Table of Contents

Chapter 1 Introduction .................................................................................... 1

Chapter 2 Wholesale Natural Gas Markets ...................................................... 5

Chapter 3 Wholesale Electricity Markets ...................................................... 37

Chapter 4 Financial Markets and Trading .................................................. 109

Chapter 5 Market Manipulation ................................................................. 125

The Energy Primer is a staff product and does not necessarily refl ect the views of the 

Commission or any Commissioner.

Energy Primer

A Handbook of Energy Market Basics

 Energy Primer | 1

Natural gas and electricity are two forms of energy that 

are of particular interest to the Federal Energy Regulatory 

Commission. This primer explores the workings of the 

wholesale markets for these two forms of energy, as well 

as energy-related fi nancial markets.

Natural gas is the second largest primary source of energy 

consumed in the United States, exceeded only by petroleum. A primary energy source is an energy source that 

can be consumed directly or converted into something 

else, like electricity. Roughly a third of the natural gas 

consumed in the United States goes into power plants for 

the production of electricity.

Electricity, a secondary energy source, results from the 

conversion of primary fuels such as fossil fuels, uranium 

or wind, into a fl ow of electrons used to power modern 

life. 

Natural gas and electric markets involve both physical 

and fi nancial elements. The physical markets contain the 

natural resources, infrastructure, institutions and market 

participants involved in producing natural gas and electricity and delivering it to consumers. They also include 

the trading of and payment for the physical commodity, natural gas. The fi nancial markets include the buying and selling of fi nancial products derived from physical 

natural gas and electricity. These fi nancial markets also 

include market structures and institutions, market participants, products and trading, and have their own drivers 

of demand and supply. In general, physical and fi nancial 

markets can be distinguished by the products and by the 

intentions of the market participants involved. Physical 

products are those whose contracts involve the physical 

delivery of natural gas or electricity. Physical market participants are those who are in the market to make or take 

delivery of the commodity. Financial products do not 

involve the delivery of gas or electricity; instead, they involve the exchange of money.

Physical markets can be further differentiated by: 

• Location: regions, nodes, zones or hubs;

• Timeframes: hourly, daily, monthly, quarterly or yearly; 

• Types of products: natural gas molecules or electrons, pipeline or transmission capacity and storage; 

and

• Nature of sales: retail sales involve most sales to enduse customers; wholesale sales involve everything else.

Physical Fundamentals

Much of the wholesale natural gas and electric industry in 

the United States trades competitively; some markets are 

established through administrative processes based on the 

cost of providing service. In competitive markets, prices 

are largely driven by the economic concepts of supply and 

demand. Underlying the supply and demand for natural 

gas or electricity are physical fundamentals - the physi-
2 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

cal realities of how markets produce and deliver energy 

to consumers and how they form prices. These physical 

fundamentals will be covered in Chapter 2, on natural gas, 

and Chapter 3, on electricity.

Wholesale natural gas and electric markets differ from 

other competitive markets, however, in critical ways. 

While this primer focuses on wholesale markets, demand 

is ultimately determined at the retail level. Retail use is 

relatively inelastic in the short-term, although this may be 

less so with some larger customers. Retail use of gas or 

electricity exhibits some unique characteristics:

Limited customer storage options: Retail consumers 

have few options for storing natural gas and electricity. 

For natural gas, large consumers and entities that sell to 

retail consumers may be able to store gas, but smaller 

consumers do not have this option. For electricity, smaller 

consumers may have batteries, but nothing adequate to 

ensure refrigeration, for example. Without storage, consumers cannot buy when prices are low and use their 

stored product when prices rise. This limits consumers’ 

response to changes in prices.

Substitutes: Retail consumers have few substitutes for 

natural gas or electricity, certainly in the short-term. If 

natural gas or electric prices go up, consumers cannot 

quickly switch to a different product. Longer term, they 

may be able to switch to gas from electricity for heating, 

or they may be able to insulate or install new windows or 

take other steps to reduce their consumption of energy. In 

addition, demand-response programs can provide benefi ts 

to those who would reduce their energy needs at certain times; this might include turning off air conditioning 

during the hottest part of a day in order to help reduce 

electric load.

Necessity: Unlike most other products, natural gas and 

electric service are necessities today, and a lack of service can mean customers without heat, the ability to cook 

or refrigerate food or the ability to run their businesses. 

Blackouts and other service disruptions create operating 

problems and hazards as well. Consumers cannot postpone the purchase of electricity or natural gas. They may 

be able to turn down their thermostats, but cannot eliminate consumption altogether for an extended period of 

time. 

Because consumers have limited ability to reduce demand, 

supply must match demand instantaneously, in all locations. 

