3

Reliability Primer

Table of Contents

I. Introduction and Executive Summary...................................................................5

II. Overview and History of the Electric Power System ............................................ 9

 A. Structure of the North American Electric Power System .................................... 10 

B. Function and Concepts of Electric Power System Operations .............................. 22

 C. NERC – From a Voluntary Council to Electric Reliability Organization 

with Mandatory Reliability Standards ................................................................... 33

III. The Energy Policy Act of 2005.............................................................................. 37

 A. FPA Section 215 ............................................................................................... 37

 B. FERC Implementation of FPA Section 215 ........................................................ 43

 C. FERC Oversight ............................................................................................... 46

IV. Role of the Electric Reliability Organization/NERC .......................................... 53

 A. Reliability Standards Development ................................................................... 53

 B. Standards Categories ........................................................................................ 57

 C. NERC Compliance and Enforcement ................................................................ 65

 D. Reliability and Adequacy Assessments .............................................................. 71

Appendix 1 - Glossary of Certain Terms Used in the Reliability Primer ............................. 73

Appendix 2 - Citations for Statutes, FERC Orders, Reports................................................ 75

Appendix 3 - Outline of Sample Reliability Standard........................................................ 76

The Reliability Primer is a staff product and does not necessarily reflect the views of the Commission 

or any Commissioner. All images credit to FERC unless stated otherwise. 
4
5

I. Introduction and Executive Summary

This primer provides an overview of the Federal Energy Regulatory Commission’s (FERC’s) role in overseeing the reliable operation 

of the nation’s bulk power system, i.e., the interconnected electric 

grid. In order to understand FERC’s reliability program, it is useful to first understand the basic structure of how the bulk power 

system operates. Therefore, the primer begins with an explanation 

of fundamental concepts and functions related to power system operations. The primer then discusses FERC’s authority under section 

215 of the Federal Power Act (FPA) with regard to reliability and 

how FERC has implemented that authority, primarily focusing on 

the oversight of the development and enforcement of mandatory 

“Reliability Standards.” Reliability Standards impose requirements 

on the users, owners and operators of the bulk power system to assure that they fulfill their responsibilities in reliable grid operations, 

consistent with the basic engineering functions and concepts discussed in the primer. Finally, the role of the FERC-certified electric 

reliability organization or “ERO” and its relationship to FERC and 

electric industry stakeholders is discussed. 

Under Part II of the FPA, FERC historically has regulated certain economic aspects of the public utility industry, such as the rates for sales by 

one utility to another in interstate commerce. Pursuant to the Energy 

Policy Act of 2005 (EPAct 2005), Congress expanded FERC’s role and 

jurisdiction under the FPA by adding a new section 215 pertaining to 

electric grid reliability. While FERC had previously addressed electric 

grid reliability in an indirect manner, such as allowing the cost recovery 

of public utility expenditures that address discrete reliability matters, 

new section 215 of the FPA tasked FERC with a direct role over an entire 

new field of activity.
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Federal Energy Regulatory Commission Reliability Primer

Section 215 of the FPA also differs from other provisions in the FPA because it defines FERC’s jurisdiction in terms of “users, owners and operators” of the 

bulk power system. This term includes numerous 

entities that are excluded from most FERC economic 

regulation, such as federal power agencies, municipal utilities, and rural electric cooperatives. As a 

result, many entities typically not regulated by FERC 

had to familiarize themselves with the 2005 reliability legislation and comply with the new requirements. One commonality, however, with other 

provisions of Part II of the FPA is that section 215 

delineates FERC’s jurisdiction in terms of the bulk 

power system, and expressly excludes facilities used 

in local distribution from the new reliability scheme. 

 

Congress gave FERC authority to certify a non-governmental entity, referred to as the electric reliability 

organization, to develop and enforce mandatory 

“Reliability Standards.” Although Congress did not 

authorize FERC to write the Reliability Standards, 

it gave FERC the role of reviewing the Reliability 

Standards the electric reliability organization develops to ensure they are “just, reasonable, not unduly 

discriminatory or preferential, and in the public 

interest.” FERC must approve the electric reliability 

organization’s Reliability Standards before they can 

take effect in the United States. Section 215 of the 

FPA requires independence of the electric reliability 

organization from the users, owners and operators of 

the bulk power system. Yet, the statute also requires 

the electric reliability organization to assure “fair 

stakeholder representation” in selecting the electric 

reliability organization board of directors and other 

aspects of the electric reliability organization, such as 

committees. 

A great amount has been accomplished since 2005. 

FERC has promulgated regulations defining the 

structure of the reliability program, certified the 

North American Electric Reliability Corporation 

(NERC) as the electric reliability organization, approved eight “regional entities” that serve as regional 

compliance authorities, approved over 100 mandatory Reliability Standards that address many facets of 

maintaining and improving bulk power system reliability, issued directives and ordered standards to be 

developed as well as reviewed thousands of electric 

reliability organization compliance and enforcement 

actions. 

The task, however, is not complete. Emerging reliability issues require a dynamic program that takes a 

proactive stance in ensuring ongoing grid reliability. 

Thus, in addition to maintaining vigilance on fundamentals of grid reliability - such as real-time balancing of load and resources, operating equipment 

within defined limits, adequate operator training, 

and tree trimming - emerging areas of concern such 

as cybersecurity and changes in the nation’s resource 

mix continue to require FERC’s attention. 

It is important to understand that in enacting 
7

section 215 of the FPA Congress did not “outlaw” 

blackouts; nor can FERC, the electric reliability 

organization or anyone else guarantee that blackouts 

will not occur. However, applying current knowledge and resources, FERC strives to implement its 

authority over the electric reliability organization 

and the Reliability Standards in a diligent manner to 

reduce the possibility of blackouts on the bulk power 

system.

This primer is written to be used either as a traditional text - read front to back - or as a reference 

guide. Consequently, some material is repeated in 

different sections and references are provided to other parts of the primer where a concept is addressed 

in greater detail. Further information about various 

aspects of reliability and FERC regulation can be 

found at http://www.ferc.gov/industries/electric/

indus-act/reliability.asp. In addition, more information on NERC’s functions as the electric reliability 

organization can be found at www.nerc.com.
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9

II. Overview and History of the Electric 

Power System

Modern society has come to depend on reliable electricity as an essential resource for national security, health and welfare, communications, finance, transportation, food and water supply, heating, 

cooling, and lighting, computers and electronics, commercial enterprise, and even entertainment and leisure - in short, nearly all aspects of modern life. Providing reliable electricity is an enormously 

complex technical challenge: it involves real-time assessment, control and coordination of electricity production at thousands of generators, moving electricity across vast interconnected networks of 

transmission lines, and ultimately delivering the electricity to millions of customers by means of extensive distribution networks. 

It is these complexities that make the North American electric system 

such a great engineering achievement. This infrastructure represents 

more than $1 trillion in asset value, more than 211,000 miles of transmission lines operating at 230 kilovolts and greater, over 1.1 million 

megawatts of generating capability, and nearly 3,500 utility organizations 

serving over 334 million people whose total electricity demand exceeds 

830 gigawatts (830,000 megawatts). 
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Federal Energy Regulatory Commission Reliability Primer

Each interconnection in the North American 

electricity system is essentially one large machine 

and comprises three main functions: generation, 

transmission, and distribution, each of which is 

discussed below. Electric generation (supply) creates 

electricity using various generating technologies 

with specific operating characteristics. The transmission system connects and transfers large amounts 

of power from generators to the distribution system, 

delivering electricity to population centers. The distribution system then routes electricity to individual 

customers, which are referred to as load. Together, 

these system parts are connected and operate in an 

electric balance. 

The first electricity systems were independent of 

each other, serving local communities or regions. As 

North American electricity demand increased and 

systems grew, especially after World War II, the systems interconnected. The drivers of interconnection 

were both technical and economic. Justifications for 

expansion and interconnection were due to economies of scale, load factor (the ratio of average load 

to the peak load for a period of time), and enhancement of reliability. First, the primary electric generators were large thermal plants fueled by coal. These 

systems have economies of scale, meaning that larger 

plants have lower per-unit production costs than 

small plants. Larger plants need a larger customer 

base, thus encouraging connections among service 

territories. Increased unit size is advantageous and 

provides incentives for utilities to connect enough 

customers so as to take full advantage of economies 

of scale. Second, by aggregating customers across 

regions, a higher load factor results, improving 

system operations. Third, the interconnection of 

many generators and customers across a wide region 

improves system reliability through the use of generation pooling which helps to ensure reliable electricity supply despite unexpected generation loss or 

outage. To this day, some service regions are referred 

to as “power pools.”2 In North America, there are 

four separate power grids or “interconnections” (See 

1 von Meier, Alexandra, Electric Power Systems: A Conceptual Introduction, Hoboken, New Jersey, John Wiley and Sons, 2006. See also 

Understanding Electric Power Systems, Second Edition, Hoboken, New 

Jersey, John Wiley and Sons, 2010.

Source: NERC

A. Structure of the North American Electric Power System 
11

illustration below). The Eastern interconnection 

includes the eastern two-thirds of the continental 

United States and Canada from Saskatchewan east 

to the Maritime Provinces. In 2006, Québec’s transmission system was recognized as a full interconnection because it is not synchronized with neighboring 

systems. The Western interconnection includes the 

western third of the continental United States (excluding Alaska), the Canadian provinces of Alberta 

and British Columbia, and a portion of Baja California Norte, Mexico. The Electric Reliability Council 

of Texas (ERCOT) interconnection comprises most 

of the state of Texas. The four interconnections are 

electrically independent from each other except for 

a few small direct current (DC) ties. Within each 

interconnection, electricity is consumed the instant 

it is produced, flowing over transmission lines from 

generators to loads.

North American Grid

As shown in the chart below, the United States and 

Canada share an integrated electrical transmission 

network. Adding the Baja California region of Mexico, which also has interconnections with the United 

States, results in what is referred to as the North 

American interconnected transmission network. 

 

FERC has certain authority over reliability for the 

portion of the bulk power system located in the 

United States. Canadian regulatory oversight of 

electric reliability rests primarily within the jurisdiction of the provinces. In Mexico, regulatory 

oversight rests with the Mexican Energy Regulatory 

Commission (Comision Reguladora De Energia or 

CRE).

Source: NERC
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Federal Energy Regulatory Commission Reliability Primer

These interconnected transmission networks provide economic benefits to each country by allowing 

electric utility companies to buy and sell power 

from each other, to save money and to share in the 

provision of support services that makes the delivery 

of energy possible. Over 30 international transmission lines are in use between the United States and 

Canada. 

The electric interconnections between the countries 

also provide alternative power paths during emergencies, such as when a generator unexpectedly 

trips offline on a hot summer day. Thus, electric 

interconnections benefit reliability and resiliency of 

the bulk power system. However, these electrical 

interconnections can also result in certain vulnerabilities, as was demonstrated during the August 14, 

2003 blackout. That blackout began in Ohio and 

rolled through eastern Canada, impacting its system, 

before cascading into New York and New England. 

By following a common set of operating protocols or 

Reliability Standards in both the United States and 

Canada, the vulnerabilities of shared interconnections are mitigated. 

Generation

Generators are devices that produce electricity. 

Generators come in many forms and use different 

methods to convert a fuel or energy source into 

electricity. The table below shows the amount of 

generation capacity installed in the United States as 

of 2014. Natural gas, coal and nuclear energy make 

up the largest sources. 

Existing Net Summer Capacity by Source 

in 2014

Energy Source Capacity (GW)

 

Coal ____________________________ 299

Petroleum_________________________41

Natural Gas ______________________ 432

Other Gases _______________________ 1

Nuclear __________________________98

Hydroelectric ______________________79

Other Renewables___________________90

Pump____________________________22

Other ___________________________ 2

TOTAL________________________ 1,068

Source: Energy Information Administration from Electric Power Annual 

Report - 2014

The various types of generation include:

• Thermal Power Plants: These plants burn fuel 

in a boiler, producing heat and converting water 

to steam at a high pressure and temperature. 

The steam is expanded through a turbine, which 

produces work to drive a generator. Steam 

plants may use coal, natural gas, oil, biomass, 

or various types of mineral or vegetative waste 

(such as by-products from fossil fuel refinement, 

wood, grasses, etc.) to produce electricity. Gas 

turbines are essentially natural-gas fired jet 

engines in which torque is produced to drive a 
13

generator. Gas turbines may be started within 

minutes whereas steam plants may require several hours to begin producing electricity. 

• Combined Cycle: In a combined cycle power 

plant, fuel (typically natural gas) is burned in a 

gas turbine. A heat recovery system captures the 

exhaust heat from the turbine and uses that heat 

to raise steam temperature and pressure, which 

is expanded through a steam turbine. Both 

turbines drive electric generators. The heat 

recovery increases efficiency over a gas turbine 

or simple steam cycle plant. 

• Cogeneration: A cogeneration plant is a simple 

steam generator that also produces steam for 

local distribution. Common in universities and 

industrial campuses, these types of power plants 

produce power and the steam is used for building heating and cooling and industrial applications. Cogeneration plants can have a very high 

thermal efficiency. 

• Nuclear: These plants capture heat released 

during nuclear fission (or the splitting of uranium atoms) to create steam in a simple steam 

cycle. Nuclear plants typically operate continuously for 18 to 24 months before undergoing a 

scheduled maintenance break for refueling. 

• Hydroelectric: Hydroelectric plants produce 

electrical power by passing flowing water 

through a turbine to drive a generator. The 

two major types of hydroelectric facilities are 

impoundment and “run-of-river.” In an impoundment facility, a dam is used to store water, 

which is then released to drive a generator. In 

a “run-of-river” facility, a portion of the river’s 

flow is diverted to a generating station. Hydroelectric facilities are characterized by their high 

level of availability (given sufficient water levels) 

and controllability. Utilities balance power 

production of hydro plants on rivers with other 

uses, such as flood control, navigation, environmental regulations and recreation. Another 

type of hydro facility, pumped storage, pumps 

water to higher elevations during low demand 

hours so that it can be used to produce electricity 

during peak hours. 
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Federal Energy Regulatory Commission Reliability Primer

• Solar: There are two types of solar generators: 

photovoltaics and concentrated solar power. 

Photovoltaics use silicon wafers or non-silicon 

thin-film panels to convert sunlight directly into 

electricity and can often be found on homes, 

commercial buildings, or aggregated into large 

plants. Concentrated solar power units use mirrors/lenses to focus solar rays toward a receiver 

where the light energy is concentrated to drive a 

simple steam cycle generating station. 

• Wind: A typical wind turbine has three rotating blades atop a tall tower. The wind turns the 

blades, directly driving a generator. Units are 

often grouped together to form wind farms in 

areas with desirable wind characteristics. The 

grouping of wind turbines together improves the 

aggregate availability of the wind farm and its 

economic viability by harnessing different wind 

speeds and currents over a larger geographic 

area.

• Geothermal: These power plants use the 

heated reservoirs of steam that already exist 

far below the earth’s crust to provide energy. 

Most people are familiar with “heat pumps” 

for residential and commercial heating and 

cooling that pump liquids through tubing in the 

ground. Utility-scale geothermal systems are 

open-loop and closed loop. Open-loop systems 

tap reservoirs of superheated steam to drive a 

steam turbine. Closed-loop systems inject water 

into wells drilled in geothermal hot spots, which 

heats the water into steam, which is used to 

generate electricity. 

• Biofuels: These power plants come in several 

forms. Some use the methane gas by-product 

of the bacterial decomposition of manure or 

landfills as the fuel source that is burned to drive 

a turbine or a small steam-cycle plant. Other 

biomass plants use non-edible agricultural products and waste such as wood pulp, grasses, corn 

residue and forest thinnings as a fuel for a simple 

steam cycle plant. 

Given their different fuel types and associated operating characteristics, generators are used to varying 

extents to serve customer demand or “load,” and 

generally fall into one of the following categories: 

base-load, load-following or peaking.

Base-load generation is traditionally comprised of 

generators that run almost continuously to serve a 

base level of demand that is typically present on the 

system due to everyday needs. Most often, nuclear 

plants, large thermal units, or hydroelectric plants 

are considered base-load generation. This type of 

generation is usually large, with respect to size and 

output, and operates within a steady range of production. For example, nuclear plants produce energy more than ninety percent of the time that they 

are in service. Due to economies of scale, large ther-
15

mal fossil fuel plants also are often more economical 

to run and provide the system with added stability 

through their design. The large, rotating turbines 

in these base-load units create spinning mass, which 

contains kinetic energy known as inertia. Inertia is 

the momentum and energy built up in the turbines 

that resists changes due to changing loads by adding 

to or absorbing energy from the system. These large 

base-load units also tend to have longer start-up or 

shut-down times and must operate within a steady 

range of production. The run-of-river hydro plants, 

where available, are useful as base-load units because 

their energy source is constantly flowing. However, 

regional weather conditions can affect river flows 

and the amount of hydro-generation available. 

Load-following generation is used when the demand 

for electricity is higher than the base level. Natural 

gas units have traditionally been used as intermediate or load-following generation. Due to prevailing 

low prices of natural gas, these plants are increasingly used to serve base-load. 

Units that can be called upon in a shorter timeframe, such as quick-responding gas combustion 

turbines, are utilized as peaking units during times of 

highest demand. While these units may have more 

operational flexibility, they may not be as economical to run due to their relatively lower efficiency and 

thus higher fuel and operating costs. 

Operating reserves are the capability above firm 

system demand required to provide for changing 

demand levels and equipment and system failures.

Aggregate Load 

Source: http://www.mpoweruk.com/electricity_demand.htm

System operators decide which generators to run 

based on their economic and operational characteristics or, in many regions, based on prices bid by competing generators. To minimize electricity production costs, system operators dispatch generation in 

order of cost (or bid) to meet load, unless reliability 

factors require otherwise. When load is at its peak, 

more expensive units generally are used to meet the 

increased demand and the overall cost goes up. 

 

The amount of power needed to serve load constantly changes. System operators must schedule 

or “dispatch” production by the generators to meet 

constantly changing demands. Scheduling typically 

occurs on an hourly basis, and is then fine-tuned 

throughout the hour, sometimes through the use 

of automatic generation controls to continuously 

match generation to actual demand. 
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Federal Energy Regulatory Commission Reliability Primer

Daily Load Curve and Generation Type 

Source: http://instituteforenergyresearch.org/electricity-transmission/

Transmission

The transmission function of the North American 

grid connects and transfers large amounts of power 

from generators to the distribution system via transmission lines, delivering electricity to population 

areas. Transmission lines are typically constructed 

using bundles of steel-reinforced copper or aluminum wires called “conductors” and are able to span 

great lengths with support from steel towers. The 

towers keep the lines suspended at a safe distance 

from trees or other objects, as well as maintain 

enough space between each conductor to keep the 

lines from connecting or arcing and to avoid mutual 

interference that could reduce transmission efficiency. Conductors are connected to the tower by insulators which prevent the flow of electricity into the 

tower. In addition to overhead towers, electricity 

can also be transmitted through underground or underwater cables, where the construction of a tower is 

not possible. A cable can include several conductors 

surrounded by an insulator.

