Corporation

Stage One
This stage started with NERC’s original formation andearly organizational developments. Rather than creatinga new government-based regulatory structure, NERC wasformed to address the obvious reliability issues stemmingfrom the 1965 blackout and much greater utility
interdependence that resulted from further integrationof the grid while maintaining the responsibility forreliability in the industry itself where the operational andplanning expertise resides.

History of the North American Electric Reliability Corporation

1

2

History of the North American Electric Reliability Corporation

1965 Northeast Blackout and its Immediate
AftermathModern society has come to depend on a reliable electricity supply
system. It is an essential resource for national security, health andwelfare, communications, finance, transportation, food and water supply,
heating, cooling, lighting, computers and electronics, commercial
enterprise, and even entertainment and leisure. Without it, society as weknow it would not exist.
On Tuesday, November 9, 1965, at 5:16 p.m. Eastern, a major cascading
system disturbance, known as the 1965 northeast blackout, resulted in
the loss of 20,000 MW of load, affecting 30 million people. This outage
lasted for 13 hours and was the most significant disruption in the supplyof electricity at that point in the history of the electric industry, affecting
parts of Ontario in Canada as well as Connecticut, Massachusetts, New
Hampshire, New Jersey, New York, Rhode Island, Pennsylvania, andVermont in the United States.
This event brought to the attention of industry, government, and societyat-large how vital a reliable supply of electricity is to public health, safety,
and the economy and focused attention on the many challenges that
accompany the operation of such a highly integrated interstate andinternational system with multiple owners and operators.
Industry and government studied in detail the initial cause of the blackout
and subsequent cascading event. In short, a backup protective relay
operated to open one of five 230 kV lines, linking a power plant in Ontario
with the Toronto load center. When the flow on this line redistributed
instantaneously over the remaining four lines, those lines trippedsuccessively by protective relay action in a total of two-and-a-halfseconds. The power swings that resulted from the loss of these lines led
to a cascading outage that affected much of Ontario and the northeast
United States.
The operation of the backup protective relay that tripped the initial line
caught operating personnel off guard as they were not aware of theoperating set point of this relay. A long-standing technical debate arose in
the months and years that followed the blackout as to whether the relay

History of the North American Electric Reliability Corporation3

engineer set the relay trip point too low3 given the current carrying
capability of the conductor or whether the operator should have known
what the relay setting was and operated the system accordingly to staywithin the relay limit. Regardless, after the initial line tripped, a series ofother 230 kV, 115 kV, and 345 kV lines tripped by protective relay action
to protect the lines from damage. In addition, 5 of 16 generators at the
St. Lawrence power plant tripped automatically according topredetermined operating procedures, followed by 10 generating units at
the Sir Adam Beck plant shutting down automatically due to low governor
oil pressure, and 5 pumping generators at the same plant tripping by overspeed governor control to prevent them from physical damage.
At the request of President Lyndon Johnson, the Federal Power
Commission (FPC) was charged with investigating the cause of themassive outage. The FPC issued its initial report on the blackout on
December 6, 1965.

Call for Legislation
The 1965 northeast blackout along with a smaller but still significant
cascading blackout that occurred on June 5, 1967, in the Pennsylvania–
New Jersey–Maryland (PJM) interconnection area, prompted the U.S.
Congress, at the urging of the FPC, to enact legislation giving the FPC
increased authority and jurisdiction over electric power systeminterconnections and reliability. This bill was known as the Electric Power
Reliability Act of 1967.
Mr. Hodel4 recalled that he accompanied Russ Richmond, thenadministrator of Bonneville Power Administration (BPA), and Floyd Goss,chief electrical engineer and assistant manager of the Los Angeles
3 Arguably, the setting in question was a so-called “Zone 3” backup protection zone of therelay that was designed to interrupt the loading current on the line for a distant fault.
Such problems plagued the North American bulk power system until NERC formed the
System Protection and Controls Task Force (now the System Protection and Controls
Subcommittee or SPCS) following the August 14, 2003, Northeast Blackout.
4 At the time, Mr. Hodel was deputy administrator of BPA. He later became administrator

and, in that capacity, a member of the NERC Board from 1973–1977, representing thefederal power sector of the industry. After leaving BPA, Mr. Hodel was named NERC
president and served in a part-time role until Walter Brown was named full-timepresident in 1980. Mr. Hodel later joined the NERC Board as an independent trustee in2001.
4History of the North American Electric Reliability Corporation

Department of Water and Power (LADWP), to a meeting in
Scottsdale, Arizona, with Edison Electric Institute (EEI) executives
and Senator Warren Magnuson. The purpose of the meeting, which
was successful, was to assure the Senator, who chaired a key Senate
committee that would most likely be involved in the proposed
reliability legislation, that the industry was up to the task of securingsystem reliability voluntarily and should be given the chance toaddress the reliability challenges exposed by the 1965 and 1967
blackouts without federal legislation.
The FPC’s final report on the blackout recommended the creation of “acouncil on power coordination made up of representatives from each of
the nation’s regional coordinating organizations to exchange
and disseminate information on regional coordinating practices to allof the regional organizations and to review, discuss, and assist in
resolving matters affecting interregional coordination.” Thus, theblueprint for NERC was created.

NERC Is Formed
The National Electric Reliability Council (NERC) came into being withan agreement dated June 1, 1968, signed by 12 regional and area
utility organizations.


East Central Area Reliability Coordination Agreement (ECAR)

Mid-Atlantic Area Coordination Group (MAAC)



Mid-America Interpool Network (MAIN)

Mid-Continent Area Power Planners (MAPP)

Northeast Power Coordinating Council (NPCC)

Southwest Power Pool (SWPP)

Western Systems Coordinating Council (WSCC)

Texas Interconnected System (TIS)

Carolinas-Virginias Power Pool Agreement (CARVA)Southern Services, Inc.



Tennessee Valley Authority (TVA)

Florida Power Corporation

History of the North American Electric Reliability Corporation

5

These 12 organizations encompassed essentially all of the power systemsof the United States5 as well as parts of Ontario, British Columbia, andManitoba in Canada. Some of these organizations were already Regional
Reliability Councils. By 1971, every Region in the United States and theabove Canadian provinces had a voluntary Regional Reliability Council topromote coordinated operations and planning, issue reliability
guidelines, and exchange best practices with each other. One
representative from each regional reliability organization served as an
initial member of the NERC Executive Board.
Mr. Goss of LADWP was named the first chair of NERC. William B. McGuireof Duke Power Company was named the first vice chair, and J. Lee Rice Jr.
of Allegheny Power System was named the first secretary treasurer. The
initial Executive Board was made up of these three officers and one
representative from each of the 12 signatory organizations.
The chairs of NERC, up until the organization’s leadership transitioned toa fully independent Board in 2001, were the following:
1968–1970
1970–1972
1973–1974
19756
1975–1977
1978–1979
1980–1981
1982–1983
1984–1986
1987–1988
1989–1990
1991–1992
1993–1994
1995–1996
1997–1998
1999–2000

Floyd L. Goss, Los Angeles Department of Water and Power
William B. McGuire, Duke Power Company
Jack L. Wilkins, Omaha Public Power District
John G. Quale, Wisconsin Electric Power Company
William McCollam, Jr., New Orleans Public Service Company
Wendell J. Kelley, Illinois Power Company
Andrew H. Hines, Florida Power Corporation
Richard O. Newman, Public Service Company of Oklahoma
John P. Williamson, Toledo Edison Company
Arthur J. Doyle, Kansas City Power and Light Company
William H. Clagett, Western Area Power Administration
Earl K. Dille, Union Electric Company
Richard E. Brooks, Central and Southwest Corporation
Richard J. Grossi, United Illuminating Company
Erle Nye, Texas Utilities
Gary L. Neale, NiSource

5 Members of the 12 signatory organizations included utilities from all segments of theindustry—investor-owned, rural electric cooperatives, state/municipal utilities, andfederal power marketing agencies.
6 Mr. John Quale served as chair from April 1975 until his untimely death in September

1975.
6

History of the North American Electric Reliability Corporation

Chairs of the Independent ERO Board
2001–2008
Richard Drouin
2009–2012
John Q. Anderson
2013–2016
Fred Gorbet
2017–
Roy Thilly
Over its history, NERC has had eight staff presidents:
Part Time
1973–1975
1975–1978
1978–1980

Floyd L. Goss, former executive of LADWP
Walter J. Matthews, former executive of Public Service Indiana
Donald Paul Hodel, former administrator of BPA

Full Time
1980–1982
1982–2005
2005–20097
2009–20172018–

Walter D. Brown
Michehl R. Gent
Richard Sergel
Gerry W. Cauley
James Robb

FPC Initial Appraisal of NERCOn April 16–17, 1969, at the meeting of the NERC Executive Board, andat the invitation of NERC President Floyd L. Goss, F. Stewart Brown, thechief of the Bureau of Power for the FPC, gave his general appraisal of
NERC’s progress and projected programs. Mr. Brown acknowledged that
he was “gratified that a National Electric Reliability Council8 had been
formed, that its membership was broadly representative of utilities
throughout the United States, that it had invited FPC to have aparticipating observer attend its Executive Committee meetings, and thatthe views of FPC’s representative were invited.”
Mr. Brown noted that the FPC and its Advisory Committee on Reliabilityof Bulk Power Supply advocated for the establishment of regional councils
and a national council in the Prevention of Power Failures reportpublished by the FPC in June 1967. He also commented that NERC’s
decision to establish a single Technical Advisory Committee (TAC) withmembers from both planning and operating groups rather than separate
planning and operating committees appeared to be commendable and7 In July 2006, NERC was approved by FERC as the ERO.
8 NERC became the North American Electric Reliability Council in 1981.

History of the North American Electric Reliability Corporation

7

should be helpful in further coordinating the efforts of these principal
elements of utility responsibility. Mr. Brown concluded his remarks bysuggesting that the purposes for which NERC was formed were all useful,but in total, it appeared to fall short of the full responsibility that NERC
should assume to ensure a reliable BPS.
In response to a request from President Floyd L. Goss, Mr. Brown
enumerated 15 study areas that he believed were representative of thekinds of responsibilities for leadership and guidance that the TAC should
assume:

Reliability Criteria and Standards



Improving the Adequacy of Load Projections



Load-Shedding Practices

Study of Potential Deficiencies in Power Supply

Mechanisms for Transferring Power in Emergencies



Cost Considerations for Multiple-Benefit Facilities



Generation ReservesCollection and Evaluation of Data on Equipment Failures

Analyses of Principal Power Failures

General Guidelines for Control and Communication

Standardization in Transmission Line Voltages



Guidelines for Operation

Equipment Availability Studies



Shop Inspections



Guidelines for MaintenanceIn conclusion, Mr. Brown stated, “I believe that NERC and its member
councils have made a good start. The responsibilities are of major
proportions and will require much sincere dedication on the part of NERC
and its Council members to produce effective results.”
NERC took the points raised by Mr. Brown as a high-level representativeof the FPC seriously, and its efforts over the next 10 years were a sincere
attempt to address as many of these points as possible.
8

History of the North American Electric Reliability Corporation

The Next 10 Years (1968–1978)
Further Development of the NERC Organization
After its initial formation in June 1968, NERC set out to further develop
the organization to enable it to meet its mission, defined initially as thefollowing:
Further to augment the reliability of bulk power supply in the electricutility systems of North America. To this end, the Council would do thefollowing:

Encourage and assist the development of inter-regional reliability
arrangements among regional organizations or their members.



Exchange information with respect to planning and operating
matters relating to the reliability of bulk power supply.



Review periodically regional and interregional activities on
reliability.

Provide independent reviews of interregional matters referred to
it by a regional organization.

Provide information, where appropriate, to the FPC with respect
to matters considered by the Council.

This mission statement was in large measure a response to many of thepoints raised by Mr. Brown at the April 1969 meeting of the NERC
Executive Board. Clearly, the industry through NERC desired to prove to
the FPC that it was up to the task of promoting reliability of theinterconnected systems.

Expanding the Organization
Originally the Executive Board of NERC consisted of one member fromeach of the 12 signatory organizations. In most cases, the member was
the chair of the respective regional or area utility organization and also a
top executive of their own system.
In January 1970, NERC became a council with nine regional organizations
upon the formation of the Southeastern Electric Reliability Council (SERC),
which combined four previous NERC signatories into one SERC Region. At
History of the North American Electric Reliability Corporation

9

that same time the Mid-America Power Pool (MAPP) was replaced with
the Mid-Continent Area Reliability Coordination Agreement (MARCA). A
year later in January 1971, Texas Interconnected System (TIS) was
replaced by the Electric Reliability Council of Texas (ERCOT). In December
1971, the Canadian province of New Brunswick became a full member of
the Northeast Power Coordinating Council (NPCC), thus expanding
representation from electric utility systems in Eastern Canada.
When NERC membership was reduced to nine regional organizations, it
was agreed that there should be two representatives from each Region
on the NERC Executive Board. In addition, an important provision in the
NERC agreement required that there must be at least two members fromeach ownership segment of the industry (i.e., investor-owned,
municipal/state, federal, and rural electric cooperative) on its Executive
Board. If the regional representatives did not fulfill that requirement,
additional members were elected to the Executive Board fromnominations submitted by the Regions.
On January 1, 1970, the NERC Executive Committee established apermanent staff, hired Walter D. Brown as its first staff employee, andopened its administrative office in New York City. Mr. Brown was named
administrative manager and assistant secretary treasurer. In May 1970,
the office was moved to Princeton, New Jersey, where it remained formore than 40 years.
Many have asked why Princeton was chosen as NERC’s home. The answer
is quite simple. When the Board was trying to decide where the NERC
office should be located, one of the Board members suggested it betemporarily located close to Mr. Brown’s residence in Princeton as he had
three sons in high school at the time. The plan was to reconsider apermanent location at a later date that turned out to be a long timecoming.
After considerable study, the NERC Executive Board created a TechnicalAdvisory Committee (TAC) as its principal technical group. The first chairof TAC was W. M. Brewer, vice president of Middle South Services, Inc.
Originally, TAC included one member from each Region. This was later
revised to include two members from each Region. Chairs of therespective subgroups of TAC were eventually added as ex-officio
10

History of the North American Electric Reliability Corporation

members. While many or all the Regions had established separate
planning and operating committees, NERC felt at the time that it wasadvisable to have a single technical committee to provide an overview for
all the BPS functions. This decision was designed to help improve thecoordination between planning and operating functions.9
Recognizing its long and successful performance, NERC also included two
members from NAPSIC on the TAC to act as liaisons between NERC and
NAPSIC. In fact, the officers of NERC stated that the success of thevoluntarily formed NAPSIC was in large part a model and an incentive for
NERC’s organizational structure.
Many leaders of the industry believed that the formation of NERC wasvery timely as evidenced by this statement in the 1969 NERC Annual
Report:“Never before in its history has the industry been faced with the
problems that have affected the reliability of bulk power systems
as it has in the recent past. Delays in the in-service dates of new
equipment, human failures, environmental concerns, and greaterthan expected load growth have all contributed to a most serious
situation. Nevertheless, without the cooperation and study
arising out of the coordination obtained through the regionalreliability organizations and NERC, the situation would have beenmuch more serious.”

Early TAC Activities
In 1969, a TAC subcommittee developed Proposed System Reliability
Criteria, based primarily on Planning Criteria submitted by the NERC
signatory organizations. At the same time, a NAPSIC committee
developed Operating Criteria and submitted them to TAC forconsideration. Differences in format were discussed and resolved, andNERC indicated its endorsement of the NAPSIC Operating Criteria.

9 The decision to have a single technical committee was reversed in 1980 when NERC

merged with NAPSIC, making it the NERC Operating Committee. TAC was renamed theEngineering Committee, and a Technical Steering Committee, made up of the officers ofeach committee plus the president and executive vice president of NERC, was formed.
History of the North American Electric Reliability Corporation

11

Two of the early assignments of TAC were to work with the FPC on
Dockets 361 and 362. The former was an order under which outages andemergency conditions were to be reported to the FPC. The second was anorder under which a wide range of information was required to bereported annually by each Region to the FPC, covering load and capacity
projections, fuel supplies, environmental considerations, newtransmission links, and other related data for a ten-year period. TAC
representatives were instrumental in having these documents patternedin the most effective form to provide the required information in the most
expeditious manner and reasonably compatible across the systems of theUnited States.
As time progressed, NERC addressed other matters of concern to thereliability of the BPS. In the spring of 1969, 1970, and 1971, the NERC
Board chair testified before the U.S. Congressional House Subcommittee
on Communications and Power of the Committee on Interstate andForeign Commerce with regard to the proposed bills relating to reliability
and power plant siting. In these hearings, NERC was in a position to speak
for the entire electric utility industry on technical matters.
NERC also responded to FPC proposed rulemaking dockets, including one
related to emergency procedures and one regarding fuel quality.
As an example of other significant NERC accomplishments during that
period, NERC Executive Board an ad hoc committee studied andappraised the status of mutual aid agreements between regional
councils, power pools, and systems or groups of systems under various
types of emergency situations.
The NERC Executive Board endorsed a National Academy of Engineering
proposal to conduct a power plant siting study and agreed to seek
assistance in funding the project in an effort to streamline power plant
siting procedures.

12

History of the North American Electric Reliability Corporation

TAC conducted current peak load/capacity/reserves surveys for bothsummer and winter peak load seasons by Region. It also surveyed theindustry to determine the impact on bulk power facility installations as aresult of labor strikes at plants of two major equipment manufacturers.
TAC maintained records of performance of the BPS in North America.

Interregional Review Subcommittee
Perhaps the most important TAC activity was its review of interregional
activities related to reliability of the BPS.
In 1970, a TAC subcommittee completed a review of interregional
coordination. This study was an analysis of the 1970 status of andindustry’s 1980 projections for interregional transmission developments
and mechanisms established for interregional coordination. Following
this report, the NERC Executive Board established the Interregional
Review Subcommittee to review, on a continuing basis, and report on theoverall adequacy and reliability of existing and planned North American
BPS in the NERC Regions.
Initially formed in 1970, the Interregional Review Subcommittee, now the
Reliability Assessment Subcommittee (RAS), is one of the longest standing
NERC subcommittee. To this day, the RAS remains one of the mostimportant groups of NERC, annually assessing and reporting on theexisting and future reliability of bulk electric systems (BESs) for the next
10 years, conducting short-term seasonal assessments of summer andwinter peak demand seasons, and performing special studies of issues
that could adversely affect BPS reliability.
The first chair of the Interregional Review Subcommittee was Ted J. Nagel,
vice president of American Electric Power Service Corporation (AEP). The
scope of the Interregional Review Subcommittee as approved by the
NERC Executive Board on October 29, 1970:“The subcommittee shall review on a continuing basis the overall
adequacy and reliability of the North American BPS as existingand planned among and within the NERC Regions…
Evaluations shall be made of the ability of the network and thegeneration supplying the overall loads connected thereto toHistory of the North American Electric Reliability Corporation13

support a generation-deficient area during time of emergency.
Recognizing that the interconnected transmission gridconstitutes the primary medium for interaction between the
Regions and among the systems comprising the Regions,particular emphasis shall be placed in these reviews upon theability of this network to prevent cascading and widespreadinterruptions…
These reviews shall include an assessment of the adequacy andreliability of the interconnected network as now existing and asplanned and contemplated for a period of 10 years into the
future. The interconnected systems’ performance shall be judged
on the basis of existing regional criteria as well as on the basis ofsuch other criteria as may be developed by the subcommittee forthese reviews.”
In a 1972 assessment, the Interregional Review Subcommittee
recommended the expansion of multiregional simulation studies forselected future load levels covering the relevant portions of the large
interconnected bulk power network, including the WSCC Region whereappropriate.10 These simulations were to appraise the interconnection ofsignificant facilities, power transfer capabilities, and the overall
performance of the network more fully. Such studies were intended to besupplemental to the several already existing multiregional studies.
In August 1973, the Technical Working Group recommended by theInterregional Review Subcommittee completed studies of transregionaland simultaneous multiregional transfer capabilities for 1973. The groupalso assessed the availability of regional data for study of 1978 conditions
and discussed the powerflow11 analysis specifications for this study. As
part of their assignment, the group evaluated and compared the twovendors with powerflow modeling and analysis capability sufficient to

10 The Eastern and Western Interconnections were first connected synchronously in 1967

when four tie lines were closed. The North American grid operated with these four weaklinks between east and west for eight years. In 1975, it became apparent that the twolarge interconnections could not operate reliably when connected by ac ties. High-voltage
dc ties replaced the ac ties in 1980.
11 Often referred to as “load flow” studies.

14

History of the North American Electric Reliability Corporationperform studies of this magnitude—AEP and Westinghouse Electric
Corporation. Eventually, AEP was chosen to conduct these studies.

Creating the Study ModelIn the early 1970s, most NERC Regions conducted studies to appraise theadequacy and reliability of the various transmission systems prior to thenext expected peak demand period. To avoid duplication of effort andenhance coordination of information, five Regions in the EasternInterconnection jointly established a study using the base model
established by NPCC, MAAC, ECAR, SERC, and MAIN Regions. Data from
SPP and MARCA data was added to the model via load flow common dataexchange format procedures. The final model consisted of data fromseven Regions. WSCC was represented by an equivalent and wascontained in the MARCA data. Texas and the Florida subregion of SERC
were not included. Total system representation consisted of 5,130 buses,
8,206 lines, and 27 areas.

Power Transfer Capability Studies
Power transfer capability studies were performed by the interregional
study groups to determine power transfer capabilities and simultaneous
power import capabilities. System normal transfer capability between
Regions was defined as the ability of a Region to import or export powerwith all transmission facilities in service without exceeding continuous
facility loading capabilities. Contingency transfer capability between
Regions was defined as the ability of a Region to import or export powerwith a critical transmission facility out of service without exceeding theappropriate long-time emergency ratings of remaining facilities. Thesestudies marked the initial efforts of NERC to define and calculate First
Contingency Total Transfer Capability (FCTTC) and First Contingency
Incremental Transfer Capability (FCITC). These definitions were later
codified in the May 1995 Transmission Transfer Capability reference
document.
Those in-depth studies, the first of their kind ever to be conducted, werecompleted in the fall of 1971 and a comprehensive report was issued by
the subcommittee in October 1971. The Interregional Review
Subcommittee report contained an appraisal of the BPS and included
recommendations to the industry for matters which required further
attention.
History of the North American Electric Reliability Corporation

15

Evaluation of Generation Delays
In the latter part of 1971 and early months of 1972, the Interregional
Review Subcommittee was requested to evaluate the impact on theadequacy of the BPS due to several U.S. Court decisions that threatened
to delay the addition of new nuclear and fossil-fired generating stations.
At the time, peak load was growing at an annual rate of seven percent(incredibly high by today’s measure), and utilities were struggling to bringsufficient generating capacity into service to meet the rapidly increasing
demand.
A NERC report, Impact of a 12-month Delay of New Nuclear and FossilFired Steam Generating Units on the Adequacy of Electric Power Supply in
the United States, was used as a basis for NERC’s testimony before the
Joint Committee on Atomic Energy. This report stood up well under
scrutiny and served to reinforce NERC’s credibility as a factual source of
information on BES reliability and adequacy.
In March and April of 1972, the NERC Board chair testified before threecongressional committees—each of which was studying the need forinterim legislation to permit the licensing of new nuclear generating units.
The committees were the following: the Joint Committee on Atomic
Energy, the Subcommittee on Fisheries and Wildlife Conservation, andSenate Interior and Insular Affairs Committee.
On April 17, the House of Representatives approved the “Dingell Bill” bya substantial margin. NERC officers were told that the successful passageof this legislation to permit licensing of new nuclear units was due in largepart to the NERC reports and testimony on these matters.
It appears that, in addition to the many specific tasks NERC undertook in
its first several years of existence, one of its greatest contributions to thereliability of the BPS was the creation of a continent-wide organization
that, through the regional councils, could effectively provide anynecessary analysis, survey, or information industry-wide in regard toreliability and adequacy of the BPS.

16

History of the North American Electric Reliability Corporation

A key to NERC’s effectiveness as a forum for solutions was succinctly
expressed by Mr. Goss, NERC chair from its formation in 1968 until 1971:“Bring together the right people and any legitimate problem can besolved.”Special Reports and Activities
Between 1972 and 1978, a number of special reports and activities werealso conducted. Annually, NERC updated the multiregional model databank for future year powerflow base cases, prepared annual reviews ofadequacy and reliability, conducted annual fuel surveys, and preparedannual reports. In addition, NERC prepared peak load surveys semiannually, compiled disturbance reports quarterly, and agreed to assume
sponsorship for the Equipment Availability Data activity. A listing of otherspecial reports and activities conducted during the 1972–1978 period
appear in the appendix.

History of the North American Electric Reliability Corporation

17

18

History of the North American Electric Reliability Corporation

Future Course of NERC (1979)
The initial introduction of competition into the United States electricindustry began in 1978 with the Public Utility Regulatory Policies Act(PURPA), which was part of the National Energy Act of 1978. Thislegislation led to limited competition among a small group of wholesale
suppliers.12
In December 1978, NERC contracted with Joseph C. Swidler, who served
as chair of the FPC at the time of the 1965 northeast blackout, to prepare
an overview of NERC’s role in the electric utility industry and provide
recommendations on possible changes in the structure and operation of
NERC and the regional councils.

Swidler Assessment of the Impact of PURPA on NERC
Mr. Swidler agreed that a reassessment of NERC’s functions andorganization was timely given the extraordinary emphasis that Congressplaced in PURPA on the subject of BPS reliability and coordination. In
particular, Mr. Swidler cited the provision requiring the U.S. Departmentof Energy (DOE) to complete and submit to Congress within 18 months ofpassage of the Act, (i.e., by May 9, 1980) a comprehensive reliability study
that needed to include recommendations on the following: desirable
level of reliability, various ways in which such level of reliability can beachieved, and various ways of dealing with emergency outages. DOE wasalso specifically required to evaluate the Reliability Standards already inuse by the industry, including standards prescribed or recommended by
NERC and the regional councils. In addition, DOE was given authority in
PURPA to recommend Reliability Standards for the industry, request
reports concerning actions the industry had taken to comply with thesestandards, and report to Congress on an annual basis concerning theindustry’s response.
Mr. Swidler concluded that the DOE report, once submitted, would serveas the basis for hearings on the need for conferring this wide range ofadditional powers on the Federal Energy Regulatory Commission (FERC)
and DOE and that it would be up to the industry to demonstrate that it
was organized in such a way that it could take responsibility for reliability.
12 In 1977, the Federal Energy Regulatory Commission (FERC) was established as areplacement for the FPC.
History of the North American Electric Reliability Corporation19

Swidler RecommendationsInterregional Reliability

Planning for Interregional Ties



Uniform Standards for Regional Ties



Need for Mandatory Standards and Sanctions Necessary

Need to Distinguish Between Adequacy and Reliability

Study of Steam Plant Construction Lag

Consideration of Emergencies in Planning Interconnections

Role of Regional Councils in Interregional Studies



Allocation of Benefits and Responsibilities



Development of Standards for Allocation of Financial
ResponsibilityStandards for Compensation for Use of Transmission
Capacity

Reliability Criteria and Standards

Transmission Failure Analysis



Failure Prevention Program



Avoidance of Competitive Issues

Data Verification

Swidler Administrative Recommendations

20



Need for NERC Organizational Changes

Need for Retention of the Pluralistic Foundation of NERCNeed for Full-time President and Strengthened Staff

Relationships with Regional Councils



Reorganization and Rationalization of Regional Councils



Location of NERC Offices

History of the North American Electric Reliability Corporation

These conclusions and recommendations were based primarily on
industry’s internal pressures for improvement in reliability andcoordination and an effort to determine how NERC might best fit into the
expanded framework of interstate bulk power supply regulation as
established by Congress in Title II: Certain Federal Energy Regulatory
Commission and Department of Energy Authorities of PURPA.

Board Actions in Response to Swidler
Recommendations
On March 2, 1979, the Executive Committee of the NERC Board wrote to
the entire Board on the results of the Swidler study on the future courseof NERC as well as their recommendations. The letter to the Board statedthat the Executive Committee had been increasingly aware of a steadily
increasing involvement by the federal government in the decision-making
processes for planning and operating electric utility systems. The letter
went on to say that proposed PURPA legislation would increase this
impact, creating a hazard that regulatory involvement could reach a levelthat would slow decisions and impede actions necessary for an adequate
and reliable power supply unless industry could successfully demonstratethat it could continue to do a good job in a voluntary way.
In April 1979, the Board, on the recommendation of the Executive
Committee, passed several resolutions based on Mr. Swidler’s report asfollows:•

NERC should remain voluntary without power to enact sanctions
against a member. NERC should remain an organization ownedby the regional councils since this is where the manpower,
expertise, support, and underlying responsibilities are located.