For natural gas, this means production, pipelines and 

storage need to be sized to meet the greatest potential 

demand, and deliveries need to move up and down to 

match changes in consumption. Natural gas has underground and above-ground storage options and linepack, 

which involves raising the pressure in a pipeline to pack 

more molecules into the same space. Gas fl ows through a 

pipeline at about 15 mph, so new supply can take hours 

or days to reach its destination. That increases the value 

of market-area storage, which vastly reduces the distance 

and time needed for gas to reach consumers.

For electricity, storage is more limited, although technology – involving batteries and fl ywheels – is being developed. Hydroelectric pumped storage is available in a few 

locations; this involves pumping water to high reservoirs 

during times of slack electricity demand, then letting the 

water fl ow downhill through electricity-generating turbines when demand for power rises. Generating plants, 

transmission and distribution lines, substations and other 

equipment must be sized to meet the maximum amount 

needed by consumers at any time, in all locations. For 

all practical purposes, electricity use is contemporaneous 

with electricity generation; the power to run a lightbulb is 

produced at the moment of illumination.
 Energy Primer | 3

Natural gas and electric industries are capital intensive, requiring access to fi nancial markets to support daily operations, trading and investment programs. Access to fi nancial 

markets requires maintaining an investment grade credit 

rating to support activities ranging from daily transactions 

to long-term development of infrastructure.

Financial Markets and Trading

Financial markets are where companies and individuals go 

if they need to raise or invest money. They are important 

to natural gas and electric markets in two key ways. First, 

they provide access to the capital needed for operations. 

Second, some natural gas- or electricity-related products 

may trade in commodity markets or, as derivative products 

(see below), in fi nancial markets.

Natural gas and electricity are traded like commodities, just 

like metals, corn, wheat or oil. They may not be visible, 

but you can turn them on and off, and measure them. 

Commodity markets began as ways for farmers to sell their 

products, or even a portion of their production before it 

was harvested, providing them with capital to continue operations. 

Commodity markets evolved to provide other tools for 

farmers (and other commodity producers) to manage their 

risk, notably the risk of adverse changes in price. These fi -

nancial products were derived from the physical natural gas 

and electric products, and are known as derivatives. Since 

their inception, trading in physical commodities and derivatives has attracted others to the market, such as speculators hoping to make a profi t from changes in price.

The market for natural gas derivatives has grown enormously within the past decade, as competitive natural gas 

and electric markets matured and investors came to see 

energy commodities as investments, not just a source of 

power. This trading affects the physical markets in a number of ways, and is discussed in Chapter 4, Financial Markets and Trading .

Market Manipulation

Where there are markets, there will be those who attempt to 

manipulate the markets for their own benefi t. These practices undermine the market’s ability to operate effi ciently, 

reduce other market participants’ confi dence in the markets and distort market outcomes, including prices. These 

practices are discussed in Chapter 5, Market Manipulation.

Addition Information

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 energy markets and FERC regulation can be found at www.ferc.gov; 

then click on Market Oversight. If you are reading this 

Energy Primer electronically, you can fi nd the market oversight pages here: http://www.ferc.gov/market-oversight/

market-oversight.asp

Google search also provides a quick path to information on 

specifi c FERC orders or to more general subjects (e.g., FERC 

regulation of natural gas pipelines).

 Energy Primer | 5

Overview

Natural gas markets have a signifi cant impact on the economy and on the individuals who rely on the fuel for electric generation, manufacturing, heating, cooking and other 

purposes. The Department of Energy’s Energy Information 

Administration (EIA) estimates that natural gas supplies 25 

percent of the energy used in the United States, or about 

24 trillion cubic feet (Tcf) of gas a year.

Under the Natural Gas Act (NGA), the Federal Energy Regulatory Commission (FERC) has jurisdiction over the transportation and sale of natural gas and the companies engaged in those activities. 

The natural gas market is an amalgamation of a number of 

subsidiary markets. There is a physical market, in which 

natural gas is produced, transported, stored and consumed. 

There is also a fi nancial market in which physical natural 

gas is bought and sold as a fi nancial product derived from 

physical natural gas. Natural gas markets are also regional, 

with prices for natural gas varying with the demand characteristics of the market, the region’s access to different 

supply basins, pipelines and storage facilities.

Natural Gas

Natural gas is primarily methane, and is colorless and odorless in its natural condition. It is also highly combustible, 

giving off a great deal of energy and fewer emissions than 

fuels such as coal and oil. Natural gas occurs in geological 

formations in different ways: as a gas phase associated 

with crude oil, dissolved in the crude oil, or as a gas phase 

not associated with any signifi cant crude oil. Natural gas 

is rich or wet if it contains signifi cant natural gas liquids 

(NGL); by contrast, natural gas is lean or dry if it does not 

contain these liquids. Processors remove water, liquefi able 

hydrocarbons and other impurities from the natural gas 

stream to make the natural gas suitable for sale. Natural 

gas liquids may be processed out and sold separately. 

Natural gas is mostly methane, which is made of one carbon atom and four hydrogen atoms (CH4

) and is among the 

materials known as hydrocarbons. 