Electricity is transmitted at high voltages. High voltage transmission can range from 345 kilovolts to 765 

kilovolts. In the United States, systems have different characteristics due to location, types of customer, 

proximity to population, and other considerations 

such as topography, geography or environmental 

conditions. Electricity from generators is “stepped 

up” from a lower voltage (10,000 to 25,000 volts) 

to higher voltages (i.e., 100,000 to 765,000 volts) 

for transportation in bulk over transmission lines. 

Transmission at high voltage reduces the power 

losses associated with conductor heating and allows 

power to be shipped economically over long distances. This is because real losses on a power line 

are directly proportional to the product of the line 

resistance and the square of the load current. As the 

line resistance is relatively fixed per unit of distance 

(though may change slightly based on factors such as 

temperature or frequency), a high current will result 

in large losses. The amount of current required to 

transfer a given amount of power is inversely proportional to the voltage, thus doubling the voltage 

halves the current. The desired power level can 

still be maintained while minimizing line losses by 

increasing the voltage. As a result, the transmission 

system relies on higher voltages. 

Transmission lines are interconnected at switching 

stations and substations to form a network of lines 

and stations that make up the power “grid.” Electricity flows through the interconnected network of 

transmission lines from the generators to the loads 

in accordance with the laws of physics in much the 

same way that water flows through a network of canals: along paths of least resistance. When the power arrives near a load center, it is “stepped down” to 

lower voltages for distribution to customers. 

The first central power plant in the United States, 

Thomas Edison’s Pearl Street Station in New York 

City, distributed direct current (DC) power. Today’s 

electricity transmission and distribution systems 

are primarily alternating current (AC) facilities. 

AC power became predominant because of the ease 
17

and low cost with which voltages in AC systems 

can be converted from one level to another. There 

are a number of modern high-voltage DC (HVDC) 

transmission links, but these are only a small part of 

the power grid. 

Modern AC power systems are three phase, meaning 

that the system is comprised of three systems, each 

operating a third of a 360-degree cycle, 120 degrees, 

from the other two. Three phase systems have two 

principal benefits. First, in synchronous generators 

and motors, three-phase power permits constant 

torque on the rotor, thus reducing vibration and improving performance. Second, three-phase systems 

improve the economy of transmission. In principle, 

every electric circuit must have a return wire. However, in three-phase systems, the sum of the delivered currents is zero, so no return wire is needed. In 

practice, the small amount of return current may be 

routed to the ground. This situation assumes that 

the currents are equal and exactly 120 degrees apart. 

Source: Google Images
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Federal Energy Regulatory Commission Reliability Primer

Real and Reactive Power

Power transferred along transmission lines consists 

of both “real” power and “reactive” power. The real 

power is the energy that is capable of performing 

work in electrical devices including industrial equipment, refrigerators, or toasters. Reactive power is 

needed to maintain the voltage as well as electric and 

magnetic fields in AC equipment, which includes air 

conditioners, motors, transmission lines, and other 

devices. Together, real power and reactive power 

comprise apparent power, which is measured in 

units of Volt-Amperes or kilo Volt-Amperes - kVA. 

Reactive power cannot be transmitted as far as real 

power and instead must be replenished locally. 

Moreover, a deficit in reactive power causes voltage 

to drop. This is seen when the lights dim as an electric motor starts. While reactive power consumed 

by facilities or devices tends to cause the voltage to 

drop, it can also be produced or injected into the 

system to increase voltage in what is often referred 

to as “voltage support.” This is accomplished in a 

variety of ways, including by adjusting the reactive 

power output of generators or by activating capacitor 

banks or other power electronic equipment. If reactive power is not supplied promptly and in sufficient 

quantity, voltages decline, and in extreme cases a 

“voltage collapse” may result. 

Transmission lines also face physical limitations 

based on their characteristics. Following the law 

of conservation of energy, the energy losses experienced in transmission (due to the resistance multiplied by the current squared) are transformed into 

heat that cause lines to stretch and sag. This expansion can cause the line to come into contact with 

trees or other objects and cause a fault, or may lead 

to permanent physical changes and damage to the 

line. Thus transmission lines have thermal ratings 

that determine the maximum amount of electricity a 

Reactive Power Analogy

Reactive power is often described in terms of 

an analogy. A useful analogy is to assume you 

are part of a three-person crew who must push 

a large ball across an inclined plane from point 

#1 to point #2. The figures below illustrate this 

analogy. To move the ball from point #1 to #2, 

the three-person crew must both push the ball 

in the proper direction but also prevent the ball 

from rolling down the incline. 

In the figures, the active power, mega-watts 

(MW), is the power required to move the ball 

from point #1 to point #2 in a given time. Two 

of the three-person crew performs this task. 

The reactive power, or mega-volt ampere-reactive (MVAR), is the power required to keep the 

ball rolling in the right direction. The MVAR is 

needed to keep the ball from rolling down the 

incline. One of the three-person crew performs 

this task.

In our analogy the MVAR does not help move 

the ball from point #1 to point #2 but it is required if you want to move the ball to point #2. 

Of the three-person crew, one is not available 

for MW work and instead is committed to the 

MVAR function.

 

Source - EPRI Power System Dynamics Tutorial, p. 2-36 to 2-37
19

line can safely conduct, thus limiting the amount of 

power that can be transferred. The thermal ratings 

can vary seasonally with the ambient temperature 

and with system conditions, such as normal (or continuous ratings) and emergency operation ratings. 

Emergency ratings may have a time limit associated 

with them such as a two-hour or four-hour rating. 

In addition, lines have voltage limits and other 

controls to make sure that generators and other elements at each end of the line are able to synchronize 

with the system when connecting. Because electricity flows freely and almost simultaneously across the 

power system, transmission lines may also have preset power transfer limits to avoid overloading other 

lines during certain system conditions. 

 

Transformers and Substations

Transformers are devices that convert AC power 

from one voltage to another. Transformers are 

essentially a conductive core that facilitates the 

transfer of electric energy between two or more sets 

of line windings through magnetic fields. Transformers are used in electric power systems to convert 

voltages to a higher (“step-up”) or lower (“stepdown”) voltage. For example, generators produce 

power at lower voltage levels and the power must be 

stepped up by transformers near the generation site 

before joining the transmission network. 

AC current flowing through the source (primary) 

winding of a transformer creates an oscillating 

magnetic field within the conductive core and produces an induced voltage potential across the load 

(secondary) winding. This causes electrons to flow 

in the secondary winding and produces another AC 

current at the output. The strength of the voltage induced is dependent on the ratio of turns in the winding; if the number of turns is greater in the primary 

winding, then the resulting voltage will be smaller, 

or stepped down. If the number of turns is greater 

in the secondary winding, the resulting voltage will 

be greater, or stepped up. Various configurations can 

support multiple sets of windings, such as a third set 

of windings to provide local power. It is also possible 

to connect or “tap” the windings so that the number 

of turns used can be changed, thus controlling the 

resulting induced voltage as needed. 

Transformers and associated equipment comprise 

the interface between two different transmission-level voltages, between generators and transmission, and between the transmission system and 

the distribution system. High voltage transformers, 

also referred to as “intertie banks,” deliver large 

amounts of power to highly populated areas or “load 
20

Federal Energy Regulatory Commission Reliability Primer

pockets” that may not have enough local generation. 

These large intertie banks are difficult and costly to 

replace because of their size, unique designs, and 

long manufacturing times. For these reasons, many 

utilities keep spare equipment on hand.

Transformers and other equipment needed to switch 

between voltage levels and multiple line terminals 

are contained within substations. Substations also 

contain a number of system control devices and 

protective elements that insulate electricity to keep 

equipment and people working within substations 

safe. Switches or circuit breakers are used to disconnect elements or portions of the system to isolate 

them, often for maintenance or to mitigate an unexpected disturbance on the line. Some switches take 

advantage of open air as an insulating medium when 

physically removing connections. This event often 

can result in arc flashes at high voltage levels as the 

conductors separate, though the arcs dissipate quickly once there is enough distance between contacts. 

Switches may also be contained within a vacuum or 

in the presence of an inert gas, which both are better 

insulators than air. Additionally, circuit breakers are 

used to separate sections of the system when faults 

are detected. Bushings are insulated connectors for 

equipment, such as circuit breakers or transformers 

to conductors. Substations also house equipment 

used to maintain the voltage across the system such 

as the capacitor banks, reactors, and static-VAR 

compensators. 

Distribution

The distribution system is generally comprised of 

sub-100kV lines that ultimately deliver power to customers, such as a home or business. Once power is 

generated and transferred over transmission lines to 

the vicinity of the load, the voltage must once again 

be lowered to move along the distribution lines. 

This happens at a substation that uses transformers 

to step-down the voltage. From the substation, energy can be transferred either directly to the load or 

must be stepped down again. Some large industrial 

and commercial customers take service at intermediate voltage levels (12,000 to 115,000 volts), but most 

residential customers take their electrical service at 

120 and 240 volts. Electric utilities ensure that this 

voltage stays within a specified range. 

Other Equipment

Because the electric power system needs to perform 

continuously, efforts are taken to ensure that operations will continue during and after an undesired 

event. These events may often be the result of a 

lightning strike, or a tree or animal that has made 

contact with a line, causing a low-resistance connection that carries excessive current flows to unintended paths (often called a “short circuit” or “fault”). 

To mitigate these events, protection systems that 

detect these high currents and other system problems and take automatic actions have been designed 

and deployed. The main purpose of these devices is 

to monitor and/or react to events and to minimize 

damage and maintain reliability. Collectively, these 

devices constitute the “protection system.” 
21

Protection system devices are installed on the grid 

to protect and isolate the entire power system from 

trouble that emerges in isolated locations, while 

leaving as much of the grid as operational as possible. Protection systems can be viewed as having 

five principal components: (1) current and voltage 

“transformers” measure currents and voltages and 

provide signals to relays; (2) protective relays that 

sense faults and initiate a “trip” or disconnect; 

(3) circuit breakers that open and/or close the line 

based on relay and other commands; (4) batteries to 

provide power in case of power disconnection in the 

system; and (5) communication channels to allow 

analysis of current and voltage at remote terminals 

of a line and allow remote tripping of equipment. 

Relays and circuit breakers that isolate affected 

sections of a line are often the first line of defense. 

Relays monitor many aspects of the system, including: temperature, current, and voltage. Depending 

on the situation, a relay will “trip” a circuit breaker 

that takes a portion of the system out of service 

by disconnecting the line to protect the rest of the 

network. Often, relays will automatically “re-close,” 

meaning that they will reconnect after a preset delay 

under the assumption that the source of the fault 

is temporary. However, if the fault is still present, 

the relay will permanently remove the affected 

portion of the line from service until the fault can be 

resolved by maintenance crews. The application of 

these devices is designed to remove from service the 

smallest part of the system possible until restoration 

can be achieved. For redundancy, often there are 

secondary and tertiary back-up relays that are timed 

to watch for the clearing of a fault. If the system 

fault is still present after a set period of time, they 

will activate, though a larger portion of the line may 

then be out of service. Other relays will act to regulate the system characteristics within a certain range, 

or will trip if a prolonged overcurrent or overvoltage 

is detected. 
22

Federal Energy Regulatory Commission Reliability Primer

The previous section discusses the structure of the 

North American electricity system and describes the 

three main functions (generation, transmission, and 

distribution) and how each interconnection within 

the system operates as essentially one big machine. 

Maintaining the reliability of the grid is a complex 

enterprise that requires trained and skilled operators, sophisticated computers and communications, 

careful planning and design, and rigorous maintenance practices, including tree-trimming or “vegetation management,” and equipment maintenance. 

This section describes some of the aspects of reliably 

operating the grid. Reliable operation of the power 

grid is complex and demanding for two fundamental 

reasons: 

• At present, it is difficult to store large quantities 

of electricity economically. Therefore, electricity must be produced the instant it is needed and 

used. 

• The flow of AC electricity cannot be controlled 

like a liquid or gas by opening or closing a valve 

in a pipe, or switched like calls over a long-distance telephone network. Electricity flows freely along all available paths from the generators 

to the loads along the “path of least resistance.” 

The unique characteristics of electricity mean that 

problems, when they arise, can spread and escalate 

very quickly if proper safeguards are not in place. 

Accordingly, through years of experience, the electric industry has developed a network of defensive 

strategies for maintaining reliability based on the assumption that equipment can and will fail unexpectedly on occasion. This principle is expressed by the 

requirement that the system must be operated at all 

times to ensure that it will remain in a secure condition (generally within emergency ratings for current 

and voltage and within established stability limits) 

following the unexpected loss of the most important 

generator or transmission facility (a “single largest 

contingency”). This is called the “N-1 criterion.” 

In other words, because a generator or line trip can 

occur at any time, the power system must be operated in a preventive mode. Use of the N-1 criterion 

means that the loss of the most important generator or transmission facility does not jeopardize the 

remaining facilities in the system by causing them 

to exceed their emergency ratings or stability limits, 

which could lead to a cascading outage. 

When a contingency does occur, system operators 

are required to identify and plan for the next contingencies based on the changed conditions. They 

must also promptly make any adjustments needed 

to ensure that if one of these contingencies were to 

occur, the system would still remain operational 

and safe. Generally, the system must be restored 

to normal limits as soon as practical but within no 

more than 30 minutes, and to a condition where 

it can once again withstand the next-worst single 

contingency without violating thermal, voltage, or 

stability limits. Most areas of the grid are operated 

to withstand the concurrent loss of two or more 

facilities (i.e., “N-2” or “N-3”). This may be done, 

for example, as an added safety measure to protect a 

densely populated metropolitan area or when lines 

share a common structure and could be affected by 

the same event (e.g., a single lightning strike).

Ensuring the reliability of a transmission grid 

involves several other key concepts, which are 

discussed below: Frequency Control - Balance of 

Generation and Load, Voltage Control – Maintaining Required Voltage Level, Power Flow and Stability Control, Short-Term and Long-Term Planning, 

Vegetation Management, Coordination and Communication, and Critical Infrastructure Protection. 

B. Function and Concepts of Electric Power System Operations
23

Frequency Control - Balance of Generation 

and Load

The “frequency” of the AC power system in the 

United States is set at 60 cycles per second or 60 

Hertz (Hz). Failure to match generation to demand 

causes the frequency of the power system to fluctuate higher or lower than the normal 60 Hz. When 

generation exceeds the load or demand to consume 

it, the system frequency increases; when there is less 

generation being produced than is needed to serve 

load, the frequency decreases. Random, small variations in frequency are normal, as loads constantly increase or decrease, and generators modify their output to follow the demand changes. However, large 

deviations in frequency can cause the rotational 

speed of generators to fluctuate, leading to vibrations 

that can cause damage to generator turbine blades 

and other equipment. Extremely low frequencies 

can trigger automatic under-frequency “load shedding” to enable frequency to increase, which takes 

sets of customers off-line to prevent a total collapse 

of the electric system. Such an imbalance of generation and demand can also occur when the system 

The Concept of Power System Frequency Explained Using the Analogy 

of Water Level in a Container

Source: The Lawrence Berkeley National Laboratory Report on “Use of Frequency Response Metrics to Assess the Planning and Operating 

Requirements for Reliable Integration of Variable Renewable Generation,” December 2010.
24

Federal Energy Regulatory Commission Reliability Primer

balance. To further control these rotational speeds, 

generators also have a device called a “governor.” 

The governor monitors the shaft speed of a generator and either increases or decreases the amount of 

turbine-spinning force, by controlling the steam input to the turbine, to proportionally adjust the shaft 

speed back to the desired level. Governors on trucks 

or boats work exactly in the same manner, allowing 

only a steady and measured decrease or increase in 

drive train rotational velocity to prevent equipment 

damage and maintain safe operating practices. This 

frequency response occurs in a fraction of a second, 

before system operators are able to take action. For 

example, the sudden loss of a large generator in Kentucky can cause a frequency dip in the entire Eastern 

interconnection, from Miami up to Toronto, during 

which time all of the generators with automatic 

generation control mode in the interconnection will 

respond by incrementally increasing the amount of 

energy they produce to make up for the sudden loss 

of this one generator.

Frequency Response Options

Inertia The kinetic energy stored as inertial energy in the rotating mass of all of the 

synchronized turbine-generators and motors on the interconnection.

Governor Turbine-generator units use turbine speed control systems, called governors, 

to control shaft speed by sensing turbine shaft speed deviations and initiating 

adjustments to the mechanical power input to the turbine.

Frequency Responsive Demand For sudden loss of generation, this load reduction is typically triggered by relays 

Response that are activated by frequency.

Energy Storage Automatic high-speed energy retrieval and injection.

Automatic Generation Control Equipment that automatically adjusts generation in a balancing authority area 

(AGC) from a central location to maintain frequency.

responds to major disturbances by disconnecting 

into separate “islands”; any such island may have an 

excess or a shortage of generation when compared 

to the demand within the island. The figure below 

presents the concept of frequency control in terms of 

maintaining the level of water in a tank. 

Many processes in place help to maintain the system 

frequency at (or close to) 60 Hz. One inherent 

quality of the system is inertial energy, or momentum that resists sudden changes in speed. The large 

amounts of energy stored in rotating masses (such 

as the spinning turbines of generation plants) are 

resistant to changes in rotational speed. The inertia 

resists a decline in speed caused by a loss of generation, allowing control systems a brief opportunity 

to automatically produce more power from the 

remaining generators. This response often occurs in 

milliseconds. Conversely, when load is added to the 

system causing the frequency to decrease, rotational 

energy from the generator will be converted into 

electrical energy to serve the load and maintain a 
25

Voltage Control – Maintaining Required 

Voltage Level

As the load changes, so do the requirements for reactive power throughout the system. Reactive power 

sources, such as capacitor banks and generators, 

adjust to maintain voltages within a specified range 

for all system electrical equipment (e.g., stations, 

transmission lines, and customer equipment see previous “box” on Reactive Power Analogy). Most generators have automatic voltage regulators that cause the 

reactive power output to increase or decrease based 

on system conditions, thus controlling voltage in an 

area. A system voltage schedule is set by the transmission operator and is designed to maintain the 

system within reliable operating limits. This schedule is done in advance so the transmission operator 

can convey voltage needs to area generators, and the 

generators can then be ready to respond based on 

their specific capabilities and requirements. When 

necessary, devices called reactors are used to contain 

excess reactive power by increasing the line reactance 

(the reactive component of impedance that absorbs 

or emits reactive power). Static VAR compensators 

and static synchronous compensators (also known 

as STATCOMs) are devices that inject and absorb 

reactive power and are used to maintain voltage by 

adjusting the impedance of the system. 