•

NERC TAC should request planning criteria and interregionaltransfer capability criteria be developed.

•

NERC should assemble and publish regional data of loads andresources.13•

EEI, American Public Power Association (APPA), and National
Rural Electric Cooperative Association (NRECA) were added as
official observers at Board meetings.

13 This became the Electricity Supply and Demand Report.

History of the North American Electric Reliability Corporation

21

The addition of three technical personnel to the NERC staff was
authorized.



It was clarified that there was no intention on the part of NERC tointerfere with any channels of communication now enjoyed by
the councils or the individual systems with any governmental orother type of regulatory agency.

Even though the Board did not take all of Mr. Swidler’s recommendations,the report paved the way for significant expansion of NERC’s activities
prior to the advent of competitive electricity markets.14

14 See Significant Milestones in the 80s in the Appendix.

22

History of the North American Electric Reliability Corporation

NERC’s Second Decade: A Period of Expansion(1980–1990)
In addition to the specific activities NERC undertook in the 1980s,
primarily as a result of Mr. Swidler’s recommendations, NERC also began
to sharpen its focus on threats to the reliability of the BPS and specificstrategies to address these threats.

Strategies for NERC
Following the April 1987 Board meeting, NERC Board Chair Arthur Doyle,asked for a survey to be conducted of regular attendees of NERC Board
meetings to help formulate strategies for meeting NERC’s charge “topromote the reliability and adequacy of bulk power supply by the electric
systems of North America.” The survey resulted in the identification of 12
reliability threats.
Reliability Threats
1. Non-utility Generators
2. Wheeling/Access
3. Approval Processes for New Facilities
4. Misincentives
5. Economy vs. Reliability
6. Sabotage and Terrorism
7. Generic Nuclear Shutdown
8. Fuel Supply Disruption
9. Environmental Issues: Health Effects and Acid Rain
10. Marked Increase in Demand Growth
11. Restructuring of the Industry
12. Diminished Manufacturing and Repair Capability
Key High Probability/Severity: Threats 3, 4, and 5
 Moderate Probability/Severity: Threats 1, 2, 8, 9 and 12
 Low Probability/Severity: Threats 6, 7, 10, and 11
History of the North American Electric Reliability Corporation

23

Specific concerns and issues were developed for each threat along withNERC strategies, resources, and milestones that helped guide NERC’sefforts in the coming years.
Some of the above identified reliability threats revealed tension between
reliability and the introduction of new players and new uses of the BPS.
There were concerns that the system was not built for such uses, that new
non-utility players would not play by the reliability rules, and thatcompetitive cost pressures might result in some decline in reliability.
Juxtaposed with these reliability concerns were concerns that reliability
requirements could have anti-competitive impacts. Over time it became
clear that the introduction of new players and open access totransmission grids did not cause a marked decline in reliability, and NERC
saw the need to give these new players a “seat at the table.”

National Electric Security Committee
While sabotage and terrorism were judged to be lower
probability/severity threats, NERC did pay attention to the threat,evidenced by the formation of the National Electric Security Committee,
which was chaired by John P. Williamson, immediate past chair of the
NERC Board. In October 1988, the Board approved the Committee’s final
report and presented it to the Engineering and Operating Committees forreview at their February 1989 meetings. Twelve recommendations were
presented:

24



FBI Letter to Utilities



Crime Scene Awareness Program

Procedures for DOE Critical Information ProcessingData Specifications for Spare Extra-High Voltage (EHV)
Transformer DatabaseEstablish and Maintain Database

Determine Need for Stockpiling Transformers

Generic Equipment Sharing Agreement



Distribute Agreement to RegionsWhite Paper on Design Modifications to Mitigate Impacts of
Sabotage
History of the North American Electric Reliability Corporation



Utility Considerations of Alternate Means of System Control



Review Changes to NERC Operating Guides

Review Other Proposed Changes to Operating Guides

These efforts dealt primarily with preventing and responding to acts ofphysical sabotage and terrorism. At this point, cyber security was notrecognized as a significant threat that needed NERC’s immediate
attention, but that changed in later years.

History of the North American Electric Reliability Corporation

25

26

History of the North American Electric Reliability Corporation

Stage Two
Often called the “advent of competition,” Stage Two wascharacterized by the introduction of new non-utility
generators and marketers without an obligation to serve,
open access to transmission service, and retailderegulation, coupled with fears that reliability rules
could be used for anti-competitive purposes. This led
NERC to ask itself “How can reliability of the bulk powersystem be assured in this new, open-access andincreasingly competitive electricity environment?” Theanswer came into focus in early 1999 and led NERC into
its next stage of development.

History of the North American Electric Reliability Corporation

27

28

History of the North American Electric Reliability Corporation

Introduction of Competitive Electricity
Markets
In 1991, the DOE issued the National Energy Strategy, which
recommended an amendment of the Public Utility Holding Company Act(PUHCA) “to allow businesses to build, own, and operate power plants forwholesale electricity in more than one geographic area in order to help
develop electricity supplies and stimulate competitive market efficiencies
that were not otherwise available under the traditional single supplierapproach.”
When this legislation became law as part of the U.S. Energy Policy Act of
1992, it revealed the significant underlying tension between traditional
utilities and new non-utility players as it created an obligation to provide
transmission service to third parties under the Federal Power Act for the
first time in history. These changes led to the most significant institutional
challenges NERC would face to this point in its history.

Significant Activities Related to the Energy Policy Act
of 1992
Following are some of the more significant activities undertaken by NERC
prior to and following the passage of this law.
1991: NERC President Michehl R. Gent wrote to Congressman Markey in
July regarding the Electric Power Fair Access Act of 1991, expressing
concern that Congress seemed to be seeking to assign responsibility forreliability to FERC. Mr. Gent also wrote to staff of the House CommerceCommittee regarding the proposed bill—Electric Policy Act of 1991—
which purported to make FERC the “arbiter of reliability.”
1992: In January 1992, the NERC Board approved a two-part policy
statement on transmission legislation:


NERC is neither for nor against transmission legislation.



If legislation is considered, the responsibility for reliability mustremain with NERC and the Regional Reliability Councils.

In April 1992, the NERC Board approved advocacy of a proposed
amendment to the energy legislation that would require FERC toacknowledge and follow NERC and the regional councils’ reliability
History of the North American Electric Reliability Corporation29

policies and standards in making determinations on reliability matters.
Mr. Gent wrote to all members of the House and Senate Energy
Committees proposing a “NERC Amendment” to energy legislation thatwould keep the responsibility for reliability with NERC and the regional
councils. In June 1992, the NERC Chair asked Board members to write tomembers of Congress urging use of the NERC Amendment in the final
version of the Energy Policy Act.
The NERC Amendment to the Energy Policy Act of 1992 barred the federal
government from ordering transmission service if the order “would
unreasonably impair the continued reliability of electric systems affectedby the order.” The NERC Amendment ultimately was not added to the billas the transmission title to which it would have been added was dropped
due to lack of consensus among industry sectors.
In anticipation of the changes that would result from the act, the NERC
Board approved six “Agreements in Principle,” regarding the future roleof NERC and the regional councils. The NERC Board also opened its
executive session policy discussions to non-utility generator andtransmission dependent utility representatives. The agreements were as
follows:

30

The NERC Board of Trustees agrees that the reliability criteria andguides of the Regional Reliability Councils and NERC arefundamental to maintaining reliable electric supply systems, andconformance to them is mandatory. (Approved 14 to 6).

The NERC Board of Trustees agrees that self-regulation throughpeer review by the Regional Reliability Councils and NERC is themost effective way to ensure conformance to reliability criteria
and guides. (Approved 20 to 0).

The NERC Board of Trustees agrees that electric utilities must
continue to have the ultimate responsibility for reliability of BESs
and will promote greater understanding and acceptance of thisby federal, state, and provincial legislators and regulators.
(Approved 20 to 0).

The NERC Board of Trustees agrees that technical disputes should
be resolved through industry-based dispute resolution

History of the North American Electric Reliability Corporation

mechanisms before turning to federal, state, or provincial
regulatory agencies or the courts. (Approved 20 to 0).
The NERC Board of Trustees agrees that non-utility generatorsand transmission-dependent utilities should be allowed someform of participation in Regional Reliability Councils and NERC
activities. (Approved 11 to 9).

The NERC Board of Trustees agrees to continue to actively
encourage interregional coordination of system operations andplanning. (Approved 20 to 0).

1993: In 1992, the NERC Board appointed the Future Role of NERC Task
Force (FUTROL-I) to address provisions of the Energy Policy Act of 1992
and develop an action plan for the future.15 The resulting report, NERC
2000, included policies for interconnected systems operation, policies forplanning reliable BESs, membership recommendations, and policies for
dispute resolution.
At the July 1993 Board meeting, Chair Dick Brooks reviewed the historyof the future role of NERC activity, beginning with the “Agreements in
Principle” approved by the Board in July 1992. He explained that theEngineering Committee, Operating Committee, and regional managers
had been given assignments to develop various policies, procedures, andrecommendations related to the Agreements. Chair Brooks and President
Michehl R.Gent visited four of the five FERC Commissioners to advise
them on the future role of NERC initiatives so they would understandwhere NERC was going and recognize NERC as the ultimate authority onelectric reliability.
NERC 2000 was issued in September 1993. NERC continued to apply the“Agreements in Principle” expressed in NERC 2000 until early 1996 when
FERC’s efforts to open up access to the grid raised concerns about NERC’s
ability to promote and ensure reliability of the BPS.
1994: NERC formed a Blue Ribbon Task Force to investigate and makerecommendations regarding the extreme cold wave in January 1994.

15

This was the initial FUTROL-I.

History of the North American Electric Reliability Corporation

31Legislative and regulatory initiatives directed at the industry encouraged
competition through participation in the electricity marketplace by many
new entities. The regional councils opened their memberships to thesenew participants, including independent power producers, power
marketers, and electricity brokers. The NERC Board added two voting
trustee positions for independent power producers.
NERC developed a set of principles for scheduling electricity interchangetransactions—“Agreements in Principle on Scheduled Interchange”—
that applied equally to electric utilities, power marketers, and otherpurchasing–selling entities.
A series of incidents in which multiple transactions resulted in overloadedtransmission lines, where no one entity had the “big picture,” led to calls
for looking at the need for security16 centers.
1995: FERC issued its notice of proposed rulemaking (NOPR) on open
access, seeking comments on proposals to encourage a more fullycompetitive wholesale electric power market. NERC took the lead in
addressing the planning and operating reliability aspects of the NOPR.
The NERC Board approved four Strategic Initiatives for NERC, to be inplace by mid-1996 when open access tariffs were expected to take effect:

Develop uniform definitions for determining Available(Transmission) Transfer Capability (ATC) and related terms thatsatisfy both FERC and electric industry needs.



Develop a recommendation and timetable to implement formal,
coordinated regional and interregional security processes.

Develop more clearly defined, uniform, and specific operating
standards as soon as possible.

Complete the Interconnected Operations Services reference
document, which satisfied both FERC and electric industry needs.

16 “Security” in this context refers to operating reliability (i.e., the system being operated

within limits and able to withstand the loss of any element). After the events of
September 11, 2001, the term “operating reliability” was adopted for this definition, andthe term “security” was reserved for dealing with acts of terrorism and sabotage.
32

History of the North American Electric Reliability Corporation

NERC facilitated an industry-wide working group that was developing
recommendations to FERC on the minimum requirements (the “What”)
for posting information about ATC on same-time electronic information
networks (EINs). The Electric Power Research Institute (EPRI) facilitated asimilar effort on the “How” of EINs. FERC ultimately named this network
Open Access Same-Time Information System (OASIS).
1996: The NERC Board unanimously approved the following resolution:“Resolved, that the Board of Trustees requests the Engineering
Committee and Operating Committee to follow the Board’s leadin opening their respective Committee memberships to allindustry sectors, including independent power producers andpower marketers, and to do so as soon as possible.”
FERC adopted Order No. 888, the open-access rule for electric utilities.
In June 1996, NERC published the Available Transfer Capability Definitions
and Determination reference document. This document was in response
to a NERC strategic initiative to “develop uniform definitions fordetermining ATC and related terms that satisfy both FERC and electricindustry needs, and which were to be implemented throughout theindustry.”

Future Role of NERC Task Force II
In January 1996, Board Chair Dick Grossi reported that the NERC Executive
Committee had held a strategy discussion on the future role of NERC. He
noted that NERC 2000 had set out a series of principles to help guide
NERC during the rapid changes occurring in the industry. Because of thesechanges, the Executive Committee believed that it was appropriate toreassess these guiding principles. As a result, the NERC Board formed a
Board-level task force (FUTROL–II) to expeditiously reexamine the“Agreements in Principle” that were the basis for NERC 2000 and reassess
NERC’s future role, responsibilities, and organizational structure in lightof the rapidly changing electric industry environment.
At the May 1996 Board meeting, Mr. Grossi thanked the committees fortheir hard work with a special note of gratitude to the NERC staff. Mr.
Grossi remarked that it was critical that NERC review its organizational
History of the North American Electric Reliability Corporation

33

and governance structure to make sure it was adequate to deal with theincreasingly competitive electricity marketplace. He added that it was
equally important for NERC to maintain its credibility in FERC’s eyes since
FERC was looking to NERC to resolve reliability issues.
Gary Neale, acting chair of the FUTROL–II, presented the following
preliminary conclusions to the NERC Board:Total generation and transmission adequacy will be as importantin the future as it has been in the past, but the focus of
responsibility for adequacy is shifting to the marketplace.



Maintaining the supply/demand balance instantaneously andoperating the transmission system within security limits will be
the responsibility of Regional Reliability Organizations (RROs)—
these may be Regional Reliability Councils, Independent System
Operators (ISOs), Regional Transmission Operators (RTOs), power
pools, or control areas.17

NERC’s role will be to develop standards for the operation of the
BES that focus primarily on the performance at the boundaries of
RROs. This is a paradigm shift for NERC in that NERC would nolonger be specifying operating standards for entities or
equipment within the RROs.



There needs to be a mechanism to ensure that RROs declarethemselves and agree to abide by NERC rules.

Compliance with NERC rules needs to be ensured, but peerpressure will not be sufficient. The actual mechanism forcompliance will depend on how RROs evolve.



NERC standards need to reflect the interests of entities that are
accountable for following the rules as well as entities who are
affected by the “state of reliability” of the BES.

FUTROL–II agreed to develop a white paper and a set of findings andrecommendations for consideration by the Board at its September 1996
meeting. These findings and recommendations needed to expand on the

17
These organizations eventually fell under the general heading of “FERC planningareas.”

34

History of the North American Electric Reliability Corporation

original conclusions and offer specific policy recommendations in thefollowing areas:Membership, Agreements, and Participation



Reliability Criteria

Performance MeasurementCompliance

The impetus for this reexamination of NERC was the rapidly changing
structure of the electric industry coupled with increasing competition inelectricity markets. Additionally, the widespread cascading outages that
occurred in the west on July 2–3 and August 10, 1996, heightenedawareness in industry and government to the importance of reliability
and created an increased sense of urgency for this review.
At the September 1996 Board meeting, Mr. Grossi noted the agenda wasstructured to give the NERC Board more time to openly and actively
discuss critical issues, such as NERC’s future role and the heightenedawareness of reliability brought about by the July and August 1996
outages and the shutdown of five nuclear units in New England. Mr.
Grossi emphasized the importance and timeliness of the FUTROL–II white
paper, which pointed to the need for a constant reexamination of what
NERC does, how it does it, and how NERC needs to anticipate and respondto change to prevent reliability from suffering in an increasinglycompetitive electric environment.
After lengthy discussion, the Board accepted the FUTROL–II white paper,
which presented the task force’s findings and recommendations on
NERC’s future role, responsibilities, and organizational structure. At theheart of this effort was the question of how NERC would ensurecompliance with its operating and planning policies, standards, principles,and guides. The Board then directed the NERC Engineering and Operating
Committees, under the auspices of the FUTROL–II, to develop a detailed
action plan consistent with the FUTROL–II white paper for presentation
to the Board at its January 1997 meeting. The committees were directed
not to be restrained by current concepts, structures, or thinking, but todetermine the best practice to ensure “reliability excellence.”

History of the North American Electric Reliability Corporation

35

Nye Speech on the Future Role of NERC

Erle Nye, in his role as vice chair of the NERC Board, gave his own viewson the future of NERC in a speech at the September 1996 NERC Board
meeting. The following are some excerpts from that speech:“The industry is changing dramatically and rapidly, and NERC will
either change dramatically or become obsolete. The NERC Board,in forming the FUTROL–II to contemplate NERC’s future role,
responsibilities, and organizational structure, has tried torecognize and respond to this change—but things are moving
faster than anyone realized. The events of recent weeks andmonths have given additional impetus for this reexamination.
This task force was a serious, conscientious group that knew that
this was a serious undertaking. After presenting their preliminary
conclusions in May, the Board charged them with expanding on
what they had done and to come back to the Board at thismeeting with their best, untempered policy recommendations.
The task force recommendations themselves are still somewhat‘nominal.’ However, the essence of the recommendations, andthe bottom line for NERC, as succinctly stated in the task force
report, is to establish standards, measure performance, anddemand compliance.
The implications of the task force recommendations are farreaching. It is a significant paradigm shift in what we do and how
we do it. It will likely mean moving away from the confederationof reliability groups that worked toward common reliability goals
in a collegial, mutual interest, self-help atmosphere to a newmodel.
Our past success as measured by the reliability of theinterconnected systems, was pretty good. However, the Regions
and roles of the Regions are changing and whether they survive
is problematic. There is a growing requirement for universal
participation to ensure reliability. We need more detailed,uniform standards and more uniform compliance. We need toraise the level of involvement throughout industry to decision
makers. We need more participation by those that can makethings happen.
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History of the North American Electric Reliability Corporation

Everyone must apply their best perspective of the big picture andraise themselves above traditional differences. This is a defining
period for NERC as we know it. It is in the interest of allparticipants to ensure reliability while fully and promptly
pursuing competition.
The Board needs to make a strong, unanimous statement callingon the Engineering and Operating Committees, under the
auspices of the FUTROL–II, to develop a detailed plan for the
implementation of the FUTROL–II recommendations forpresentation to the Board at its January 1997 meeting. The
committees should approach this with completely open minds
and not be restrained by current concepts or thinking. We needto develop a new model for NERC that anticipates what the next
century will look like and one that will allow us to ensure
reliability excellence.”
FERC Commissioner Comments on Future Role of NERC

FERC Commissioner Vicky Bailey commended NERC for operating nearly
30 years as a voluntary organization and providing for unparalleled system
reliability. Ms. Bailey commented that, as NERC is faced with newchallenges, there will be many observers watching to see how thosechallenges are met. She urged NERC to move forward quickly to define a
new framework for ensuring reliability, take advantage of the diversity of
NERC’s participants, and not be timid about taking the next step—
whatever it needs to be. FERC is very interested in reliability and wants tomake sure that it doesn’t do anything from a policy viewpoint that would
injure reliability. FERC is looking to NERC to highlight any such issues.
Chair Grossi’s “Call to Action” Letter

Following the September 1996 Board meeting, Mr. Grossi wrote to morethan 3,000 industry chief executive officers, calling on them to “actively
and personally support a fundamental reshaping of NERC to keep pacewith the changes taking place in our industry.” His letter went on to say,“This reshaping is needed now if NERC is to continue to be recognized as
the industry-based authority on reliability of interconnected BESs in
North America.”

History of the North American Electric Reliability Corporation

37

NERC Reliability Compliance Team
Just prior to the September 1996 Board meeting, the NERC Board chairestablished a special team composed of six senior people18 in the electricindustry to address reliability compliance and make recommendations forreliability management with options and pros and cons of each and to
submit its report to the FUTROL–II by October 1996.
Based on insights gained from its discussions and its review of several
other industries,19 the NERC Reliability Compliance Team identified anumber of alternative approaches to the development and enforcementof NERC required protocols, including a hybrid approach recommended
for the “new” NERC that had the following four principles as its
foundation:

Because of the technically complicated interactions withininterconnected electric grids, mandatory reliability protocols are
best developed and maintained by NERC.



Because universal participation is critical to ensuring reliability,
100 percent compliance should be achieved through regulatory
pressure by way of an “obligation to comply” with all NERC andregional reliability protocols in commercial contracts.

Because RROs will normally have access to real-time information
on operating compliance with reliability protocols, inspection andenforcement should be left to the RROs with NERC providing
oversight and audit.



RROs must refuse service if a participant does not abide byapproved protocols with an escalating scale of stipulated
contractual penalties to address violations.

18 Paul Barber (Citizens-Lehman Power), Vikram Budhraja (Southern California Edison),

Jim Byrd (Texas Utilities), David Goulding (Ontario Hydro), Bill Newman (Southern
Company Services), and Bill Phillips (Entergy Services)
19 Nuclear, health care, telecommunications, and securities and exchange were among
the other models reviewed.

38

History of the North American Electric Reliability Corporation

The Reliability Compliance Team’s principal recommendation was thefollowing:
NERC should perform a complete review and evaluation of its
management structure, administrative processes, capabilities,
membership, and committee structure in light of the emerging
competitive and disaggregated industry structure. It shouldorganize to represent reliability interests while recognizing
commercial needs and be responsive to the reliability needs ofthe industry. Due to the difficulty associated with reinventing
itself, the NERC Board should consider seeking outside support
for this effort.
Among the most significant of the team’s recommended next steps were
the following:

NERC should develop proposed means (including, if necessary,
the pursuit of legislation) by which to ensure that all segments of
the industry are subject to NERC’s reliability requirements.



The NERC Engineering and Operating Committees should
perform a comprehensive review of existing policies, standards,
and criteria to ensure they are specific, measurable, adequate,
and appropriate for the new industry environment and define
how compliance monitoring will be accomplished.

NERC should develop certification policies, processes, practices,
and/or programs for use by the industry, including certification ofpeople, facilities and tools, and training programs.

Form a Security Coordinators Committee composed ofmanagement personnel from each of the security coordination
centers to develop a minimum set of expectations regarding
authority, span of control, responsibilities, capabilities, tools, etc.

Following presentation of the Reliability Compliance Team report at its
January 1997 meeting, the NERC Board approved the following actions:

Accept the Options to Ensure Compliance report and commit tomove forward in the directions suggested by the “Next Steps”
section of the report.

History of the North American Electric Reliability Corporation39



Direct the FUTROL–II as an arm of the NERC Board to provide
continuing oversight and implementation direction to theEngineering Committee, Operating Committee, and staff, asappropriate, and regularly report to the Board.

Direct the FUTROL–II to report to the Board any projects andinitiatives required to satisfy the “Next Steps” that havesignificant policy implications and/or that require major new
funding.

Other Related Activities in 1996–1997



Two transmission-dependent utility (TDU) representatives joined
the NERC Board.

The Florida peninsula left SERC and became a separate NERC
Region (i.e., Florida Reliability Coordinating Council (FRCC)),
resulting in NERC having ten members.



The two major blackouts that occurred in the WesternInterconnection (July 2–3 and August 10) prompted the Western
Systems Coordinating Council (now WECC) to pursue a contractbased reliability management system to encourage and enforce
compliance with reliability rules.



The NERC Board approved recommendations to develop regional
and interregional security centers. Regional councils were in theprocess of developing security coordination centers inconjunction with NERC’s interregional security network.



NERC added large20 and small end-use customer representatives
to its Board.

20 The large end-use customer segment was represented by John A. Anderson, presidentof the Electricity Consumers Resource Council (ELCON). Mr. Anderson remained
extremely active throughout NERC’s transition to a self-regulatory organization,
including the development and promotion of consensus reliability legislative language.
He eventually chaired the NERC Member Representatives Committee. The small end-use
customer segment was represented by the National Association of State Utility
Consumer Advocates.
40

History of the North American Electric Reliability Corporation

NERC’s First Official Planning Standards
In September 1997, the NERC Board approved NERC’s first official
Planning Standards, replacing its planning guides, and a due process fordeveloping operating standards. Virginia Sulzberger of NERC and Sam
Daniel of Southern Company worked tirelessly with industry
representatives on the development and eventual approval of the
Planning Standards by the NERC Board.
NERC also developed two coordinated programs—the System Operator
Certification Program and the System Operator Training Accreditation
Program—to establish standards for the training and qualifications of
persons who operate the BESs of North America.
NERC, the Commercial Practices Working Group (an industry groupaddressing electricity marketplace issues), and NERC regional reliability
coordinators worked together to build a more viable and reliable
marketplace.
The Operating Committee put into place a transaction information systemthat provided a method for tagging all interchange transactions. The tag
provided information to identify and track the purchase and sale ofelectricity so that the reliability of the BPS could be maintained.

Outages Prompt Creation of WSCC Reliability
Management System
Industry restructuring, competition, and the 1996 summer outages in the
WSCC Region combined to focus attention on the need to take additional
steps to ensure the reliability of the Western Interconnection. Concerns
regarding reliability were also heightened by pressures faced by theelectric industry in the transition from the existing vertically integrated
system to a competitive model with customer choice.
In March 1997, the WSCC Board of Trustees established a policy groupand three task forces to develop an implementation plan for reliability
management. On October 27, 1997, the WSCC Board adopted aresolution recommending that council members approve the proposed
concept for the Reliability Management System (RMS) data reporting. The
RMS implementation plan was developed through an open and inclusive
process that involved independent power producers, marketers, andregulatory bodies along with all electric utility ownership segments.

History of the North American Electric Reliability Corporation

41

On February 1, 1998, a phased approach that included meetingcompliance standards, data collection, and letter notification fornoncompliance for the below standards was implemented on a trial basis:Control Performance (CPS1 and CPS2)

Disturbance Control (DCS)Operating Reserve (OR)

Operating Transfer Capability (OTC)Power System Stabilizer (PSS) Operation



Automatic Voltage Regulator (AVR) Operation

A second phase of the program began its evaluation in September 1998
and included the following additional criteria:
Operating Limits Available to System Operators

Certification of Protective Relay Applications and Settings

Certification of Remedial Action SchemesProtective Relay and Remedial Action Scheme Misoperation

Assessment of sanctions for noncompliance was based on four levels of
noncompliance and the number of occurrences within a specified period.
Compliance actions ranged from a letter to the participant’s chief
executive officer with copy to NERC, up to and including the greater of$10,000 or $10 per MW of Sanction Measure.

Changes to NERC Bylaws
In January 1997, the NERC Board approved changes to the Membership
Obligations section of the NERC Bylaws as follows:“A Member or Affiliate Member Regional Council, on behalf of its
members, shall agree, in writing, to accept the responsibility topromote, support, and comply with the purposes and policies of
the Corporation as set forth in its Certificate of Incorporation,
Bylaws, and Planning and Operating Policies that from time totime may be amended, adopted, or approved. In addition, it shallprovide for its share of the financial support of the Corporation
in a timely manner.”
42

History of the North American Electric Reliability Corporation

NERC Forms the Electric Reliability PanelAs noted previously, the primary recommendation of the NERC Reliability
Compliance Team led to the creation of the Electric Reliability Panel, also
known as the Blue Ribbon Panel, in August 1997. The panel was formed
as an independent body to recommend the best ways to set, oversee, andimplement policies and standards that ensured the continued reliabilityof North America’s interconnected BESs in a competitive and restructured
industry. NERC imposed no limits on the panel’s advice about what kindof reliability organization would be needed for the future.
The issuance of the panel’s report in December 1997 provided the specificrecommendations that formed the basis of the ERO and launched acomplete reorganization of NERC, the proposal and ultimate passage ofreliability legislation, and finally the emergence of “The New NERC.”

Panel Members
The panel was composed of a number of highly knowledgeable and wellrespected individuals from both inside and outside the electric utility
industry and was facilitated by representatives of the Florida Conflict
Resolution Consortium, based at Florida State University, listed here:21
Richard Drouin: former chair and chief executive officer ofHydro-Quebec (Panel Co-chair)Charles Stalon: an economist and former member of FERC
(Panel Co-chair)

Dr. Richard Balzhiser: president emeritus of EPRI

William H. Clagett: former administrator of the Western Area
Power Administration and former chair of NERC

George L. Edwards: president of the Alliance for
Telecommunications Industry Solutions

Dr. Victor Gilinsky: former commissioner of the U.S. Nuclear
Regulatory Commission

21 NERC is indebted to J. Ken Wiley, former general manager of the Florida Reliability

Coordinating Council for recommending NERC consider using the Consortium for thiseffort.
History of the North American Electric Reliability Corporation

43

Richard Hemstad: member of the Washington Utilities andTransportation CommissionLeonard S. Hyman: senior industry advisor to Smith Barney’s
Global Energy and Power Group

Hazel O’Leary: former secretary of the DOE

Alex Radin: former executive director of APPADr. Vernon Smith: regents’ professor of Economics and research
director of the Economic Science Laboratory, University of
ArizonaMary L. Schapiro: president of NASD Regulation, Inc. (Panel
Advisor)Panel’s Report and Recommendations
The panel’s report, Reliable Power: Renewing the North American Electric
Reliability Oversight System, called on NERC to restructure itself into a
new organization, called the North American Electric Reliability
Organization (NAERO) that could function as an audited self-regulatingorganization with the authority to set, measure, and enforce reliability
planning and operating standards. The panel’s recommendations werebased on a belief that the introduction of competition within the electricindustry and open access to transmission systems required the creationof a new organization that had the technical competence, unquestioned
impartiality, authority, and the respect of participants necessary to
enforce Reliability Standards on the BES. The panel also believed that aself-regulating organization for setting and enforcing Reliability Standards
would be more flexible, more effective in marshalling technicalcompetence, and more open to new technology than government
agencies, but should have general oversight and approval fromappropriate agencies of governments with relevant oversight authorities.
To develop its recommendations, the panel held meetings in Toronto, San
Francisco, and Austin, met by means of conference calls, examined a wide
range of materials, and conducted a survey of many leaders in the electric
supply market. All meetings were open to the public and attended byindustry participants, observers, and the media. The panel actively
solicited the viewpoints of those attending the meetings andincorporated many of their suggestions into the deliberations.
44

History of the North American Electric Reliability Corporation

Panel Recommendations Areas

Mission and Functions



GovernanceRegional Arrangements

Participation in NAERO



FinancesCompliance and Enforcement

Implementation

Government Interface

Public Participation

Florida Power Corporation

Richard Drouin, co-chair of the panel and first chair of the independent
NERC Board, remarked recently about the work of the panel and theconcept in particular of “audited self-regulation” it recommended. As aformer chief executive officer, Mr. Drouin was impressed the work doneby NERC. The opening of electricity markets had resulted in a completechange of paradigms, and he was struck at the first panel meeting thatindustry had already made up its mind how it had to change and that
NERC taking initiative would preempt government from taking its own
unilateral action. He noted it was important to have legislation to give theorganizational credibility to what NERC had to do. It was a bold move, but
one that was necessary. He added that the relationship with the Member
Representatives Committee (MRC) had worked well with the NERC Board
attending MRC meetings and listening to their discussions of issues before
taking action as it was critical that the Board not reach their decisions inprivate.
In parallel with this panel, DOE formed the Electric System Reliability Task
Force (chaired by former Congressman Philip Sharp) to conduct its own
investigation. The DOE task force reached similar conclusions to the panelin the same timeframe. In particular, the task force noted that in an
increasingly competitive marketplace, grid reliability rules had to be
History of the North American Electric Reliability Corporation45

made mandatory and enforceable. Further, they stated that an
independent, self-regulatory ERO should be established to develop andenforce Reliability Standards throughout North America, and that federal
legislation was necessary in the to accomplish this important task.

NERC Board Action on Panel Report
At its January 1998 meeting, the NERC Board took the following actions
related to the panel’s report:

Approved creating the Future NERC Review Team, made up of
FUTROL–II and several panel members or others, to develop
policy recommendations and an implementation plan outline forapproval at the May 1998 Board meetingDirected the review team to create a Government Interface
Issues Task Group to research whether NERC and the regional
councils needed additional authority to carry out the mission andfunctions, including the need for any additional legislation,
regulation, or international agreements, described in the panel’sreport

Approved the action plan and budget recommended by the Task
Force through May 1998



Agreed that NERC should move forward toward the concept of an
independent board



Directed the review team to work toward January 1999 as thetarget date for electing the new NERC Board for the restructured
NERC and May 1999 as the date the new Board members would
take office

At its May 1998 meeting, the Board approved the following actions on thereports and recommendations of the four Future Role of NERC Task
Groups:

Accepted the status reports and associated preliminary
recommendations of the review team and task groups22

22 The four Future NERC Task Groups were the following: Governance, Standing

Committees, Funding, and Government Interface Issues (i.e., Legislation).
46

History of the North American Electric Reliability Corporation

Accepted the goal of having an augmented Board seated no later
than May 1999



Recognized that the recommendations might require further
elaboration and clarification of outstanding issues by the task
groups and that interim amendments to the bylaws were also
requiredInstructed the task groups to provide opportunity for all
stakeholders to comment on the task group recommendations
and to recommend to the Board any necessary further actions ormodifications no later than May 29, 1998, to be incorporated in
the task group reports presented at the next Board meetingIntended to take further Board action in July 1998 to incorporate
any further additions or modifications recommended by the task
groups

Instructed NERC staff to develop interim modifications of thebylaws necessary to permit the transition to an independent
Board with the expectation that the final modifications of thebylaws would be accomplished in a public process withparticipation of the independent Board members

At its July 1998 special meeting, the NERC Board approved electing nine
independent members to the NERC Board in January 1999. These
members joined the existing NERC Board of 37 stakeholder members,
resulting in a hybrid Board that would govern NERC until the following:

The United States and Canadian governments provided forappropriate grants of authority to a self-regulating reliability
organization (SRRO) to set standards, enforce compliance, andcollect funds (with a similar grant of authority from thegovernment of Mexico to follow).

NAERO applied for and was approved as the only SRRO by theappropriate regulatory authorities in the United States andCanada.



The funding of NAERO was decoupled from the Regional
Reliability Councils.

History of the North American Electric Reliability Corporation47

After these conditions were satisfied, all but the independent membersof the Board would step down and NAERO would be governed by an allindependent Board. While not explicitly stated in this resolution, thestakeholder representatives that stepped down from the Board would
comprise a new Stakeholders Committee, chaired initially by Mike Greeneof TXU with Howard Hawks of Tenaska as vice chair.23 The Stakeholders
Committee later became the MRC, following passage of reliability
legislation and approval by FERC of NERC as the ERO.

23 Mr. Greene served a second term as Stakeholders Committee chair when Howard

Hawks declined the chair position. Mr. Roy Thilly of Wisconsin Public Power, Inc.
assumed the role of vice chair.
48

History of the North American Electric Reliability Corporation

Critical Steps in the Transition from NERC to
NAERO
The July 9–10, 1998 special meeting of the Board was truly a seminal
event in NERC’s history that put in motion the many steps required forthe successful transition of NERC to NAERO.
At this meeting, the NERC Board took action on a series ofrecommendations prepared by the four Task Groups with guidance fromthe future NERC Review Team. Each issue was presented in an “Issue
Summary Format” in which the issue was stated in the form of a question,a statement of the action recommended, a brief statement of the relevant
background information included as well as the pros and cons for each
option that stated the arguments for and against that option.
Issues Presented
Mission and Purpose of NAERO



Composition of the NAERO Board

Definition of “Independence”

Augmentation Nominating CommitteeRegional Reliability Implementation Agreements

Membership in NAERO



Membership and Voting of NAERO Standing Committees

Interim Market Interface CommitteeInterim Funding Approach for NERC



Draft Standalone Reliability Legislation

 1999 Budget
Interimtoformation
NERC Bylaws
NERC alsoChanges
approvedof an interim Market Interface Committee(iMIC) to review NERC reliability policies and standards for impacts oncommercial markets.

History of the North American Electric Reliability Corporation

49

NERC Efforts Continue in 1999
In addition to continued efforts to secure enactment of reliability
legislation, NERC made progress on several other fronts.
NERC agreed, at the request of the U.S. Deputy Secretary of Energy, tolead the electric industry’s efforts to assess and report on industry
readiness to deal with Year 2000 issues.
Secretary of Energy Bill Richardson enlisted NERC’s assistance in a
program to protect critical infrastructure in response to Presidential
Decision Directive 63, which eventually led to NERC taking the lead insponsoring the Electricity Sector Information Sharing and Analysis Center(ES-ISAC).
NERC also began working with the Federal–Provincial–Territorial Assistant
Deputy Ministers Working Group in Canada, which was set up to examine
how the Canadian jurisdictions would relate to the self-regulatory
reliability organization to be established in the United States.

NERC Elects Independent Board Members
At its meeting on January 4, 1999, the NERC Board elected nine new
independent members to its Board of Trustees, adding these members to
the existing Board of 37 stakeholder members with the plan that theindependent trustees would succeed the industry stakeholder Board after
reliability legislation was enacted in the United States. This action
represented a bold step in the continuing transformation of NERC into anindependently governed self-regulating organization that would set andenforce compliance with Reliability Standards throughout North America.

50

History of the North American Electric Reliability Corporation

NERC Board Chair Erle Nye stated the following:“The addition of these outstanding individuals to the NERC Board
signals our strong and continuing commitment to make thechanges necessary to prepare NERC for its new role in a morecompetitive electric industry.
The electric industry in North America is changing dramaticallyand rapidly, and NERC knows that it must either change
dramatically or become obsolete.”
The original nine independent Board members were the following:Richard Drouin: part-time vice chair of Morgan Stanley, Canada,
partner in McCarthy & Tetrault, and former chief executive officer
of Hydro Quebec.

John Q. Anderson: former executive vice president for CSX
Transportation, senior vice president at Burlington Northern
Sante Fe Railroad, and former partner at McKinsey & Company,
Inc.



Thomas W. Berry: former general partner at Goldman, Sachs &Co., involved in investment banking for telecommunications andpower utilities.

Elaine L. Chao: distinguished fellow at The Heritage Foundation,
former president and chief executive officer of United Way of
America, former secretary of the Department of Labor, andcurrent secretary of the Department of Transportation.



Michael Enthoven: president of M. Enthoven & Sons LLC andformer managing director at J. P. Morgan & Company for
operations, information technology, and trading and risk
management functions.

James M. Goodrich: president of Goodrich Enterprises, Inc., andformer executive vice president and founder of Energy
Management Associates, which provided operations andfinancial planning software to electric and natural gas utilities.

History of the North American Electric Reliability Corporation

51

Charles J. Henry: president and chief operating officer of the
Chicago Board Options Exchange and former president and chief
executive officer of the Pacific Stock Exchange.

Sharon Nelson: former chair of the Washington Utilities andTransportation Commission, legislative counsel to Consumers
Union of the United States, Inc., past president of NARUC, andpast president of Western Conference of Public Service
Commissioners.

William H. White: chief executive of the Wedge Group, former
chair and founder of Frontera Resources, and former deputy
secretary of energy.

The Board also appointed a special steering committee to develop an
action plan to implement the next steps in the process of enacting the“NERC Consensus Legislative Language on Reliability.”

Other Significant Actions in 1999
The Board disbanded the old standing committees and createdthree new standing committees whose members represented all
sectors of the industry.



NERC initiated standards and compliance procedures andlaunched a pilot compliance program to test the effectiveness of
NERC and regional compliance review procedures andcompliance with 22 NERC Reliability Standards and theirassociated measurements.



NERC initiated a second-generation electronic transaction
tagging system to avoid problems inherent in email systems andprotocols.



NERC certified almost 2,400 system operators under its System
Operator Certification Program, which tested their understandingof NERC Operating Policies.24

NERC initiated a new approach to project management by which
NERC staff would provide technical support and project

24 By 2001, all system operators on duty had to be certified by NERC.

52

History of the North American Electric Reliability Corporation

management to implement the decisions and directives of therespective standing committees.


NERC released its Study on NOx Rule, which assessed thepotential impact of certain Clean Air Act nitrous oxide emission
requirements on BPS reliability.



The NERC Board approved the development of an interchange
distribution calculator to predetermine the effects of interchangetransactions on all transmission paths in the EasternInterconnection and its funding.

History of the North American Electric Reliability Corporation

53

54

History of the North American Electric Reliability Corporation

NERC to NAERO: Continuing Transformation
Mr. Gary Neale, NERC’s outgoing Board chair, stated the following in the2000 NERC Annual Report:“The year 2000 marked a clear dividing line between two
millennia. A clear dividing line cannot be drawn, however,between the traditional regulated electric industry of the pastand the emerging deregulated electric industry of the future.
Deregulation is very much a ‘work in progress,’ with the progress
being both uneven and, in some instances, more difficult thananyone could have predicted.
Given the accelerating pace and degree of change in the electricindustry, time is of the essence for reinventing an electricreliability oversight system for North America. The current system
of voluntary peer supervision of reliability is one of the great
success stories in the history of self-regulation. But we as anindustry must continue to change and adapt. The status quo is
not an option. The growing digital demand for reliability requires
innovative solutions that are fully compatible with the changing
electricity business environment.
As outgoing chair, I am confident that NERC, led by its new
independent Board, is ready, willing, and able to accept and meetthese challenges in the new century.”

Legislation Stalls: Contingency Plan Considered
The most critical and essential step in this process involved reachingconsensus on stand-alone reliability legislation and having that language
enacted by the U.S. Congress. Over the six months following the July 1998
meeting, the Government Interface Issues Task Group worked diligently
on consensus legislative language. On February 1, 1999, the NERC Board25
gave its approval. What remained was having that language introduced inCongress and enacted either as a stand-alone piece of legislation or as
part of a broader energy bill.

25

At this time, the NERC Board comprised 37 stakeholder members plus the 9
new independent directors.
History of the North American Electric Reliability Corporation

55

The consensus reliability language was first introduced in 1999 when it
was included in the administration’s larger energy bill (H.R. 1868) that did
not pass. A stand-alone reliability bill (S. 2071) was introduced in the U.S.
Senate in 2000 by Senator Slade Gorton, whose lead staffer, coincidently,
was Philip Moeller, who later became a FERC Commissioner. The bill failed
to be considered in the U.S. House of Representatives and died on thedesk of the Speaker of the House. More work was done on the languagewith many visits to House and Senate committee members along withtestimony before key subcommittees and committees. It was again
submitted in the House in 2001, but it failed to be considered in the
Senate.

Reliability Legislation: Status and Plan B
With the House’s apparent lack of support for stand-alone reliability
legislation in year 2000, NERC Board Chair Gary Neale proposed theformation of three new Board-level task groups—Governance, Funding,and Compliance Enforcement—to develop specific recommendations formoving forward with the transition of NERC to NAERO in the absence oflegislation. The charges to each task group that were approved by the
Board were the following:Governance: To recommend the details of how NERC’s
governance could be turned over to the nine NERC independent
trustees with a stakeholder committee available to provide
advice and recommendations

Funding: To consider a new funding model for NERC that would
incorporate the concept of user feesCompliance Enforcement: To recommend a contract-basedmodel in which regional councils enforce compliance withselected NERC and regional standards, including the impositionof monetary penalties and other sanctions. NERC would have
responsibility for oversight, coordination, and assessment ofeffectiveness of the regional programs26

26 This model was patterned after the Reliability Management System implemented by

WSCC following several significant outages that occurred in 1996 in the WesternInterconnection.
56

History of the North American Electric Reliability Corporation

Other Year 2000 Activities
NERC agreed to the U.S. Secretary of Energy’s request to serve as theelectric utility industry’s primary point of contact with the federal
government for issues relating to national security and criticalinfrastructure protection. As part of this effort, NERC became a founding
member of the Partnership for Critical Infrastructure Security (PCIS),
which coordinated cross-sector initiatives and complemented public andprivate efforts to promote and ensure reliable critical infrastructureservices.
NERC significantly increased its outreach to government officials in boththe United States and Canada, reflecting the critical role governments
play in the restructuring of the electric utility industry. As part of thisoutreach, NERC and FERC took major step toward improving coordinationand communication between the two organizations with the execution ofa “Consultation and Communications Protocols,” which called forincreased FERC participation at NERC Board and committee meetings andperiodic discussions between the FERC chair and NERC executives.
NERC sponsored a long-term planning initiative to address market
reliability interface issues. The issues identified were molded into actionplans and approved by the NERC Board.
The Control Area Criteria Task Force defined basic operating reliability
functions that could be rolled up into other entities. The concepts
discussed in its report served as the basis for new reliability policies andstandards.27
The Standards Task Force was established and charged by the NERC Board
to recommend changes to the NERC Reliability Standards and the processused to develop them. NERC used the redesigned standards development
process to prepare new Organization Standards.
The NERC Compliance Enforcement Program completed the second yearof a multi-year phase-in and completed audits of all Reliability
Coordinators, focusing on all aspects of Reliability Coordinatorresponsibilities, by the end of 2001.
27 See subsequent section on the NERC Reliability Functional Model.

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57

NERC Reliability Functional Model
NERC passed several resolutions to approve a functional reliability model,
ensure the independence of the Reliability Coordinators, and initiate atransition to Organization Standards.
Historically, control areas were established by vertically integrated
utilities to operate their individual power systems in a secure and reliable
manner and provide for their customers’ electricity needs. The control
area operator balanced load with generation, implemented interchangeschedules with other control areas, and ensured transmission reliability.
As utilities began to provide transmission service to other entities, thecontrol area also began to perform the function of Transmission Service
Provider through tariffs or other arrangements. NERC’s Operating Policies
reflected this traditional electric utility industry structure and ascribedvirtually every reliability function to the control area.
Beginning in the early 1990s, the functions performed by control areas
began to change with the advent of open transmission access andrestructuring of the electric utility industry to facilitate the operation ofwholesale power markets. These changes occurred because of thefollowing:Some utilities were separating their transmission from theirmerchant functions (functional unbundling), and even selling off
their generation, sometimes at the direction of state regulators.

Some states and provinces were instituting customer choice
options for selecting energy providers.



The developing power markets were requiring wide-areatransmission reliability assessment and dispatch solutions thatwere beyond the capability of many control areas to perform.

As a result, the NERC Operating Policies in place at that time that centeredon control area operations were beginning to lose their focus and become
more difficult to apply and enforce. The NERC Operating Committee
formed the Control Area Criteria Task Force (CACTF) to address thisproblem. In 1999, the task force, chaired by Mr. Jim Byrd of TXU, began
its work to address the issue of control area functions and responsibilities.

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History of the North American Electric Reliability Corporation

ERCOT had developed a model of those functions that were being
performed within the Texas Interconnection that represented a minimum
subset of the whole picture. Building from that model, the task force
began by listing all the tasks required for maintaining electric system
reliability and then organizing these tasks into basic groups called“functions.” Ultimately, the task force decided to build a “Reliability
Functional Model.”This involved breaking down the previous reliability functions more finely,such that all organizations involved in ensuring reliability—whether they
are traditional, vertically integrated control areas, Regional Transmission
Organizations (RTOs), Independent System Operators (ISOs), independenttransmission companies, etc.—could identify those functions they
performed and register with NERC as one or more of the functional
entities.
Initially the model dealt with operating functions, but in Version 2 it was
subsequently expanded to incorporate planning-related functions as well.
This framework provides guidance to NERC standards drafting teams towrite Reliability Standards in terms of the functional entities who performthese reliability functions. Then, as new organizations emerged, such as
RTOs, ISOs, and independent transmission companies, they would
register with NERC for the functions they performed as well as thestandards that they would need to comply with.

History of the North American Electric Reliability Corporation

59

2001 Arrives Without Reliability Legislation: Plan B
Developed
The year 2001 was very busy as NERC pressed forward with plans for thetransition from NERC to NAERO.
At the February 2001 Board meeting, Chair Gary Neale stated that NERC
was working in the right direction to set up a truly independent Board
that had been unanimously approved two years earlier. He also expressed
his belief that NERC had not moved too quickly on this transition, despite
the lack of reliability legislation.
Richard Drouin, co-chair of the Electric Reliability Panel, who was elected
as one of the nine new independent trustees, reported on the work of
the Governance Task Group, which he chaired. He noted that the task
group was “to recommend the details of how governance could be turned
over to the NERC Board’s independent trustees with a stakeholders
committee available to provide advice and recommendations.”
The Board approved a special meeting on March 30 to address theGovernance Task Group recommendations and vote on the changes tothe Bylaws and Certificate of Incorporation as well as for the members28
to vote on the proposed changes to the Certificate of Incorporation. As aresult of these changes, the independent Board and initial Stakeholders
Committee would have separate organizational meetings. Based on thechanges approved to the Bylaws, the new Stakeholders Committee would
have authority to elect independent trustees, vote on amendments to the
Bylaws, participate in the budgeting process, and provide advice andrecommendations to the Board on other matters.
Chair Neale also announced formation of a task force, chaired by Mike
Greene of ERCOT, to develop recommendations on the composition,
governance, and voting structure of an inclusive Stakeholders Committeeby June 2001. Regarding the voting structure, Mr. Greene emphasized
Guiding Principle #2, which stressed the importance of the Stakeholders
Committee being flexible and adaptable as experience and needschanged, and the importance of Guiding Principle #6, which indicated thecommittee would not vote on policy issues but rather seek to resolve or
28 At this time, the “members” of NERC were the Regional Reliability Councils.

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History of the North American Electric Reliability Corporation

narrow differences and define them clearly. This would ensure that the
NERC Board had the benefit of the full range of stakeholder views andwould keep the Stakeholder Committee from becoming a “shadowboard.” This principle continues to be followed today by the MRC.
Other committee actions reported were the following:

Formed a task force to examine and prepare recommendations
on the evolution of representation on NERC/NAERO standing
committees, including what “balance” means today and moving
forward.



Expressed support for the Canadian Electricity Association (CEA)
position that NERC should seek ANSI accreditation of its
standards process, but not look to ANSI to certify individual
Organization Standards.



Raised concerns on how NERC was dealing with the issues of thecompetitive advantages of being a control area andindependence of security coordinators.

Discussed concerns with the status of development of Available
Transfer Capability (ATC), Total Transfer Capability (TTC), Capacity
Benefit Margin (CBM), and Transmission Reliability Margin (TRM)
standards, especially the regional CBM standards, andcompliance with them.29



Recommended going forward with electronic transaction tagging(E-Tag 1.7) with funding taken from the NERC fund balance.

Gave its recommendations on the 2002 Budget to the Financeand Audit Committee.

Originally, the independent trustees believed the Stakeholders
Committee could discharge its responsibilities by meeting just twice ayear—one annual meeting of the stakeholders and the second in
conjunction with completion of the budget process. However, theStakeholders Committee also agreed to meet prior to each Board meetingin order to provide its views on issues that would go before the Board.

29 These terms were originally defined in the June 1996 Available Transfer Capability

Definitions and Determination framework report.

History of the North American Electric Reliability Corporation

61

In the absence of new reliability legislation, nine of the ten Regional
Reliability Councils signed agreements for regional Compliance andEnforcement Programs with NERC (the so-called “Plan B” approach).30
The agreements, patterned after the WECC Reliability Management
System, were intended to enforce compliance with NERC reliability rules
through contractual means. Although the agreements were not a
substitute for federal legislation, they would allow NERC to ensure ameasure of compliance with some of the rules.
In presenting Plan B to the Board, NERC staff was asked why a contractbased system like WSCC implemented wouldn’t suffice, obviating theneed for reliability legislation. Staff responded that the chief reason wasthat there was nothing to compel entities to sign a contract to be held
accountable to relevant Reliability Standards. One Board member asked
which entities in WSCC had not signed the WSCC Reliability Management
System (RMS) contract. Staff noted that only one major entity in WSCC
had not signed the contract.

9/11 Attack on World Trade Center
The World Trade Center and the Pentagon were attacked by terrorists on
September 11, 2001. Shortly after the attack, Mr. Richard Clarke, thennational coordinator for Security, Infrastructure Protection, and Counterterrorism, met with NERC officials to discuss ways of protecting theelectric system from acts of terrorism. After hearing NERC references to“security coordinators,” Mr. Clarke interrupted to say, “Wait a minute—I’m the security coordinator.” Shortly thereafter, NERC began to use theterm “operating reliability” in place of “security,” and “Reliability
Coordinators” in place of “security coordinators.”
In the wake of the terrorist attacks on the World Trade Center, NERC
continued to work to improve the electric industry’s physical and cybersecurity and provide a common point for coordination with the U.S.
government by forming the Critical Infrastructure Protection Advisory
Group. The advisory group developed a compendium of security
guidelines for the electric sector for protecting critical facilities against a
30 The only Regional Reliability Council that did not sign the agreement was the Mid-

Atlantic Area Council (MAAC). The two MAAC representatives to the NERC Board also
were the only “no” votes on the reliability legislative language that the Board voted infavor of in February 1999.
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History of the North American Electric Reliability Corporation

spectrum of physical and cyber threats and established the Electricity
Sector Information Sharing and Analysis Center (ES-ISAC). It alsoestablished a Critical Spare Equipment Database, replacing a smaller,
limited database and designed a standardized public key infrastructure(PKI) implementation plan for the industry with support from the DOE.

History of the North American Electric Reliability Corporation

63

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History of the North American Electric Reliability Corporation

Reorganization despite No Legislation
In 2001 and 2002, NERC and its stakeholders continued efforts to secure
passage of reliability legislation in the United States. On March 31, 2001,
despite the failure of Congress to pass legislation that contained the NERC
Consensus Reliability Language, NERC reorganized its governance. The
nine independent trustees and the management trustee formed the new
NERC Board of Trustees in place of the 46-member hybrid Board. The
former stakeholder members of the stakeholder Board became the
Stakeholders Committee. Mike Greene of Oncor served as its first chair,and Howard Hawks of Tenaska served as its first vice chair.31
Of particular note is that February 2002 marked the first time the NERC
chair wrote to the Stakeholders Committee specifically inviting policy
input from the members as well as all sectors of the industry on issues
scheduled to come before the Board. The committee did not vote onthese issues, but rather provided input to the independent Board on thefull range of views and inputs from across the industry. This practice thatwas consistent with one of the committee’s “Guiding Principles”
continued successfully for the next several years as a way to provide theBoard with a broad range of input from stakeholders on issues that wereon the Board’s agenda.32

NERC–NAESB Resolution
In response to industry concerns about having related standards
developed by two different organizations (i.e., NERC and the newly
formed North American Energy Standards Board (NAESB)), the NERC
Board voted in October 2001 to take all necessary steps to become thesingle organization in North America to develop both Reliability Standards
and wholesale electric business practice standards through a fair, open,
balanced, and inclusive process.
This decision by the Board was discussed and debated throughout all
sectors of the industry with some suggesting that NAESB be the soledeveloper of all standards—including both reliability and business
31 After its first year of existence, Mr. Hawks stepped down as vice chair of the

Stakeholders Committee and was replaced by Roy Thilly, chief executive officer of
Wisconsin Public Power, Inc. while Mr. Greene served a second term as chair.
32 The “Chair’s Letters” were suspended in 2005 with the change in staff leadership andwere reinstated in 2009 when staff leadership changed again.
History of the North American Electric Reliability Corporation65

practice standards. In February 2002, the NERC Board reversed courseand committed instead to a coordinated process by which NERC would be
responsible for developing Reliability Standards while NAESB would
develop business practice standards and electronic communications
protocols for the wholesale electric industry.
In recognition of the close relationship between some Reliability
Standards and business practice standards, NERC and NAESB signed amemorandum of understanding that detailed how coordination between
the two organizations would be achieved. A Joint Interface Committee(JIC), made up of representatives from NERC and NAESB, was created to
examine each standard proposal submitted to NERC or NAESB todetermine which organization should have the lead in developing thestandard.
The Board also agreed to use a weighted segment voting model that was
eventually accredited by the ANSI, for approval of Reliability Standards.
The process was called the Wholesale Electric System Model (WESM).

Organization and Personnel Certification
The Reliability Functional Model identified the functions that needed tobe performed to ensure the reliable planning and operation of the grid.
Some of the entities that expected to perform these functions needed tobe certified, similar to the way control areas were certified previously.
New Reliability Standards were developed to identify reliability
responsibilities along with the certification requirements for each ofthese functions.
On a related front, the System Operator Certification Program was
expanded to offer four credentials for specialized personnel testing in thefollowing areas: balancing and interchange, transmission,balancing/interchange and transmission, and Reliability Coordinator. The
program provided enhanced individual utility training, self-study
workbooks, computer training programs, and support workshops.