Large deviations in voltage levels can have severe 

impacts. Low voltage can cause electric system instability or collapse and, at distribution voltages, can 

cause damage to motors and the failure of electronic 

equipment. Low voltage levels occur when there 

is a lack of reactive power, which can result from a 

load-driven surge of reactive power demand or when 

there are high reactive power losses due to heavy 

power transfers. At the other extreme, high voltages 

can exceed the insulation capabilities of equipment 

and cause dangerous electric arcs known as “flashovers.” These conditions can occur when there 

is light loading on the system (e.g., less customer 

demand), causing an excess of reactive power that 

elevates the voltage beyond safe operating limits. 

Outages of reactive power equipment, transmission 

lines, or generators can also contribute to both 

under-and over-voltages. 

Power Flow and Stability Control

Because the electric system is interconnected and 

dynamic, the system must be operated within electrical stability limits. Stability problems can develop 

very quickly – in timeframes ranging from milliseconds to minutes. Electricity system operators often 

describe events in terms of the number of “cycles” 

of alternating current that pass. One cycle is 1/60th 

of a second. The main concern is to ensure that generation dispatch and the resulting power flows and 

voltages are such that the system is stable at all times. 

Stability limits, like thermal limits, are expressed as 

a maximum amount of electricity that can be safely 

transferred over transmission lines. 

There are two types of stability limits. First, voltage 

stability limits are set to ensure that the unplanned 

loss of a line or generator (which may have been 

providing locally critical reactive power support, as 

described previously) will not cause voltages to fall 

to dangerously low levels. If voltage falls too low, it 

begins to collapse uncontrollably, at which point automatic relays either shed load or trip generators to 

avoid damage. Second, power (angle) stability limits 

are set to ensure that a fault or an unplanned loss 

of a line, transformer, or generator will not cause 

the remaining generators and loads being served 

to lose synchronism with one another (recall that 

all generators and loads within an interconnection 

must operate at or very near a common 60 Hz). Loss 

of synchronism with the common frequency means 

generators are operating out-of-step with one another. Even modest losses of synchronism can result in 
26

Federal Energy Regulatory Commission Reliability Primer

damage to generation equipment. Under extreme 

losses of synchronism, the grid may break apart into 

separate electrical islands; each island would begin to 

maintain its own frequency, determined by the load/

generation balance within the island.

Short-Term and Long-Term Planning 

Reliable power system operation requires far more 

than monitoring and controlling the system in 

real-time. Thorough planning, design, maintenance, and analysis are required to ensure that the 

system can be operated reliably and within safe 

limits. Operations planning looks at day-ahead, 

week-ahead, seasonal and up to one year planning 

horizons. Short-term planning addresses one to five 

year planning horizons. Long-term planning focuses on providing adequate generation resources and 

transmission capacity to ensure that in the future the 

system will be able to withstand severe contingencies without experiencing widespread, uncontrolled 

cascading outages.

A utility that serves retail customers must estimate 

future loads and, in some cases, arrange for adequate 

sources of supplies and plan adequate transmission 

or distribution infrastructure. Utilities must identify 

a range of possible contingencies and set corresponding expectations for system performance under several categories of possible events, ranging from every 

day “probable” events to “extreme” events that may 

involve substantial loss of customer load or generation in a widespread area. Utilities must also address 

requirements for voltage support and reactive power, 

disturbance monitoring, facility ratings, system 

modeling and data requirements, system protection 

and control, and system restoration. 

System operators must take the steps described 

above to plan and operate a reliable power system. 

However, emergencies can still occur because of external factors such as severe weather, operator error, 

or equipment failures that exceed planning, design, 

or operating criteria. For these less frequent events, 

an operating entity maintains emergency procedures 

that address a credible range of emergency scenarios. 

System operators must be trained to recognize and 

take effective action in response to these emergencies. To deal with a system emergency that results in 

a blackout, such as the one that occurred on August 

14, 2003, system operators must have procedures and 

capabilities to use “black start” generators, which 

are capable of restarting and synchronizing with no 

external power source, and to coordinate operations 

to quickly restore the system to a normal and reliable 

condition. 

Vegetation Management 

Vegetation management is critical to any utility 

company that maintains overhead energized lines 

because electric power outages can occur when trees, 

or portions of trees, grow or fall onto overhead electric power lines. While not all vegetation-related 

outages can be prevented (due to storms, high winds, 

etc.), some outages can be mitigated or prevented 

by managing the vegetation before it becomes a 

problem. Tree contact with a power line causes a 

fault, which signals the line’s relays to remove the 

line by interrupting the current flow. Direct physical contact is not necessary for a fault to occur. An 

electric arc can occur between a part of a tree and a 

nearby high-voltage conductor if a sufficient distance 

separating them is not maintained. Arcing distances 

vary based on such factors such as voltage, ambient 

temperature, and humidity conditions. Arcs can 

cause fires as well as faults and line outages. Most 

utilities have right-of-way and easement agreements 

allowing the utility to trim vegetation as needed 

along their lines to provide safe and reliable electric 

power. Electric utilities enter into easements or 

agreements with landowners to establish contractual 
27

rights regarding what can be pruned or removed in 

the transmission right-of-way. Transmission easements generally give the utility a great deal of control over the landscape, with rights to do whatever 

work is required to maintain the lines with adequate 

clearance through the control of vegetation.

FERC has approved a Reliability Standard on vegetation management, to reduce the risk of outages 

caused by inadequate tree trimming. This Reliability Standard, however, applies only to high voltage 

lines, typically 200 kilovolts and higher. Tree trimming for lower voltage lines generally falls under the 

jurisdiction of state or local authorities. 

Source: FERC, Utility Vegetation Management Final Report

Coordination and Communication

Operating the electric system continuously at an optimal state requires that numerous entities communicate effectively in real-time to maintain the system 

balance between generation and load, stay within 

operating limits, and address issues that may arise. 

This communication occurs both through interpersonal channels (telephone, radio, email) and automated data exchange systems (e.g., links between 

neighboring transmission operators). The principal 

entities involved in coordination and communication include:

• Reliability coordinator: The entity that is the 

highest level of authority responsible for the 

reliable operation of the electric power system; 

it has a wide-area view, and has the operating 

tools, processes and procedures, including the 

authority to prevent or mitigate emergency operating situations in both next-day analysis and 

real-time operations. The Western interconnection and ERCOT interconnection each have 

one reliability coordinator, while the Eastern 

interconnection has 11 reliability coordinators.

• Balancing authority: The entity that is initially 

responsible for maintaining the balance between 

generation and load within a “balancing authority area,” which is its defined electric boundary. 

Approximately 105 balancing authorities across 

the United States collectively make-up the areas 

where generation and load need to be kept in 

balance. 

• Transmission operator: The entity that is responsible for the reliability of its “local” transmission system, and that operates or directs the 

operations of the transmission facilities. While 

some entities both own and operate transmission assets, others do not. Transmission operators that do not own the transmission facilities 

have agreements with the owner to coordinate 

and operate those facilities. Approximately 

315 transmission operators are registered with 

NERC to operate these “local” transmission 

systems across the United States. 

• Generator operator: The entity that operates 

generating facilities and performs the functions 

of supplying energy and interconnected operations services. While some entities both own 
28

Federal Energy Regulatory Commission Reliability Primer

and operate generation assets, this is not always 

the case. Generator operators that do not own 

the generating facilities have agreements with 

the owner to coordinate and operate those 

facilities. Approximately 936 generation entities 

are registered with NERC across the contiguous 

United States. Many of these entities own more 

than one generator, and not all generators fall 

under NERC authority. 

• Distribution provider: Provides and operates 

the “wires” between the transmission system 

and the end-use customer. For those end-use 

customers who are served at transmission 

voltages, the transmission owner also serves as 

the distribution provider. Thus, the distribution 

provider is not defined by a specific voltage, but 

rather as performing the distribution function 

at any voltage. Approximately 393 entities are 

registered with NERC for this function across 

the United States.

The reliability coordinator typically has the highest 

level of authority, followed by the transmission 

operator and the balancing authority. These entities 

must maintain continuous communications with 

each of the appropriate entities, which also include 

neighboring entities that are affected by conditions 

within an operator’s area. Additionally, these entities must have plans to restore communications and 

establish an alternative communication capability. 

Critical Infrastructure Protection 

Physical Security 

Physical security for the electric power system revolves around the protection of essential assets from 

physical harm. Different types of facilities present 

different physical security challenges. Centralized 

facilities that are normally manned, such as control 

centers, communication facilities, and corporate 

offices, present a different physical security challenge 

than do the decentralized and typically unmanned 

facilities, such as substations and transmission 

lines. While the more centralized nature of attended facilities allows more focused and economical 

security measures, this advantage is balanced against 

the risks associated with the greater impact to the 

electric power system by a failure of that facility. As 

such, these centralized facilities need to use the most 

stringent security controls. Decentralized facilities, 

on the other hand, will often rely on automated 

security controls monitored from a different facility. 

This presents a different challenge to keep up to date 

with both automated security control technologies 

and communication technologies to ensure effective 

security for such facilities.

Physical security typically comprises at least six 

distinct concepts:

• Deter - visible physical security measures installed to induce individuals to seek other, less 

secure targets.

• Detect - physical security measures installed to 

detect unauthorized intrusion and provide local 

and/or remote intruder alarms. 

• Delay - physical security measures installed to 

delay an intruder’s access to a physical asset 

and provide time for incident assessment and 

response. 

• Assess - the process of evaluating the legitimacy 

of an alarm and the procedural steps required to 

respond. 

• Communicate - communication systems used 

to send and receive alarm/video signals and 

voice and data information. Also, includes the 

documented process to communicate detected 

intrusions. 

• Respond - the immediate measures taken to 

assess, interrupt, and/or apprehend an intruder. 
29

Cyber Security

For many years the control systems for utilities and 

industrial companies have operated in a stand-alone 

environment without computer or communication 

links to external information technology infrastructure. More recently, such stand-alone systems have 

been increasingly connected to both the corporate 

information technology environment and the external world via the Internet, and the electric power 

system is no exception to this trend. Computer and 

communication network interconnection brings 

with it the potential for cyber-attacks on these systems by adversaries. The problem is particularly important because such an attack can potentially affect 

several entities across the country simultaneously. 

Controlling electronic access is one of the keys to 

preventing a successful cyber-attack. An adversary 

that can gain electronic access to a computer system 

may be able to gain control over that system and use 

it for his purposes. In today’s environment, many 

infrastructure control systems have an electronic 

pathway that leads to the outside world, which can 

create a potential for access that is vulnerable to 

exploitation by an adversary. 

The potential solution to such cyber threats is a 

strong cyber security posture by entities that may be 

vulnerable to such attacks. A major challenge to preserve system protection is that computer and communication system architectures change, technology 

changes, and threats change, all of which means that 

defenses must change. Traditionally, threats can 

change faster than defenses. To meet or minimize 

these risks, one widely recognized cyber security 

strategy is “defense in depth.” This strategy involves 

layering of defense mechanisms in a way that discourages an attack and increases the potential that an 

entity will be alerted to an attack on it. While other 

strategies exist, defense in depth is a widely accepted, 

effective strategy to address cyber threats that is both 

comprehensive and flexible. 

The development of a home security system provides a useful analogy for understanding the defense 

in depth strategy. For example, a home security 

system might include the following defenses: (1) a 

motion sensor light that goes on whenever someone gets close to the house, (2) a video camera that 

records the approaches to the house, (3) a door with 

a deadbolt lock and a chain, (4) an alarm system that 

activates if a door or window is opened (along with 

decals notifying a potential intruder that the system 

exists), and (5) a dog inside the house. Several of 

these items are designed to keep an intruder out, 

some are designed to activate if an intruder gains 

access, and some are designed to record the event 

if it occurs. Each of these measures provides some 

degree of protection and, in combination, substantially increases the chances of successfully deterring 

a burglary. 

Cyber defenses work in a similar manner. Some 

defenses, like firewalls, are designed to keep intruders out. Others, like intrusion detection systems, 

are designed to activate if someone gains access. 

Still others, like audit logs, are designed to inform 

a computer operator whether another person has 
30

Federal Energy Regulatory Commission Reliability Primer

gained access. Information sharing, where entities 

voluntarily share information about attempted or 

successful access attempts with each other, is also a 

valuable security control. The combination of all of 

these technologies, and how they are combined and 

implemented, determines whether computer security personnel have effectively protected cyber assets. 

Whereas grid operations usually involve readily 

measured quantities and activities, cyber security 

involves a careful balance of the technologies available with the existing control equipment and the 

functions they perform. Compared to general grid 

operations, cyber security is in many ways as much, 

or even more, a matter of subjectively balancing 

physical and technical options rather than a purely 

objective task of achieving a single, steady, physical 

state. The task of balancing technical options for 

cybersecurity comes into play as one selects and 

combines various available technologies into a 

comprehensive architecture to protect the specific 

computer environment. 

Major Blackouts and Responses

System failures, particularly when compounded 

with multiple problems, can result in cascading 

blackouts across multiple operating systems. System planners study such cascading disturbances and 

draw lessons from them to prepare their systems 

and avoid these problems in the future. Below is 

a description of some of the most severe cascading 

blackouts experienced in North America. 

November 9, 1965: Northeast Blackout

On November 9, 1965, a blackout occurred in 

the northeastern United States and southeastern 

Ontario, Canada that affected 30 million people and 

interrupted more than 20,000 MW of electrical load 

for up to thirteen hours. This event is often referred 

to as “the Great Northeast Blackout,” mainly because 

this was one of the most significant blackout events 

of the time and affected major population centers 

such as New York City, Boston, and Toronto, as well 

as smaller or rural areas. Virtually all of New York, 

Connecticut, Massachusetts, Rhode Island, small 

segments of northern Pennsylvania and northeastern New Jersey, and substantial areas of Ontario, 

Canada, were affected. 

The blackout was caused by the tripping of a 230 

kV transmission line near Ontario, Canada, which 

caused several other heavily loaded lines also to fail. 

An initial protective relay tripped (due to incorrect 

settings) when a transmission line was overloaded. 

This also caused several other relays to operate on 

other transmission lines, which resulted in a power 

surge that overwhelmed the transmission system in 

western New York. Several generators also tripped 

off-line according to design because they were 

unable to transmit their power due to the overloaded transmission lines. The resulting power swings 

caused a cascading outage that blacked out much of 

the Northeast.

Subsequent blackouts 

Several other notable blackouts occurred through 

the years, but the November 1965 outage is significant due to the geographic size of the outages and 

underlying mechanical or human failures, rather 

than weather related causes. The July 13, 1977 

New York City blackout occurred when two 345-kV 

lines on a common tower in Northern Westchester 

County, New York were struck by lightning and 

tripped out. With the loss of power imports ordinarily carried by these lines, generation in New York 

City was not sufficient to serve the load in the city, 

leading to load loss. The event affected nine million 

people, with 6,000 MW of load lost. Outages lasted 

for up to 26 hours. 
31

A West Coast blackout occurred on December 22, 

1982. This disturbance began when high winds 

caused the failure of a 500-kV transmission tower. 

This ultimately resulted in the loss of 12,350 MW of 

load and affected over 5 million people in the West.

On July 2-3, 1996, a 345-kV transmission line in 

Idaho sagged into a tree and tripped on July 2. A 

protective relay on a parallel transmission line 

detected the same fault and incorrectly tripped a 

second line. Similar conditions and initiating factors 

were present on July 3; however, as voltage began to 

collapse in the Boise, Idaho area, the operator disconnected customers to maintain system integrity. 

This event resulted in the loss of 11,850 MW of load 

and affected 2 million people in 14 states; Alberta 

and British Columbia in Canada; and Baja California 

Norte in Mexico. Outages lasted from a few minutes 

to several hours. 

Another western interconnection blackout followed 

on August 10, 1996 when the transmission system 

from Canada south into California was heavily 

loaded with north-to-south power transfers. These 

flows were due to high Southwest demand caused by 

hot weather, leading to transmission lines sagging 

into untrimmed trees, causing the system to trip out. 

This resulted in the loss of over 28,000 MW of load 

and affected 7.5 million people in many of the same 

14 states as the previous month’s event; Alberta and 

British Columbia in Canada; and Baja California 

Norte in Mexico. Outages lasted from a few minutes 

to as long as nine hours. 

August 14, 2003: Midwest and Northeast US-Canadian 

Blackout

On August 14, 2003, the North American power 

grid experienced its largest blackout ever, impacting 

large portions of the Midwest and Northeast United 

States and Ontario, Canada. The outage affected 

an estimated 50 million people and 61,800 MW of 

electric load was lost in the states of Ohio, Michigan, 

Pennsylvania, New York, Vermont, Massachusetts, 

Connecticut, New Jersey and the Canadian province 

of Ontario. Although utilities successfully restored 

power to most customers within hours, some areas 

in the United States did not have power restored 

for several days. Parts of Ontario suffered rolling 

blackouts for up to two weeks before full power was 

restored. Estimates of total costs in the United States 

ranged between $4 billion and $10 billion; in Canada, gross domestic product was down 0.7 percent 

in August, there was a net loss of 18.9 million work 

hours, and manufacturing shipments in Ontario 

were down C$ 2.3 billion. 

A combination of human error and equipment failures caused the August 14, 2003 blackout. A generating plant near Cleveland, Ohio tripped offline amid 

high heat and high electrical demand. The hot day 

also caused power lines to sag as power losses due to 

higher currents heated the lines. A transmission line 

in northern Ohio sagged into overgrown trees and 

tripped. Three other transmission lines sagged into 

trees and switched off, forcing other power lines to 

shoulder the extra burden. Normally, the problem 

would have activated an alarm in the control room 

but the alarm system failed. As designed, the power 

was diverted to other transmission lines, but they 
32

Federal Energy Regulatory Commission Reliability Primer

were not able to handle the increase. This, in turn, 

activated these lines’ relays which tripped lines and 

again diverted greater amounts of power to other 

transmission lines. For the next hour and a half, system operators tried to understand what was happening as load was shifting and transmission lines were 

overloading. Once the multiple line trips occurred, 

multiple generators also tripped out to prevent damage. The failures cascaded throughout southeastern 

Canada and eight northeastern states.