Reliability Coordinator Audits
By the end of 2002, the Compliance Enforcement Program had audited all
NERC Reliability Coordinators. The audits focused on all aspects of the
Reliability Coordinator responsibilities. Overall, the audit teams found66

History of the North American Electric Reliability Corporation

that Reliability Coordinators were acting effectively and independently topreserve the reliability of the BES.

Synchro-Phasor Measurement System
NERC, in conjunction with the Consortium for Electric Reliability Technical
Solutions (CERTS), developed and implemented area control error (ACE)
and area interchange error (AIE) real-time monitoring system applications
for North America. These applications enabled the Reliability
Coordinators to monitor ACE frequency performance and compliancewith performance operational guides as well as allowed NERC to analyze
and assess control data to improve reliability performance.

FERC NOPR on Standardization of Generator
Interconnections
A draft agreement designed to standardize and streamline the generator
interconnection process was developed. NERC filed comments with FERC
suggesting that further work was required to ensure that reliability
requirements were consistent with NERC Reliability Standards and would
not affect the reliability of the BES.

NERC Standards Process
In 2002, the NERC Board approved and implemented a new process fordeveloping Reliability Standards. A Standards Authorization Committee
was created, and a NERC standards director appointed. NERC standards
became mandatory and enforceable in the province of Ontario as a partof the Ontario Independent Electric System Operator’s market rules.

NERC Strategic PlanAt the October 2002 meeting of the NERC Stakeholders Committee, NERC
Board chair Richard Drouin informed the committee that the Board would
be conducting a strategic review and planning initiative to identify andanticipate challenges for NERC. He noted that the Board had identified
four areas where NERC needed to focus its attention while continuing topursue enactment of reliability legislation: Reliability Standards
development, compliance with Reliability Standards, NAESB relationship,
and funding.

History of the North American Electric Reliability Corporation

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History of the North American Electric Reliability Corporation

NERC Responds to 2003 Blackout
A massive blackout occurred in the Eastern Interconnection on August 14,
2003, affecting the states of Michigan, Ohio, Pennsylvania, and New York,and the Province of Ontario in Canada. A total of 50,000,000 customers
lost power.
Richard Drouin, chair of the NERC Board, remarked in the 2003 NERC
Annual Report, “It was a stark reminder to everyone that constantvigilance and adherence to reliability rules is essential to fulfilling NERC’s
mission. But knowing that the rules need to be followed and actuallyfollowing the rules are two different things. We have learned many
valuable lessons from the blackout investigation. But what we alreadyknew, and which the blackout underscored, is that our system ofvoluntary compliance with reliability rules is simply no longer adequate.”
Mr. Drouin’s remarks continued, “NERC’s blackout investigation resulted
in a series of findings and recommendations that we have directedindustry to implement. We will also do everything within our power forindustry to regain the public’s trust and provide reassurance that
preserving the reliability of the BES is of paramount importance.”
Restoration was completed for most customers within 29 hours, but
Ontario continued to experience power shortages for another two weeks
as its nuclear units were slowly brought back online. NERC initiated aninvestigation into the causes as did a joint United States–Canada task
force. The factual investigation was done jointly with scores of industry
volunteers participating.
In 2003, NERC President Michehl R.Gent stated in the 2003 NERC Annual
Report, “As the organization responsible for establishing and monitoring
compliance with electric Reliability Standards, NERC’s first action on theafternoon of August 14 was to contact the affected entities anddetermine the extent of the blackout. Thanks to the prompt response
from the industry, we were able to gather enough information to answer
the immediate and pressing questions and concerns in the hours and days
that followed. Determining the root causes of the massive grid failure
took a little longer; however, our detailed technical investigation is finallydrawing to a close.”

History of the North American Electric Reliability Corporation

69

When the blackout occurred, NERC was still awaiting United States
legislation that would require all industry participants to follow NERC
Reliability Standards. Despite the fact that there was broad support,
Congress had not enacted legislation to provide for the creation of an ERO
with authority to adopt and enforce compliance with mandatory
Reliability Standards. While there was strong and universal agreement on
the need for reliability legislation, there was not full agreement on otheraspects of broader energy legislation.
The blackout investigation discovered that NERC Reliability Standards
were violated and that these violations contributed directly to theblackout. The NERC Board and entire NERC organization was deeply
disturbed by this finding as well as by the fact that problems identified instudies of prior large-scale blackouts were repeated. All agreed that theindustry must do better than this, and the NERC Board pledged to makesure it did. Although compliance remained voluntary until reliability
legislation passed, NERC used all available means to obtain fullcompliance with its Reliability Standards in the meantime. The NERC
Board stated emphatically that it was counting on the full support andcooperation of both industry and government to achieve this goal.
Among the steps taken as a result of the blackout were that NERC Board
would receive detailed information on all violations of NERC Reliability
Standards. Up to that point, virtually all compliance data was kept
confidential at the regional level. NERC worked diligently to improve
compliance with its Reliability Standards and provide greatertransparency to violations of those standards. In doing so, NERC worked
closely with the federal energy authorities and with other federal, state,
and provincial regulatory authorities in North America to ensure that the
public interest was met with respect to reliability and compliance withNERC standards. Finally, NERC undertook a comprehensive set oftechnical initiatives that, once implemented by the industry, would serve
to enhance and further ensure the reliability of the grid in the future.
As NERC Board Chair Drouin opined, “The silver lining to this black cloudis that NERC and the industry have learned some key lessons from theblackout that will enable us to improve the overall reliability of the grid.
Of course, NERC and the industry must together take all of these lessons
and implement them in a timely fashion. Only then will we truly be able
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History of the North American Electric Reliability Corporation

to say that we have learned from history and that history will not repeat
itself.”
In November 2003, the U.S.–Canada Power System Outage Task Forceissued their Interim Report: Causes of the August 14th Blackout in the
United States and Canada. They issued a final report in April 2004. The
task force also issued The August 14, 2003, Blackout One Year Later:
Actions Taken in the United States and Canada to Reduce Blackout Risk
report and a Final Report on the Implementation of the Task ForceRecommendations in September 2006.
In the 2003 Annual Report, President Michehl R. Gent wrote, “I want topublicly and wholeheartedly thank all of the men and women who
unselfishly gave of their time and talent to make the investigation the firstclass operation that it was. No one can come away from this investigation
untouched and unimpressed by the herculean efforts of the manyindustry professionals we have had the privilege and honor to work with.
I would like to express my sincere appreciation to the NERC and regional
staffs for their unwavering commitment to this investigation, and to ourblackout investigation steering group for their objective and thoroughguidance in helping to get to the bottom of this event. I would also like tothank each and every person who volunteered their time and expertiseto NERC for the duration of this investigation, and also thank thoseorganizations that made their participation possible. I salute you all.”

A Constructive Partnership with Government
Pat Wood III, chair of FERC, attended each of the NERC Board meetings,
expressed strong support for NERC’s activities, and challenged the entire
industry to do all that was needed to ensure the reliability of the BES
while awaiting passage of the reliability legislation. He commented in the2004 NERC Annual Report, “NERC works with the governments of theUnited States and Canada to promote cooperation, understanding, andsupport for a broad range of initiatives aimed at maintaining a reliable
electric system. The investigation of the August 2003 blackout illustrates
an important example of such cooperation. NERC was responsible for thetechnical investigation and worked closely with the U.S.–Canada Power
System Outage Task Force. NERC provided the task force with the resultsof its technical investigation along with a comprehensive set ofrecommendations to address deficiencies uncovered by the investigation.
History of the North American Electric Reliability Corporation

71

These recommendations later formed the core of the governments’
blackout report.”
In 2004, FERC issued a policy statement outlining the actions that FERC
planned to take to improve electric system reliability in response to thegovernment’s blackout recommendations. The statement strongly
supported legislative reform that would authorize the creation of an ERO
and provide a clear federal framework for developing and enforcing
mandatory reliability rules. FERC also outlined steps it could take within
its existing authority to promote reliability and support NERC’s efforts toimprove the current voluntary, industry-based approach until legislation
was enacted. NERC worked closely with FERC’s newly formed reliability
division and included FERC representatives on its reliability readinessaudit teams.
Following the blackout, the United States and Canadian governments
established the Bilateral Electric Reliability Oversight Group (BEROG),
composed of the Canadian Federal/Provincial/Territorial ADM Energy
Working Group, DOE, and FERC. The BEROG served as an important forum
for identifying and resolving reliability issues in an international,
government-to-government context. BEROG, which grew out of the U.S.–
Canada Power System Outage Task Force, developed principles for thecreation of an international ERO. The NERC Board endorsed thoseprinciples for all of North America, a necessary step as FERC would only
have jurisdiction over the ERO with respect to U.S. BESs under the
proposed legislation.
The creation of a government-sanctioned ERO was largely dependent on
the passage of reliability legislation in the United States. A memorandumof agreement guided interactions between NERC and FERC. NERC had
similar arrangements in place with the U.S. Nuclear Regulatory
Commission and the U.S. Energy Information Administration. NERC
worked to update its memorandum of understanding with FERC andbegan discussions about potential arrangements that would govern therelationship between NERC and regulators in Canada. NERC also had closeworking relationships with DHS, DOE, and Public Safety and Emergency
Preparedness Canada to coordinate protection of this criticalinfrastructure. NERC also worked with the National Association ofRegulatory Utility Commissioners (NARUC) and the Canadian Association
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History of the North American Electric Reliability Corporation

of Members of Public Utility Tribunals and participated in other state andprovincial forums to keep regulators fully abreast of NERC activities as
efforts continued to enact reliability legislation and establish the ERO.

Follow-up on Blackout Recommendations
NERC spent much of 2004 implementing the most critical blackout
recommendations. Initially, NERC worked to ensure that the deficiencies
that were identified as direct causes of the blackout were corrected. Not
only were these deficiencies corrected, but the affected organizations
made significant improvements to their systems and procedures thatwent well beyond the recommendations offered by NERC and thegovernment task force.
NERC continued to work closely with the U.S.–Canada Power System
Outage Task Force and industry to track and implement all of therecommendations resulting from the blackout investigation. Althoughmany of the most important initiatives were completed or were wellunderway during 2004, some would take years to implement. Taken as awhole, these efforts went a long way to reduce the risk of another major
outage in North America.
Two of the most important and effective changes enacted by NERC
following the blackout were the establishment of the System Protection
and Controls Task Force (SPCTF),33 which addressed protective relaying
issues discovered during the event, and the so-called “Tree Standard” onvegetation management that addressed the initiating cause of theblackout (i.e., tree contacts with power lines). Both efforts made asignificant impact on reducing the number and severity of system
disturbances. The changes recommended in those areas were
subsequently codified in the current NERC Reliability Standards.

33 SPCTF was elevated to a permanent subcommittee of the Planning Committee (i.e.,

System Protection and Controls Subcommittee (SPCS)) in 2007.
History of the North American Electric Reliability Corporation73

Chair Drouin stated the following in the 2004 NERC Annual Report:“Regrettably, one important blackout recommendation was not
implemented; this was the passage of legislation in the UnitedStates that would make compliance with NERC Reliability
Standards mandatory and enforceable. Until that occurs, we willcontinue to work with government and the industry to do
everything we can to help all entities whose operations affect theoperation of the grid comply with NERC standards. We haveworked hard to transform NERC into an independent ERO.
Although Congress still has not passed an energy bill, we havemade great strides toward the goals that are embodied in thereliability legislation. We will continue to do everything possible
to uphold our Reliability Standards in the coming years while stillseeking the legislation that would make them mandatory andenforceable.”Compliance Reviews and Reliability Readiness Audits
In a major effort to improve reliability performance immediately
following the blackout, NERC initiated an innovative voluntary program toaudit the reliability readiness of system operators. The initial step inestablishing the program was to survey all control areas for what they
were doing to protect reliability of the BES, focusing primarily on thelessons learned from the 2003 blackout investigation. After evaluating theresults of the survey, NERC set up teams of industry representatives and
NERC staff to conduct Reliability Readiness Audits. The audits were
designed to promote excellence and ensure that control areas andReliability Coordinators were prepared to operate reliably. The audits
helped these entities recognize and assess their reliability responsibilities
and evaluate how well their operations supported those responsibilities.
This program provided a way to identify areas of concern that could becorrected by registered entities before they led to reliability problems.
NERC then used the results of these audits to champion the changes
required to improve the reliability performance of the entire industry.
Once legislation was enacted and the Compliance Enforcement program
established, the Reliability Readiness Audits were phased out as they
were seen to be not compatible with mandatory compliance andenforcement.

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History of the North American Electric Reliability Corporation

NERC took another major step to improve compliance with Reliability
Standards when it began to publicly disclose the results of compliancereviews and readiness audits. Such transparency was vital if industry
stakeholders, regulators, and the public were to have confidence that theelectric industry was doing all that was necessary to maintain a reliable
BES. The ultimate goal in disclosing the audit findings was to promote acollective willingness on the part of everyone with reliability
responsibilities to remedy any problems these audits uncovered.

Revamping Reliability Standards and the Standards
Development Process
The 2003 blackout challenged NERC and the industry to make Reliability
Standards clear, measurable, and enforceable. Both the U.S.–Canada
Power System Outage Task Force’s final report and FERC’s policy
statement on reliability recommended that NERC improve its standards
development process and accelerate the adoption of clear andenforceable Reliability Standards.
NERC met this challenge by translating its operating policies, planning
standards, and compliance requirements into a set of 90 Reliability
Standards. This was a large, expedited effort undertaken by NERC andstakeholders to revise the existing Operating Policies and PlanningStandards into a comprehensive set of Reliability Standards suitable forsubmission as enforceable standards (the so-called “Version 0”
Standards) once legislation passed and NERC was approved as the ERO.
There was strong stakeholder consensus that Version 0 was an extremely
important effort and that the Board should provide guidance to theRegistered Ballot Body on development of the Version 0 Standards.
While the technical content of the standards remained largely
unchanged, two important improvements were made. First, thestandards adopted the definitions in the NERC Reliability Functional
Model for responsible operating entities to provide greater accountability
for following the reliability rules. Second, the reliability requirements
were made more concise, objective, and measurable.
The industry voted overwhelmingly to approve the new standards inDecember 2004. Following Board adoption, the Version 0 Standards
became effective on April 1, 2005, and the existing NERC operating
History of the North American Electric Reliability Corporation75

policies and Planning Standards were retired. With this landmark
achievement, NERC was better positioned to monitor and enforce
compliance with its Reliability Standards and expedite the developmentof new standards addressing other blackout recommendations and otherknown technical issues representing risks to the reliability of the BES.
The transition to new Reliability Standards was not without challenges asconverting reliability guides and criteria to enforceable standards proved
much harder than anticipated. Several Planning Standards were notincluded in the translation because they required additional work to
resolve outstanding technical issues and build industry consensus. That
work took place in 2005. The new standards only partially implemented
the Reliability Functional Model, which assigned specific reliability tasks
to entities whose operations affected the BES. NERC began registering
entities that would be responsible for performing certain reliability tasks;
however, additional work was required to reconcile the Reliability
Functional Model with the new standards. A task force was formed in2005 to develop recommendations to resolve these issues. Resolution
was essential for further development of Reliability Standards,
establishing organization certification criteria, and ensuring that thecompliance program was properly structured to monitor compliance withNERC standards in the future.
This was not the end of NERC’s standards development work, but rather
an important first step that provided a solid foundation for further
standards development.

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History of the North American Electric Reliability Corporation

New Standards ProgressAdopting an interim vegetation management standard
that required Transmission Owners to have a
documented vegetation management program in place
and to report vegetation-related line outages

Proposing a vegetation management standard thatdetailed the minimum clearances between vegetationand energized conductors in utility rights-of-ways andaddressed other concerns, such as line design,
vegetation management programs and work plans,personnel qualifications, and reporting of vegetationrelated outages

Extending the interim cyber security standard for one
year while a permanent standard was developed toreplace it in 2005

Instituting minimum requirements for emergency
training and conducting an analysis of training needs inanticipation of developing training standards in 2005



Drafting certification standards for reliability authorities,
Balancing Authorities, and Transmission Operators withfinal standards expected to be adopted in 2005. Whencomplete, these standards would enable NERC to certify
organizations’ capabilities to perform reliability functions
and complete a final step in the transition from thehistorical “Control Area” model to the responsibilities
outlined in the Functional Model

Developing a standard that would ensure the reliabilityof off-site power supply to nuclear power plants.
Although nuclear plants have always received highpriority for electric supply to serve emergency auxiliary
equipment, the proposed standard would create a
uniform set of requirements across North America

History of the North American Electric Reliability Corporation77

Another significant milestone during this period was the approval of achange to the Reliability Standards Process Manual that gave theStandards Authorization Committee greater flexibility to streamline andimprove the administrative steps in the standards process. The
committee sought and received ANSI review and approval of the revised
process in 2005. NERC also strengthened its working relationship with
NAESB, which was developing complementary business practicestandards. The Joint Interface Committee created to coordinate thestandards development activities of NERC and NAESB became more
active as the volume of standards development work by bothorganizations increased.
NERC also implemented memoranda of understanding with NAESB and
the ISO/RTO Council to avoid overlap and duplication of effort of the threeorganizations by distinguishing the establishment of reliability andbusiness practice standards from the development, proposal, andimplementation of ISO and RTO policy.

Event Analysis and System Protection Initiative
In order to better capture lessons learned from system disturbances andnear misses, NERC began performing routine analyses of system events,
large and small, and established an internal Event Analysis group in
2004.34 That group’s first large-scale disturbance analysis was of the June
14, 2004, Westwing Outage, working directly with WECC on the WECC
Detailed System Disturbance Report.
The NERC Event Analysis team either led or participated in more than 15
detailed analyses of major disturbances, beginning in 2003. It developed
several tools to help determine root cause(s) of events as well as a robust
regime of analysis for a wide range of events, coupled with a lessons
learned and alert system to advise the industry on problems
encountered.
In May 2004, NERC took its first steps in addressing the many system
protection issues encountered during the analysis of the 2003 blackout
and formed the System Protection and Controls Task Force (SPCTF), which
was later elevated to subcommittee status. The first priority was to34 Contractors were initially used to supply manpower to this effort.

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History of the North American Electric Reliability Corporation

address the “Zone 3” backup protection issues that had been
contributory to every major system disturbance since the 1965 blackout.
Transmission Owners were requested to perform detailed technicalreviews all of their load-responsive relays and ensure that their trip
settings were such that the system operators would have time to react tosystem overloads before the lines tripped. The review saw dozens ofpotential problems that were then mitigated on the BPS. That review wasthen codified in a system protection Reliability Standard concerning relay
loadability. That review and the standard resulted in the virtual
elimination of relay loadability contributing to the severity of system
disturbances since 2007.

Critical Infrastructure Security Initiatives
Protecting the electricity infrastructure from cyber and physical threats
was becoming an increasingly important responsibility for NERC and theindustry in 2004. NERC achieved a major milestone in this area when it
adopted the urgent action cyber security standard (i.e., UA 1200), the firststandard to be developed through the new standards development
process, approved by the industry, and adopted by the Board. This
standard was designed to reduce risks to the reliability of the BESs fromany compromise of critical cyber assets, including computers, software,and the communication networks that support those systems. The
standard required that critical cyber assets related to the reliable
operation of the BESs be identified and protected.
NERC also elevated the Critical Infrastructure Protection Advisory Groupto standing committee status in 2004, calling it the Critical Infrastructure
Protection Committee (CIPC). NERC monitored Reliability Coordinatorsand control areas for compliance with Cyber Security Standard UA 1200,
and the results showed that industry was well on its way to fullcompliance by the end of 2004.
The NERC Board adopted two more electric sector critical infrastructure
protection security measures dealing with securing remote access toelectronic control and protection systems and threat and incident
reporting.
In further support of critical infrastructure protection, NERC sponsored aseries of workshops across the country that focused on security
History of the North American Electric Reliability Corporation

79

guidelines for the electricity sector. As the Electricity Sector Information
Sharing and Analysis Center (ES-ISAC), NERC also spent considerable timeworking with DHS to ensure continuity of critical infrastructure protection
activities as the department took on responsibilities previously held byother government agencies.
Because cyber security is key to critical infrastructure protection, NERC
extended cyber security standard UA 1200 for one year while apermanent replacement standard that would build upon the original
standard and cover a broader range of electric facilities with morecomprehensive requirements was developed.
Because utility control and data acquisition systems are integral to all
aspects of electric system operations, NERC took steps to protect thesesystems beyond the requirements of UA 1200. A security guideline wasdeveloped to address remote connectivity to control systems, and two
guidelines were developed that expanded on the connectivity issue,
addressed patch management of control systems, and consideredapproaches to mitigate potential cyber attacks. NERC also established aworking relationship with the Idaho National Engineering andEnvironmental Laboratory, which had a test bed that could be used toevaluate control systems vulnerabilities and the means to eliminate them.
NERC also developed a security guideline to address physical security for
substations, outlining methods and policies that could enhance thesecurity of primarily unmanned facilities. NERC successfully tested theSpare Equipment Database, which included policies and procedures toassist in locating suitable spare equipment in the event of the loss of key
components. NERC also investigated industry’s needs for the acquisition,
storage, and transportation of spare transformers.
A NERC-sponsored task force worked with the Congressional HighAltitude Electromagnetic Pulse Commission to develop clarity on impacts
to the BES and mitigation approaches.
NERC worked with DHS and other critical infrastructure industries
through the Partnership for Critical Infrastructure Security—agovernment and private sector coordinating council. NERC recommended
to DHS that the CIPC Executive Committee and the president and chief
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History of the North American Electric Reliability Corporation

executive officer of NERC serve as the industry representatives on the
council. NERC also provided input on the National Infrastructure
Protection Plan developed by DHS and worked with DHS to develop theHomeland Security Information System—a full-featured information
system that enabled the rapid exchange of information among andbetween sector participants, DHS, and other critical infrastructure
sectors.

NERC Strategic Plan
A significant action affecting NERC’s mission going forward was thedevelopment of the NERC Strategic Plan 2003–2006, which outlined
NERC’s mission, vision, values, and goals for the next several years.35
NERC also adopted a complementary business plan and budget that
identified the specific objectives NERC would pursue in 2004.

Reorganization of NERC Standing Committees
NERC’s extensive review of its standing committees concluded that theexisting committee structure should be retained, but that the committee
scopes should be revised to reflect new responsibilities. As part of thisreview, the Market Interface Committee was dissolved without
opposition. However, stakeholders expressed concern that NERC remain
diligent about continued effective coordination with NAESB on thedevelopment of business practice standards and Reliability Standards.

Natural Gas/Electricity Interdependency
Because of the high degree of interdependency between natural gas andelectricity systems, the NERC Board approved the creation of a Natural
Gas/Electricity Independency Task Force to identify areas of concern andways to resolve them. This became an important issue that would be
addressed each year in the annual Long-Term Reliability Assessments aswell as in special assessments.

System Operator Training and Certification
NERC inaugurated a continuing education program to approve training
providers and the courses they offer. The program provided the industry
with a supply of high-quality training activities and providers. By the end
35 This was the first of several strategic plans that NERC would develop over the next

dozen years.
History of the North American Electric Reliability Corporation81

of 2004, NERC had approved continuing education providers with almost
3,000 hours of approved learning activities that were delivered to system
operators throughout North America. NERC also developed a system
operator training program to implement a key blackout recommendation.
Program Objectives


Identify best practices in training

Define excellence in job performance of system operators



Identify commonalities in tasks performed by system
operators across a variety of organizations



Identify conditions that support human performance

Develop comprehensive training standards and training
program criteria

NERC also conducted a system operator training study that determined
the skills and traits needed to become a top performer and the tasks
being performed by different classifications of system operators, such as
Transmission Operators. Data from this study helped NERC develop a
training curriculum for inclusion in a training standard. A training program
study identified innovative ways to improve the effectiveness of training
to help organizations bridge the knowledge gap between aging andretiring system operators and the new trainees.

GADS Services
The Generating Availability Data System (GADS) provided power plantowners and operators, consultants, and government officials with thefundamentals of power plant data collection and analysis. GADS pc-GAR
was the premier software available for analyzing power plant
performance. It was used in twelve countries and was the model for use
by the World Energy Council’s Performance of Generating Plant
Committee. In 2004, GADS went international when Tenaga Nasional
Berhad, an electric utility in Malaysia, joined the GADS database.
Although a number of countries collect data using the GADS system,
Tenaga Nasional was the first entity outside North America to report data
to NERC.

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Stage Three
Stage Three was marked by the passage of the Energy
Policy Act of 2005, which provided for a new form of
reliability assurance organization—the Electric Reliability
Organization (ERO). The ERO would be responsible formandatory, enforceable Reliability Standards developed
by industry and adopted and enforced by NERC withoversight by its independent Board, FERC, and Canadianprovincial regulators. The ERO would also be responsible
for conducting and reporting on periodic short- and longterm assessments of the reliability of the grid, including
analysis of emerging risks. In 2006, NERC was approved
to fill this role in the United States and, over time, madearrangements to provide for mandatory compliance withNERC Reliability Standards throughout the Canadianprovinces.

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83

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History of the North American Electric Reliability Corporation

Legislation Finally Passes: New NERC Begins!
The Energy Policy Act of 2005 was finally adopted and signed into law on
August 8, 2005, adding a new Section 215 on reliability to the Federal
Power Act. Section 215 authorized FERC to certify and provide oversightof one ERO for the United States.36 NERC subsequently applied for FERC
certification in April 2006 and was certified in July 2006.
While many attribute the final passage of legislation containing theconsensus reliability language to the occurrence of the 2003 blackout, theneed for legislation was established long before the blackout occurred.
Nevertheless, the 2003 blackout underscored what Mr. David Cook,
NERC’s general counsel, stated earlier with regard to major blackouts if
legislation was not passed: “It’s not a question of whether there will be
another major blackout, but when.”Preparing for ERO Certification
In October 2005, given the importance of having mandatory enforceable
Reliability Standards, the NERC Board adopted the following resolution tocreate a steering committee to oversee the project of getting NERC
certified as the ERO:
“Resolved, that management, in consultation with thestakeholders and Members,37 is directed to form a steeringcommittee to oversee NERC’s development of an application forcertification as the ERO under the new reliability legislation andall matters related to NERC’s transition to the ERO with themembership of that steering committee to be appointed by the
Board.”
A significant part of preparing for ERO certification was following up on
the extensive and detailed recommendations made by NERC and theUnited States–Canada Power System Outage Task Force on a wide range
36 During development of the consensus reliability language, there was some concern

from entities in the Western Interconnection about their ability to develop Reliability
Standards that might be different than ERO standards. There was even some thinking that
there should be a separate Western ERO. Language was added to provide deference toentities organized on an interconnection-wide basis to have different standards as longas they met certain criteria. This language was eventually transferred into the Rules ofProcedure when the consensus language was shortened.
37 At this point, the “members” were the ten Regional Reliability Councils.

History of the North American Electric Reliability Corporation85

of actions needed to reduce the possibility of a wide-scale outage
occurring in the future.
Also in 2005, Mr. Gent, who joined NERC in 1980 as executive vicepresident and became president in 1982, retired, turning over the reins
to Mr. Richard Sergel.
At the August 2005 NERC Board meeting, Mr. Hodel, who had rejoined
the Board as an independent trustee in 2001,38 remarked on the historicnature of the meeting. Passage of long-sought reliability legislation by the
U.S. Congress, Mr. Hodel noted, marked an historic shift—perhaps more
historic than the creation of NERC in the first place—in how industry dealt
with reliability. In contrast to the volunteer effort that had characterizedindustry to that point, government would have a role in all elements that
affect reliability. Mr. Hodel continued, that as NERC looked at standards
in the future, it should not lose sight of critical infrastructure needs. The
legislation also changed the role of state commissions, moving their focus
from local to regional matters. NERC would need increased sensitivity toissues of planning and resource adequacy that would require a stronger
relationship between the new ERO and the states. Mr. Hodel expressed
confidence that NERC would be diligent in that effort.
A Post-Legislation Steering Committee was formed to develop a
consensus draft rulemaking to submit to FERC. A series of actions weretaken at subsequent meetings of the Stakeholders Committee and theBoard; these are summarized here to provide a chronological context for
the flurry of activity that occurred following passage of the legislation. It
is worth noting and underscoring that the input from all stakeholders andthe independent Board’s willingness to listen intently to, and take into
account, that input in making critical decisions along the way was crucial
to the successful transition of NERC to the North American ERO.
At the October 31, 2005, Stakeholders Committee meeting, reports ofthe four ERO transition task groups were discussed prior to submitting
them to the Board. Major issues included in the reports were as shownon the next page:

38 Mr. Hodel was one of the original stakeholder Board members from 1973–1977 when
he served as administrator of the Bonneville Power Administration.

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History of the North American Electric Reliability Corporation



Members Task Group: Whether the Regions should be voting
members of a proposed ERO Members Executive Committee andwhether the current Stakeholders Committee model should be
retained in full or whether the Registered Ballot Body should also
be considered as a model for organizing ERO membershipFunding Task Group: What costs should be included in the ERO
budget submitted to regulators, whether the ERO should approve
Regional Entity budgets for delegated functions, and how costs
should be collected for delegated functions



Regional Entity Delegation Task Group: Draft pro formadelegation agreement will be drafted that meets the principles
developed by the groupCompliance Penalties and Sanctions Task Group: Description of
the high-level principles covering possible monetary and nonmonetary penalties, appeal processes, and ways in which funds
collected might be used, and an enforcement policy documentthat recognizes these principles

Following discussion, the Board directed staff to develop a draft
certification application.
At its February 6, 2006, meeting, the Stakeholders Committee discussed
the draft ERO application with Board members present. The committee
agreed to hold a special meeting prior to Board’s March 28 meeting togive stakeholders the opportunity to provide input to the Board.
At its February 7, 2006, meeting, the Board focused its discussion on theissues raised by the stakeholders the previous day. President Sergel
requested written comments with emphasis on role of stakeholders,regional relationships, penalty guidelines, transition and timing, andfunding of reliability-related activities be submitted.
At the special March 28, 2006, meeting, in addition to the areas requested
to be addressed in written comments, stakeholders commented onwhether it was appropriate to codify the Personnel Certification and
Governance Committee in the Bylaws, the need to distinguish between
statutory and non-statutory ERO functions for budgeting purposes, theneed to avoid remand of standards, the extent to which balanced decision
History of the North American Electric Reliability Corporation87

making would need to extend within the subordinate structures of the
ERO and regional entities, whether settlements of disputes should occur
at the regional or ERO level, the role and structure of the operating andplanning committees, the need to clearly define dispute resolution
procedures, the need for consistency between the bylaws and Rules ofProcedure, the need for fair representations of all stakeholders at theRegional Entity level as well as at the ERO level, and the need to ensure
coordination and cooperation across government jurisdictions.
It was at this meeting that the Board approved creating the North
American Electric Reliability Corporation, a non-operating subsidiary ofNERC, as a necessary step in the formation of the ERO.39

NERC Application Filed with FERCOn April 4, 2006, NERC filed its application with FERC to be named the
ERO. Under the revised NERC bylaws, the MRC would effectively replace
the Stakeholders Committee with the following functions andresponsibilities: elect the independent trustees to the NERC Board; vote,jointly with the Board, on amendments to the Bylaws; and provide advice
and recommendations to the Board with respect to the development ofannual budgets, business plans, funding mechanisms, and other mattersrelated to the operations of NERC.
Article VIII, Section 1 of the Bylaws, state: “These provisions help toensure member representation in the selection of directors and a role forthe members (through the MRC) in the primary governance of the ERO.”This critical role afforded to the stakeholders continues to be recognized
as a key reason for the success of NERC. As previously cited by Mr. Drouin,
NERC’s first independent trustee chair, it was important to create anorganization in which the Board had the opportunity and requirement tolisten to the stakeholder discussion at MRC meetings.

NERC Certified by FERC as the ERO
On July 20, 2006, FERC certified NERC as the ERO and ordered acompliance filing to be made by October 18. The order imposed a numberof conditions, including the following: further explanation on the
proposed makeup of the MRC; concern that the supermajority
39 The NERC Council still existed at this time.

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History of the North American Electric Reliability Corporation

requirement for standards approval might be an obstacle tostrengthening reliability; need to provide for FERC deadlines set for
remand of standards; and need for more detailed, uniform compliance
enforcement procedures.
On October 30, FERC approved NERC’s revised bylaws, including NERC’s
proposal to use different voting models for the Registered Ballot Body andthe MRC, to add the ISOs and RTOs to the Registered Ballot Body as aseparate segment, and to give the Regional Entities two votes on the MRC
with the remaining Regional Entities being non-voting members of the
MRC. The Regional Entities decided annually which two Regions would bevoting members of the MRC.
Regional Delegation Agreements were planned to be filed on or about
November 22, 2006, for FERC approval by June 2007.
In October 2006, NERC Council, NERC Corporation, and the eight regional
councils adopted an agreement and plan of merger by which NERC
Council and NERC Corporation would merge with NERC Corporation being
the surviving corporation. This agreement was made effective on January
1, 2007, after satisfying the following conditions to closing in late 2006:


NERC Corporation succeeded to all assets and liabilities of NERC
Council, and regional councils would be eligible for membershipin NERC Corporation.



The membership of NERC Corporation would be expanded toinclude all those with an interest in the reliable operation of the
BPS of North America.



FERC approval of the 2007 business plans and budgets of NERC
and the eight Regions who intended to enter into delegationagreements with NERC under Section 215.



NERC signed memorandums of understanding with Ontario,
Quebec, Nova Scotia, and the National Energy Board of Canada
regarding compliance with ERO standards.

Proposed regional delegation agreements were filed with FERC
for approval. FERC subsequently approved delegation

History of the North American Electric Reliability Corporation89

agreements with eight regional entities: Florida Reliability
Coordinating Council; Midwest Reliability Organization;
Northeast Power Coordinating Council: Cross Border Regional
Entity, Inc.; ReliabilityFirst Corporation; SERC Reliability
Corporation; Southwest Power Pool, Inc.; Texas Reliability Entity,
a division of ERCOT; and Western Electricity Coordinating Council.
All of the Canadian Provinces were very supportive of NERC as the ERO
with the majority of provinces either having signed a memorandum of
understanding or providing other indications of support related to NERC’s
ERO activities.
On February 12, 2007, the first annual meeting of the NERC Corporation
MRC was called to order. As of February 1, 2007, NERC had 516 members
spread across 12 sectors, whose members had elected their sector
representatives to the MRC. One Canadian representative was selected inaccordance with the bylaws.
The MRC members elected Mr. Billy Ball of Southern Company as the firstchair of the newly formed MRC, and Mr. Ball presided over the remainderof the MRC meeting. Mr. Steve Hickok of Bonneville Power Administration
was elected vice chair.
What followed was a series of developments that were triggered by the
FERC certification:

90

Version 0 Reliability Standards were submitted to FERC for
approval, followed by Version 1 of the Critical Infrastructure
Protection Standards.

East Central Area Reliability Coordination Agreement (ECAR),
Mid-Atlantic Area Council (MAAC), and Mid-American
Interconnected Network (MAIN) merged to form a new reliability
council—the ReliabilityFirst Corporation, leaving NERC with eight
members.

NERC’s mandatory Reliability Standards were approved by FERC
and took effect June 18, 2007.



NERC opened an office in Washington, D.C.
History of the North American Electric Reliability Corporation

NERC’s 40th Anniversary Ushers in the Next
DecadeOverview
June 1, 2008, marked the 40th anniversary of NERC’s formation. While theorganization and its activities had changed significantly over the previous
four decades, NERC was still in the very early formative stages of
becoming the world-class ERO that it is today.
Focus on the Mission

NERC’s fifth decade was one of transition, transformation, andstrengthened focus on its mission of reliability and accountability. NERC
worked to achieve reliability through its mandatory standards, risk-based
compliance, and its culture of being a transparent learning organization,
sharing lessons learned and best practices. NERC is accountable togovernment, industry, and, ultimately, consumers for ensuring a reliable
BPS.
As the ERO, NERC prioritized standards by focusing resources on highpriority projects, implemented a new model to balance complianceactivities with enforcement discretion, and participated with FERC in joint
inquiries of significant electric power outage events, most notably the
September 8, 2011, Arizona–Southern California outages.
NERC also dedicated efforts to the continued evaluation of emerging
threats and vulnerabilities, examined power system impacts fromextreme weather conditions, and participated in technical discussions
and opportunities focused on securing reliability of the BPS.
CEO Reflections

Rick Sergel, NERC’s president and chief executive officer from 2005–2009,
stated the following:“When trying to explain who NERC is and what we do, I am often
asked: ‘How can an industry regulate itself? Isn’t there a conflictof interest?’ I answer them by explaining that the electric industry
is different than others in that we are critically interconnected:
the BPS is only as strong as its weakest link. Every asset owner has
an interest in ensuring its neighbors keep reliability a priority—
History of the North American Electric Reliability Corporation

91

what happens on one system affects the next, and so on. In short,
we are in a unique position to make the self-regulatory modelwork. The incentives are in the right place, the experts areengaged. Mutual interest exceeds personal gain. I firmly believe
this is the right model for ensuring the reliability of the bulk
power system in North America, but we’re still in the formative
stages of this new effort. The opportunity for success is clear.
Becoming the self-regulatory ERO for North America has
thoroughly transformed NERC, how we operate, and what others
expect of us.”
Four Pillars of Success and Three Strategic Transformations

During this decade, NERC based its key programs and activities on fourpillars of continued success:

Reliability: to address events and identifiable risks, thereby
improving the reliability of the BPSAssurance: to provide assurance to the public, industry, andgovernment of the reliable performance of the BPSLearning: to promote learning and continuous improvement ofoperations and adapt to lessons learned for improvement of BPS
reliability



Risk-based Approach: to focus attention, resources, and actions
on issues most important to BPS reliability

Based on these four pillars, NERC, the Regional Entities, and industry
worked together to focus efforts on three strategic transformations toachieve better reliability outcomes:

92Standards: Improve the tools for developing Reliability Standards
and focus on continued execution and delivery of high-quality,
results-based standards



Risk Initiatives: Use NERC’s capability to analyze system eventsusing multiple sources to determine root causes and define
mitigation actions, and mature risk work by structuring solutions
around increased accountability

History of the North American Electric Reliability CorporationCompliance: Work closely with stakeholders to construct a newrisk-based model for compliance that is more coherent andmanageable

Risk-Based Approach

NERC recognized the risk-based approach to both standards andcompliance had led to significant and visible progress, and theorganization gained awareness and confidence across industry andgovernment. Almost every conversation on BPS reliability was about
identifying and prioritizing the most significant risks to reliability andinitiating targeted solutions to minimize them.
Infrastructure Security

Infrastructure security issues, both physical and cyber, were a primaryand increasingly important area of focus during the decade. Physicalsecurity efforts became a particular priority following the events at the
Metcalf substation in California and FERC’s approval of the Critical
Infrastructure Protection (CIP) Version 5 standards. Participation in gridsecurity initiatives increased, and NERC made improvements to theElectricity Information Sharing and Analysis Center (E-ISAC).
Strategic Planning and the ERO Enterprise

ERO strategic planning became an annual undertaking with key inputs
from Regional Entities, the MRC, and the Reliability Issues Steering
Committee (RISC). These strategic plans identified the mission, vision,core values, guiding principles, and four pillars of success for the ERO
Enterprise.40 They also detailed the objectives, valued outcomes, and key
deliverables for five identified goals.
Strategic Goals
Goal 1: Reliability Standards
Goal 2: Organization Registration and Certification
Goal 3: Compliance Monitoring and Enforcement
Goal 4: Emerging Risks and Essential Reliability Services
Goal 5: ERO Enterprise and Stakeholder Coordination and
Collaboration

40 See the ERO Enterprise Operating Model on the NERC website

History of the North American Electric Reliability Corporation

93

The ERO Enterprise tools that support NERC’s collaborative operations
improved communication between registered entities, the Regions and
NERC and also served to provide valuable data used in reliability
assessments, performance analysis, and reliability risk management.
Five-Year ERO Performance Assessment

The Five-Year ERO Performance Assessment, which was accepted by FERC
in November 2014, highlighted various achievements of the ERO during
the five-year assessment period as well as ongoing efforts to continueenhancing the reliability and security of the BPS. FERC stated in its orderaccepting the performance assessment that NERC and the Regional
Entities continued to satisfy statutory and regulatory criteria for
certification as the ERO and acknowledged NERC’s numerous efforts andinitiatives to improve the performance of and mitigate risks to the BPS.
ERO Enterprise Long-Term Strategy

In 2017, after the substantial progress achieved in its first 10 years ofoperations, the NERC Board approved the first ERO Enterprise Long-Term
Strategy, identifying significant new developments and related risks
affecting reliability and establishing key focus areas to guide the ERO
Enterprise’s work over a five-to-seven year horizon. The strategy included
mitigating risk through improved analytics that address the operationalchanges being driven by the growth of variable, renewable resources andgreater dependence on natural gas generation. Key to the ERO
Enterprise’s success would be maintaining strong partnerships with many
regulators and policy makers, including Congress, FERC, DOE, theDepartment of Energy, and U.S. state and Canadian provincial regulators.
International Coordination and Collaboration

NERC’s international work during the latter part of the decade
emphasized the importance of a regulatory framework for reliability thatworked across the jurisdictions of three sovereign nations, involving
greater cooperation with Canada and the first steps toward implementing
historic energy reforms in Mexico.

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History of the North American Electric Reliability Corporation

Reflections of the NERC Chair

As stated by NERC Chair Roy Thilly in the NERC 2017 Annual Report is thefollowing:“The ERO Enterprise model owes its strength to the hard workand expertise of the entire ERO Enterprise community—theelectric utility industry and other stakeholders, NERC’s staff, andRegional Entity staff who provide essential compliance andenforcement services across the ERO footprint. Coupled with theBoard’s focus on strategic priorities and independent oversight,
this combined expertise and dedication safeguards the reliabilityof the North American bulk power system…
The ERO Enterprise has faced many challenges over last 10 years
and more remain in the coming years. These ongoing challenges
include addressing the reliability impacts of growing cyber andphysical security threats to the grid and the rapidly changing
electric resource mix driven by economics and environmental
concerns. At the same time, the ERO Enterprise is committed toincreasing operational efficiency and effectiveness in all of its
activities in order to meet its mission to assure the reliability ofthe bulk power system.”

History of the North American Electric Reliability Corporation

95

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History of the North American Electric Reliability Corporation

NERC Program Area Developments andActivities: Fifth Decade
The following excerpts cover each of NERC’s major program areas overthe past decade of its 50-year history. As many of the program area
activities overlap time-wise, covering each program area by itself allows
the reader to see how each program area evolved over the decade.

Standards
When NERC’s Version 0 mandatory Reliability Standards were approved
by FERC to take effect on June 18, 2007, it marked the beginning of many
improvements in NERC’s efforts to develop strong, performance-based
Reliability Standards and the process by which they were developed.
Collectively, these achievements demonstrated the ERO’s improved
efficiency in standards development as well as its ability to respondquickly in response to emerging threats. By narrowing the scope ofoutstanding standards work, NERC moved closer to a steady state forstandards, making it better poised to address future risks to reliability.
Results-Based Standards

In pursuit of NERC’s results-based initiative, a team of industry, NERC, andRegional Entity representatives, developed a guiding set of principles for
improving the development and format of Reliability Standards based on
performance and risk-based methods. In 2009, this concept of “resultsbased standards” received widespread support from stakeholders andthe NERC Board and set the foundation for future work on standards.41
Strategic Improvements to Standards Development

The Standards Processes Manual was revised based on recommendations
from the MRC Standards Process Input Group (SPIG). The changes
enabled the ERO to develop technically sound standards more efficiently
and with better use of industry resources. Further, with the Board’s
direction, the Standards Committee developed a strategic plan andenhanced its charter, focusing on increasing its effectiveness and ability
to deliver quality standards in a timely manner.

41 See New Risk-Based Approach to Compliance Monitoring and Enforcement

for how
the interrelationship of results-based standards development and risk-based compliance
enforcement processes were made more efficient and effective.
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97

NERC cemented the implementation and continuation of these importantchanges with Board’s approval of the 2013–2015 Reliability Standards
Development Plan (RSDP), which represented a bold revision of NERC’s
approach to managing the standards development workload. Itestablished an ambitious goal of transforming the current body ofstandards to a set of clear and concise results-based standards that
ensured reliability while addressing NERC’s regulatory directives andconducting five-year reviews of standards. With these changes, NERC waspoised to transform the ERO’s standards into a body of steady-state,
results-based Reliability Standards.
BES Definition

A critical element in standards development was clarifying which systemfacilities were subject to the various requirements of the Reliability
Standards. The ERO Enterprise and its stakeholders worked together todevelop a definition that addressed the FERC Order Nos. 743 and 743-A.
The definition eliminated the basis for Regional Entity discretion in theapplication of the standards. As a result, Phase 1 of the BES definition wasapproved by the NERC Board of Trustees and filed with FERC andCanadian regulatory authorities in January 2012.
A BES definition, approved by FERC in 2012, provided a bright-line
definition of the facilities included in the BES with detailed inclusions andexclusions based on specific technical criteria that could be consistently
and uniformly applied across North America. Further work was initiatedto develop appropriate technical justification to support refinements tothe definition that were suggested by stakeholders during Phase I of theeffort.
In March 2014, FERC approved a further revision of the BES definition as
outlined in FERC Order Nos. 743, 773 and 773-A. As a result of the new
definition, all elements and facilities necessary for the reliable operationand planning of the BPS would be included as BES elements. FERC also
approved the process for review of elements on a case-by-case basis toallow for exceptions from the definition, where appropriate, as well as aprocess for entities to self-notify Regions of their determinations of BES
elements.

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The ERO also developed an enterprise-wide software application, the BES
Notification and Exceptions Tool (also called BESnet). Registered entities
could use BESnet to submit to their respective Regional Entity
notifications of changes to BES assets that affected the entity’s
responsibilities for compliance with the Reliability Standards.
Transformation to Steady-State Standards

In 2013, NERC retained a team of five industry experts to independently
review all standards requirements, setting the foundation for thetransition to a clear, concise, and sustainable body of standards. The
experts assessed the content and quality of the standards, including
identification of potential risks that were not adequately mitigated, anddeveloped recommendations for each requirement. The initialassessment determined whether a requirement should be retired andgave the remaining requirements a content and quality grade. The
experts assigned each requirement a reliability risk level andrecommended prioritization of future work based on the assigned grades
and risk.
In 2015, NERC continued to address the remaining FERC directives andrecommendations to retire requirements that did little to promotereliability, further transitioning to a stable set high-quality, technicallysound, and results-based Reliability Standards.
Once the Reliability Standards reached steady state, future projects
would assess standards for quality, content, or alignment with otherstandards through enhanced periodic reviews, projects addressing FERC
directives, or newly identified risks to the BPS.
Addressing 2003 Blackout Issues

Two sets of pivotal NERC standards adopted in 2008 addressed issues
from the August 2003 northeast blackout:


PRC-023-1–Transmission Relay Loadability addressed the
expected settings of load sensing relays to ensure they did notoperate undesirably during a system event. Following theblackout, events involving relays of this type significantly
decreased, and this standard helped ensure continued emphasison this issue.

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In August 2013, the Board adopted PRC-025-1–Generator Relay
Loadability under Phase 2 of the Relay Loadability project. This
three-phase project addressed FERC Order 733, which directed
NERC to address three areas of relay loadability that included
modifications to the approved PRC-023-1, development of a new
standard to address generator protective relay loadability, anddevelopment of another standard to address the operation ofprotective relays due to power swings.

Also stemming from the 2003 blackout, the electric industry approved
revised standards for operating personnel training that required the useof a systematic approach to training and a more rigorous and structured
framework for developing and delivering operator training.
Cyber Security Standards

FERC Order No. 706, which modified NERC’s CIP standards, was perhaps
the most high profile standards project early in the decade. In their
January 2008 conditional approval, FERC required an expedited review of
the CIP standards to address several weaknesses identified in the order.
NERC’s Cyber Security Order 706 drafting team developed a multi-phaseapproach and produced a first set of modifications for industry commentin only 45 days. Members of Congress and intelligence organizations
closely monitored the progress of this project into 2009.
In response to FERC Order No. 706, NERC diligently worked through its
industry-based drafting team to dramatically improve the scope andeffectiveness of its cyber security standards (i.e., CIP-002 through CIP009). In 2009, NERC submitted and FERC approved Versions 2 and 3 ofthese standards, providing incremental improvement to the original
versions approved in 2008. The majority of the improvements wereembodied in Version 4 of the CIP standards, which saw development in
the second half of 2009.
Frequency Response Concerns

NERC and FERC shared concerns about the frequency response of anInterconnection following a significant loss of generation. In February
2013, the Board adopted BAL-003-1–Frequency Response and Frequency
Bias Setting. This standard set a minimum frequency response obligationfor each Balancing Authority, provided a uniform calculation of frequency
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response and frequency bias settings that transition to values closer tonatural frequency response and encouraged coordinated automatic
generation control operation. The standard addressed two FERC Order
693 directives on BAL-003.
Vegetation Management Performance

Ineffective vegetation management was identified as a major cause of theAugust 14, 2003, blackout as well as other large-scale North American
outages. In response, NERC developed FAC-003–Transmission Vegetation
Management, formalizing transmission vegetation management
programs and reporting requirements.
Enhancements were made in FAC-003 Version 3, and a staged
implementation began in July 2014. Version 3 expanded the standard toinclude overhead transmission lines operated below 200 kV if they were
either an element of an Interconnection Reliability Operating Limit (IROL)
or an element of a major WECC transfer path. The standard also madeexplicit a Transmission Owner’s obligation to prevent an encroachment
into the minimum vegetation clearance distance, regardless of whether
that encroachment resulted in a sustained outage or fault.
For the first time, this standard required Transmission Owners to annuallyinspect all transmission lines subject to the standard and complete 100
percent of their annual vegetation work plan. Version 3 also incorporated
the minimum vegetation clearance distances into the text of the standard
rather than relying on clearance distances from an outside reference as
was the case in Version 1.
FERC issued Order No. 777, which called for additional research on
vegetation management issues and ordered NERC to conduct testing todevelop data on the flashover distances between conductors andvegetation. Since FAC-003-1 became effective in 2007,42 transmission
outages from grow-ins have consistently decreased.
Geomagnetic Disturbance Mitigation

In November of 2013, the Board adopted the standard EOP-010-1–
Geomagnetic Disturbance Operations, which required Transmission
Operators and Reliability Coordinators to develop and implement
42 FAC-003-1 was superseded by FAC-003-3 in July 2014.

History of the North American Electric Reliability Corporation101

operating procedures to mitigate the effects of geomagnetic disturbance(GMD) events.
The first-stage standard took effect in April 2015 and required entities
throughout North America to have GMD operating procedures to mitigate
the potential impacts of GMD on the electric grid. The second-stage
standard (i.e., TPL-007-1–Transmission System Planned Performance for
Geomagnetic Disturbance Events) was approved by FERC in September
2016. The new standard required entities throughout North America toperform state-of-the-art vulnerability assessments of their systems andequipment for potential impacts from a severe 1-in-100 year benchmark
GMD event and mitigate against identified impacts.
In 2017, entities began implementing the new requirements and mustmeet several steps leading to the completion of vulnerability assessments
and mitigation plans by 2022. In approving TPL-007-1, FERC directedcertain revisions to the standard, aimed at enhancing the benchmark
GMD event used in GMD vulnerability assessments, establishingdeadlines for entities to complete mitigation actions, and expanding thecollection of GMD data.

Compliance
Early NERC Efforts in Compliance Monitoring and Enforcement

The first full year of mandatory Reliability Standards in the United States
involved significant development, evaluation, and maturation of NERC’s
new “start-up” Compliance Monitoring and Enforcement Program(CMEP). In 2008, nearly 800 mitigation plans for more than 2,400
individual violations were submitted to NERC, demonstrating that
reliability across North America was being improved as a direct result of
NERC’s compliance monitoring and enforcement efforts. On June 4, thefirst 20 formal Notices of Penalty (NOPs) for violations of NERC Reliability
Standards were filed with FERC. A total of 40 NOPs with a total sum ofover $540,000 in financial penalties were filed in the first year of the
program. In addition, NERC and the Regional Entities performed andposted reports for more than 200 audits and participated in 19
investigations.

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In 2008, PRC-005–Transmission and Generation Protection System
Maintenance and Testing was the most violated standard, followed by
CIP-001–Sabotage Reporting.43 The majority of these violations were
documentation-related, and NERC and the Regional Entities considered
options to expedite the processing of such low-risk, low-severity
violations. Over 45 percent of the mitigation plans were completed withthe remaining plans either associated with violations identified late in theyear or underway according to plan. In 2008, a considerable backlog ofcompliance violations developed as the Regional Entities and NERC began
to move a large volume of initial violations through the compliance
process.
As of December 31, 2009, NERC had 1,950 active violations, the majorityof which were being assessed and validated. The others were insettlement negotiations or were being addressed in a NOP filing with
FERC. During 2009, NERC filed 221 enforcement actions with FERC, an
increase from 2008. The increase was due primarily to improvements in
enforcement processes and procedures made possible by staffing
increases as well as the natural growth in NERC and Regional Entity
expertise and experience in compliance monitoring and enforcement.
NERC made substantial headway on streamlining enforcement processing
by focusing both NERC and Regional Entity resources on the cases thatmost significantly impacted reliability. In 2009, NERC submitted to FERC
an “Omnibus” filing that resolved 564 violations, including a number ofolder, minor violations. The NERC Compliance Registry was fully
integrated into the Compliance Reporting, Analysis, and Tracking
Software (CRATS) program with an increase from 1,872 to 1,881
registered entities.
Also in 2009, Crowe Horwath LLP conducted an extensive CMEP audit on
NERC’s behalf. The resulting report contained 62 recommendations that
included providing more information to the industry and improving
auditor training. All but 10 of these recommendations were implemented
by the end of the second quarter in 2010.

43 This trend in “most violated” standards continued well into the decade.

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New Risk-Based Approach to Compliance Monitoring and
Enforcement

In order to focus efforts on those issues that had the most impact onreliability of the BPS, the ERO Enterprise needed to make changes to the
CMEP. This realization led to the development and implementation ofrisk-based compliance monitoring and enforcement processes.
NERC’s initial approach to compliance monitoring and enforcement was
driven by FERC’s and NERC’s zero tolerance stance. This stemmed in partfrom the 2003 Northeast Blackout—lack of trust at FERC and thedetermination that a zero penalty was a penalty determination and had
to be filed with FERC so all had to go through the legal process. This
resulted in very minor infractions being treated identically to major
violations, clogging up the system. It also resulted in substantial delay inthe development of improved standards as participants were wary ofcompliance pitfalls.
This problem was addressed after 2011: By better standards project
management by NERC, industry appointing more experienced people tostandards drafting teams, NERC moving to risk-based compliance withminor matters being handled expeditiously and with stakeholder supportand input, and NERC removing unnecessary requirements from standards
and eliminating some standards entirely. This cleared the backlog,
enabled standards to be developed and improved in much shorter timeframes, and allowed industry, NERC, and the Regions to focus on the mostsignificant risks to reliability.
Violation processing efficiency improved in 2010. This was due to theintroduction of risk-based processes and the lessening the administrative
burdens associated with processing lower-risk violations. Industry
continued the trend of self-reporting violations and timely mitigation—
both excellent indicators of a strong culture of reliability compliance.
Under the risk-based processes, new templates for NOPs were created inan effort to streamline the enforcement effort based on the magnitude
and risk of each violation.
An administrative citation process that enabled NERC and the Regional
Entities to address new violations by submitting a single streamlined NOP
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covering numerous lower risk violations, rather than requiring eachviolation to go through the several levels of process and documentation,
was also initiated.
Find, Fix, and Track Compliance Enforcement Initiative

The Find, Fix, and Track (FFT) initiative, which FERC endorsed in March
2012, allowed issues to be handled more efficiently by focusing on thoseposing a higher risk to reliability, streamlining administrative paperwork,and continuing to encourage self-reporting and mitigation. The FFT
initiative was a paradigm shift in how issues were processed and reflecteda risk-informed approach that recognized that all possible violations were
not equal and should not be treated in the same manner. By focusing
resources on violations that had a serious risk to the reliability of the BPS,NERC was able to better fulfill its mission.
Reliability Assurance Initiative

In August 2012, NERC’s Board began to discuss how to reach a desiredend state of compliance monitoring and enforcement for a mature ERO
as well as activities that would support an overall Reliability Assurance
Initiative (RAI). RAI was formally introduced at NERC’s November 2012
Board meeting with the purpose of identifying and implementing changes
to enhance the effectiveness of the ERO’s CMEP while avoiding cascading
events and the resulting major loss of load.
Foundational Elements in The Need for Change White Paper

Restyling the compliance monitoring approachEvaluating compliance data requirements

Refining compliance and enforcement information flowRedesigning the enforcement strategy

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The paper outlined a risk-based approach that drove a consistent
application of compliance monitoring practices based on risk, tools toprioritize and treat violations based on risk, enforcement practices withclear distinctions based on risk to reliability, and a strengthened feedback
loop from compliance monitoring and enforcement to the standards
development process to incorporate considerations of actual risk into thestandards themselves.
RAI built on the success of the FFT initiative and developed enforcement
incentives to distinguish between poor performance that must be
discouraged and positive behaviors that contributed to higher
accountability and improved performance. RAI recognized an entity’s risk
to reliability along with its management controls and corrective action
programs to meet the Reliability Standards and reduced CMEP’s
administrative burdens on industry while gaining efficiencies.
In 2014, NERC intensified its outreach efforts to ensure that the objectives
and design of the risk-based CMEP were clear to all interested parties.
NERC conducted training and outreach directed at ERO Enterprise staff toensure successful and consistent implementation. NERC also provided aseries of training opportunities for industry, including an “RAI 101”
webinar, which attracted more than 700 participants. In addition, NERC
conducted two industry outreach workshops, one on each coast, focusing
on stakeholder understanding.
Risk-Based Registration and Enforcement

Beginning at the end of 2013 and continuing throughout 2014, the ERO
Enterprise continued to implement two key, risk-based enforcement
programs—the Reliability Assurance Initiative (RAI) and the Risk-based
Registration (RBR) initiative—that allowed Regional Entities andregistered entities to focus their efforts on issues that posed the greatest
risk to reliability. The ERO Enterprise further expanded enforcement
discretion by identifying minimal-risk noncompliance that would berecorded and mitigated without triggering a formal enforcement action.
Noncompliance that was not pursued through an enforcement action by
the ERO was referred to as a “compliance exception.”