As with previous cross-border blackouts, the United States and Canadian governments conducted a 

joint-review into the events that occurred. A U.S. - 

Canadian Power System Outage Task Force, including personnel from FERC, carefully investigated the 

causes of the blackout and issued a detailed report 

that made recommendations on ways to reduce the 

possibility of recurrence. 

The causes of the outages and the cascading significant load drops were many, but were summarized 

as the “3 Ts” - trees, tools and training. Overgrown 

trees had contacted multiple high-voltage transmission lines, tripping them out of service and thus 

increasing the load on the remaining lines that 

caused further sagging on additional lines, resulting 

in even more lines tripping. The system operators 

in the Midwest region at the time did not have the 

tools to make them aware of this chain of events, 

allowing the reliability problem to cascade further. 

The cascade continued onward as system operators 

did not have timely awareness of the events taking 

place. When they did begin to recognize the trouble, 

the system operators did not have adequate training 

on how to respond to the emergency conditions. 

The report included 46 recommendations for the 

industry and entities to undertake, including that 

“the U.S. Congress should enact the reliability 

provisions...to make compliance with Reliability 

Standards mandatory and enforceable. If that could 

be done, many of the other recommended actions 

identified in the report could be accomplished readily in the course of implementing the legislation.” 

U.S./Canada form a 

Blackout Task Force

Blackout Task Force 

identifies causes 

• inadequate system understanding

• inadequate situational awareness

• inadequate tree trimming

• inadequate reliability coordinator 

diagnostic support

Many root causes same 

as those for the other 

blackouts from the 

1960s-1990s

Renewed & bipartisan 

call for change

Blackout Response
33

C. NERC - From a Voluntary Council to Electric Reliability Organization with 

Mandatory Reliability Standards

Following the 1965 Northeast Blackout, the National Electric Reliability Council (the predecessor 

organization to the North American Electric Reliability Corporation and also referred to as NERC) 

was established to provide a means for coordinating 

among interconnected utilities to ensure that the 

interconnected transmission network in the United 

States was reliable, adequate and secure. Additionally, regional reliability organizations were formalized 

under NERC, as well as regional planning coordination guides, which NERC maintained. The utilities 

maintained and practiced voluntary operating 

criteria and guides. NERC successfully operated for 

numerous years as a voluntary organization, relying on reciprocity, peer alignment, and the mutual 

self-interest of all involved to ensure the voluntary 

compliance with reliability requirements. 

By 1981, NERC had expanded to include the interconnected electric systems in Canada and its name 

was changed to the North American Electric Reliability Council to more accurately reflect the broader 

scope of NERC’s membership. As the electric industry evolved, the regional councils broadened their 

membership to include all segments of the electric 

industry: investor-owned utilities; federal power 

agencies; rural electric cooperatives; state, municipal 
34

Federal Energy Regulatory Commission Reliability Primer

and provincial utilities; independent power producers; power marketers; and end-use customers. 

Collectively, the members in the NERC regions 

account for virtually all the electricity supplied in 

the contiguous United States, Canada, and a portion 

of Baja California Norte, Mexico. 

After the 2003 blackout, NERC’s role and responsibilities changed. Congress added section 215 to the 

FPA in 2005, which authorized the development of 

mandatory Reliability Standards by an independent 

electric reliability organization. 

FERC established rules and regulations governing 

the formation and certification of an electric reliability organization in accordance with the reliability 

provisions of the newly enacted legislation. In April 

2006, NERC filed an application with FERC for 

certification as the electric reliability organization. 

NERC also submitted 107 Reliability Standards to 

FERC for approval. The 107 proposed Reliability 

Standards were largely the existing voluntary protocols and guidelines repackaged to be the mandatory 

and enforceable Reliability Standards under the new 

statute. Concurrently with its FERC application, 

NERC made filings seeking comparable recognition 

from government authorities in Canada, including the provinces of British Columbia, Alberta, 

Saskatchewan, Manitoba, Ontario, Quebec, New 

Brunswick, and Nova Scotia, and the National Energy Board. Today, NERC is recognized as an electric 

reliability standards-setting organization in its role 

as the North American ERO.

FERC certified NERC as the electric reliability organization in July 2006 and, at the start of 2007, NERC 

reorganized as a corporation: the North American 

Electric Reliability Corporation. In March 2007, 

FERC approved 83 of NERC’s proposed 107 Reliability Standards, which were the first set of legally 

enforceable mandatory standards for the U.S. bulk 

power system, to become effective June 2007. For 

the remaining 24 proposed standards, FERC determined that NERC must submit additional information. However, FERC held that NERC and the 

utilities should voluntarily comply with NERC’s 

non-approved standards as good utility practice 

while FERC continued to evaluate them.
35

FERC also approved delegation agreements by which 

NERC delegates its authority to monitor and enforce 

compliance with NERC Reliability Standards to the 

eight regional entities, with NERC continuing in 

an oversight role. Under NERC’s oversight, the regional entities perform certain aspects of the electric 

reliability organization functions through these delegation agreements. The delegation agreements with 

each regional entity address, among other things: 

• Development of regional Reliability Standards 

• Monitoring compliance with and enforcing 

mandatory Reliability Standards (both North 

American wide and regional), certification of 

registered entities, and registration of owners, 

operators and users of the bulk power system

• Reliability assessment and performance analysis

• Training and education 

• Event analysis and reliability improvement

• Situation awareness and infrastructure security

 

Today, NERC is a not-for-profit international entity 

whose mission is to assure the reliability of the bulk 

power system in North America. NERC develops 

and enforces Reliability Standards; annually assesses seasonal and long-term reliability; monitors 

the bulk power system through system awareness; 

and educates, trains, and certifies industry personnel. NERC’s activities cover the users, owners, and 

operators of the bulk power system, which serves 

more than 334 million people. NERC-developed 

Reliability Standards apply in whole or part to more 

than 1,400 bulk power system users, owners and 

operators. 

NERC and the eight regional entities are often 

referred to as the ERO Enterprise, which collectively 

brings together the leadership, experience, judgment, skills, and supporting technologies of NERC 

and the regional entities to fulfill the electric reliability organization’s statutory obligations to assure the 

reliability of the bulk power system.
36
37

III. The Energy Policy Act of 2005

A. FPA Section 215

 

Purpose and Scope

Following the August 2003 blackout, Congress enacted the Energy 

Policy Act of 2005 (EPAct 2005), which President George W. Bush 

signed into law on August 8, 2005. Title XII of EPAct 2005 added 

a new section 215 to the FPA, titled “Electric Reliability.” Section 

215 of the FPA does not prohibit or otherwise “outlaw” blackouts. 

Instead it authorizes FERC to certify an entity to operate as an independent electric reliability organization to develop and enforce 

mandatory Reliability Standards that “provide for reliable operation of the bulk power system,” subject to FERC oversight. Moreover, the statute does not pertain to outages on the distribution 

system that may occur, for example, when a tree falls on a local 

distribution wire. Rather, section 215 of the FPA makes clear that 

the Reliability Standards are to address the reliable operation of the 

bulk power system so that “instability, uncontrolled separation, or 

cascading failures” will not occur as a result of a sudden disturbance. 

This mandatory approach replaces the electric industry’s voluntary 

protocols and guidelines for operating and planning the bulk power 

system that had been in place since the 1960s. 

The statute contemplates an electric reliability organization that leverages the expertise of the industry in developing Reliability Standards. 

EPAct 2005 requires that the electric reliability organization have an 

independent governing board, without financial ties to the users, owners 

and operators of the bulk power system. At the same time, the electric 

reliability organization must have rules that provide for fair stakeholder 

representation in the selection of its directors, and there must be balanced decision-making in the electric reliability organization’s committees. The electric reliability organization must provide “reasonable
38

Federal Energy Regulatory Commission Reliability Primer

notice and opportunity for public comment, due 

process, openness, and balance of interests” in developing Reliability Standards and otherwise exercising 

its duties. 

The electric reliability organization develops and 

enforces Reliability Standards that provide for an 

“adequate level of reliability” of the interconnected 

transmission network.

FERC only approves Reliability Standards that are 

applicable to registered entities in the contiguous 

United States. Governmental organizations outside 

of the United States, but in North America, can also 

approve NERC’s standards for applicability in their 

respective countries. Under section 215 of the FPA, 

NERC develops the Reliability Standards, not FERC. 

Once NERC develops a Reliability Standard, FERC 

may approve the standard or remand the standard to 

NERC. FERC also has authority to direct NERC to 

develop a new or modified Reliability Standard that 

addresses a specific reliability matter. FERC does not 

have the authority to write a Reliability Standard. 

FERC must approve a Reliability Standard before it 

may be enforced in the United States. An approved 

Reliability Standard may be enforced by NERC, and 

NERC’s enforcement of a Reliability Standard is 

subject to FERC’s review. FERC also may initiate a 

compliance action – including imposition of a penalty - independent of NERC. 

In enacting section 215 of the FPA Congress did 

not “outlaw” blackouts; nor can FERC. Under 

section 215, the threshold for FERC approving one 

of NERC’s proposed Reliability Standards is if it 

is “just, reasonable, not unduly discriminatory or 

preferential, and in the public interest.” Moreover, 

section 215 requires FERC to “give due weight to the 

technical expertise of the Electric Reliability Organization with respect to the content of a proposed 

[Reliability Standard]. . . .” 

Definitions of Key Terms

In enacting EPAct 2005, Congress added a number 

of new terms to the FPA. Of particular note are the 

definitions in section 215(a) of “bulk power system,” 

“reliability standard” and “reliable operation.” 

 “Bulk power system” means the facilities and 

control systems necessary for operating an interconnected electric energy transmission network (or any 

portion thereof) and electric energy from generation 

facilities needed to maintain transmission system 

reliability. The term does not include facilities used 

in the local distribution of electric energy. 

“Reliability Standard” means a requirement 

approved by FERC to provide for reliable operation 

of the bulk power system. The term includes requirements for the operation of existing bulk power 

system facilities and the design of planned additions 

or modifications to such facilities to the extent necessary to provide for reliable operation of the bulk 

power system, but the term does not include any 

requirement to enlarge such facilities or to construct 

new transmission capacity or generation capacity. 

The term also includes standards for cybersecurity 

protection. 

A New Era: EPAct 2005:

August 2005 - EPAct 2005 becomes law

• Amends FPA to include new section 215 - 

Mandatory electric reliability regime

• Purpose: creates an independent “electric reliability 

organization” (ERO), certified by the Commission, to develop and enforce mandatory reliability 

standards for “reliable operation” of the nation’s 

bulk-power system

• ERO develops Reliability Standards that provide an 

“adequate level of reliabiilty”

• Commission role: certify the ERO, approve proposed standards, review NERC-imposed penalties, 

and independent enforcement authority 
39

“Reliable operation” means operating the elements of the bulk power system within equipment 

and electric system thermal, voltage, and stability 

limits so that instability, uncontrolled separation, or 

cascading failures of such system will not occur as a 

result of a sudden disturbance, including a cybersecurity incident, or unanticipated failure of system 

elements. 

Jurisdiction 

The authority Congress gave FERC under section 

215 of the FPA pertains to the bulk power system. 

As mentioned above, facilities used in the local 

distribution of electric energy are not included in 

the bulk power system. The statute also provides in 

section 215(i) that “Nothing in [section 215] shall be 

construed to preempt any authority of any State to 

take action to ensure the safety, adequacy, and reliability of electric service within that state,” as long as 

such action is not inconsistent with any Reliability 

Standard. Upon application by the electric reliability organization or another affected party, FERC 

has authority to determine whether a state action 

is inconsistent with a Reliability Standard and may 

stay the state action pending the determination. 

Section 215(b) of the FPA also identifies the persons/

entities that are subject to FERC jurisdiction for purposes of bulk power system reliability. In particular, 

FERC has jurisdiction in the U.S. over the electric 

reliability organization and “regional entities” that 

receive delegated enforcement authority from the 

electric reliability organization (discussed later). 

FERC also has jurisdiction over all owners, operators, and users of the bulk power system, including 

state and municipal utilities, rural electric cooperatives, and federal entities, “for purposes of approving 

reliability standards ... and enforcing compliance 

with [section 215 of the FPA].” All users, owners and 

operators of the bulk power system must comply 

with the mandatory Reliability Standards developed 

by the electric reliability organization and approved 

by FERC. Section 215 of the FPA does not apply to 

Alaska or Hawaii. 

Electric Reliability Organization Certification

Section 215(c) of the FPA authorizes FERC to certify 

one entity as the electric reliability organization, 

which is responsible for the development and 

enforcement of mandatory Reliability Standards. 

The statute sets forth the following criteria that any 

entity certified as the electric reliability organization 

must satisfy:

Reliability Jurisdiction – Who Must Comply 

Section 215(b) – Commission has jurisdiction over:

All “users, owners and 

operators of the bulk-power 

system” within the U.S. 

(other than Alaska and 

Hawaii)

Regional 

Entities

ERO

 Includes entities 

specifically excluded 

from other jurisdiction 

(e.g., federal agencies 

like BPA, municipals, 

rural coops)

Includes 

entities in 

ERCOT
40

Federal Energy Regulatory Commission Reliability Primer

• The electric reliability organization must have 

the ability to develop and enforce Reliability 

Standards that provide for an adequate level of 

reliability of the bulk power system; and 

• The electric reliability organization must have 

rules that provide for:

• Independent governance: The electric 

reliability organization must be independent 

of owners, operators, and users of the bulk 

power system, while assuring fair stakeholder representation in selection of electric reliability organization directors and balanced 

decision making in any electric reliability 

organization committee or subordinate 

organizational structure;

• Dues and fees: The electric reliability organization must have rules to allocate equitably reasonable dues, fees, and other charges 

among end users for all activities under 

section 215 of the FPA;

• Reliability Standards: The electric reliability organization must provide reasonable 

notice and opportunity for public comment, 

due process, openness, and balance of interests in developing Reliability Standards and 

exercising other duties under the statute;

• Enforcement: The electric reliability 

organization must provide fair and impartial 

procedures for enforcement of Reliability 

Standards; and

• International recognition: After certification, the electric reliability organization will 

take appropriate steps to gain recognition in 

Mexico and Canada.

The electric reliability organization operates under organization rules, which are subject to FERC 

review. The electric reliability organization must 

submit proposed revisions to its rules to FERC for 

approval before they may take effect. FERC may 

propose a change to an electric reliability organization rule, which takes effect after notice and opportunity for public comment, and a finding by FERC 

that the change is “just, reasonable, not unduly 

discriminatory or preferential, [and] is in the public 

interest.” 

The statute does not set a temporal limit on the 

electric reliability organization certification. Periodic “re-certification” is not required. However, 

pursuant to FERC regulation, the electric reliability 

organization must submit a periodic performance 

assessment (discussed later) to demonstrate that the 

electric reliability organization continues to satisfy 

the certification criteria on an ongoing basis. Further, FERC has stated that it may remove the electric 

reliability organization designation for cause “as a 

last resort after all other attempts to resolve a significant compliance matter have failed.” 

Regional Entities 

Section 215(e)(4) of the FPA requires that FERC issue 

regulations authorizing the electric reliability organization to enter into an agreement to delegate authority to a qualified regional entity for the purpose 

of proposing Reliability Standards to the electric 

reliability organization and enforcing them. (As discussed later, FERC promulgated such regulations in 
41

Order No. 672, issued in 2006.) The regional entity 

must meet the same statutory criteria as the electric 

reliability organization (discussed above), except 

that the statute allows more flexibility for regional 

entity governance structure. While the electric 

reliability organization must have an independent 

board, a regional entity may have an independent 

board, a balanced stakeholder board or a combination balanced stakeholder and independent board. 

In addition, a delegation agreement must promote 

“effective and efficient administration of bulk power 

system reliability.” No delegation agreement may 

take effect until approved by FERC. By statute, the 

electric reliability organization and FERC must 

rebuttably presume that a proposal for a delegation 

agreement with a regional entity organized on an 

interconnection-wide basis promotes effective and 

efficient administration of bulk power system reliability and should be approved. 

Reliability Standards Development and 

Approval

Section 215(d) of the FPA provides the process for 

the electric reliability organization to propose a 

Reliability Standard, subject to FERC review and approval. The electric reliability organization must file 

with FERC each Reliability Standard that it proposes 

to make effective and enforceable in the U.S. The 

statute provides that FERC may act on a proposed 

Reliability Standard “by rule or order,” meaning that 

FERC can address a standard by either initiating a 

rulemaking proceeding or by an adjudicatory order. 

Under either approach, FERC provides public notice 

and opportunity for comment when addressing a 

proposed standard. 

The statute requires FERC to give “due weight” to 

the technical expertise of the electric reliability organization or any regional entity organized on an interconnection-wide basis with respect to the content 

of a standard it proposes. Further, section 215(d) 

of the FPA provides that FERC is not to defer as to 

the effect of a standard on competition. If FERC 

disapproves a Reliability Standard, it cannot unilaterally modify the Reliability Standard but must 

remand it to the electric reliability organization for 

further consideration. However, FERC may direct 

the electric reliability organization to submit a new 

or modified standard to address a specific reliability 

matter that FERC deems appropriate to carry out 

section 215 of the FPA. 

Enforcement 

Section 215(e) of the FPA authorizes the electric 

reliability organization, after notice and opportunity 

for hearing, to impose a penalty for a violation of 

a Reliability Standard, subject to review by FERC. 

Pursuant to the statute, the electric reliability organization may impose a penalty on an owner, operator, 

or user of the bulk power system if, after notice and 

an opportunity for a hearing, the electric reliability 

organization finds that the owner, operator, or user 

violated a Reliability Standard. A penalty must 

“bear a reasonable relation to the seriousness of the 

violation” and must take into account the efforts by 

the owner, operator, or user to remedy the violation 

in a timely manner (section 215(e)(6)). 
42

Federal Energy Regulatory Commission Reliability Primer

The electric reliability organization must file notice 

and the record of the penalty proceeding with FERC. 

The alleged violator, or FERC on its own motion, 

has up to 30 days from the date of the filing to seek 

review of the penalty. If no timely review is initiated, the penalty may not take effect earlier than the 

31st day after the electric reliability organization 

files the notice with FERC. Upon review, FERC may 

affirm, modify, or set aside the penalty. 