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Also, a small number of registered entities with demonstrated effective
reliability management practices were permitted to self-log minimal-risk
issues that would otherwise be individually self-reported. The number ofentities eligible to participate in this voluntary self-logging program
gradually expanded, allowing the ERO Enterprise to further adjust related
processes.
In 2014, NERC established the Risk-Based Registration Advisory Group(RBRAG) and its technical task force to provide input and advice on thedesign framework and implementation plan for the Risk-Based
Registration (RBR) initiative. The RBR framework included refined
thresholds based on sound technical analysis, risk considerations andsupport; reduced NERC Reliability Standard applicability based on soundtechnical analysis, risk considerations and support; and clearly definedterms, criteria, and procedures that were risk-based and ensured thereliability of the BPS as outlined in the BES definition. The proposed
enhancements reduced unnecessary burdens while preserving BPS
reliability.
FERC approved the first phase of the RBR initiative in March 2015,
resulting in proposed revisions to Sections 302 and 501 and Appendices2, 5A, and 5B of the NERC Rules of Procedure. The revisions wereapproved by FERC on March 19, 2015. The new registration processestablished clearer thresholds and ensured that registration was basedon risk to reliability, to the benefit of all stakeholders.
On February 19, 2015, FERC also issued an order approving the risk-based
CMEP developed under the RAI. The order directed NERC to propose
revisions to the Rules of Procedure to articulate the risk-based CMEP
concepts and programs. Five months later, NERC submitted a compliancefiling and petition for approval of Rules of Procedure revisions thatdefined fundamental risk-based CMEP elements, recognized theexistence of the risk-based CMEP processes, and articulated the riskbased CMEP concepts and programs.

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Coordinated Oversight for Multi-Regional Registered Entities

In 2014, the ERO Enterprise developed a program for CoordinatedOversight of Multi-Regional Registered Entities (MRREs).44 The program
was intended to streamline risk assessment, compliance monitoring andenforcement, and event analysis activities for the MRRE. It also resulted
in reduced administrative burdens for the MRRE and improved
consistency. Initial implementation of this program began in January
2015.
Align ProjectIn 2017, the ERO Enterprise executive team agreed that more unified
processes and systems were needed to help ensure that compliance andenforcement with Reliability Standards was monitored consistently
across the ERO Enterprise. The resulting Align Project, initially called the
CMEP Technology Project, was established with the vision and mission topromote greater efficiencies in work, better use of resources, and lower
costs while offering more flexibility and better alignment.
The Align Project—a suite of tools to integrate and share data—will betteraligned the business process of NERC and the Regional Entities, improve
documentation, sharing, and analysis of compliance and enforcement
work activities, and make CMEP activities more efficient and effective
across the entire ERO Enterprise.
The expected benefits of this complex project to the ERO Enterprise areundeniable and include the following:Improved ability to share and analyze compliance andenforcement information by being risk informed and adaptive totrends

Aligned and consolidated business processes and common tools
to increase efficiencyEnsured consistency in practices and data

44

An MRRE is a registered entity that has a single NERC Compliance Registry
number in more than one Region or affiliated registered entities in multiple
Regional Entities with multiple NERC Compliance Registry (NCR) numbers.
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

Defined and standardized the compliance monitoring andenforcement data for consistency in submission, reporting, andanalysisMeeting planning, conducting, reporting, and quality assurance
requirements under the Rules of ProcedureSignificant cost savings as the Regions won’t have to pay the costof supporting the upgrade of a number of different systems

When fully implemented in 2020, Align will provide the ERO Enterprisewith a more comprehensive, consistent, and efficient CMEP platform on
which to carry out the ERO’s mission of reliability and accountability.

Infrastructure Protection and Cyber Security
Initiatives
While NERC’s fifth decade saw significant growth and change in its
Reliability Standards and compliance monitoring and enforcement
programs, attention to infrastructure protection and cyber security grewand changed even more dramatically. Critical infrastructure protection
emerged as a top priority for NERC, the utility industry, and North
America. NERC’s efforts to improve the physical and cyber security of the
BPS dovetailed with virtually all of the organization’s responsibilities,
including standards development, compliance monitoring andenforcement, assessments of risk and preparedness, and disseminationof critical information to raise awareness of key issues.
In 2012, the NERC Board approved the Critical Infrastructure Strategic
Roadmap and Coordinated Action Plan recommended by the Electricity
Subsector Coordinating Council (ESCC). NERC also streamlined its
situation awareness and critical infrastructure protection programs,
expanded its role in ensuring the security of critical assets, issued six
security-related alerts, and worked closely with industry to begin
revisions of the CIP standards. NERC also established the Electric Sector
Steering Group—a group of industry chief executives who guided NERC’sefforts to address security-related issues.

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CIP Version 5 Standards

In November 2012, the NERC Board adopted ten CIP Version 5 standards
along with an associated implementation plan, Violation Risk Factor andViolation Security Level assignments, and revised terms for the NERC
Glossary. These standards recognized the differing roles of each entity inthe operation of the BPS, the criticality and vulnerability of the cybersystems needed to support BPS reliability, and the risks to which they are
exposed.
Key Advancements in CIP Version 5 Standards

Incorporation of implementation and audit lessons
from past versions

Flexibility for entities to tailor security in a manner best
suited to their own operations

Transition from the “in or out” classification of criticalassets and their associated critical cyber assets to a“low-medium-high” impact-based categorization

Categorization of cyber assets as low-, medium-, orhigh-impact assets, providing all bulk power systemcyber assets with a level of protection based on theimpact the cyber assets had on the grid.

The CIP Version 5 standards represented a significant change andimprovement over the CIP Version 3 standards as they included new
cyber security controls and extended the scope of the systems that the
CIP Reliability Standards were designed to protect. They were also thefirst risk-based standards focused on mitigating cyber risks to the BPS. As
such, these standards represented a milestone in the industry’s
continuing and growing emphasis on the importance of mitigating cyberrisks to the BPS.
In 2013, FERC approved the CIP Version 5 standards, permitting utilities
to transition from CIP Version 3 to CIP Version 5 without having to comply
with CIP Version 4. NERC initiated the CIP Version 5 Transition Program inan effort to collaborate with Regional Entities and applicable registeredentities in support of a timely, effective, and efficient implementation.
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technical security requirements for CIP Version 5 and clarify the
expectations for compliance and enforcement. NERC developed atransition guidance document and compatibility tables that comparedrequirements in CIP Version 5 with requirements in CIP Version 3. NERC
also developed an implementation study to collect and evaluate relevant
data from utilities regarding their implementations of CIP Version 5.
In November 2014, the NERC Board adopted proposed revisions to the
CIP Version 5 standards to remove the “identify, assess, and correct”
language and address FERC’s communication networks directive.
In July 2015, FERC issued a NOPR on the revised CIP standards that
addressed issues ranging from personnel and training to security of cybersystems and information protection. FERC’s notice sought to modify thescope and applicability of certain CIP standards to protect communication
links and sensitive data among control centers and sought comments oncontrols for transient electronic devices. The notice also called for thedevelopment of a standard (or standards) for supply chain management
security controls to further protect the BPS from security vulnerabilities
and malware threats.
Over the course of 2015, NERC and the Regional Entities provided a seriesof CIP workshops and curriculum to further prepare entities for CIP
Version 5 implementation.
This represented significant progress toward mitigating cyber risks to the
BPS by addressing vulnerability assessments, security management
controls, personnel and training, electronic security perimeters, incident
reporting and response planning, and recovery of cyber systems.
Supply Chain Risk Mitigation

On August 10, 2017, the NERC Board adopted proposed supply chain
standards and their associated implementation plans that addressedcyber security supply chain risk management issues and met thedirectives of FERC Order No. 829. NERC filed the supply chain standards
with FERC in September 2017. In January 2018, FERC issued a NOPR forthese standards.
In adopting the supply chain standards, the Board concurrently adopted
a resolution related to their implementation and evaluation that outlined
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six actions to assist in the implementation and evaluation of the supply
chain standards and other activities to address potential supply chain
risks for assets not currently subject to the standards.
ActionsSupport effective and efficient implementation.

Initiate a cyber security supply chain risk study.

Communicate supply chain risks to industry.



Develop forum white papers.



Develop association white papers.



Evaluate effectiveness of supply chain standards.

Electricity Information Sharing and Analysis Center

The mission of NERC’s E-ISAC45 is to reduce cyber and physical security
risk to the electric industry in North America by providing unique insights,
leadership, and collaboration. The vision is to be a world-class, trusted
source for quality analyses and rapid sharing of electric industry security
information.
This NERC division underwent significant transformation during thedecade as it built out its secure portal,46 added capabilities to aid in
information sharing and incident analysis, and rebranded as the E-ISAC.
The E-ISAC’s secure members’ portal was populated with reports andother relevant data on a nearly daily basis. In addition, the portal received
Indicators of Compromise that had been declassified from sources, suchas the classified United States Computer Emergency Readiness Team (USCERT) portal. The E-ISAC reformatted the data for distribution to the BPS
registered entities as well as other asset owners and operators on thegrid, including distribution providers. More than 40 percent of all
45 The Electricity Sector Information Sharing and Analysis Center was rebranded to theElectricity Information Sharing and Analysis Center in 2015. The terms will be usedinterchangeably in this book.
46 For much of the industry, this portal was the first and often primary interface with the
ES-ISAC. It allowed the ES-ISAC to reach thousands of customers and hundreds oforganizations across the industry, and this portal serves as the mechanism to reach out
to ES-ISAC staff with questions, concerns and security-related information.
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registered entities were represented on the portal, including nearly 700
unique user accounts.
NERC’s Board approved a policy statement that formalized the separationof functions between the E-ISAC and the ERO Enterprise’s CMEP to assure
industry of the separation and encourage an even greater flow of
information between industry participants and E-ISAC staff.
The E-ISAC improved its analytic capabilities by building out its operations
room to include data feeds from multiple sources, such as NERC’ssituation awareness monitoring tool and procuring services that delivercyber awareness and continuous monitoring.
The E-ISAC developed the NERC Crisis Action Plan, which guides ERO
Enterprise coordination in the face of a large security or operational
impact to the grid. It also supported federal sector and industry
coordination plans and DOE’s incident response survey project
development. These activities all supported greater coordination acrossindustry and with the federal government for responding to significant
cyber security events.
E-ISAC staff provided substantial support toward efforts initiated by
Executive Order 13636, “Improving Critical Infrastructure Cybersecurity,”
and a corresponding Presidential Policy Directive on critical infrastructure
security and resilience (i.e., PPD-21), issued in February 2013. The DHS
led implementation activities and established eight working groups toaddress different components of the order and policy. Working group
activities all focused on enhancing public–private partnerships,
developing tools and best practices for sectors to use, and ultimately,
reducing risk to critical infrastructure sectors. For all of these efforts,
NERC worked closely with industry representatives and government
partners to build new and improve on existing cyber security-focusedideas, processes, and products.
As part of PPD-21, government and industry updated the National
Infrastructure Protection Plan to reflect the partnership environment.
NERC and industry participated significantly in this effort and focused
efforts on maintaining the baseline partnership model that included thesector coordinating councils, the government coordinating councils, andHistory of the North American Electric Reliability Corporation

113the information sharing and analysis centers. This work included
identifying critical cyber assets within the electricity sector anddeveloping the National Institute of Standards and Technology (NIST)
Cybersecurity Framework. The partnership model remained intact
through the final version of the revised National Infrastructure Protection
Plan.
The E-ISAC continued to conduct Cyber Risk Preparedness Assessments(CRPA) exercises, expanding this effort in 2013. An industry workshop
provided specific training for industry to conduct CRPAs themselves. The
E-ISAC directly supported six CRPA engagements in 2013, including thefirst exercise with a Canadian entity. The CRPA program continued tomature in 2013 with the addition of the Electricity Sub-sector
Cybersecurity Capability Maturity Model key practice areas, which
informed and complemented the CRPA program.
In August 2013, the NERC Board approved a new Electricity Subsector
Coordinating Council (ESCC) charter, which included new membershipand bylaws. The charter provided for a total of 30 chief executive officer
level representatives, including members of the ESCC Steering
Committee. It also provided for continued collaboration of the ESCC with
the ISAC and DOE in communicating with the electric sector andenhancing industry’s ability to prepare for and respond to cyber andphysical threats, vulnerabilities, and incidents.
In January 2015, the ESCC began a six-month strategic review of E-ISAC to
improve its effectiveness and enhance its role in helping industry focus
on the reliability and resiliency of the BPS in the face of growing threats
to cyber and physical security.
Members of the ESCC received a report on the review of the E-ISAC,
comparing it to other ISACs and identifying challenges to theeffectiveness of information sharing in the electricity sector andopportunities to strengthen that effectiveness.

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Review Recommendations
Strengthen governance structure and processes tobuild a more effective and responsive E-ISAC

Advance the E-ISAC’s information collection capabilities
through enhanced member engagement, better
intelligence feeds, and an improved portal

Advance the E-ISAC’s analysis capabilities by continuing
to upgrade operational and staff capabilities



Improve the quality and value of E-ISAC products byidentifying member needs and expectations

As a result of the strategic review, the E-ISAC established an 11-person
Member Executive Committee (MEC), endorsed by the NERC Board, toincrease its stakeholder engagement and receive industry guidance. It
also expanded its capability by including real-time monitoring of the gridthrough close collaboration with NERC’s BPS Awareness team, thecreating two watch team shifts to extend monitoring, increasing industry
participation in the Cybersecurity Risk Information Sharing Program(CRISP),47 enhancing monitoring and industry awareness of physicalsecurity threats, initiating monthly presentations analyzing current threat
trends, and incorporating a Traffic Light Protocol into E-ISAC portal
communications.
The MEC’s role was to provide the E-ISAC with industry leadership andsupport on the implementation of the ESCC’s 2015 strategic review of the
ISAC. The committee was made up of 11 chief information officers or chief
security officers from all ownership sectors in the United States andCanada. This helped shape the direction of the E-ISAC and increase its
focus on member services. The committee’s ongoing activities include:
recommending short- and long-term strategic visions for the E-ISAC;
proposing goals for E-ISAC operations, capabilities, and controls; defining
a business strategy for products and services; and providing the E-ISAC
with industry leadership and guidance.

47 CRISP facilitates real-time, computer-to-computer data exchange involving potential
security threats identified through the monitoring of participating utilities’ networks.

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NERC’s E-ISAC has also worked to identify and help industry mitigate
cyber and physical security risks to the BPS with greater information
sharing capabilities, a strong response to cyber security events, and thelaunch of a pilot project for automatic threat information sharing among
utility networks. Information sharing efforts were enhanced by theincreased participation of portal members and broader industry
information sharing about potential cyber and physical security risks,
increased industry participation in the CRISP, continued issuance of NERC
alerts when appropriate, and regular interaction with industry,
stakeholders, and policy makers.
In 2016, the number of entities participating in CRISP grew as the program
included more than 30 utilities serving 75 percent of the United States’
electricity users. A key CRISP benefit for non-members continued to bethat registered entities throughout North America could receive valuable
unattributed threat information, including indicators of compromise,through the secure E-ISAC portal.
To address emerging cyber risks, the E-ISAC also launched a pilot projectto test automated threat information sharing technology among the
networks at a select group of utilities in anticipation of commercializing
the technology at a later date.
Grid Security Exercises (GridEx I–IV)

In November 2011, NERC hosted a grid security exercise (GridEx 2011)48
that focused the efforts of more than 75 organizations on validating thereadiness of the industry to respond to a cyber incident andstrengthening the crisis response functions of utilities to provide input forinternal security program improvements.
More than 230 organizations participated in NERC’s second grid security
exercise, GridEx II in November 2013. The event brought together
industry and government from the United States, Canada, and Mexico towork together on the response to a scenario that simulated a physical andcyber security attack. The 2013 exercise incorporated recommendations
detailed in the GridEx 2011 report and added an executive discussion
after completion of the simulated scenario. A report on the exercise
48 This exercise was the first GridEx. NERC followed with GridEx II, GridEx III, and GridEx

IV in 2013, 2015, and 2017, respectively.
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highlighted recommendations and lessons learned for industry to use
when preparing for and responding to cyber and physical threats,vulnerabilities, and incidents. The results were also incorporated into
strategic action by CIPC and the ESCC.
Participation in the biennial grid security exercises continue to grow in
scope and participation with more than 350 organizations participating in
NERC’s third grid security exercise. GridEx III was designed to enhance thecoordination of cyber and physical security resources and practices within
the industry as well as communication with government partners andother stakeholders, including those in Canada and Mexico. Built on
lessons learned from NERC’s past grid exercises, GridEx III brought
together more than 4,000 participants from across North America,
spanning the electric industry, DOE, DHS, the FBI, and the Department of
Defense as well as state and provincial governments in the United States,
Canada, and Mexico. The GridEx III scenario was designed to stress thesystem through a series of coordinated cyber and physical attacks against
automated systems and key transmission and generation facilities toallow utilities to enact their crisis response and recovery plans and walkthrough internal security procedures.
Mexican officials built upon their participation in GridEx III by asking NERC
to conduct a Cyber Risk Preparedness Assessment on Mexican utilities.
NERC also commented with the Edison Electric Institute on a UnitedStates–Canadian grid security and resiliency strategy.
The most recent grid security exercise, GridEx IV, involved more than
6,500 stakeholders from 450 organizations. The large-scale cyber andphysical attack scenario in GridEx IV was designed to overwhelm even themost prepared organizations. NERC used input from participants todevelop observations and propose recommendations to help industry
enhance the security, reliability, and resilience of North America’s BPS. A
separate but parallel executive tabletop was held between Canadianindustry and government leaders during GridEx IV. GridEx V will take place
November 2019.
NERC remains focused on its mission to assure the reliability andresilience of the BPS, which is inextricably tied to grid security. Exercises
like GridEx ensure industry is as prepared as possible.
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117

GridSecCon

The first Grid Security Conference (GridSecCon 2011), a two-day
conference hosted by NERC in the SERC Region, brought more than 260
industry and government security experts from the United States andCanada together to provide real tools and information that would
improve the security posture of companies. NERC hosts GridSecCon
annually since 2011, rotating each year to a different NERC Region.
GridSecCon 2012 in the WECC Region added a training day with cyber andphysical security tracks to the conference and attracted more than 270
stakeholders overall.
GridSecCon 2013, which occurred in the FRCC Region with 325 industry
and government security experts, again focused on physical and cybersecurity issues. Speakers addressed transformational, strategic, andtactical approaches to securing systems. Participants also considereddifferent information-sharing techniques; determined whether theirorganizations were resilient through self-assessments; tested response
activities through exercises; worked to ensure that security is consideredwhen building operations; and developed ways to enhance the workforce
by recruiting, training, and retaining individuals who can address theseand other issues. Additionally, almost 200 stakeholders attended
credentialed training sessions in cyber and physical security.
GridSecCon 2014 in the Texas RE Region drew even more participation to
discuss prevention of cyber and physical threats and share best practices.
More than 360 senior industry and government leaders and subject
matter experts discussed strategy, tactics, and tools to ensure thereliability and resiliency of the grid. As in GridSecCon 2012 and 2013,attendees received credentialed training sessions in cyber and physicalsecurity.
GridSecCon 2015 in the ReliabilityFirst Region drew more than 400
industry and federal partners. The objectives of this conference included
promoting reliability of the BPS through training and industry educationand delivering cutting-edge discussions on critical infrastructure
protection security threats and lessons learned. Senior industry andgovernment leaders informed participants of security best practices on
reliability concerns, risk mitigation, physical security, and cybersecurity
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NERC’s E-ISAC, cyber and physical security technology options, and thetransition to CIP Version 5 standards.
GridSecCon 2016 in the NPCC Region drew more than 410 participants,
who heard from NERC President and CEO Gerry Cauley that the Ukraine
incident49 was a “game changer” requiring the industry to assess thebreadth of its connectivity to the internet and narrow potential accesspoints for potential adversaries. The discussion at GridSecCon 2016 also
focused on the ongoing cyber and physical security collaboration of U.S.
and Canadian utilities with government agencies and how CIP V5
Reliability Standards provide the foundation for a comprehensive gridsecurity approach.
GridSecCon 2017, hosted in the MRO Region, was attended by more than
500 leading cyber and physical security experts from industry andgovernment who gathered to discuss the latest training and tools to
succeed in a dynamic threat environment. Discussions included UnitedStates and Canadian perspectives on industry and government
collaboration addressing potential grid security threats, industry
partnerships with law enforcement, insider threats, geomagnetic
disturbances, and electromagnetic pulse research. The agenda also
featured a day of cyber and physical security training for industry, aclassified security briefing, and a tabletop exercise to prepare GridSecCon
participants for NERC’s GridEx IV.
GridSecCon 2018, held in the WECC Region, was co-hosted by NERC andWECC to highlight cooperation on security challenges within the ERO
Enterprise and attracted close to 600 industry, government, and vendor
attendees.

49 NERC’s involvement in the investigation of the Ukraine cyber attack and its robust

information sharing with industry following the event culminated in a confidential alert
to the North American electric sector and showcased the benefits of industry
membership in the E-ISAC. Ukrainian utilities affected by the attack lacked the basic
cyber hygiene embodied in NERC’s CIP standards, according to a lessons learned reportby NERC and the SANS Institute.

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119High-Impact, Low-Frequency Risks

In July 2009, NERC and DOE partnered in an effort to address high-impact,
low-frequency risks to the reliability of the North American BPS. NERC’s
Critical Infrastructure Protection team partnered with NERC’s Reliability
Assessment and Performance Analysis team to gather industry and risk
experts for the development of a workshop on the subject.
While there are several threats labeled “high impact, low frequency,” theERO Enterprise’s greatest concern is being prepared for possible events
that could debilitate the BPS for extended periods, such as widespread,coordinated physical and cyber attacks, pandemics, and electromagnetic
pulses or geomagnetic disturbances. To address these types of events,
NERC produced the Spare Equipment Database System report in October
2011 and the Effects of Geomagnetic Disturbances on the BPS interim
report in February 2012.
Collaboration with Governments

NERC’s fifth decade was also a period of close collaboration on cybersecurity with the U.S. Congress through the DHS Emerging Threats, Cyber
Security, and Science and Technology Subcommittee. This collaboration
culminated in an unprecedented summit meeting with top
government officials and industry chief executives and focused on
raising industry awareness and building public–private partnerships toaddress this issue in Washington, D.C. NERC outlined plans to conduct
an assessment of industry’s preparedness to appropriately address
cyber security threats as well as its plans to develop a comprehensive
and continuous security risk assessment process.
In 2013, the E-ISAC, DHS, DOE, and the FBI collaborated to host a seriesof briefings focused on tactics and tools of emerging cyber threat actors.
This campaign included a multi-city tour of the United States and wasdeveloped following a NERC alert that detailed how common tools could
be used to infiltrate critical infrastructure networks and gain access tocontrol system networks.
In the wake of the April 16, 2013, Metcalf substation incident in California,
the E-ISAC, FERC, DHS, DOE, National Labs, and selected major tradeorganizations began a physical security briefing series to raise awarenessof physical attack threats; increase local, regional, and federal security
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partnerships; and support mitigation efforts. The series kicked off inDecember 2013 and ran through the first quarter of 2014 in 13 locations
across the United States and Canada.
NERC’s Critical Infrastructure Protection program led the North American
Synchro-Phasor Initiative (NASPI) in partnership with DOE and madesignificant progress toward driving the adoption of this promisingtechnology across the grid. In 2008, approximately 20 synchro-phasors
were installed as a result of these efforts with notable progress made in
ERCOT and PJM.

Reliability Assessment Activities
Reliability assessments have been a staple of NERC’s activities since thefirst reliability assessment report issued by the NERC Interregional Review
Subcommittee in 1970. Over the years, the scope and depth of NERC’slong-term, seasonal, and special reliability assessments has grown as
NERC analyzed an industry in transformation with natural gas overtaking
coal as the largest source of peak generating capacity and more than
260,000 MW of new renewable generation (biomass, geothermal, hydro,
solar, and wind). These changes have raised a variety of emerging issues
and risks including greenhouse gas reductions, transmission siting, cybersecurity, reactive power, voltage control, and energy storage.
NERC’s reliability assessments reached a watershed level of recognitionin 2010, when NERC issued several reports to raise awareness and help
industry prepare for changes, such as proposed Environmental Protection
Agency regulations, integration of renewable resources, and smart gridtechnologies. NERC issued a Special Reliability Scenario Assessment:
Resource Adequacy Impacts of Potential U.S. Environmental Regulations.
Individually and collectively, these assessments showed the vital role
NERC plays in educating the industry, policy makers, media, and the public
about the reliability risks of changing the resource mix for the BPS without
adequate coordination and planning.

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121

Reliability Impacts of Climate Change

In late 2008, NERC released its Special Report on Electric Industry
Concerns on the Reliability Impacts of Climate Change Initiatives. The
report addressed the potential impact of policies to reduce carbon
emissions versus direct impacts of climate change, such as more severe
weather, rising sea levels, drought, etc.
Improvements to data collection, completed early in the year, drove
significant improvements to the entire assessment process, enabling staff
to analyze issues in greater detail and identify findings that were invisible
in earlier years.
Increased Dependence on Natural Gas

NERC released its 2011 Special Reliability Assessment: A Primer of the
Natural Gas and Electric Power Interdependency in the United States as afoundational review of natural gas and electric interdependencies thatassessed existing and future challenges, identified areas of vulnerability,and provided recommendations for enhancing reliability.
In 2013, NERC published its second phase report, Accommodating an
Increased Dependence on Natural Gas for Electric Power. The report
determined the different risks that can affect reliability and identified
approaches to minimize vulnerabilities and areas where coordinatedinter-industry efforts could provide enhanced system reliability. The
report advocated a layered approach for transmission and resource
planners to consider in the context of larger, multi-area vulnerability andinfrastructure assessments.
In 2015, natural-gas-fired generation surpassed coal as the predominantfuel for electric generation and was the leading fuel type for capacity
additions. The emerging dependence on natural gas generation
combined with growing reliance on wind and solar resources increased
electric and natural gas infrastructure interdependencies and resulted in
BPS operational and planning reliability challenges, according to Special
Reliability Assessment: Potential Bulk Power System Impacts Due to
Severe Disruptions on the Natural Gas System.
Several regional study groups, including the Western Interstate Energy
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Midcontinent Independent System Operator, focused their attention onthese issues and used NERC’s recommendations as a foundation forfurther analysis.