In addition to reviewing penalties imposed by the 

electric reliability organization, FERC has independent authority to initiate a compliance action 

and may assess a penalty for violation of a Reliability Standard, separate from the electric reliability 

organization or a regional entity. Further, FERC 

may order compliance with a Reliability Standard 

and impose a penalty on an owner, operator, or user 

of the bulk power system if it finds that the owner, 

operator, or user has engaged in, or is about to engage in, activity that violates a Reliability Standard. 

As discussed later, in practice, FERC and the electric 

reliability organization have conducted joint investigations of significant bulk power system events.

FERC may also take appropriate action against the 

electric reliability organization or a regional entity 

with delegated enforcement authority to ensure 

compliance with a Reliability Standard or any FERC 

order regarding the electric reliability organization 

or the regional entity. 

 Reliability Reports

Section 215(g) of the FPA requires that the electric 

reliability organization conduct periodic assessments 

of the reliability and adequacy of the bulk power 

system. While the electric reliability organization 

reports assess resource adequacy, FPA section 215(i) 

states that the electric reliability organization does 

not have the authority to set or enforce mandatory 

standards for adequacy or safety of electric facilities 

or services. The statute also makes clear that the 

electric reliability organization and FERC do not 

have the authority to require the construction of 

generation or transmission assets. 

 

Regional Advisory Bodies 

The statute allows for the establishment of one or 

more “regional advisory bodies,” for the purpose of 

providing advice to the electric reliability organization, a regional entity, or FERC regarding regional 

entity governance; whether a proposed Reliability 

Standard meets the statutory criteria for approval; 

the reasonableness of regional entity fees; and other 

responsibilities that FERC requests. FERC may defer 

to advice from a regional advisory body if it is organized on an interconnection-wide basis. 

Section 215(j) of the FPA requires FERC to establish 

a regional advisory body upon petition of at least 

two-thirds of the states within a region that have 

more than one-half of their electric load served within the region. Each state participating in the advisory body is to have one representative appointed by 

the governor. A regional advisory body may include 

representatives of agencies, states, and provinces 

outside the U.S. 

To date, one regional advisory body has been 

established, the Western Interconnection Regional 

Advisory Body (WIRAB), which is organized on an 

interconnection-wide basis.
43

B. FERC Implementation of FPA Section 215

Certification of the Electric Reliability 

Organization and Procedures for the 

Establishment, Approval, and Enforcement of 

Reliability Standards

In February 2006, FERC issued Order No. 672, in 

which FERC promulgated new Part 39 of its regulations to implement section 215 of the FPA, as 

required by EPAct 2005. The regulations address 

electric reliability organization certification, Reliability Standard development and enforcement, and 

NERC’s periodic reports and assessments. 

Electric Reliability Organization Periodic Assessment

To ensure that the electric reliability organization 

complies with the certification criteria on an ongoing basis, FERC required the electric reliability 

organization to undergo a performance assessment 

three years after certification and every five years 

thereafter.

Specifically, in such an assessment, the Commission’s regulations require: (1) the electric reliability 

organization’s explanation of how it satisfies FERC’s 

regulations for maintaining an adequate level of 

reliability; (2) recommendations by regional entities, 

users, owners, and operators of the bulk power system, and other interested parties for improvement 

of the electric reliability organization’s operations, 

activities, oversight and procedures, and the electric 

reliability organization’s response to such recommendations; and (3) the electric reliability organization’s evaluation of the effectiveness of each regional 

entity, recommendations by the electric reliability 

organization, users, owners, and operators of the 

bulk power system, and other interested parties for 

improvement of the regional entity’s performance 

of delegated functions, and the regional entity’s 

response to such evaluation and recommendations. 

FERC may require the electric reliability organization to take follow-up actions to establish compliance with the statutory and regulatory qualifications 

for the electric reliability organization. 

 Electric Reliability Organization Funding

FERC’s regulations specify procedures for funding 

the electric reliability organization in the United 

States. NERC’s annual business plan and budget 

for its U.S. operations are subject to FERC approval. 

NERC’s annual funding is provided through assessments to load-serving entities. These assessments 

are allocated on a net-energy-for-load basis.2 This 

means that NERC allocates costs based on those who 

benefit from a reliable bulk power system: the end 

users. NERC allocates its operating costs and those 

of the regional entities to “load-serving entities” 

- those owners, operators and users of the bulk 

power system responsible for delivering electricity 

to retail customers - based on how much net energy 

they need to meet their users’ energy requirements. 

Funds are then collected from these load-serving 

entities. 

The regional entities’ funding requirements are 

addressed separately in their respective business 

plans and budgets, which also must be reviewed and 

approved by NERC and FERC. Regional entity assessments are also based on net-energy-for-load and 

billed to the load-serving entities within the regional 

entity’s geographical region or “footprint.” 

2 In one of the few court challenges to FERC’s reliability authority, 

the District of Columbia U.S. Court of Appeals upheld the allocation of 

NERC assessments on a net-energy-for-load basis. Alcoa, Inc. v. FERC, 

564 F.3d 1342 (D.C. Cir. 2009).
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Federal Energy Regulatory Commission Reliability Primer

NERC’s budget is based on a calendar year. Each 

August, NERC submits to FERC a combined filing 

consisting of NERC’s business plan and budget, as 

well as the business plan and budget for each of the 

eight regional entities. FERC addresses the business 

plan and budget filing enough in advance of the 

next calendar year to allow NERC and the regional 

entities to send out timely assessment notices to 

load-serving entities.

Certification of NERC as the Electric 

Reliability Organization

On July 20, 2006, FERC certified NERC as the 

electric reliability organization for the contiguous 

United States under section 215(c) of the FPA. FERC 

found that NERC satisfied the criteria to be the electric reliability organization responsible for developing and enforcing mandatory Reliability Standards 

for the United States. Further, FERC directed NERC 

to provide additional information and make specific 

revisions to its rules of procedure, bylaws, enforcement hearing procedures, and sanctions guidelines, 

which NERC filed in a series of subsequent compliance filings. 

Governance: NERC is governed by an independent board of trustees, which has responsibility for 

approving Reliability Standards, electing and appointing officers, appointing committees, handling 

budgetary and financial matters, and overseeing all 

electric reliability organization programs. NERC’s 

bylaws require that the board include proportional 

representation from Canada and, when appropriate, 

Mexico. Membership in NERC is voluntary, free, 

and open to persons and entities with an interest 

in the reliable operation of the bulk power system. 

Each member is assigned to one of twelve membership sectors, which elect the representatives to the 

member representatives committee. The member 

representatives committee elects the board, votes on 

amendments to the bylaws, and provides advice to 

the board with respect to the budgets, business plans, 

funding mechanisms, proposed Reliability Standards, 

and other matters related to NERC’s operations. 

Reliability Standard Development: Section 215(c) 

of the FPA requires NERC to have the ability to 

develop Reliability Standards that provide for an “adequate level of reliability of the bulk power system.” 

A more detailed description of the standards development process is below. 

Enforcement: NERC’s compliance and enforcement 

tools include compliance audits, investigations, spot 

checks and other procedures for the identification, 

mitigation and assessment of penalties for non-compliance. NERC oversees the regional entities’ 

enforcement programs and appeals processes. NERC 

also has guidelines that set out factors NERC or a 

regional entity should consider to determine the 

appropriate penalty for a violation of a Reliability 

Standard. 

Each Reliability Standard identifies the categories of entities (such as balancing authorities and 

transmission operators) that must comply with the 

standard. To determine which entities are users, 

owners, or operators of the bulk power system that 

are required to comply with Reliability Standards, 

NERC has developed a “compliance registry,” which 

lists all of the registered users, owners and operators 

of the interconnected transmission network and the 

categories they are in. The registry is posted on the 

NERC website and updated monthly. NERC developed a “statement of compliance registry criteria” that delineates the selection criteria employed by 

NERC and the regional entities to determine which 

organizations should be registered as owners, operators, or users of the interconnected transmission 

network and the categories for which they should be 

registered and therefore included on the compliance 

registry. Details of the registry criteria are discussed 

in Section IV.
45

NERC Regional Entity Delegation: Under FPA 

section 215 authority, FERC developed regulations 

regarding the process for NERC to delegate authority to propose and enforce NERC Reliability Standards to regional entities. NERC developed a pro 

forma delegation agreement that contains standard 

language that is included in each individual delegation agreement unless specifically amended for a 

particular regional entity. The pro forma agreement 

incorporates customized exhibits, which address 

such matters as regional entity Reliability Standard 

development procedures and regional enforcement 

program requirements. 

Regional entities may not amend their regional entity rules without NERC and FERC approval. However, NERC may issue directives developed through 

a collaborative process, guidance, or directions to the 

regional entity regarding how it performs its delegated duties. 

Activities that the electric reliability organization 

may delegate to a regional entity include, but are not 

limited to: 

• Certification of bulk power system entities in 

accordance with the NERC rules of procedure.

• Registration of owners, operators, and users of 

the interconnected transmission network as 

responsible for compliance with requirements of 

Reliability Standards.

• Development of reliability assessments and 

performance analysis to ensure that data and 

information are collected, analyzed, provided to 

NERC in support of reliability assessments, and 

used for performance metrics and risk assessments. 

• Conducting and coordination of event analysis with NERC and dissemination of lessons 

learned to the electric industry.

• Providing training and education to registered 

entities.

• Gathering and assessing situational awareness 

information provided by registered entities, 

and assisting NERC in monitoring current 

conditions and responding to events on the bulk 

power system. 

• Collaboration with NERC to promote critical 

infrastructure protection of the bulk power 

system.

A delegation is effective only after FERC approves 

the delegation agreement. In April 2007, NERC entered into a separate delegation agreement with each 

of the eight regional entities. The most recently-filed 

delegation agreements provide for a five-year term 

ending on December 31, 2020. These agreements 

are subject to FERC re-evaluation and re-approval 

following the term. Currently, NERC has delegated authority to the following: Florida Reliability 

Coordinating Council (FRCC), Midwest Reliability 

Organization (MRO), Northeast Power Coordinating Council (NPCC), ReliabilityFirst Corporation 

(RFC), SERC Reliability Corporation (SERC), 

Southwest Power Pool RE (SPP), Texas Reliability 

Entity (TRE), and Western Electricity Coordinating 

Council (WECC). (See map on page 41.)

Major Actions Timeline

August 8, 2005 EPAct 2005 enacted

February 3, 2006 FERC issues Order No. 672 implementing requirements of EPAct 

July 20, 2006 FERC certifies NERC as the electric reliability organization

March 15, 2007 FERC issues Order No. 693 approving 83 Reliability Standards

June 17, 2007 83 approved Reliability Standards become mandatory and enforceable in the United States 

October 21, 2007 FERC approves delegation agreements establishing regional entities

January 18, 2008 FERC issues Order No. 706 approving initial critical infrastructure protection Reliability Standards
46

Federal Energy Regulatory Commission Reliability Primer

C. FERC Oversight 

FERC does not control or operate the electric grid. 

Rather, under section 215 Congress gave FERC a role 

over certification of the electric reliability organization and in the development and enforcement of Reliability Standards. This role is conducted through 

oversight of the electric reliability organization and 

regional entities primarily by FERC’s Office of Electric Reliability and the Office of Enforcement. In addition, the Office of Energy Infrastructure Security 

helps identify, communicate and seek collaborative 

solutions to potential risks to the bulk power system 

from cyber attacks and physical threats.

 Office of Electric Reliability 

The Office of Electric Reliability helps FERC oversee NERC, the regional entities and their various 

activities. The Office of Electric Reliability is organized into three divisions (Division of Engineering, 

Planning and Operations; Division of Compliance; 

and Division of Reliability Standards and Security) 

but the work between divisions overlaps and is often 

completed in cross-divisional teams with assigned 

leadership.

Reliability Standards: The Office of Electric Reliability helps FERC oversee the development and 

review of Reliability Standards and helps ensure 

compliance with these standards by the users, owners, and operators of the bulk power system. 

The Office of Electric Reliability monitors NERC’s 

Reliability Standard development. Office of Electric 

Reliability staff participate in NERC’s development 

process as “observers” and do not actively engage in 

drafting the language of a new or revised Reliability 

Standard. This regulatory staff also keeps channels 

of communication open with NERC, NERC standard drafting teams, and the regional entities with 

regard to any observations concerning the substance 

or clarity of a draft standard. Likewise, NERC 

apprises FERC staff regarding the timing and content 

of a draft Reliability Standard. These informal communications ensure that all are aware of the progress 

of a draft standard and that FERC staff concerns are 

considered in the drafting process, regardless of the 

ultimate outcome. 

Once the drafting process is complete and a proposed 

Reliability Standard is approved by the NERC board, 

NERC submits the standard to FERC for approval. 

Public notice and opportunity for comment is provided, and the Office of Electric Reliability reviews 

the proposed standard and comments provided in 

the proceeding. The staff then advises FERC Commissioners on the proposed standard. FERC also has 

the authority to direct the electric reliability organization to develop a new or revised Reliability Standard to address a specific matter, which may include 

a reliability risk to the bulk power system. NERC 

also issues interpretations of Reliability Standards 

language, which FERC also reviews. 

Cyber Security: The Office of Electric Reliability 

oversees the electric reliability organization’s Critical 
47

Infrastructure Protection Reliability Standards and 

supporting activities. In addition, staff tracks and 

evaluates cyber incidents, participates in inter-agency activities, and monitors vendor activities dealing 

with security-related products. 

Compliance: The Office of Electric Reliability also 

monitors and tracks the compliance of all registered 

entities with the approved Reliability Standards and 

works with the Office of Enforcement to investigate 

and resolve alleged violations of the standards. This 

activity includes monitoring mitigation plans and 

Notices of Penalty. The Office of Electric Reliability 

performs incident and alleged violation analyses 

and/or investigations following bulk power system 

incidents, in partnership with the Office of Enforcement, as appropriate. Gaps in standards may be 

identified through these compliance monitoring activities. The office also evaluates appeals of NERC’s 

registration decisions.

Event Analysis: The Office of Electric Reliability 

analyzes and monitors issues concerning the performance of the nation’s bulk power system, including real-time event reports, planning studies and 

longer-term assessments of resource adequacy and 

reliability. This work centers on providing technical support to FERC leadership as part of reviewing 

reliability-related filings with a focus on evaluating 

relevant engineering subject materials. These efforts 

also oversee and track the electric reliability organization’s performance metrics for its effectiveness. 

Other Activities: In support of the agency’s broader 

mission, the Office of Electric Reliability actively 

supports the rates divisions of the Office of Energy 

Market Regulation, making certain that reliability-related cost recovery filings are evaluated for their 

engineering aspects and assessing potential impacts 

to the bulk power system. The office works with 

other FERC offices and external groups to evaluate 

issues that may impact bulk power system reliability 

and cost recovery options for potential solutions. 

The Office of Electric Reliability can lead or join 

in periodic and unscheduled reviews and audits of 

the electric reliability organization, regional entities, and users, owners, and operators of the bulk 

power system to determine the effectiveness of 

their programs and their compliance with NERC’s 

Reliability Standards. The office also leads or joins 

in the analysis and any investigations concerning 

major blackouts on the bulk power system. During 

these reviews, the office considers whether additional or revised Reliability Standards are warranted to 

prevent the occurrence of the unwanted behavior 

or detrimental impacts to the bulk power system, or 

if other additional avenues to address the concerns 

might be appropriate. 

The Office of Electric Reliability, in conjunction 

with the Office of General Counsel and Office of 

Enforcement, participate in the Trilateral Electric 

Reliability Oversight Group meetings, together with 

representatives of Canadian Federal and Provincial 

regulators, and Mexican government officials. Recognizing the need for a continent-wide coordinated 

framework for of the interconnected bulk power 

system, the Trilateral Group meets to discuss electric 

reliability matters of mutual interest. 

The office will, when appropriate, suggest or direct 

long-term strategic research programs to identify 

emerging reliability and security issues and examine 

their implications for bulk power system planning, 

operations and FERC regulations. 

Office of Energy Market Regulation 

FERC’s Office of Energy Market Regulation is responsible for reviewing electric reliability organiza-
48

Federal Energy Regulatory Commission Reliability Primer

tion rules of procedure, bylaws, budgets, and business plans. It is also the lead office in reviewing the 

delegation agreements and NERC’s five-year electric 

reliability organization performance assessments. 

Office of Enforcement 

Following EPAct 2005, FERC reorganized its enforcement activities to establish an Office of Enforcement 

(Enforcement) and included compliance with Reliability Standards in its scope of activities. This office’s mission is to protect consumers through market oversight and surveillance; ensuring compliance 

with tariffs, rules, regulations, and orders; detecting, 

auditing, and investigating potential violations; and 

crafting appropriate sanctions for violations, including civil penalties and other measures. 

Enforcement and the Office of Electric Reliability 

review events and incidents that occur on the bulk 

power system for possible Reliability Standard violations. Enforcement conducts joint or independent 

investigations of possible violations of the Reliability 

Standards, and conducts or participates in scheduled 

or unscheduled audits relating to compliance with 

the Standards. Any penalty proposed by Enforcement must be approved by FERC. 

Enforcement Guidance

Enforcement’s activities are informed by FERC’s 

2005 and 2008 Policy Statements on Enforcement. 

They are intended to place jurisdictional entities on 

notice of the consequences of violating the statutes, 

orders, rules, and regulations that FERC enforces. 

FERC subsequently crafted, with the input of public 

commenters, more detailed policy statements, rules, 

and orders to describe Enforcement’s policies and 

procedures. 

Since EPAct 2005, FERC has held conferences and 

workshops on enforcement policy topics; initiated 

annual reports on Enforcement’s activities; and 

issued many settlement orders and show cause 

orders that further explain and define its approach 

to performing the enforcement role strengthened in 

EPAct 2005.

EPAct 2005 provides that persons and organizations 

that violate a Reliability Standard are subject to civil 

penalties of up to $1 million per day per violation, 

helping to ensure reliability of the nation’s bulk 

power system.

In 2010, FERC issued the Penalty Guidelines to 

provide greater fairness, transparency, and consistency in civil penalty determinations pursuant to 

EPAct 2005. The Penalty Guidelines use objective 

characteristics and a uniform set of factors weighted 

similarly for similar violations and similar violators. 

In determining a penalty under the Penalty Guidelines, FERC considers the nature and seriousness of a 

violation and the violator’s efforts to remedy the vi-
49

olation in a timely manner. The Penalty Guidelines 

include a specific section relating to penalties for Reliability Standard violations. In general, the Penalty 

Guidelines reduce possible penalties when a violator 

promptly self-reports its violation or implements an 

effective program to prevent and detect violations.