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123

Essential Reliability Services

The changing resource mix projections identified in NERC’s long-term
reliability assessments signaled that more attention and focus wasneeded to address the straining of essential reliability services, including
new operational tools and procedures.
The Essential Reliability Services Task Force Measures Framework reporthighlighted the need to provide voltage control, frequency support, andramping capability to balance and maintain reliability of the grid; raiseawareness of potential impacts to reliability; and produce definitions,characteristics, and a tutorial for policy makers at federal, provincial, andstate levels. The group’s concept paper identified the key characteristics
of a reliable grid in two main categories: voltage support and frequency
support.
In November 2016, FERC proposed to require that large and small
generators provide primary and sustained frequency response capability
and apply certain operating requirements based on NERC guidelines. It
was significant that FERC’s proposal recognized the importance of
frequency response as an essential reliability service.
The operating characteristics of smaller distributed energy resources,
including rooftop solar, were also a focus for NERC in 2016. The newly
formed NERC Distributed Energy Resources Task Force discussed the needfor observability and control of these resources as well as appropriateload and generation modeling to evaluate their potential BPS impacts.
NERC recommended an initiative to undertake a comprehensive review
of its Reliability Standards to ensure they promoted sufficient levels of
essential reliability services, generator performance, system protection
and control, and balancing functions.
Integration of Variable Generation

The NERC Integration of Variable Generation Task Force (IVGTF)
developed a number of recommendations that spurred significant action
across the industry. This included the identification of potential gaps andenhancements to NERC Reliability Standards and guidance on developing
new operating procedures and planning considerations, specifics on

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unique regional challenges, differing market structures, and regulatory
policies.
The IVGTF, led by NERC and made up of nearly 100 industry experts,
tackled the enormous challenge of assessing the reliability impacts ofintegrating large amounts of generation, such as wind and solar, into the
BPS. This fundamental change in North American energy supply required
significant adjustments to the industry’s historic planning and operating
techniques for maintaining reliability. The task force’s 95-page report
included a work plan, pursued by more than a dozen task groups, focusedon topics including modeling, capacity/energy planning, wind forecasting,Reliability Standards, and energy storage. Leadership of this task force
earned NERC a technical achievement award from the Utility Wind
Integration Group for “a seminal effort in investigating the impact of[variable] resources on bulk system reliability.”Frequency Response Initiative

In 2010, NERC launched the Frequency Response Initiative tocomprehensively address the issues related to frequency response. In
addition to coordinating the myriad efforts underway in frequency
performance analysis and related standards development, the initiative
included in-depth analysis of Interconnection-wide frequency response
performance to achieve a better understanding of the technical factors
influencing frequency behavior across North America.
In 2012, NERC published the Frequency Response Initiative report, which
presented a comprehensive overview of the work done to-date towardgaining understanding of frequency response. The report included indepth statistical analysis of frequency response performance trends, an
overview of the current state of frequency responsive resources, ananalysis of the frequency response requirements, and technicalrecommendations for improving frequency performance across North
America.
A related key achievement was the passage of the BAL-003-1–Frequency
Response and Frequency Bias Setting standard. This standard clarified
frequency response obligations for Balancing Authorities and offered ameans for measuring their performance.

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2017 Frequency Response of the Eastern Interconnection

In a June 2017 filing on FERC Order No. 794, NERC submitted an updated
assessment of the primary frequency response for the EasternInterconnection. The report concluded that the Interconnection
frequency response obligation under Reliability Standard BAL-003-1.1 forthe Eastern Interconnection was adequate during light-load conditions.
As a result, NERC found no impending need for immediate action but
recommended that the ERO Enterprise continue its efforts to improve
dynamic modeling for studying frequency response and continue its
analyses of frequency response-related matters.
Geomagnetic Disturbances

NERC, as part of the Geomagnetic Disturbance Task Force, released the2012 Special Reliability Assessment Interim Report: Effects ofGeomagnetic Disturbances on the Bulk Power System. This reporthighlighted the potential for voltage collapse and the damage or loss oflimited number of vulnerable transformers across the BPS of North
America. The interim report provided industry with a roadmap for action
to address geomagnetic disturbances.
Specifically, the report identified four recommendations for industry:126Improve tools for industry planners to develop geomagnetic
mitigation strategies.



Improve tools for system operators to manage geomagnetic
impacts.



Develop education and information exchanges between
researchers and industry.



Review the need for enhanced NERC Reliability Standards.

History of the North American Electric Reliability Corporation

Achievements in 2012 included the following:

Development of operating procedure templates for transmission
and generation operators that reflected best practices andconsensus among technical experts

Improved ground conductivity models that represented thegeological regions of North America and a draft application guidefor geomagnetic induced current (GIC) modelingInitiation of a transformer modeling and testing project tovalidate models used to assess the effects of GIC on transformers

The Phase 2 action plan was officially kicked off via a public webinar in
July 2012. The task force's quarterly webinars and in-person meetings
contributed to a strong collaborative climate between industry,
researchers, and policy makers to continue development of an effective
risk control strategy for geomagnetic disturbances.
Cold Weather Assessments

The NERC Operating Committee developed the Reliability Guideline:
Generating Unit Winter Weather Readiness–Current Industry Practices,which provided a general framework for developing an effective winterweather readiness program for generating units throughout North
America. A “Cold Weather Event Training Package” was developed toassist nontraditional cold weather registered entities in properly
preparing for cold weather events.
NERC’s review of the extreme weather event that occurred January 6–8,
2014, detailed how the BPS showed its resiliency during the polar vortex
and that BPS reliability was maintained despite sustained record-low
temperatures occurring over a large geographic area in North America.
Key factors during the event included fuel deliverability issues, natural gas
pipeline outages, natural gas service interruptions, frozen electricity andnatural gas equipment, and other extreme cold weather operating
challenges. Grid operators employed techniques, such as voltage
reduction and demand-side management to ensure that BES reliability
was maintained during the event.

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127

Potential Reliability Impacts of the EPA’s Proposed Clean Power
Plan Preliminary Report

The Potential Reliability Impacts of EPA’s Proposed Clean Power Plan
special assessment examined the potential reliability concerns that could
result from the plan’s implementation. This assessment provided afoundation for future reliability analyses and evaluations required by the
ERO Enterprise, stakeholders, and federal and state policy makers tocreate a framework with realistic timelines that accommodated the
expected infrastructure deployments needed to support BPS reliability
while achieving the environmental objectives of the proposed rule.
Solar Eclipse White Paper

In 2017, NERC developed A Wide-Area Perspective on the August 21,
2017, Total Solar Eclipse white paper —the first white paper of its kind.
While the eclipse did not pose any reliability concerns for the North
American BPS, the white paper recommended preparation and increased
coordination by system planners and operators to understand how the
eclipse affected power flows and resource commitment. It also called for
utilities across the United States to conduct studies of the eclipse’s impact
on solar photovoltaic output and on their systems’ ability to meet theincreased electricity demand from non-solar resources.
Solar Inverter Report

A joint NERC and WECC task force investigated the August 16, 2016,
occurrence in the Western Interconnection that resulted in the loss ofapproximately 1,200 MW of solar photovoltaic generation. The task force
found the loss of inverter power injection was due to an incorrectly
calculated low-frequency condition and momentary cessation of theinverters in response to depressed voltages. The loss of significant
amounts of inverter-based resources due to transmission faults
highlighted a previously little understood risk to reliability.
The task force produced the 1,200 MW Fault-Induced Solar Photovoltaic
Resource Interruption Disturbance Report, which found that inverters are
susceptible to tripping during transients generated by faults on thetransmission system. The report found many of the resources tripped asthey used near-instantaneous frequency calculations that erroneously
indicated very low frequencies. The task force recommended a minimum
delay for frequency tripping to ensure accurate system frequency
calculations. The task force continues to work on recommendations for
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inverter behavior and momentary cessation during fault conditions to
support BPS reliability.

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129

Special Reliability Assessment on Generator Retirements

NERC issued a special assessment in late 2018 to identify potential
resource and transmission planning challenges that might arise or beexacerbated by an accelerated pace of conventional generator
retirements. Using a stress-test scenario, NERC examined how theaccelerated pace of generation retirements could impact resource
adequacy, fuel assurance and fuel diversity, and transmission system
reliability.

Event Analysis and Trends
Analyzing BPS events for lessons learned and trends is a fundamental partof assuring and improving system reliability. BPS events, large and small,offer a treasure trove of information about BPS behavior during unusual
conditions that can help system planners and operators avoid future
events and improve overall reliability.
NERC itself came into being as a result of the 1965 northeast blackout andmany of the Reliability Standards, practices, and procedures in place
today came about due to detailed analyses of that event.
Event Analysis Program

In 2010, NERC started a new Event Analysis program that provided a
wealth of information for trending the causes of system events andeffective mitigating actions. It also allowed NERC and the Regional
Entities, working together with industry, to assess several hundred events
each year to determine steps needed to minimize future risks.
NERC formed the Event Analysis Coordinating Group to provide
coordination between the Regional Entities and the Interconnections tofacilitate consistency, accuracy, and timeliness in event analyses.
In 2009, two major technical reference documents—both the culminationof several years of work—were published. The Protection System
Reliability–Redundancy of Protection System document provided
technical justification for a Standard Authorization Request (SAR) on
protection system redundancy. The landmark Power Plant andTransmission System Protection Coordination document resulted from arecommendation in the August 14, 2003, northeast blackout report aswell as from the ongoing need for generation–transmission protection
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coordination, as demonstrated by findings by NERC Event Analysis. This
document was referenced by the standards drafting team that worked on
PRC-001–System Protection Coordination and was the subject of ongoingcollaboration with the IEEE Power System Relay Committee.
NERC Alerts

In 2008, NERC issued its first “alerts,” launched the online “Reliability
Benchmarking Dashboard,” and, for the first time, included reliability
performance statistics in the Long-Term Reliability Assessment. The 17
alerts, generated by the Events Analysis and Critical Infrastructure
Protection programs, covered issues from cyber vulnerabilities to lessons
learned on relay maintenance practices. The alerts program showedsignificant promise in helping owners, operators, and users of the BPS
improve reliability.
NERC issued a Level 1 advisory alert after the identification of a trend in
345 kV SF6 puffer-type circuit breaker failure and the potential risk this
posed to the reliability of the BPS. The alert made industry aware of therecent failures and the published maintenance advisories so appropriate
action could be taken by entities with this type of equipment.
While the alert was advisory in nature and did not require specific action,
there was close collaboration with the North American Generator Forumand North American Transmission Forum as well as trade associations
with members who had that type of 345 kV equipment. The advisory
provided an excellent opportunity for NERC to work directly with theforums and trades to determine the extent of the condition and address
the potential risk to the BPS.
Collaboration with FERC on Joint Inquiries

In 2011, FERC and NERC collaborated on two joint inquiries the Southwest
extreme cold weather event in Texas and Arizona in February and theSouthwest outage in Arizona and California in September. By partneringin these efforts, the expertise of both FERC and NERC was leveraged, andthe importance both organizations placed on reliability to the grid wasemphasized. These inquiries examined the policies and procedures ofaffected utilities and identified potential improvements and lessons
learned.

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131Southwest Extreme Cold Weather Event

The southwestern region of the United States experienced unusually cold
and windy weather during the first week of February 2011. Lows during
the period were in the teens for five consecutive mornings and there weremany sustained hours of below freezing temperatures throughout Texas
and in New Mexico. These extreme cold weather temperatures caused
electric and natural gas outages and curtailments that affected a total of
4.4 million customers over the course of the event from February 2
through February 4.
On August 16, 2011, FERC and NERC concluded a six-month inquiry into
the event and released a staff report with recommendations to help
prevent a recurrence of rolling blackouts and natural gas curtailments
experienced by customers in the Southwest.
Southwest Outage

On September 8, 2011, a major cascading outage occurred inSouthwestern United States and Northern Mexico, leaving approximately
2.7 million customers without electricity. The outage affected parts of
Arizona, Southern California, and Baja California Mexico.
NERC and FERC co-led the investigation of the outage, identifying 27
findings and associated recommendations. NERC staff worked closelywith WECC staff to follow up on actions required to be taken by entities
directly involved in the event as well as other Transmission andGeneration Owners/Operators, Transmission Planners/Coordinators,
Balancing Authorities, Reliability Coordinators, ISOs, and WECC itself. Oneof the results of the investigation was the separation of the Reliability
Coordinator function from WECC, leading to the formation of Peak
Reliability—an independent Reliability Coordinator for the WesternInterconnection.50 The joint report on the event investigation was
released in May 2012.
Additionally, the seven other Regional Entities and the NERC Operating
and Planning Committees worked to address the report’s findings andrecommendations, resulting in a broad range of reliability actions acrossthe North American grid. From the 27 recommendations, WECC
50 The status of Peak Reliability as the single Reliability Coordinator for the entire WECC

Region is currently uncertain.
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undertook 52 specific activities with another 77 specific activities
addressed by eight WECC registered entities. The activities were divided
into four categories: Organization, Reliability Coordinator, Operations andPlanning, and Compliance. All the recommendations identified in the
FERC/NERC joint report applied to all entities—not just those in theWestern Interconnection.
NERC, WECC, and the other Regional Entities recognized that theactivities undertaken as a result of the blackout provided a unique
opportunity to make significant long-term improvements to the reliabilityof the BPS throughout North America.
Reliability Metrics and State of Reliability Reports

In 2010, NERC developed a set of reliability performance metrics forcomparing year-to-year performance. It also adopted risk-based priorities
in standards development, compliance audits, enforcement, and training.
NERC’s initial efforts were on improving performance in relay
maintenance, operator training and communications, and right-of-way
maintenance, including vegetation management.
The first State of Reliability report, released in May 2011, assessed gridreliability based on performance trends identified through data andanalysis of system disturbance events. The report represented NERC’s
integrated view of ongoing BPS reliability performance trends andassessed 18 reliability performance metrics that measured whether anadequate level of reliability existed in North America. The report also
included an analysis from the frequency response initiative, the 2011
demand response availability assessment, event analysis trends, andpost-seasonal assessments.
The State of Reliability reports represent a premier evaluation of BPS
reliability performance in North America and serve as a key vehicle togather insights and identify trends—grounded in solid technicalperformance data—that industry can use to improve reliability andaccountability. The overall strength of the performance analysis, solid
technical foundation, sophisticated statistical analyses, and integrated
validation with actual system events are considered one of the strengthsof a risk-informed approach to ensuring and enhancing BPS reliability.

History of the North American Electric Reliability Corporation133

According to the State of Reliability 2018 report, protection systemmisoperations continued a five-year decline, decreasing to 7.1 percent,down from 8.3 percent in 2016, 9.4 percent in 2015, and 10.4 in 2014.
The three largest causes of misoperations remained the same, including
Incorrect Settings/Logic/Design Errors, Relay Failure/Malfunctions, andCommunication Failures. Report findings indicated that the BPS
continued to perform well in 2017 and that improvements across several
areas in the past year boded well for continued reliable operation.

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Energy Management System Reliability

In 2013, the NERC Event Analysis program received 30 event reports
detailing a complete loss of System Control and Data Acquisition (SCADA)
system monitoring or control lasting more than 30 minutes. As a result,
NERC hosted its first Monitoring and Situational Awareness conference in
September that focused exclusively on improving Energy Management
System (EMS) reliability. The conference brought together more than 90
operations and EMS experts from more than 55 registered entities fromacross North America as well as a variety of vendors and consultants.
NERC published four lessons learned about EMS outages and worked tobuild and support an industry-led EMS Task Force. The work and active
information sharing of this group has reduced residual risk associatedwith this potential loss of situation awareness and monitoring capability
and continues to provide valuable information to the industry.
Resilience

In 2017, resilient BPS across North America maintained reliable
operations during hurricanes Harvey and Irma and quickly recovered fromstorm-related damage. Many lessons learned from past weather events
as well as infrastructure hardening and new technologies were deployed
to speed restoration efforts.
The revamped E-ISAC Portal, GridEx, and GridSecCon were among the
programs and initiatives that strengthened the cyber and physicalsecurity posture of the industry and contributed to the reliability andresilience of the BPS as a whole during the events.
RISC Report on Resilience

In response to an August 2017 DOE report on reliability and resilience inlight of the changing energy environment, the NERC Board directed theRISC to develop a framework for resilience and examine resilience intoday’s environment. The RISC worked with NERC stakeholders to
reexamine the meaning of resilience in today’s changing environment andhow resilience impacts NERC activities. RISC’s November 2018 reportsummarized the results of this examination of resilience, including theRISC Resilience Framework. The report stated that resilience is a criticalaspect of reliability of the BPS and central to NERC’s mission.

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135

Risk-Based Strategies and Initiatives
Reliability Risk Management Principles and Priorities

In 2012, NERC’s Board, responding to the recommendation of theStandards Process Input Group (SPIG), created the RISC and tasked it withadvising the Board on ERO reliability strategy. The RISC was made up ofindustry executives and thought leaders, including representatives fromthe Operations, Planning, Standards, Critical Infrastructure Protection,
and Compliance and Certification Committees. As such, RISC was acollaborative effort created to assist setting priorities on issues ofimportance to the reliability of the BPS.
The initial work of RISC led to a set of recommended broad ERO priorities
that were critical in formulating the overall risk-informed ERO strategic
approach. These priorities encompassed cyber attacks, workforce
capability and human error, protection systems, monitoring, andsituational awareness. The emphasis was to clearly identify the mostimportant reliability risks so relevant projects could be formulated andresources allocated to best address them through a disciplined approachat both the NERC and Regional Entity level.
Based on further input from the State of Reliability report and several
assessments, a refined set of risk recommendations was finalized for
NERC’s Board. These recommendations included an additional highpriority reliability risk: adaptation and planning for change to reflectsignificant fundamental changes occurring in the industry, such asincreased use of renewables, environmental regulations, increased
dependence on natural gas, and the growing use of demand response.
NERC hosted a Reliability Leadership Summit in 2013 for key industry
executives and business leaders to provide insights about reliability of the
BPS. A composite set of top priority reliability risks were identified forfocus and strategic attention to lessen these potential risks in the future.
Reliability Leadership Summits are conducted every other year.

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2013 Top Priority Reliability Risks
1. Changing Resource Mix
2. Resource Planning
3. Protection System Reliability
4. Uncoordinated Protection Systems
5. Extreme Physical Events
6. Availability of Real-Time Tools and Monitoring
7. Protection System Misoperations
8. Cold Weather Preparedness
9. Right-of-Way Clearances
10. 345 kV Breaker Failures
As the Reliability Risk Management Process matured, it produced periodic
updates, broad input and staged evaluation of the effectiveness ofongoing risk management projects, and served as input to the ERO
Business Plan and Budget.
Assessing Facility Ratings

To assess the accuracy of their facility ratings, Transmission Owners
developed lists of high-, medium-, and low-priority facilities. For theirhigh-priority facilities, they developed remediation plans and reported
every six months on the status of remediation efforts. More than 96
percent of the transmission facilities classified as high-priority by theirowners were determined to have as-built field conditions consistent with
their design and ratings. Of those with discrepancies, 88 percent were
fully remediated by the end of 2013. While assessing the accuracy offacility ratings is an ongoing activity, these initial efforts substantiallyreduced the risk to BPS reliability.

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Risk-Based Initiatives and Reliability Risk Priorities Report

Over the course of 2015, the ERO Enterprise focused on fully
implementing several risk-based initiatives to further prepare the ERO to
adapt as the BPS faced a new and exciting future. The adoption of a riskbased approach benefited reliability by allowing the ERO to allocate
appropriate time and effort to higher-risk issues that faced the BPS
without ignoring lesser risk issues. These initiatives focused on
improvements to compliance and registration to better reflect thisevolving reliability approach.
In the 2017 ERO Reliability Risk Priorities Report, the RISC reviewed andassembled information from ERO Enterprise stakeholders, policy makers,
and focused executive leadership interviews to develop a composite setof risk profiles, categorized as high, moderate, or lower risk.
High Risk Profiles:


Cyber Security Vulnerabilities



Changing Resource MixBulk Power System PlanningResource Adequacy

Moderate Risk Profiles:

Increasing Complexity in Protection and Control Systems



Loss of Situational AwarenessPhysical Security Vulnerabilities

Extreme Natural Events

Lower Risk Profiles:

Human Performance and Skilled Workforce

These results were incorporated into the ERO Enterprise’s 2018 strategicand operational plans.

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ERO Enterprise Long-Term Strategy and Enterprise Program
Alignment Process

In 2017, after the substantial progress achieved in its first 10 years ofoperation as the ERO, the NERC Board approved the first ERO EnterpriseLong-Term Strategy, identifying significant new developments andrelated risks affecting reliability and establishing six key focus areas toguide the ERO Enterprise’s work over a five-to-seven year horizon:


Risk-Responsive Reliability Standards

Objective, Risk-Informed Compliance Monitoring, Mitigation,
Enforcement, and Entity Registration

Reduction of Known Reliability Risks



Identification and Assessment of Emerging Reliability Risks



Identification and Reduction of Cyber and Physical Security Risks



Effective and Efficient ERO Enterprise Operations

This strategy, informed by expertise from all sectors of the industry,
provided an excellent basis on which to develop the ERO Enterprise’s
coordinated annual budgets and business plans and three-year work
plans, enabling everyone to keep a laser-like focus on achieving the ERO’s
mission.
The long-term strategy included mitigating risk through improved
analytics that address the operational changes that are being driven by
the growth of variable—renewable resources and greater dependence onnatural gas generation. Key to the ERO Enterprise’s success will bemaintaining strong partnerships with many regulators and policy makers,
including Congress, the Federal Energy Regulatory Commission, theDepartment of Energy and United States state regulators as well as
Canadian provincial and national regulators and policy makers.
Using the ERO Enterprise Program Alignment Process, NERC captured
identified issues from various resources in a centralized repository. NERC
then classified the issues through an initial screening to ensure theappropriateness for this process and then worked with Regional Entities
and the Compliance and Certification Committee to analyze the issues
and determine their scope and material impact. Finally, NERC posted theHistory of the North American Electric Reliability Corporation139issues along with recommendations and results and provided status
updates on its activities.

Collaboration with Canada, Mexico, and International
Entities
The international mission of the ERO recognizes that the interconnected
BPS in North America is an international grid, spanning ten sovereign
jurisdictions in three countries. As this grid continues to evolve in
response to policy mandates in each of these jurisdictions, advances intechnology, and other drivers, it is essential that the regulatory
frameworks for reliability are compatible and consistent acrossjurisdictional boundaries to provide clarity and certainty for planners andoperators and to prevent a recurrence of the international blackouts that
led to the creation of an international ERO.
Collaboration with Canada

In 2013, NERC enhanced outreach initiatives with Canada in an effort tobetter communicate and collaborate with Canadian stakeholders andregulators. An important step was expanding the number of Canadianstakeholders on NERC standard drafting teams. Associated with thiseffort, the Canadian Electricity Association conducted a workshop for
NERC Standards staff that gave an overview of province-specificframeworks that govern the adoption of standards in that country.
Throughout the year, NERC continued policy discussions with Canadianstakeholders and the several provinces through forums including theCanadian Association of Members of Public Utility Tribunals and theFederal–Provincial–Territorial Electricity Working Group (FTP Group).
NERC also expanded its liaison with Canadian utilities working with theCanadian Electricity Association. The FTP Group and its Monitoring and
Enforcement Subgroup (MESG) served as the primary forums for crossjurisdictional coordination to ensure that the consistency espoused in the
Bilateral Principles, which were developed for an effective internationalreliability organization, was maintained.51
51 The Bilateral Principles include the following: Governance of the ERO—independence

and representation; Membership in the ERO—not a condition of participation nor
compliance; Funding—ERO costs shared based on net energy for load; Remand ofStandards—coordination to avoid inconsistency; Enforcement and Audits—professional,
consistent, transparent; and Regional Entities—governance, organization.
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In the third quarter of 2014, an agreement between the Régie de l’énergie
du Québec (Régie), NERC, and NPCC was executed, supplementing andcompleting the agreement that was first executed in 2009. This set thestage for several key actions by the Régie, including issuance of the
Québec Reliability Standards Compliance Monitoring and Enforcement
Program (QCMEP) and the roles and responsibilities of the Régie, NPCC,
and NERC regarding implementation of the QCMEP.
In addition, NERC established a full-time Canadian affairs position to workwith the Canadian reliability stakeholders to support their continued
implementation of a robust international reliability framework.
August 2015 marked the 10-year anniversary of the Bilateral Principles.
At the 10-year milestone, every interconnected jurisdiction in North
America had established, though legislation, regulation, memorandumsof understanding, or some combination of these, a mandatory reliability
framework. Each province, working in collaboration with their respective
Regional Entities, uses their individual mechanisms for adoption andenforcement of NERC Reliability Standards.
Collaboration with Mexico

In 2016, Mexico made significant progress toward implementing historicenergy reforms, including the country’s first comprehensive mandatory
reliability framework. NERC continued to build relationships with the
Mexican regulator, Comisión Reguladora de Energía (CRE), officials from
the Mexican Energy Ministry (SENER) as well as the system and market
operator (CENACE) to offer support and resources to implementation
efforts.
On March 8, 2017, the first MOU between NERC and Mexico was signed
by NERC, CRE, and CENACE. The MOU outlined a framework for acooperative relationship between Mexico and NERC to enhance reliabilityof electric power systems and recognize the established and growinginterconnections between the United States and Mexico and the roles ofeach party in support of continued reliability. The MOU also establisheda collaborative mechanism for identification, assessment, and preventionof reliability risks to strengthen grid security, resilience, and reliability.

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141

Under the MOU, a steering group of executives from NERC, CRE, and
CENACE began working together to establish priorities and objectives forthe technical collaboration envisioned in the MOU.
International Collaboration

In July 2016, NERC signed an administrative agreement with the European
Commission’s Directorate General for Energy (DG Energy) to collaborate
on grid reliability. The agreement recognized the shared interest of NERC
and DG Energy in grid reliability in the face of emerging challenges. The
agreement signaled the intent of both organizations to expand technicalcollaboration and exchange information related to ensuring gridreliability, including governance and standards. As a world-classinternational ERO, NERC continued to reinforce the importance of sharing
experiences in North America and learning from experiencesinternationally to secure a sustainable energy future.

System Operator Training and Certification and
Human Performance
System Operator Training and Certification

In late 2008, the electric industry approved revised standards for system
operating personnel training that required the use of a systematic
approach to training and a more rigorous and structured format fordeveloping and delivering operator training.
The NERC System Operator Certification and Continuing Education
program completed the transition to a new operator certification
database in 2008, streamlining the certification process and allowing
system operators to track the status of their certification online. Nearly
400,000 continuing education credits were completed and tracked
through the new system.
NERC also completed work on several standards related to personnel
certification, including the development of PER-005-01, whichstrengthened and clarified existing training requirements and put a focus
on defining skills required for each specific operating environment.
Human Performance

Field personnel play an important role in the maintenance and operationof the BPS. As a result, risks can be introduced when field personnel
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operate equipment in a manner that reduces the redundancy of the BPS,
sometimes creating single points of failure that would not typically exist.
In 2011, NERC established a Human Performance program with the goalof improving individual and organizational performance throughprocesses and procedures that highlight accuracy, completeness, andefficiency. The first human performance conference and workshop took
place in March 2012 with more than 200 participants from industry, theRegions, academia, and other industries.
NERC continues to hold annual human performance conferences that
focus not only on individual human performance, but the organizationaland management challenges around human capital. Hundreds ofstakeholders attend these conferences each year. NERC also supports
other similar events and provides industry support to many electricutilities across North America.

History of the North American Electric Reliability Corporation

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Final Thoughts
The 50th anniversary of NERC’s formation, June 1, 2018, was a significant
milestone in the history of the North American electric industry. Thechanges that have taken place over this half century altered many of the
traditional mechanisms, relationships, incentives, and responsibilities formaintaining the reliability of the BPS. Throughout this transformation,
one thing remained constant and will hopefully continue long into NERC’s
future as a world-class ERO—that is, a universal dedication andcommitment by industry, stakeholders, and governments alike to “Work
Together to Keep the Lights On.”