 

The Penalty Guidelines do not foreclose Enforcement staff’s ability to exercise discretion to close 

investigations or reviews of self-reports without 

sanctions, if appropriate, such as when insufficient 

evidence of a violation exists. Moreover, staff may 

close an investigation or review of a self-report without sanctions for violations that are relatively minor 

in nature and that result in little or no potential or 

actual harm. 

Reliability Standard Violations

Pursuant to the delegation agreements, NERC’s 

regional entities are the primary enforcers of the 

Reliability Standards, and NERC coordinates and 

reviews the regional entities’ compliance and enforcement activities. These activities may culminate 

in NERC’s filing with FERC of notices of penalty. 

Over time, NERC has developed different “tracks” 

or processes for addressing non-compliance matters 

based in large part on the seriousness of risk posed by 

the non-compliance. For non-compliance matters 

that pose a greater risk to reliability, NERC or the 

regional entity will utilize a process that allows for 

more scrutiny. NERC provides transparency in the 

disposition of compliance matters, as they are posted 

on the NERC website and/or submitted in public 

filings with FERC. 

In addition to these efforts by regional entities and 

the electric reliability organization, in a limited 

number of circumstances, FERC staff conducts its 

own analysis of occurrences on the bulk power 

system that may implicate Reliability Standards 

violations. FERC staff may conduct inquiries following serious system events, for example. FERC staff 

conducted three such inquiries in 2011, in conjunction with staff of NERC and regional entities. FERC 

staff also monitors potential violations of Reliability 

Standards based upon information that it collects or 

that regional entities report to NERC under the electric reliability organization Compliance Monitoring 

and Enforcement Program. 

As a result, in some circumstances, FERC staff itself 

reviews potential violations. Included in these 

circumstances were the most significant system disturbance events since 2005 - the March 2008 Florida 

Blackout and the September 2011 Southwest Outage. 

March 2008 Florida Blackout: The 2008 event was 

caused by a fault at a substation on the Florida Power 

& Light Co. (FPL) system in west Miami that rapidly cascaded, disabling dozens of transmission lines 

around the state. As a result, millions of consumers 

in Florida lost power for several hours. FPL paid a 

$25 million civil penalty under a settlement with 

staff of FERC and NERC of an investigation. FPL 

paid $10 million to NERC and $10 million to the 

United States Treasury and spent $5 million for 

reliability enhancements for its system to offset a 

penalty payment. FPL agreed to a broad program of 

remedial measures to enhance its system and operations, including specific compliance and training 

process improvements to help prevent future similar 

violations. Under a related settlement with FERC 

and NERC staff, the Florida Reliability Coordinating 

Council, in its capacity as reliability coordinator for 

the area of Florida affected by the blackout, paid a 

$350,000 civil penalty, split between NERC and the 

U.S. Treasury, and agreed to improve its operations 

to help prevent a future blackout. These settlements 

were FERC’s first civil penalty assessments for 

violations of Reliability Standards and its first joint 

enforcement effort with NERC. 

 
50

Federal Energy Regulatory Commission Reliability Primer

September 2011 Southwestern Outage: The 

September 2011 Southwest cascading outage left 

more than five million people without power for up 

to 12 hours in Southern California, Arizona and Baja 

California Norte, Mexico. Staff of FERC and NERC 

conducted a joint inquiry and issued a detailed 

report in April 2012 on the event, recommending 

reliability improvements that focused on planning, coordination and situation awareness among 

reliability entities in the Western interconnection, 

as well as changes to relevant Reliability Standards. 

Enforcement then led investigations with the Office 

of Electric Reliability and NERC staff that resulted in 

settlements related to this event with seven entities: 

WECC in its capacity as reliability coordinator for 

the Western interconnection and Peak Reliability, 

WECC’s successor as reliability coordinator; Imperial Irrigation District; California Independent 

System Operator Corporation; Southern California 

Edison Company; Arizona Public Service Company; and the Western Area Power Administration 

(WAPA). 

Collectively, these settlements assessed these entities, other than WAPA, $37.9 million in civil penalties for Reliability Standard violations related to the 

outage. Of this amount, $27.65 million was invested 

in reliability enhancement measures that go above 

and beyond mitigation of the violations and compliance with requirements of the Reliability Standards as offsets to possible penalty payments. These 

investments included WECC’s hiring of additional 

reliability coordinator personnel and Imperial Irrigation District’s installation of a utility-scale battery 

storage system. Each entity also agreed to mitigation 

and reliability activities and to submit to compliance 

monitoring. Penalty payments were split evenly 

between the United States Treasury and NERC.

Following other investigations, Enforcement has 

entered into settlements with bulk power system 

owners and operators regarding Reliability Standard 

violations, which FERC has approved. While most 

of these investigations did not involve unexpected 

losses of load, they addressed situations that posed 

potentially serious risk to bulk power system reliability. These settlements have imposed civil penalties and required mitigation efforts and compliance 

monitoring. Information on these settlements is 

available on FERC’s website. FERC staff generally 

conduct these investigations with NERC staff and, 

when appropriate, regional entity staff. 

Enforcement’s audit staff, in conjunction with Office 

of Electric Reliability technical staff, has conducted, 

participated in, or observed numerous audits related 

to reliability. Some of these activities have related 

to compliance audits conducted by regional entities; 

others have involved various audits of registered 

entities, regional entities, and NERC. FERC staff 

coordinates its Reliability Standards enforcement 

activities with those of the regional entities and 

NERC. 
51

Office of Energy Infrastructure Security

The Office of Energy Infrastructure Security provides expertise and assistance to FERC to identify, 

communicate and seek solutions to potential risks 

to FERC-jurisdictional energy facilities from cyber 

attacks and physical threats such as electromagnetic 

pulses, including voluntary efforts beyond Reliability Standard compliance.

The Office of Energy Infrastructure Security formulates and makes recommendations for identifying, 

communicating and mitigating potential cyber 

and physical security threats and vulnerabilities to 

FERC-jurisdictional infrastructure. The office also 

provides assistance, expertise and advice, and undertakes collaborative engagement with other federal 

and state agencies, and the energy industry. This 

work includes, but is not limited to, participating 

in conferences, workshops, and classified briefings. 

The office conducts outreach with private sector 

owners, users, and operators of energy delivery systems regarding identification, communication, and 

mitigation of cyber and physical threats to energy 

facilities. The office works with other federal agencies, state agencies, national laboratories, vendors 

and universities to identify effective mitigation for 

new threats. 
52
53

IV. Role of the Electric Reliability 

Organization/NERC

This section describes how NERC has implemented programs to fulfill the role and responsibility of the electric reliability organization. 

Also described is how NERC interacts with FERC in fulfilling its role 

as the electric reliability organization. NERC’s programs, discussed 

below, include: (A) Reliability Standards Development; (B) Compliance and Enforcement; (C) Delegation to Regional Entities; and 

(D) Reliability and Adequacy Assessments. 

A. Reliability Standards Development

 

NERC’s Standards Development Process

Section 215(c)(1) of the FPA and section 39.3(b)(2)(iv) of FERC’s regulations require the electric reliability organization’s Reliability Standards 

development process to provide for reasonable notice and opportunity 

for public comment, due process, openness, and balance of interests. 

In certifying NERC as the electric reliability organization, FERC approved NERC’s Reliability Standards development process. In 2003, 

the American National Standards Institute (ANSI) Executive Standards 

Council accredited NERC’s Reliability Standards development process. 

The following is a summary of the standards development process. 
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Federal Energy Regulatory Commission Reliability Primer

Procedures

The first step in NERC’s Reliability Standards development process is the submission by a person or 

entity of a request for a Reliability Standard, modification of a standard, or withdrawal of a standard 

using a “standard authorization request.” Any member or committee of NERC, a regional entity, or any 

person or entity directly and materially affected by 

the reliability of the bulk power system may request 

development, modification or withdrawal of a Reliability Standard. NERC issues a public notice of the 

standard authorization request with an opportunity 

for public comment. The standards committee will 

authorize development of the proposed standard if 

there is sufficient stakeholder consensus on the scope 

and justification of the Reliability Standard. 

The standards committee appoints a Reliability Standard drafting team that has the technical expertise, 

competencies, and diversity of views that are necessary to develop the standard. Typically, a standard 

drafting team consists of electric industry volunteers, 

although volunteers outside industry (e.g., Federal 

or State government employees, or regional entity 

staff) with the necessary expertise may be appointed. 

Further, NERC assigns a “standards developer” from 

NERC staff to guide the drafting team and ensure 

that the drafting team follows NERC’s standards 

development process. The standard drafting team 

develops a draft Reliability Standard based on engineering and technical criteria and on actual data 

and lessons learned from operating incidents. All 

meetings of the drafting team are open and notice is 

provided to the public. 

After the Reliability Standard has been drafted, the 

standards developer reviews it for consistency of 

quality and completeness, and to ensure the draft 

standard is within the scope and purpose identified 

in the standard authorization request. The draft 

Reliability Standard is then posted for public comment for at least 45 days. The standard drafting team 

may recommend to the standards committee that 

the draft Reliability Standard be field tested. Field 

testing, when practical, provides actual data that the 

drafting team can utilize to assess the effectiveness of 

a proposed Reliability Standard. The drafting team 

may also decide, on the basis of comments received, 

to revise the draft standard and post it for additional 

comments. Once the drafting team determines that 

the draft Reliability Standard is ready for balloting, the drafting team submits the draft Reliability 

Standard to the standards committee with a request 

to proceed to balloting. The standards committee 

reviews the draft Reliability Standard to ensure it is 

consistent with the standard authorization request 

and is compatible with existing Reliability Standards. 

A ballot pool is formed during the first 30 days of the 

initial posting for ballot. A notice is sent to every 

member of the registered ballot body to establish a 

ballot pool to vote on the proposed Reliability Standard. Any member of the registered ballot body may 

elect to join the ballot pool for the proposed Reliability Standard. Members may cast an affirmative vote, 

a negative vote, or a negative vote with an explanation. Approval of a new Reliability Standard or 

revision to an existing Reliability Standard requires 

a quorum of at least 75 percent of the members of 

the ballot pool voting and a two-thirds majority of 

the weighted segment votes in the affirmative. The 

use of a weighted segment voting calculation ensures 

that there is a balance of interests in the development and approval of Reliability Standards. 

If there are any negative votes in the ballot with 

reasons specified, the ballot pool will be presented 

with the proposed Reliability Standard again along 

with the reasons for the negative votes. All members 

of the ballot pool are given a chance to reconsider 
55

and change their vote. When a second ballot is 

conducted, its results determine the status of the Reliability Standard, regardless of the outcome of the 

first ballot. New Reliability Standards or revisions 

to Reliability Standards approved by the ballot pool 

will be submitted to the NERC board of trustees for 

approval. The board considers the results of the balloting and dissenting opinions, as well as any advice 

offered by the member representatives committee. 

The NERC board must adopt or reject a proposed 

Reliability Standard and may not modify a proposed 

Reliability Standard. If the NERC board chooses 

not to adopt a proposed Reliability Standard, it must 

provide its reasons.

NERC’s standards development procedure allows a 

standard to be developed and approved in as little as 

four months; however, more complex standards requiring the development of new technical concepts, 

methods, and measures can take 12 to 15 months 

or longer to approve. After a proposed Reliability 

Standard receives board approval, NERC submits the 

proposed Reliability Standard to FERC for approval. 

NERC also has a truncated process for development 

of an “urgently needed” Reliability Standard when 

delay could materially impact bulk power system 

reliability. Like all Reliability Standards, an urgently needed Reliability Standard must be adopted by 

the NERC board before being submitted to FERC 

for approval. The urgent action process allows a 

Reliability Standard to be approved by stakeholders 

and the NERC board within 60 days of receiving a 

proposal. A Reliability Standard approved under the 

truncated process is considered an interim standard 

with a termination date that cannot exceed one year 

from the approval date. This interim status prevents 

an urgent Reliability Standard from becoming a de 

facto permanent Reliability Standard. 

Registered Ballot Body

Any person or entity with a legitimate interest in 

the reliability of the bulk power system may join the 

registered ballot body and a ballot pool, whether 

or not that person or entity is a member of NERC. 

Proposed Reliability Standards are approved by the 

members of the registered ballot body that join a 

ballot pool for consideration of a particular draft 

standard. The segments of the registered ballot 

body are: (1) transmission owners; (2) regional 

transmission organizations and independent system 

operators; (3) load-serving entities; (4) transmission 

dependent utilities; (5) electric generators; (6) electricity brokers, aggregators and marketers; (7) large 

electricity end users; (8) small electricity end users, 

(9) federal, state, and provincial regulators or other 

government entities; and (10) regional reliability 

organizations. The registered ballot body process 

ensures fair representation (using proxy and weighted segment voting) of all views in the development 

of a Reliability Standard.

NERC Standards Committee

The NERC standards committee provides oversight 

of the Reliability Standards development process to 

ensure stakeholder interests are fairly represented. 

The standards committee is a representative committee consisting of two representatives of each segment 

of the registered ballot body. Standards committee 

members are elected for staggered two-year terms by 

their respective segments. 

 Criteria for Reliability Standards

FERC, in Order No. 672, articulated a non-exclusive 

set of factors that FERC will consider in determining 

whether a proposed Reliability Standard satisfies 

the statutory threshold for approval. Specifically, 

a Reliability Standard should: (1) achieve a specific 
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Federal Energy Regulatory Commission Reliability Primer

reliability goal and contain technically sound means 

to achieve the goal; (2) be developed initially by 

industry experts; (3) be based on sound engineering 

and technical criteria and on actual data and lessons 

learned from operating incidents; (4) be clear and 

unambiguous regarding what is required and who 

must comply; (5) include clear and understandable 

consequences for a violation, including the range 

of penalties; (6) contain a clear and objective measure of whether the entity is in compliance; and (7) 

achieve the goal effectively and efficiently. 

NERC’s Reliability Standards incorporate the criteria by containing elements including a statement of 

purpose, requirements, measures, and compliance 

elements associated with each Reliability Standard. 

An example of a mandatory Reliability Standard, 

depicting these elements, is included as Appendix 3. 

The standards developer continuously monitors the 

Reliability Standard’s conformance to these criteria. 

NERC uses comments from stakeholders during the 

development of a standard to verify that the Reliability Standard meets the criteria. The resulting 

standard is reviewed by the standards committee 

prior to the Reliability Standard being sent to the 

NERC board for approval.

 

 NERC’s Actions in Response to a Directive

If FERC remands a Reliability Standard to NERC 

or directs NERC to develop a Reliability Standard, 

NERC develops a plan and timetable for modification or development of the Reliability Standard. In 

the rare instance that the NERC board determines 

that the standards process did not result in a standard 

that addresses a specific matter that is identified in a 

directive issued by FERC, then the NERC board can 

remand a draft Reliability Standard to the standards 

committee, with instructions; require a technical 

conference to discuss the directive; or direct the 

preparation of a draft Reliability Standard that will 

comply with the directive. NERC’s rules of procedure state that the NERC board has the authority to 

choose which one (or more) of the authorized alternative actions is appropriate, but that it must, to the 

extent feasible, choose actions that seek to maximize 

stakeholder participation. 

 Modifications to Standards Since NERC’s 

Initial Submission

NERC has proposed modifications to the Reliability 

Standards since the first 83 standards were approved. 

The modifications have included changes to fill 

gaps, add clarity or consolidate requirements for 

efficiency. NERC also has continued to modify the 

standards to transition to a more risk-based approach 

that results in less prescription on how to perform a 

reliability task. NERC labeled the initial Reliability 

Standards as “Version 0,” and each subsequent version of a standard is labeled Version 1, then Version 

2, etc. 
57

B. Standards Categories

Today, NERC’s Reliability Standards program currently consists of about 117 separate standards and 

a Glossary of Terms Used in Reliability Standards. 

The standards are grouped into 14 topical categories, each designated with a three-letter code. For 

example, the “transmission operations” category 

is designated as “TOP” and the first in the series of 

TOP standards as TOP-001-1. Below, we discuss each 

category of standards.

Resource and Demand Balancing

Resource and demand balancing (BAL) standards 

aim to ensure real-time balancing of generation 

and load to maintain frequency at or around 60 Hz. 

Requirements include ensuring that all facilities and 

load are electrically synchronized in each interconnection and included within a metered boundary 

of a balancing area so that the real-time balancing 

of resources and demand can actually be achieved. 

Back-up reserves (or contingency reserves) are 

needed to compensate for any unexpected loss of 

generation resources so that the system frequency 

can be returned to 60 Hz when a contingency occurs. 

Generation that may unexpectedly trip (go off line) 

must be replaced by substitute generation or by preplanned interruptible load. Metrics established in 

this category provide a way to measure the performance of balancing authorities. 

Communications

The communications (COM) standards require 

applicable entities operating the system to have 

adequate internal and external telecommunications 

facilities, back-up facilities and procedures to enable 

a necessary exchange of information. Communication channels must have necessary redundancy for 

security purposes. Personnel performing operations 

impacting the bulk power system must have equipment, facilities and interpersonal communications 

and must be adequately trained to effectively communicate when addressing real-time emergencies. 

This includes the use of three-part communication 

for issuing directives, i.e., when a directive is communicated, the recipient must repeat back the directive, followed by an affirmation or correction from 

the one giving the directive. This protocol, used in 

many industries, better ensures that communications are accurately understood. 

Emergency Preparedness and Operations

The emergency preparedness and operations (EOP) 

category of Reliability Standards address basic expectations for actions taken during system emergencies. 

The standards also address system restoration and 

reporting after a disturbance has occurred. More 

specifically, each transmission operator and balancing authority must develop an operating plan to 

mitigate operating emergencies and the plan must 

be coordinated within a reliability coordinator 
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Federal Energy Regulatory Commission Reliability Primer

area. The reliability coordinator reviews the plans 

within its defined geographic boundary (known as 

the reliability coordinator area). System planning is 

performed in advance and with the intent of anticipating potential emergencies. When an emergency 

does occur, the reliability coordinator in the area primarily impacted plays a lead coordination role across 

an interconnection in order to resolve the emergency. The EOP standards also require system operators 

to have the capability to manually or automatically 

shed load in a timely manner to return the system 

to a stable condition. While shedding load, i.e., 

turning off the electricity for a group of customers, 

is a measure of last resort, at times such “controlled” 

shedding of load is the best means to mitigate the 

risk of an uncontrolled, cascading blackout.