History of the North American Electric Reliability Corporation

145

146

History of the North American Electric Reliability Corporation

Appendix
Evolution of the Electric Utility Industry (1882–1970)
To further understand the nature of the electric utility industry, it is usefulto briefly chronicle the early history of its evolution.
1882: The first commercial operation of electric power generation
occurred at the Pearl Street Station in New York City.
1892: Three generating stations of the Boston Edison Company were
electrically interconnected to permit the station located on thewaterfront that had condensing steam engines and relieve the other two
without condensers. This was the first recorded implementation of
economic dispatch.
1901: The first turbine-driven electric generating units were designed for
installation at the Fisk Street Station in Chicago, Illinois.
1903: Service began at the Fisk Street Station, where the 9,000 volt
output of the generating unit permitted transmission over greater
distances to electric substations throughout Chicago. Progressive
increases in the capacity of electric generating units were made as rapidly
as the manufacturers could resolve the problems that surfaced. The
maximum size ranged from 5,000 kW in 1903 to 35,000 kW in 1917.
Progress in the design of larger generating units faltered during the FirstWorld War. In 1928, progress accelerated again, and the first 100,000 kW
rated unit, the Crawford Avenue Station Unit #6 in Chicago, was achieved.
1920s: Electrical interconnections between non-affiliated companies
began in Texas.
1923: Philadelphia Electric Company installed the first open-scale
impedance bridge frequency recorder. During this era, the control ofsystem frequency was normally assigned to one generating station oneach system.
1924: The first 132,000 volt transmission lines were constructed on steel
towers from Calumet Station to Joliet Station and to the Gary steelmaking
district in Northern Indiana.
History of the North American Electric Reliability Corporation

147

1926: On November 19, 1926, electric power systems from Boston to
Chicago were briefly operated in parallel (synchronism). In some areas,
the links were operated at as low as 33 kilovolts kV.
1927: The first Power Line Carrier equipment was installed on the PacificGas & Electric Company’s 220 and 110 kV lines between the hydro plants
at Pit River and the local dispatcher’s office in Oakland—a distance ofabout 240 miles.
1927: Automatic frequency control was requested and developed. In
1927, the first controller was installed at the New England Power
Company.52
1927: The Pennsylvania–New Jersey (PA–NJ) Interconnection was formed
when three utilities,53 realizing the benefits and efficiencies possible byinterconnecting to share their generating resources, formed the world’s
first power pool. Total capacity at that time was 1,500 MW. Additional
utilities joined in 1956, 1965, and 1981.
1928: The Interconnected Systems Group (ISG) was formed.
1929: The first automatic Load Frequency Control was developed andinstalled at the Windsor Plant in West Virginia.
1933: On December 11–12, 1933, a total of 42 representatives from 27
companies met in Pittsburgh and formalized the ISG organization andprocedures for the coordinated operation of the interconnected powersystems.
1934: The first tie-line bias control was installed in the New England
Power Company and also tested using 9 plants in the ISG. On June 14,
1934, tie-line bias expanded, using the Windsor Plant in West Virginia as
the master frequency control station.

52

For more details on the history of control of interconnected power systems, see “TheGrid - History of an American Technology,” by Julie Cohn, MIT Press, 2017.
53 Philadelphia Electric Company, Pennsylvania Power & Light Company, and PublicService Electric & Gas Company were interconnected through 210 miles of 230 kV
transmission.
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1936: The concept of the “control area” began to evolve when it became
the responsibility of each area to regulate generation to match thecustomer load changes in that area.
1939: The first interconnected operations in New Mexico began when El
Paso Electric Company and the Rio Grande Project, United States Bureau
of Reclamation, became interconnected.
1940s: Coordination of operating and planning among major electriccompanies began in Texas as part of the war effort. The Texas
Interconnected System (TIS), having experienced the benefits of theircoordinated operations, continued to expand activities after the war.
1940: First tie between California and Phoenix, Arizona area was made. A
stronger tie was placed into service in 1946.
1941: The Southwest Power Pool was formed to help coordination offormally isolated systems in distributing the limited electric power
available for the war production of aluminum and magnesium.54
1941: Following the interconnection of Utah Power & Light Company withfive other utilities, a 6-company pool was formed. It was made up of
Northwestern Electric Company, Pacific Power & Light Company,
Washington Water Power Company, Montana Power Company, Utah
Power & Light Company, and Idaho Power Company. A coordinating office
was established in Portland, Oregon.
1942: Northwest Power Pool was created as a result of the War
Production Board Order L-94, issued shortly after the United Statesentered World War II, directing utilities throughout the country tocooperate among themselves in order to increase electric capacity tomeet added wartime loads. After the war, the participating utilities
decided that the gains that had been realized through coordinatedoperation were so beneficial that the pool should be continued on a
voluntary basis.

54 See “The Power of Relationships - 75 Years of Southwest Power Pool, 2016.”

History of the North American Electric Reliability Corporation

149

1942: Oklahoma Gas & Electric Company (OG&E) conducted the first test
to determine the system’s load/frequency characteristic for use in setting
the bias control. This was accomplished by completely isolating a large
segment of the OG&E system and purposely tripping one of thegenerating units contained within that segment and observing thefrequency excursion.
1942: Pacific Southwest Power Interchange Committee formed as the first
voluntary operating organization in the California/Nevada area withmembers from both public and private generating and transmission
systems. It was formed as a cooperative effort to ensure an adequate
power supply to support the national war effort. A technical committee
was formed to deal with the problems of load/frequency control.
1943: The interconnections between California and Arizona, as well as thedevelopment of additional ties between California systems led to theformation of the Pacific Southwest Interconnected Systems.
1945: The Northwest region of ISG pioneered the concept ofsimultaneous regulation of multiple energy sources influenced by theread-out of their area requirement (ACE55). This concept of controlling
generation from a control center created the need for many additional
communication channels.
1950s: North Texas Interconnected System (NTIS) and South Texas
Interconnected System (STIS) remained active as informal organizations
with voluntary participation. Committees met periodically to exchange
planning information and maintain operating guidelines with NTIS andSTIS meeting in joint sessions when necessary.
1953: There was vast expansion of the 230 kV transmission system in the
PA–NJ interconnection.
1954: The Southern Services System installed the “Early Bird” computer,which was the first analog computer to incorporate transmission losses
as well as the incremental bus-bar cost of generation to achieve improved
economic dispatch.
55 ACE is the difference between scheduled and actual electrical generation witha control area while taking frequency bias into account.

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1956: The former PA–NJ interconnection expanded into Pennsylvania–
New Jersey–Maryland (PJM) interconnection when Baltimore Gas andElectric Company and Jersey Central Power & Light Company,
Metropolitan Edison Company, New Jersey Power & Light Company, andPennsylvania Electric Company, the four subsidiaries of General Public
Utilities Corporation along with the three original companies became
signatories to the new PJM interconnection agreement.
1956: The first formal approach to interconnected system operations in
New Mexico began when a Power Pool Agreement was entered into by
five members.
1958: On January 20, 1958, the Rocky Mountain Power Pool (RMPP)56 wasorganized as a non-contractual organization into three committees:
Policy, Engineering, and Operations. The members located in Colorado,
Wyoming, and Western Nebraska were a group of utilities operating as an
isolated interconnected system, except for one 161 kV tie to theNorthwest Power Pool interconnected at Billings, Montana.
1959: Ties between New York State and Ontario and ties from Ontario toMichigan were closed, forming the Canada–United States EasternInterconnection (CANUSE). Ties between Ontario and Quebec were used
to transfer load and capacity back and forth between the two systems,
but they were not normally closed continuously. Ties were also available
between New York State and PJM interconnection, but they normallywere operated open.
1962: Prior to 1962, PJM operated un-interconnected with adjacentsystems, except for the intermittent closure of ties to New York State.
With the addition of more and higher voltage transmission lines, thegenerating and transmission resources of PJM were interconnected on apermanent basis with adjacent systems in New York, Western
Pennsylvania, Western Maryland, and West Virginia.

56 Charter members of RMPP were Public Service Company of Colorado, Pacific Power &Light Company (Wyoming Division), Consumers Public Power District (Western Area),
Tri-State G&T Association, Bureau of Reclamation (Region 7), and Black Hills Power &Light Company.

History of the North American Electric Reliability Corporation

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1962: With the closure of the New York–PJM ties, and ties between PJM
and ISG, CANUSE became part of a larger interconnection extending
south to Florida and west to Montana. Operating guides for CANUSE57
alone were no longer possible, leading to the formation of the North
American Power Systems Interconnection Committee (NAPSIC). NAPSIC
developed operating guides that were voluntarily accepted by thecompanies in the CANUSE area.
1963: The first Arizona–New Mexico tie was established.
1967: Northern and Southern Texas systems officially combined to form
the Texas Interconnected System (TIS). When NERC was formed in 1968,
TIS became one of the participating Regions.
1969: Arizona–New Mexico systems were organized.58
1970: Electric Reliability Council of Texas (ERCOT) came into being as anatural outgrowth of the previous coordinating groups.
Reflections

Clearly, industry’s efforts in support of the war efforts marked a significant
upturn in industry coordination and the vivid realization of the benefits
that could be achieved by working together toward a common goal. This
coordination further expanded as electric utilities continued tointerconnect their systems for both reliability and economic benefits.
Over the decades that followed its formation, NERC played an increasingly
important role in these coordination efforts.

57 CANUSE Operating Guides: frequency bias settings, time error standards, time error

correction procedures, and procedures in the event of a power emergency.
58 Members of the Arizona–New Mexico Systems: Arizona Public Service Company, Salt
River Project, Tucson Gas and Electric Company, Arizona Electric Power Corp, WAPA
Lower Colorado Area, El Paso Electric Company, Plains Electric G&T Cooperative, Inc.,
Public Service Company of New Mexico, and Community Public Service Co.
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Regulation of Electricity in North America
To appreciate the context within which NERC was initially formed andthen evolved over its 50 years of existence requires a general
understanding of how regulation of electricity is accomplished in North
America.59
The regulation of electricity in North America is a combination of state,provincial, and federal jurisdictions. The summary that follows is a very
brief description of the major regulatory roles and responsibilities. It is by
no means a detailed account of these roles as they exist today and as they
may change in the future.
In the United States, FERC approves rates for wholesale sales of electricity
and transmission in interstate commerce for private utilities, power
marketers, power pools, power exchanges, and independent system
operators acting under the legal authority of the Federal Power Act of1935, the Public Utility Regulatory Policies Act of 1978, the Energy Policy
Act of 1992, and the Energy Policy Act of 2005.
State regulatory commissions require utilities to provide adequate, safe,and reliable electric service as part of an “obligation to serve”
requirement. In about half of the states in the United States, the investorowned electric utilities are vertically integrated entities (i.e., utilities thatown or control the bulk power generation and transmission facilities aswell as the local distribution facilities). Their facilities are principally state
regulated, meaning that state commissions set the retail power sales
rates and the transmission and distribution rates of the utilities. Somestate commissions have ordered their vertically integrated utilities torestructure and divest their generation assets, leaving them primarily
with only state-regulated distribution service functions. As of the end of
2005, a total of 27 states were traditionally regulated, 3 had limited
restructuring, 17 had full restructuring, and 4 had formally reversed,
suspended, or delayed restructuring.
Some state commissions also have the authority to regulate the end useof electricity as well as its distribution and delivery. State commissions orother state agencies are also typically in charge of the certification and
59 Excerpted from “North America - The Energy Picture,” prepared by North American

Energy Working Group, June 2002
History of the North American Electric Reliability Corporation

153

siting processes for transmission, distribution, and generation facilities.
This means that generation and/or transmission facilities cannot be built
without state approval.
In Canada, the predominant regulatory authority with respect toelectricity infrastructure is provincial. Each province has established its
own regulatory regime for approving energy-related projects. The
economic regulation of utility companies takes place through regulatoryboards for the most part or directly by provincial governments. The
adoption of initiatives to restructure the electricity industry has varied
across Canada. With the exception of Alberta, which is a fully competitivemarket, the balance of Canada’s provincial electricity markets are
regulated or hybrid in nature with most having implemented wholesale
access. The provinces of Alberta and Ontario have had retail open accesssince 2001 and 2002, respectively.
The National Energy Board of Canada authorizes the construction andoperation of international and designated inter-provincial power lines
under Canadian federal jurisdiction and regulates electricity power
exports with respect to the restructuring of both wholesale and retailelectricity competition taken at the provincial level. Each province is
responsible for all other aspects of electricity regulation, including siting
processes for electricity generation and transmission facilities.
Due in part to policies promoted in the 1992 Energy Policy Act,
momentum grew to provide more wholesale electric competition,
leading to the concept of “open access.” This concept was the driving
principle behind FERC’s Order 888, which led to the creation of Regional
Transmission Organizations (RTOs) and Independent System Operators(ISOs).
Many think the efforts to establish mandatory, enforceable Reliability
Standards for the BES began with the 2003 Northeast Blackout. To thecontrary, these efforts began much earlier—primarily due to the increasein competition and open access in the United States electric industry. Thisis evidenced by the fact that reliability legislation was initially developedby the industry and first introduced in Congress in 1999 as Administration
Bill H.R. 1828. While the 2003 Northeast Blackout highlighted theimportance of mandatory, enforceable standards, and the creation of an
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ERO, it was not the sole reason that the Energy Policy Act of 2005 wasenacted.
Subsequently in 2010, FERC released Order 1000 in an attempt to create
more competition in the transmission sector by promoting additional
regional planning processes and requiring competitive bidding on certaintransmission projects within Regions.

North American Power Systems Interconnection
Committee
In Omaha, Nebraska, on April 25, 1962, at the invitation of the chair of
the ISG, representatives of interconnected systems throughout theUnited States and Eastern Canada met to discuss future coordination
requirements in light of the explosive pace of interconnection
developments. It was at that meeting the idea of the North American
Power Systems Interconnection Committee (NAPSIC) was conceived.
A temporary Interconnection Coordinating Committee emerged to study
and make recommendations on the type of organization needed tocoordinate the operation of a looming coast-to-coast interconnection.
After two meetings of the committee, recommendations were drafted on
the size and scope of the permanent organization required and referred
to all systems for approval. On January 15–16, 1963, in New Orleans,
NAPSIC was formalized and held its first meeting.
Purpose and Scope

The purpose of NAPSIC was to provide an operating organization
responsible for the coordination of operating matters, especially thosefactors necessary to promote reliability of operation among theinterconnected systems. It was agreed that many operating matters wereof a local nature requiring the attention of individual systems, or a limited
number of adjacent systems, and should not involve NAPSIC.
To fulfill this responsibility, it was agreed NAPSIC’s scope should include
consideration of operating guides, recommendations, and standards
regarding the following:

Operating Reliability CriteriaFrequency Regulation

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155



Time Control

Tie-Line Frequency Bias

Operating Reserves

Time Error Correction Procedures

Emergency Operating Procedures

Load Shedding and Restoration

Tie Separation and Restoration



Generating Unit SecurityScheduled Maintenance Outages of Major FacilitiesInterchange Scheduling ProceduresProcedures for Handling Inadvertent Interchanges



Other Operating Matters Requiring Coordination to Affect
Reliable Interconnected Operation

The responsibilities of NAPSIC were to be carried out through thedevelopment of standards and guides that would be approved by vote of
the interconnected systems.
After NERC was formed, NAPSIC added communicating with NERC’s
Technical Advisory Committee and other technical organizations
concerned with operating matters to its responsibilities.
Operating Areas of NAPSICNAPSIC was formed as an informal, voluntary organization of 22 operating
personnel representing 10 interconnected operating areas. As of April 1,
1976, those areas were the following:Northeast Power Coordinating Council (NPCC)



Pennsylvania–New Jersey–Maryland Interconnection (PJM)

East Central Area Reliability Coordination Agreement (ECAR)



156

East Central Systems of the Interconnected Systems Group(ECS ISG)

Southeastern Electric Reliability Council (SERC)
History of the North American Electric Reliability CorporationSoutheast Region of the Interconnected Systems Group (SEISG)

Mid-Continent Area Reliability Coordination Agreement (MARCA)


North Central Region of the Interconnected Systems Group(NCR ISG)

Southwest Power Pool (SPP)

Western Systems Coordinating Council (WSCC)

Rocky Mountain Power PoolNorthwest Power Pool

California–Nevada Interconnected Systems



Arizona–New Mexico Systems

In 1979, the Electric Reliability Council of Texas (ERCOT) was formally
accepted into NAPSIC. Historically, the Texas Interconnected System (TIS)and subsequently ERCOT followed NAPSIC guidelines in developing theirown operating guides and procedures. Individual ERCOT systems
maintained contact with NAPSIC by attending NAPSIC general meetings.
NAPSIC Subcommittees

Performance Subcommittee: Conducted and evaluated surveys
of ACE, frequency response characteristics, inadvertentinterchange, and other surveys of operating data.



Operating Manual Subcommittee: Made necessary revisions tomaintain an up-to-date operating manual.

Communications Subcommittee: Kept informed of the activitiesof all organizations involved in electric utility communications for
system operation and perform communication coordination
work requested by the committee.

General Meeting Subcommittee: Planned the program,coordinated details, and assisted the NAPSIC chair in conducting
annual general meetings.

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Regional Council Changes

From NERC’s beginning in 1968, there have been a number of changes in
the makeup of several regional councils that were the members of NERC
until 2006 when NERC was certified as the ERO. At that time, the Regions
became Regional Entities and operated in accordance with delegationagreements with NERC to monitor and enforce NERC Reliability Standards
and conduct various reliability assessments and event analyses within
their respective boundaries.
Midwest Reliability Organization (MRO)

MRO traces its roots as far back as World War II, when the ISG performed
coordination for its members. The Flood Control Act of 1944 led to largehydro-power projects on the Missouri River, which was one of thestrongest catalysts leading to the formation of the Mid-Continent Area
Power Pool (MAPP). The late 1940s through the early 1960s saw theformation of several different power pools, including the United Power
Pool, the Nebraska Pool, the Iowa Pool, and the Mississippi Valley Power
Pool. In 1963, NAPSIC succeeded ISG with MAPP serving as its Northwest
Region. In the same year, the Mid-Continent Area Power Planners wasformed. Following the 1965 Blackout, the MAPP Coordination Center was
authorized on February 25, 1966. When NERC was formed in 1968, MAPP
members became signatories to the Mid-Continent Area Reliability
Coordination Agreement (MARCA). In 1972, MAPP members became
signatories to the MAPP Agreement. In 1982, MAPP assumed
responsibilities of MARCA. A separate but related organization,
MAPPCOR, was founded in 1990 to serve the electric power industry withtransmission planning and operations, including generation reserve
sharing
pool
operations,reliability
coordination,energyscheduling/tagging, open-access transmission tariff administration,
open-access same-time information system (OASIS) operations,transmission planning, powerflow/stability analysis, and technical project
management for transmission study initiatives. MAPPCOR also
represented the MAPP organization as the NERC-registered Regional
Planning Authority (now called Planning Coordinator) for the MAPP
Region as well as other interregional coordination venues until it wasdissolved in 2015. In January 2005, MRO superseded the MAPP
organization in anticipation of the passage of reliability legislation and
NERC becoming the ERO. In 2018, MRO membership expanded to include

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the bulk of SPP members when the SPP organization gave up its role as a
Regional Entity.
Southeastern Electric Reliability Council (SERC)

In 1970, four organizations in the Southeast—the Carolina/Virginia(CARVA) Pool, Tennessee Valley Authority (TVA), Southern Company(SOCO), and the Florida Electric Power Coordinating Group (FEPCG)—
combined to form the Southeastern Electric Reliability Council (SERC) asa member of NERC, reducing NERC’s members from the original 12 tonine. In 1996, SERC members, formerly represented by FEPCG, formed
the Florida Reliability Coordinating Council (FRCC), and separated from
SERC, increasing NERC membership to ten. At the same time, theoperating companies of Entergy, Associated Electric Cooperative, andLouisiana Generating, LLC (formerly Cajun Electric Power Cooperative)
became official members of SERC, adding a fourth subregion of SERC (i.e.,Entergy subregion). In 2005, SERC incorporated in Alabama as SERC
Reliability Corporation, dropping the Southeastern Electric Reliability
Council name, but keeping the acronym. In 2006, SERC membership
expanded to include several members in the central part of the UnitedStates as a fifth subregion of SERC with the subregion names changed toCentral (formerly TVA), Delta (formerly Entergy), Gateway (newly added),Southeastern (formerly Southern), and VACAR. Several members of the
SPP Region also joined SERC in 2018 as a result of SPP no longer serving
as a Regional Entity.
ReliabilityFirst (RF)The creation of RF was the result of consolidation of the ECAR, MAAC,
MAIN Regional Councils and a portion of the MAPP Region. This
consolidation was driven in part by certain recommendations in the U.S.–
Canada Power System Outage Task Force final report on the 2003
northeast blackout. At the time of the blackout, the expanded PJM
footprint covered all or parts of these four regional councils, and the MidWest Independent System Operator (MISO) operated in parts of four
regional councils. At the time, a MISO–PJM joint and common market wasunder development. In addition, choices in RTO participation had createdan overlap of reliability councils and Transmission Operators. Additionally,
the NERC regional managers’ Future Role of the Regions report
recommended more rational boundaries. Among the benefits ofconsolidation were the following: uniformity of standards across a large
History of the North American Electric Reliability Corporation159

section of North America, better alignment of market and reliability
boundaries, and resolution of existing regional council independence
issues. The project was approved in the first quarter of 2005, andReliabilityFirst became operational in January 2006.

Number of Major Interconnected Systems in North
America
Between 1960 and 1967, the number of major interconnections dropped
from six to two with the closure of interties between the Eastern andWestern Interconnections. However, the ac links between East and Westfailed regularly. By 1975, the utilities abandoned the four ac ties andreplaced them with six dc links. See table below from The Grid - Biographyof an American Technology by Julie A. Cohn.
Interconnected Systems in North America from 1960–1967
Number ofYear
System(s)Interconnections
6

CANUSE, ISG, Northwest Power
Pool, Pacific Southwest Power
Pool, Texas Interconnection; PJM

1964

5

ISG (including CANUSE and PJM),
Northwest Power Pool, PacificSouthwest Power Pool, Texas
Interconnection, Rio Grande–
New Mexico Pool

1966

4

ISG, Northwest Power Pool,
Pacific Southwest Power Pool,
Texas Interconnection

1967 (Preclosure)3

ISG, Western Interconnected
System, Texas Interconnection

1967 (Postclosure)2

East–West System, Texas
Interconnection

1975

3

Eastern Interconnection,
Western Interconnection, Texas
Interconnection

4

Eastern Interconnection,
Western Interconnection, Texas
Interconnection, QuebecInterconnection

1960

2006

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History of the North American Electric Reliability Corporation

NERC Special Reliability Assessments: 1972–1978
This listing of Special Reliability Assessments illustrates the broad rangeof reliability studies NERC performed from 1972 to 1978 as theorganization matured and became a respected authority on reliability
matters throughout North America.
1972/1974


Assessment of the State-of-Technology of Air Pollution Control
Equipment and of the Impact of Clean Air Regulations on the
Adequacy of Electric Power SupplyTransfer Capability Definition

1973Southern Florida Outages: April 3–4, 197360

Multiregional Transmission Study of Power Transfer Capabilitiesof the 1973 Bulk Power Interconnected NetworkAppraisal of Reliability and Adequacy of the North American BPS
for the Five-Year Period 1973–1977

1974


Multiregional Transmission Study of Power Transfer Capabilitiesof the 1978 Bulk Power Interconnected NetworkPotential Savings of Residual Oil in PAD-1 by Transmission ofEnergy from Remote Coal-Fired GenerationComments on Effluent Limitations Guidelines and Standards for
Steam-Electric Power Generating Point Source Category

1975Current View of the Impact of Postponements and Cancellations
on Future Electric Bulk Power Supply in the United States

60

This event triggered a discussion of under-frequency and under-voltage
relays applied to generating units and the coordination of these relay settings
with those of under-frequency load-shedding relays.
History of the North American Electric Reliability Corporation

161



A Study of Interregional Energy Transfers, 1975–1976, for theTransfer of Coal-Fired Energy to Replace Gas- And Oil-Fired
Capacity during the Winter Period

Nuclear Energy Centers: An Assessment of Impact on Reliabilityof Electric Power Supply

National Grid–GAO Efforts to Promote Interties between ElectricPower Systems

1976


A Study of Interregional Energy Transfers for the Year 1980

1977


Emergency Energy Support in the Event of a Coal Strike

1978

Analysis of the Impact of the 1978 Coal Strike

NAPSIC Performance Subcommittee Review of Time Error
Correction and Inadvertent Payback Procedures during Adverse
Weather Conditions (Operating Guide No. 4)Underfrequency/Undervoltage Relay Study

Significant NERC Milestones in the 1980s
1980: After conducting a candidate search, NERC elected Walter D. Brown
as its first full-time president. Mike Gent, who had been general managerof the Florida Electric Power Coordinating Group, was named executive
vice president.
NAPSIC merged with NERC and became the NERC Operating Committee.
The NERC Technical Advisory Committee became the NERC Engineering
Committee. The chairs and vice chairs of each committee along with thepresident and executive vice president of NERC became a new TechnicalSteering Committee.61
61

There was a great deal of discussion about whether NAPSIC should become asubcommittee of TAC or its own committee with direct reporting to the Board.
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History of the North American Electric Reliability Corporation

January 1980 marked the first meeting of the NERC Engineering
Committee. High on the list of agenda topics was discussion of the scopestatements for the Engineering, Operating, and Technical Steering
Committees.
Also on the agenda was a discussion of the Reliability Criteria Task Force,chaired by William D. Masters of Cleveland Electric Illuminating
Company—who posed the following discussion questions to thecommittee:
How broadly should the task force view/define the term
“Reliability”—i.e., BPS, service to ultimate customers, etc.?



If actual criteria are developed, should it be framed so that theRegions would/could adopt them by consensus or consider themmore like rules and regulations?



How should criteria be enforced?

This marked NERC’s initial efforts to establish NERC-wide reliability
criteria.
Other topics on the agenda of this first Engineering Committee meetingwere the following:

Development of a reference document on transfer capability

Input/comments on DOE reliability studyComments on national power grid study

Review of Underfrequency/Undervoltage Relay Task Forcereport

Status report on Generating Availability Data System (GADS)

Impact of Nuclear Regulatory Commission Actions on Reliability
and Adequacy - Licensing Moratorium

Regional responses to Federal Power Commission
recommendations following July 1977 New York City BlackoutStatus of oil conservation study

The merger of NERC and NAPSIC may not have occurred had this issue not been
resolved as it was.
History of the North American Electric Reliability Corporation

163

1981: To recognize the Canadian membership in the regional councils,
NERC changed its name to the North American Electric Reliability Council,
keeping the acronym NERC. NERC also submitted comments on the DOE
National Electric Reliability Study.
1982: Walter Brown retired. Mike Gent was promoted to president ofNERC.62
1983: Alaska Systems Coordinating Council became NERC’s first affiliate
member.
1984: NERC developed the Organizational Structure of TechnicalCommittees Procedures document.
1985: At the urging of the NERC Chair John P. Williamson, NERC
established a formal communications program, including a director ofCommunications staff position, to better communicate the importance of
reliability. NERC developed Power in Balance, a communications brochurefor regional councils and their members to use to explain various aspectsof reliability.
1986: EEI transferred the integrated Hourly Load Database to NERC. NERC
expanded the database to include all ownership sectors of the electricutility industry.
1987: At the urging of the United States government’s National Security
Council and DOE, NERC formed the National Electric Security Committee(NESC) to address terrorism and sabotage of the electricity supply system.
John Williamson, past chair of the NERC Board, chaired the NESC.
1988: The ad hoc Strategic Planning Committee report, Planning
Strategies for NERC, was published. The Operating Committee approved
the scope of Interconnection Dynamics Task Force.
1989: Two reference documents—How the Transmission System Worksand Representation of Minimum Capacity Margins in NERC Reports—
were developed.
62 An interesting coincidence surrounding the election of Mike Gent as NERC’s president

is that he previously worked at LADWP for Floyd Goss, who was NERC’s first president.
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History of the North American Electric Reliability Corporation

1990: Congress passed the Clean Air Act Amendments of 1990. NERC
used the GADS database to provide the Energy Information
Administration with a summary of forced and planned outages in the
1985−1987 period. The EPA used the GADS data to set generator unit
emission allocation values.

History of the North American Electric Reliability Corporation

165

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History of the North American Electric Reliability Corporation