Each transmission operator must have a system 

restoration plan to reestablish its electric system in 

a stable and orderly manner in the event of a partial 

or total shutdown of its system. Personnel must be 

trained to enable this restoration of load to occur, 

based on expected blackout conditions. Generation 

operators with blackstart resources (generating units 

that have the ability to be started without support 

from the rest of the bulk power system) must have 

established procedures related to the use of these 

units when called upon. Each transmission operator’s area must have a blackstart capability plan 

to ensure that the quantity and location of system 

blackstart generators are sufficient and can be executed. These plans are rolled into larger regional system 

restoration plans.

Facilities Design, Connections, and Maintenance - Including Vegetation Management

The facilities design, connections, and maintenance 

(FAC) standards address an assortment of facility 

connection and coordination requirements, documentation of facility ratings, and vegetation management (tree trimming) adjacent to transmission 

facilities. The FAC standards also address transmission line ratings used in system modeling and 

standardize transfer capabilities calculations. 

Specifically, the FAC standards require system 

performance assessments to ensure that facilities 
59

can be interconnected to the bulk power system 

reliably under normal and contingency conditions. 

Other requirements include ensuring that facility 

ratings and transfer capabilities of transmission lines 

are based on rigorous engineering analysis. These 

requirements are intended to avoid adverse impacts 

to generation and transmission equipment from 

exceeding safe operating specifications.

 

Pursuant to Reliability Standard FAC-003 (Vegetation Management), entities that own bulk power 

system transmission facilities must maintain a transmission vegetation management program. FAC-003 

does not apply to local distribution wires that serve 

residences and other local customers - such facilities 

are typically regulated by the States. FAC-003 sets 

minimum clearance distances between bulk power 

transmission lines and vegetation that is located beneath or adjacent to the transmission lines. Further, 

the standard sets a minimum annual inspection cycle 

for transmission owners to inspect for trees or other 

vegetation that could fall into transmission lines. 

As discussed earlier, vegetation falling into bulk 

power system transmission lines has been an initiating cause of numerous cascading blackouts, including the August 2003 blackout that preceded the 

enactment of EPAct 2005. NERC maintains records, 

published online quarterly, on outages caused by 

vegetation contact with transmission lines. These 

vegetation outage statistics are available at http://

www.nerc.com/pa/comp/ce/pages/vegetation-management-reports.aspx. 

While vigilance with vegetation management is one 

necessary aspect of maintaining a reliable bulk power system, tree trimming at times results in conflicts 

with nearby residents who prefer to maintain the 

aesthetics of local vegetation. FERC has developed a 

series of documents pertaining to vegetation management, intended to inform landowners on such 

matters, including: Why Tree Trimming is Necessary, Clearances Between Power Lines and Trees, and 

Landowner Rights. These resources are available 

online at http://www.ferc.gov/resources/resources.

asp.

Interchange Scheduling and Coordination 

The interchange scheduling and coordination (INT) 

standards detail the responsibilities for those involved in power flow when electricity is purchased 

and transmitted from a seller to a buyer across the 

bulk power system. Before the energy actually 

flows, specific information about the transaction 

must be identified in electronic labels, known as 

tags, to allow a reliability assessment of the projected 

flow. This information can also be used as a reference should the loading of transmission lines start 

to reach operating limits, when the tag information 

can be used be to strategically manage the schedules specifically contributing to the overload. This 

tagging of proposed energy transactions must occur 

across and within balancing authority boundaries 

or where any type of point-to-point transmission 

service is used. 

Interconnection Reliability Operations and 

Coordination

The interconnection reliability and coordination 

(IRO) standards detail the responsibilities and authorities of the reliability coordinators that oversee 

the bulk power system. A reliability coordinator 

monitors the interconnected transmission system 

across multiple local utilities. By virtue of this 

wide-area view, the reliability coordinator is best 

positioned to address an adverse condition on the 

bulk power system. The reliability coordinator’s role 

is analogous to the role performed by air traffic controllers in the airline industry, particularly during 

emergencies. 
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Federal Energy Regulatory Commission Reliability Primer

The reliability coordinator and the transmission 

operator conduct next-day and current day reliability analyses to ensure the system can be operated 

in anticipated normal and contingency conditions. 

The transmission operator studies the forecasted use 

of the system compared to its limits, voltage, and 

stability conditions, and examines expected flows 

across critical transmission lines. The reliability 

coordinator provides oversight to this process and, if 

overloads occur on equipment or if other unexpected events occur, the reliability coordinator overseeing each transmission operator can coordinate 

with neighboring transmission operators to assist in 

remedying the situation.

The reliability coordinator has authority under the 

IRO Reliability Standards to act or direct others 

to act, such as by issuing operating instructions to 

transmission operators to maintain system reliability and to prevent or mitigate emergency operating 

situations.

Modeling, Data, and Analysis

The modeling, data, and analysis (MOD) category 

of standards is a collection of requirements intended to standardize methodologies and system data 

needed for traditional transmission system operation and expansion planning, reliability assessment, 

and the calculation of available transfer capability. 

The MOD standards obligate entities to document, 

review and validate the transfer capability of the 

transmission system and, specifically, what must 

be considered and demonstrated when this transfer capability is calculated. The standards in this 

category are important for transmission information 

uniformity.

Good data and system models are essential for 

accurately simulating the performance of the bulk 

power system. Requirements in this category call 

for accurate data inputs that are necessary for this 

system modeling. The MOD standards require generators to provide accurate information on gross and 

net real power capability used for system operator 

models. Steady-state analysis is used to verify that 

voltages are maintained within limits, and to determine the real and reactive load output and voltage 

controlling device adjustments necessary to balance 

generation and loads. Transmission providers and 

reliability coordinators are required to monitor any 

thermal limit exceedances on transmission lines as 

part of this analysis. Meanwhile, dynamic analyses 

are performed to study whether there are stability 

issues during line switching or when a disrupting 

event occurs. 

Simulation Model

source: http://wiki.uvig.org/index.php/Test_System:_Simulation_Model

Nuclear 

The nuclear (NUC) category requires nuclear plant 

operators to coordinate operations and planning 

with the interconnecting transmission operator. 

The single standard in the NUC category requires 

written procedures for coordination between a nuclear plant operator and the transmission provider 

that must address any outages scheduled or transmission limits or conditions that may potentially impact 

the nuclear plant. 
61

Personnel Performance, Training, and 

Qualifications

The personnel performance, training, and qualifications (PER) standards impose obligations on personnel performance, training, operating personnel 

credentials and qualifications for various registered 

entities. Entities must maintain suitably trained 

and qualified personnel for positions that impact the 

reliable operation of the bulk power system. Specific requirements call for training programs for all 

operating personnel who either have the primary 

responsibility, directly or through communication 

with others, for real-time operation of the bulk power system or who are directly responsible for complying with the Reliability Standards. 

Protection and Control 

The protection and control (PRC) category specifies obligations for a range of matters related to the 

protection and control of the bulk power system. 

Protection systems are designed to detect faults 

and isolate faulted elements on the system, thereby 

limiting the severity and range of system disturbances and preventing possible damage to protected 

elements. The failure of a protection system has the 

potential to create and has resulted in major outages 

and cascading events. Protection systems take and 

act on real-time electrical measurements, such as 

current, voltage, and frequency. These systems need 

to be set to recognize certain measurements as indicating a fault and, from that set-point, send a signal 

to an interrupting device such as a circuit breaker to 

disconnect the element from the rest of the system. 

The PRC standards deal with matters including the 

testing and maintenance programs for this equipment. Requirements include the need to analyze 

and correct any misoperations of the equipment. 

Since supply (generation) and demand (load) need 

to be balanced at all times, any significant departure 

from operating limits for frequency or voltage will 

impact the system. Under normal operating conditions, there are slight changes of frequency or voltage 

when generation or load suddenly increases or 

decreases. If a large imbalance occurs between load 

and generation - where frequency or voltage change 

significantly - the bulk power system is designed 

to restore the balance. Due to such a mismatch in 

supply and load, if under-frequency or under-voltage conditions occur on the bulk power system, the 

PRC standards require the protection equipment to 

be set up to recognize the problem and isolate it to 

one area. This is done to prevent the spread of the 

problem to a much larger footprint and also prevent 

uncontrolled cascading events. This protection and 

control is also needed to prevent or minimize damage to transmission, distribution, and generation 

equipment. 

The PRC standards also call for the installation of 

disturbance monitoring equipment and support 

capabilities. This equipment serves an important 

function of reading and recording events on the bulk 

power system. The recording mechanism is vital to 

timely and accurate modeling and analysis of system 

events that occur. The use of models with accurate 

data allows a timely and complete recreating of 

system events or disruptions so problems can be 

understood and addressed.

Other PRC requirements ensure that power swings 

are stable. Power swings are oscillations in power 

flows on an electric system due to an event or disturbance, such as a fault or loss of generation or load. 

Power swings occur most commonly when a fault 

and faulted facilities are quickly removed from the 

system, typically within one-tenth of a second from 

detection, and the system and affected generators 

stabilize within several seconds. Dynamic but stable 

power swings occur when the system recovers from a 
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Federal Energy Regulatory Commission Reliability Primer

disturbance and achieves transient stability, typically 

within zero to three seconds, and then returns to a 

steady state over a longer period of time, typically 

within three to thirty seconds or even minutes. 

Prior to the system returning to a new steady state 

operating condition, it can exhibit power swings 

that may decrease rapidly or increase in magnitude. 

When the power swings decrease, the system will be 

able to achieve a new stable operating status.

Transmission Operations

The primary reliability goal of the transmission 

operations (TOP) standards is to ensure that the 

transmission system is operated within safe operating limits. Also, transmission operators have 

the authority and must have the capability to take 

appropriate actions or direct the actions of others to 

return the transmission system to normal conditions 

following an emergency. The TOP standards aim to 

ensure that reliability coordinators and transmission 

operators work together and with other functional 

entities when managing transmission line and other 

equipment limits. 

The TOP standards require that transmission operators develop operating plans to meet dynamic changes to the system. These plans include scheduled and 

unscheduled changes in system configuration, different demand patterns, varying generation dispatch 

and interchange schedules. Unscheduled changes 

to system configuration and generation dispatch are 

referred to as contingencies (defined as the loss of a 

transmission circuit, generator, single DC pole, or 

transformer). Following a single contingency, the 

TOP standards require adjustments to the system to 

compensate for the contingency as soon as possible 

but no later than 30 minutes after the contingency 

occurs. This time period is to ensure that the system 

is returned to a secure operating state, so it can 

withstand the next contingency without causing 

instability, uncontrolled separation or cascading outages. When a contingency occurs that impacts the 

system, the matter must receive swift attention, with 

appropriate entities addressing the overload before 

additional equipment is damaged or the problem 

further escalates, e.g., further overloading, equipment damage or load loss. 

Transmission Planning

The transmission planning (TPL) category is intended to ensure that the transmission system is planned 

and designed to meet an appropriate and specific 

set of reliability criteria. One TPL standard specifically describes conditions that must be considered 

when making planning assessments. The standard 

ensures that the system is studied for an array of 

system conditions and contingencies (i.e., loss of 

line, transformer, generator, etc.) to determine 

the need for system upgrades or reinforcements so 
63

that any underlying weaknesses or deficiencies can 

be identified. Another TPL standard also requires 

studying the performance of the system for a variety of scenarios. Such scenarios would typically 

simulate a range of generation dispatches, including 

generator outages; a range of demand levels; a range 

of transactions; and a range of transmission outages. 

The simulations determine the most severe set of 

system conditions. Studies must anticipate these 

possible system conditions so there is lead time 

to purchase and install equipment if necessary to 

resolve any identified problems. The studies would 

also potentially identify generators that must run to 

remove local transmission constraints, or, alternatively, identify the inability to deliver generation to 

load due to insufficient transmission capacity. The 

studies must also include long term and short-term 

(including seasonal and stressed case) studies. 

When the system studies indicate an inability to 

meet performance requirements specified in the TPL 

standards, the transmission planner must develop a 

“corrective action plan” that addresses how the performance requirements will be met. This plan could 

result in the development of operating procedures; 

or it could involve the installation, modification, or 

retirement of transmission or generation facilities.

Voltage and Reactive Control

The voltage and reactive control (VAR) category of 

standards aims to ensure that voltage levels, reactive flows, and reactive resources are monitored 

and controlled within limits in real-time to protect 

equipment. Adequate voltage and reactive power 

levels are essential for keeping the power system 

robust to respond to hourly energy demands. For 

instance, a major imbalance between reactive power 

consumption and supply will lead to voltage collapse and cascading power outages. This has been a 

common cause of major power outages worldwide. 

Transmission owners are required to have sufficient 

reactive resources within their area to protect voltage 

levels under normal and contingency conditions, 

and maintain system and interconnection voltages 

within established limits. These voltage and reactive 

services are provided by traditional generators, with 

more recent contributions from newer technologies 

owned by transmission customers and transmission 

owners. 

Critical Infrastructure Protection 

Critical infrastructure protection (CIP) standards 

provide requirements to protect the bulk power 

system from cyber and physical attacks on critical 

infrastructure. 

Cybersecurity: The CIP standards require users, 

owners, and operators of the bulk power system 

to identify and categorize cyber systems based on 

“bright-line” criteria for the application of cyber security requirements commensurate with the adverse 

impact that loss, compromise, or misuse of those 

cyber systems could have on the reliable operation 

of the interconnected transmission network. Once 

these assets are identified, the CIP standards require 

Source: pjm.com that the responsible entities establish plans, proto-
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Federal Energy Regulatory Commission Reliability Primer

cols, and controls to safeguard physical and electronic access to these systems, train personnel on security 

matters, report security incidents, and be prepared 

for recovery actions. 

A new set of CIP standards, Version 5, effective 

beginning July 1, 2016, introduces a tiered approach, 

so that assets are identified as High, Medium or Low 

risk to bulk power system reliability if compromised. 

Required protections are commensurate with the applicable risk level. Documented and regular reviews 

of these protection programs are required. 

Entities must also document and implement a cyber 

security policy that addresses electronic security perimeters, security patch management, and incident 

response planning.

Physical Security: Reliability Standard CIP-014 

addresses physical security. The standard requires 

entities to identify and protect transmission stations 

and their associated primary control centers that, if 

rendered inoperable or damaged as a result of a physical attack, would result in instability, uncontrolled 

separation, or cascading within an interconnection. 

The standard requires entities to determine what 

facilities are critical, assess the critical facilities for 

vulnerabilities, and implement a plan to mitigate 

vulnerabilities.

Geomagnetic Disturbance 

A recent addition to the Reliability Standards addresses geomagnetic disturbances. Geomagnetic disturbance events occur when the sun emits charged 

particles that interact with, and cause changes in, 

the magnetic fields of the Earth. A geomagnetic 

disturbance may induce currents that cause transformer hot-spot heating or damage, loss of reactive 

power sources, increased reactive power demand, 

and protection system misoperation, the combination of which may result in blackout of the electric 

grid. Although major geomagnetic disturbances are 

infrequent, they have the potential to significantly 

impact reliable operation of the bulk power system 

under certain conditions. 

Pursuant to Reliability Standard EOP-010-1, owners 

and operators of the bulk power system are required 

to develop and implement operational procedures 

to mitigate effects from these geomagnetic disturbances. In addition, Reliability Standard TPL-007-1 

establishes requirements for certain registered entities to assess the vulnerability of their transmission 

systems to geomagnetic disturbance events. Applicable entities that do not meet certain performance 

requirements, based on the results of their vulnerability assessments, must develop a plan to achieve 

the performance requirements.
65

C. NERC Compliance and Enforcement 

NERC and the regional entities have a program for 

ongoing monitoring of compliance with Reliability 

Standards by the users, owners, and operators of 

the bulk power system. The eight regional entities, based on authority granted by the delegation 

agreements in place, carry out compliance monitoring and enforcement activities on behalf of NERC. 

NERC oversees the regional programs and seeks to 

ensure their consistency and fairness. NERC and the 

eight regional entities monitor compliance through 

a number of methods, including regularly scheduled 

compliance audits, random spot checks, compliance 

investigations, and a complaint process. 

The focus of NERC’s compliance program is to 

improve the reliability of the bulk power system in 

North America by fairly and consistently enforcing 

compliance with NERC Reliability Standards. Specifically, the program is designed to ensure that the 

right practices are in place so that the likelihood and 

severity of future system disturbances are substantially reduced, while recognizing that no Reliability 

Standards or enforcement process can fully prevent 

all such disturbances. 

Below, we discuss two aspects of compliance: (1) 

compliance registry, and (2) addressing non-compliance matters pursuant to NERC’s Compliance 

Monitoring and Enforcement Program. 

Criteria for Registered Entities

FERC regulations require each user, owner, and 

operator to register with the electric reliability 

organization and the regional entity for each region 

within which it uses, owns or operates bulk power 

system facilities. NERC developed a registration 

process that identifies and registers the entities that 

are responsible for compliance with one or more Reliability Standards. NERC identified the following 

twelve reliability functions, necessary for the reliable 

operation of the electric grid:

• Reliability Coordinator (RC) 

• Balancing Authority (BA) 

• Planning Authority (PA)

• Transmission Planner (TP)

• Transmission Operator (TOP)

• Transmission Service Provider (TSP)

• Transmission Owner (TO) 

• Resource Planner (RP)

• Distribution Provider (DP)

• Generator Owner (GO)

• Generator Operator (GOP) and 

• Reserve Sharing Group (RSG)

NERC and the regional entities identify and register entities that perform these functions, applying 

certain “de minimis” thresholds set forth in a Registry 

Criteria document. Each Reliability Standard contains an “applicability” provision that sets forth one 

or more of the above reliability functions. An entity 

is responsible to comply with the Reliability Standards with applicability provisions that correspond 
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Federal Energy Regulatory Commission Reliability Primer

to the functions for which the entity is registered. 

In this way, the compliance registration program 

ensures that the proper entities are registered and 

that each entity knows which Reliability Standards 

are applicable to it. 

Registered organizations included on the compliance 

registry are responsible for knowing the content of 

and for complying with all Reliability Standards. 

The compliance registry is posted on the NERC 

website and updated monthly. New entities are 

added to the registry and others are “de-registered” 

for some or all functional categories, as the activities 

and functions of entities change over time. NERC 

provides notice of registration or deactivation to all 

organizations when they are included or removed 

from the compliance registry. 

Delegation and Sharing of Compliance Tasks

An entity may delegate reliability tasks to third 

parties; however, the entity is still responsible for 

compliance. For example, a registered entity can 

delegate “responsibility” for completion of a task 

(e.g., relay testing), but the registered entity is still 

responsible for complying with the relevant standard. NERC facilitates the delegation of reliability 

tasks by establishing rules that permit “coordinated 

functional registration” and “joint registration organizations.” 3

 

A coordinated functional registration is a written 

agreement pursuant to which two or more entities 

agree to a division of compliance responsibility for 

one or more Requirements or Reliability Standards. 

The parties must submit the agreement to NERC 

and the relevant regional entities, identifying points 

3 For more information, see NERC “Guidance for Entities that Delegate 

Reliability Tasks to a Third Party Entity”

 http://www.nerc.com/files/2010-004%20v1%200.pdf 

of contact and clearly specifying the entities’ respective compliance responsibilities. The entity point 

of contact informs the applicable regional entity of 

any changes to an existing coordinated functional 

registration, and the regional entity notifies NERC 

of each such revision. Coordinated functional registrations are posted on NERC’s website.

A joint registration organization may be used by a 

joint action agency, generation and transmission 

cooperative or similar organization to accept compliance responsibility on behalf of its members. Under 

this process, a “central” organization registers as 

responsible for compliance for itself and collectively on behalf of its members. Each member within 

a central organization may separately register to 

be accountable for a particular reliability function 

defined by the Reliability Standards. In all cases, 

NERC and the regional entities will hold the registered “central” entity accountable for compliance 

responsibilities and any violations. While a registered entity may delegate the performance of a task 

required by a Reliability Standard to another entity, 

the registered entity may not delegate its responsibility for ensuring the task is completed. In addition to 

registering as an entity responsible for all functions 

that it performs itself, multiple entities may each 

register using a coordinated functional registration 

for one or more Reliability Standards and/or for one 

or more requirements within a particular Reliability 

Standard applicable to a specific function. 

Appeals of Registry Decisions 

NERC’s rules of procedure include a process for an 

entity to appeal its registration. For example, an 

entity may believe that it should not be included 

on the compliance registry because it does not believe it performs a particular reliability function for 

which it was registered. The entity must first seek a 

review of the registry decision from the NERC Board 
67

of Trustees Compliance Committee. If unsuccessful 

with the Board, the entity may then petition FERC 

to review the registry determination. 

Additional Certification

Entities providing certain reliability functions 

deemed particularly crucial to the reliability of the 

bulk power system not only must be registered but 

also must meet or exceed certain minimum criteria 

demonstrating that the entity is capable of performing these functions. These critical functions are: 

reliability coordinator, balancing authority, and 

transmission operator. Certification ensures that an 

entity seeking to perform any of these functions has 

the tools, processes, training, and procedures to meet 

the requirements or sub-requirements of all of the 

Reliability Standards applicable to that function. The 

decision to certify an entity is a collaborative decision between NERC and the regional entity.

The certification process must be completed within nine months of the application acceptance date 

unless otherwise agreed by all parties involved in the 

process and approved by NERC. After an entity has 

been certified, the applicable regional entity notifies 

all entities as to the date that the entity may begin its 

operation as a certified entity. The entity must commence operation within 12 months of certification. 

Failure to begin operation within the 12-month 

period requires the entity to reapply for certification. 

An entity may need to obtain certification or 

re-certification when it experiences changes to its 

footprint or operational challenges, organizational 

restructuring that could impact bulk power system 

reliability, or a change to entity ownership requiring major operating procedure changes, such as the 

relocation of control centers, or replacement of a 

Supervisory Control and Data Acquisition/Energy 

Management System (SCADA/EMS) that controls 

or monitors the flow of electricity.

Monitoring and Enforcement 

Section 215 of the FPA requires the electric reliability organization and regional entities to have the 

ability to enforce Reliability Standards that provide 

for an adequate level of reliability of the bulk power 

system and to provide fair and impartial procedures 

for enforcement of these standards. When certifying NERC as the electric reliability organization, 

FERC required NERC to establish and implement an 

enforcement program under its rules of procedure. 

FERC found that the enforcement function includes 

both proactive compliance efforts by the electric reliability organization and regional entities, as well as 

after-the-fact investigations and penalty assessments. 

The compliance function includes audits, best practices programs that prepare entities for compliance 

with Reliability Standards, and remedial actions that 

bring a registered entity into compliance. NERC 

and the regional entities also may assess monetary 

and non-monetary penalties, in conjunction with or 

after action to bring a registered entity into compliance.

FERC has approved a detailed Compliance Monitoring and Enforcement Program (CMEP), proposed 

by NERC, which is Appendix 4C to NERC’s rules of 

procedure. The CMEP sets forth procedures under 

which NERC and the regional entities implement 

their compliance and enforcement functions in the 

U.S. portion of the bulk power system. Among 

other topics, the CMEP includes detailed procedures 

for how staff of regional entities and NERC conduct 

compliance audits, spot checks, and compliance 

investigations. The CMEP specifies procedures for 

handling complaints, self-reports of possible violations, and registered entities’ self-certifications 

whether they are in compliance with applicable 

Reliability Standards. Procedural rules included in 

the CMEP also address how staff of regional entities 

and NERC impose a penalty, consider a mitigation 
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Federal Energy Regulatory Commission Reliability Primer

plan a registered entity submits to bring itself into 

compliance, enter into a settlement, and issue a remedial action directive to require a registered entity 

to become compliant. The CMEP specifies requirements for regional entity reports about enforcement 

matters to NERC, and NERC’s subsequent reports 

of the matters to FERC, and establishes data retention requirements for NERC and regional entities 

on CMEP matters. Procedural rules for contested 

hearings relating to possible violations of Reliability 

Standards also appear in the CMEP. 

Sanction Guidelines

FERC has approved NERC’s Sanction Guidelines 

as Appendix 4B to NERC’s rules of procedure. This 

document sets out the processes and principles to 

be followed, and factors to be considered, when 

NERC or a regional entity determines penalties 

or sanctions. The Sanction Guidelines establish a 

three-step process for determining a penalty for a 

particular violation. First, a regional entity or NERC 

staff determines a base penalty amount, taking into 

consideration: (1) the violation risk factor that reflects the expected or potential impact to bulk power 

system reliability for a violation of the applicable 

requirement and (2) a violation severity level based 

on the extent to which the registered entity was out 

of compliance with that requirement. The base penalty amount can range from $0 to $1 million. In the 

second step, the regional entity or NERC determines 

whether to increase or decrease the base penalty 

amount by considering factors such as the violator’s 

compliance history, cooperation in the enforcement 

process, self-disclosure of the violation, voluntary 

corrective actions, and the violator’s internal compliance program. In the third step, the violator’s 

financial ability to pay a penalty may reduce the 

penalty, and a determination that the violator made 

an economic choice to violate may require the violator to disgorge any unjust enrichment or economic 

benefits resulting from the violation. 

Significantly, the Sanction Guidelines also state 

that in settlements of possible violations, regional 

entities and NERC can supersede any corresponding 

penalties or sanctions that would otherwise be determined pursuant to these guidelines. In practice, this 

provision has encouraged settlements by regional 

entities and NERC with registered entities to resolve 

Reliability Standard violations without engaging in 

contested proceedings. 

Notices of Penalty

Under FPA section 215, NERC must file with FERC 

a notice of penalty (NOP) for each penalty that 

NERC or a regional entity assesses against a registered entity. If, within 30 days of an NOP’s filing, 

FERC does not review the NOP on its own motion, 

or the registered entity does not appeal the NOP, 

it becomes final on the 31st day. The vast majority 

of NOPs result from settlements rather than contested penalty determinations. Since 2008, FERC 

has reviewed one NOP on its own motion, and two 

appeals of an NOP by the entity being penalized. In 

each review, FERC affirmed the penalty. 

FERC initially emphasized that NERC must file an 

NOP for violation of a Reliability Standard with a 

full discussion of the underlying facts and reasons 

supporting a penalty determination. Violations of 

Reliability Standards increased as regional entities 

began implementing the CMEP by starting compliance audits in 2007 and, again, after the CIP Reliability Standards addressing cybersecurity became 

enforceable in the U.S. beginning in 2008. A backlog 

of pending enforcement matters under the CMEP 

resulted. NERC then requested that, for certain 

types of violations that posed minimal risk to bulk 

power system reliability, FERC accept NOPs that did 

not include such a full record. NERC reasoned, and 
69

FERC agreed, that NERC’s ability to file abbreviated 

forms of NOPs could speed up processing of possible 

violations by regional entities and NERC, thereby 

reducing the backlog of unresolved possible violations. Currently, NERC files most NOPs as elements 

of a Spreadsheet Notice of Penalty (SNOP) that 

NERC files in an Excel spreadsheet format. NERC 

continues to file more significant Notices of Penalty 

in the original NOP format, known now as a Full 

NOP. 

FERC’s acceptance of abbreviated filing formats for 

NOPs itself did not completely reduce the backlog 

of possible violations in the CMEP process. NERC 

proposed a Find, Fix, and Track (FFT) process under 

which NERC would submit determinations on 

minimal risk violations in an informational filing, 

not an NOP. FFT matters would not constitute 

penalties for violations of Reliability Standards. In 

2012, FERC approved NERC’s FFT proposal with 

conditions, specifying that FFTs would be subject to 

reopening within 60 days of submission for FERC 

review; that they must, at least initially, pose only 

minimal risk to the BPS; and that FFTs would be 

included in a registered entity’s compliance history. 

After FERC approved the FFT process, which NERC 

justified on the basis that it and regional entities used 

too many resources to process low-risk Reliability 

Standard violations, NERC sought to align further 

the electric reliability organization’s compliance 

efforts with the risk posed by particular violations. 

In 2014, NERC asked FERC to approve its Reliability Assurance Initiative, under which NERC and 

regional entities would transition to a risk-based 

approach for compliance monitoring and enforcement. The Reliability Assurance Initiative’s premise 

was that a risk-based approach to these functions 

would benefit reliability by focusing electric reliability organization efforts on higher-risk issues while 

still identifying, correcting, and tracking lesser risk 

issues. NERC proposed to tailor compliance efforts 
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Federal Energy Regulatory Commission Reliability Primer

by: (1) identifying and prioritizing bulk power system-wide risks; (2) reviewing inherent risks applicable to each individual registered entity through use 

of an inherent risk assessment process; (3) obtaining 

additional insight on a voluntary basis on risks posed 

by individual registered entities through an internal 

controls evaluation on how their internal controls 

detect, correct and mitigate their risks determined 

by the inherent risk assessment; and (4) determining, based on the three previous steps, the frequency 

and type of compliance monitoring tools a regional 

entity would apply to each registered entity for 

which it is responsible. Also, NERC proposed that 

it submit to FERC information about “compliance 

exceptions” – minimal-risk, fully-mitigated instances of noncompliance that would not warrant 

a penalty but instead be resolved as an exercise of 

enforcement discretion. Finally, NERC proposed 

that a particular registered entity be allowed to “selflog” possible violations rather than self-report them 

to its regional entity, upon approval by the regional 

entity and NERC. A regional entity would review 

the registered entity’s self-logged items periodically, 

using a presumption that each item would be eligible 

for treatment as a compliance exception. 

In 2015, FERC approved NERC’s implementation 

of the Reliability Assurance Initiative and found 

reasonable its overall goal to focus electric reliability 

organization and industry compliance resources 

on high-risk issues that matter more to reliability. 

FERC imposed several conditions on Reliability 

Assurance Initiative implementation, including: 

NERC must publicly post compliance exceptions on 

its website; and NERC must file an annual report on 

the progress of the Reliability Assurance Initiative 

program. 

NERC now refers to the electric reliability organization’s “risk-based compliance and enforcement 

program” rather than the Reliability Assurance 

Initiative. 

 
71

D. Reliability and Adequacy Assessments 

NERC conducts independent assessments of the 

overall (existing and planned) electric generation 

and transmission reliability (adequacy and operating 

reliability) of the interconnected North American 

bulk power system. NERC also assesses and reports 

on the key issues, risks, and uncertainties that affect 

or have the potential to affect the reliability of existing and future electric supply and transmission.

The adequacy and reliability of the bulk power 

system is evaluated by NERC through identifying, 

analyzing and projecting trends in electric customer 

demand, supply, and transmission and their impacts 

on reliability. NERC investigates, assesses, and 

reports on the potential impacts of new and evolving electricity market practices, integration of new 

technology resources and loads, change in resource 

mix, new or proposed regulatory procedures, and 

new or proposed legislation (e.g., environmental 

requirements). NERC has discretion regarding the 

number and type of periodic assessments that are to 

be conducted. NERC also conducts special reliability assessments from time to time as circumstances 

warrant.
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Federal Energy Regulatory Commission Reliability Primer
73

Appendix 1 – Glossary of Certain Terms Used in the Reliability Primer

Bulk power system - facilities and control systems necessary for operating an interconnected electric energy transmission network and electric energy from generation facilities needed to maintain 

transmission system reliability. The term does not include facilities used in the local distribution of 

electric energy. 

Compliance registry – a NERC list of the owners, operators, and users of the bulk power system, 

and the entities registered as their designees that perform one or more functions in support of 

reliability of the bulk power system and are required to comply with one or more Reliability Standards.

Contingency - the unexpected failure or outage of a system component, such as a generator, transmission line, circuit breaker, switch or other electrical element.

Demand - the rate at which electric energy is delivered to or by a system or part of a system, generally expressed in kilowatts or megawatts, at a given instant or averaged over any designated interval 

of time. 

Electric reliability organization - the organization that is certified by FERC to establish and enforce Reliability Standards for the bulk power system in the United States.

Element - any electrical device with terminals that may be connected to other electrical devices, 

such as a generator, transformer, circuit breaker, bus section, or transmission line. An element may 

be comprised of one or more components.

Facility- a set of electrical equipment that operates as a single element (e.g., a line, a generator, a 

shunt compensator, transformer, etc.) 

Fault - an event occurring on an electric system such as a short circuit, a broken wire, or an intermittent connection.

Interconnection - a geographic area in which the operation of bulk power system components 

is synchronized such that the failure of one or more of such components may adversely affect the 

ability of the operators of other components within the system to maintain reliable operation of 

the facilities within their control.

Load - An end-use device or customer that receives power from the electric system.

Reactive power - the portion of electricity that establishes and sustains the electric and magnetic 

fields of alternating current equipment. 
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Federal Energy Regulatory Commission Reliability Primer

Real power - the portion of electricity that supplies energy to the load.

Regional entity – an organization to which the electric reliability organization may delegate authority for the purpose of proposing reliability standards to the electric reliability organization and 

enforcing reliability standards.

Registered entity - an owner, operator, or user of the bulk power system, or the entity registered as 

its designee for the purpose of compliance, that is included in the NERC Compliance Registry.

Reliability Standard - a requirement approved by FERC to provide for reliable operation of the 

bulk power system. The term includes requirements for the operation of existing bulk power 

system facilities and the design of planned additions or modifications to such facilities to the extent 

necessary to provide for reliable operation of the bulk power system, but the term does not include 

any requirement to enlarge such facilities or to construct new transmission capacity or generation 

capacity. The term also includes standards for cybersecurity protection. 

Reliable operation - operating the elements of the bulk power system within equipment and 

electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or 

cascading failures of such system will not occur as a result of a sudden disturbance or unanticipated 

failure of system elements. 

Statement of Compliance Registry Criteria – part of the NERC Rules of Procedure that describes 

how NERC will identify organizations that may be candidates for registration and assign them to 

the Compliance Registry.
75

Appendix 2 – Citations for Statutes, FERC Orders, Reports 

Statutes

Energy Policy Act of 2005, Pub. L. No. 109-58, §§ 1261 et seq., 119 Stat. 594 (2005).

Reports

• Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations

• Energy Primer: A Handbook of Energy Market Basics

• Arizona-Southern California Outages on September 8, 2011, Causes and Recommendations

Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1-5, 2011, 

Causes and Recommendations

FERC Orders

• Process to Select and Certify an ERO: Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric 

Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, order on reh’g, Order No. 

672-A, FERC Stats. & Regs. ¶ 31,212 (2006).

• ERO Certification Order: North American Electric Reliability Corp., 116 FERC ¶ 61,062, 

order on reh’g and compliance, 117 FERC ¶ 61,126 (2006), order on compliance, 118 FERC ¶ 

61,030, order on compliance, 118 FERC ¶ 61,190, order on reh’g, 119 FERC ¶ 61,046 (2007), 

rev. denied sub nom. Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).

• Order Approving Initial Reliability Standards: Mandatory Reliability Standards for the 

Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 

693-A, 120 FERC ¶ 61,053 (2007).

• Initial Order Approving Cyber Security Reliability Standards: Mandatory Reliability Standards for Critical Infrastructure Protection, Order No. 706, 122 FERC ¶ 61,040 (2008). 

• Definition of Bulk Electric System: Revisions to Electric Reliability Organization Definition 

of Bulk Electric System and Rules of Procedure, Order No. 773, 141 FERC ¶ 61,236 (2012). 
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Federal Energy Regulatory Commission Reliability Primer

Appendix 3 – Outline of Sample Reliability Standard

A. Sample of Standard:

1. Title: a phrase that describes the topic of the Reliability Standard. 

2. Number: A unique identification number that starts with three letters to identify the group 

followed by a dash and a three digit number, followed by a dash and the version number 

e.g., PRC-014-0.

3. Purpose: One or more sentences that explicitly states the outcome to be achieved by the 

adoption of the Reliability Standard.

4. Applicability: 

4.1 Each entity, as defined by the NERC Functional Model, that must comply with the 

Reliability Standard, such as “transmission owner.”

B. Requirements:

R1. A listing of explicitly stated technical, performance and preparedness requirements 

and who is responsible for achieving them.

C. Measures:

M1. A listing of the factors and the process NERC will use to assess performance and outcomes 

in order to determine non-compliance, and who is responsible for achieving the measures. 

Measures are the evidence that must be presented to show “compliance” with a standard and 

“are not intended to contain the quantitative metrics for determining satisfactory performance.”

D. Compliance:

1. Compliance Monitoring Process

 1.1 Compliance Monitoring Responsibility: NERC’s explanation of who is responsible for 

assessing performance or outcomes.

 1.2 Compliance Monitoring Period and Reset Timeframe: The timeframe for each compliance monitoring period before it is reset for the next period.

 1.3 Data Retention: How long compliance documentation needs to remain on file.

 1.4 Additional Compliance Information: Any other information relating to compliance.

E. Regional Differences: Identification of any regional differences that have been approved by the 

applicable NERC Committee (including Regions that are exempt).

Version History: The chronological history of changes to the standard.
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