Other gases such as ethane, butane, propane and pentane 

may be mixed in with the methane. These may be processed out and sold separately. Gas containing signifi cant 

amounts of natural gas liquids is known as wet gas. The 
6 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

gas that fl ows through pipelines to natural gas consumers 

typically has these liquids removed, and is known as dry 

gas. 

While natural gas is typically a gas, it can be cooled to a 

liquid and transported in trucks or ships. In this form, it is 

referred to as liquefi ed natural gas, or LNG.

Natural Gas Markets

As noted, natural gas markets are both physical and fi nancial. This chapter focuses on the physical natural gas markets, but it should be noted that fi nancial markets can have 

signifi cant impacts on the physical natural gas market.

For this discussion, the natural gas industry has three segments. The fi rst is the supply segment, which includes exploration and development of natural gas resources and reserves, and production, which includes drilling, extraction 

and gas gathering. The second segment is the midstream 

sector, in which small-diameter gathering pipeline systems 

transport the gas from the wellhead to natural gas processing facilities, where impurities and other hydrocarbons are 

removed from the gas to create pipeline-quality dry natural 

gas. The third segment is transportation, which includes 

intrastate and interstate pipeline systems that move natural 

gas through large-diameter pipelines to storage facilities 

and a variety of consumers, including power plants, industrial facilities and local distribution companies (LDCs), 

which deliver the gas to retail consumers. 

Each component of the supply chain is critical in serving customers. The quantity of reserves and production 

can affect market participants’ expectations about current 

and future supply, and thus can affect prices. Similarly, 

the availability of pipeline and storage capacity determines 

which supply basins are used and the amount of gas that 

can be transported from producers to consumers. All of 

these factors affect the supply chain, but they also affect 

the supply-demand balance, both nationally and regionally.

Natural gas markets are generally divided into the West, 

Midwest, Gulf Coast, Northeast and Southeast regions. 

These regions have differing supply, transportation and demand characteristics, resulting in different prices. 

Within these regions are hubs – the interconnection of 

two or more pipelines – that also become market hubs for 

buying and selling gas. The key hub used to refl ect the 

U.S. natural gas market as a whole is the Henry Hub, in 

Louisiana. Prices at other locations are frequently shown 

as Henry Hub plus or minus some amount. 

These regional differences in supply and demand result in 

different prices for natural gas at various locations. Prices 

are lowest in areas with low-cost production, ample infrastructure and limited demand – the Opal Hub in Wyoming, 

for example – and highest where production or transportation is limited and demand is high – Algonquin citygate, in 

Massachusetts, for example.
 Energy Primer | 7

Current Trends in Physical Natural Gas Markets

Natural gas markets in the United States are undergoing a 

period of transition. Within the last decade, various factors 

have shifted the dynamics of supply and demand. These 

include, but are not limited to, the following:

1. Development of technology, like hydraulic fracturing 

and horizontal drilling, enables producers to access unconventional resources such as those in shale 

formations. This has vastly expanded supply and is 

increasing the amount of natural gas produced, which 

has reached levels not seen in more than 35 years. It 

also has moderated prices across the country. Notably, 

some of these resources are located close to eastern 

population centers, providing access to low-cost gas 

supplies with lower transportation costs.

2. Natural gas has become an investment opportunity as 

it is a traded commodity. As noted above, there are 

physical and fi nancial investment markets. There are 

two distinct markets for physical natural gas: (1) a 

cash market, which is a daily market where natural gas 

is bought and sold for immediate delivery; and (2) a 

forward market, where natural gas is bought and sold 

under contract for one month or more in the future. 

The fi nancial gas market is directly linked to the physical natural gas market. 

3. Natural gas demand for power generation is rising 

and is expected to increase signifi cantly in the coming 

years. Power plant demand for natural gas refl ects the 

environmental benefi ts of the fuel, the operating fl exibility of natural gas-fi red generators, and lower natural gas prices. Natural gas-fi red power plants emit less 

air pollution than generators using coal or oil. These 

plants are also relatively easier to site, can be built in 

a range of sizes and can increase or decrease output 

more fl exibly than large baseload generators, such as 

nuclear or coal. This ability to change output quickly 

aids electric system operators in matching generation 

to customer loads, and enables operators to offset 

rapid changes in output from wind and other intermittent generators. 

4. Pipeline expansion has changed the relationships 

between prices in various regions. New interstate pipelines have enabled regions such as the Northeast and 

Mid-Atlantic to access new supply sources, expanded 

the amount of natural gas that can fl ow from traditional supply sources and enhanced the amount that 

can fl ow overall. This has reduced prices and 

tempered extreme price movements during periods of 

peak demand.

 

Natural Gas Demand

Natural gas already is the fuel of choice for many sectors 

of the U.S. economy. Natural gas demand, however, can 

fl uctuate dramatically, but it generally provides about 25 

percent of U.S. energy needs.

Demand Drivers

Over the long term, natural gas use is driven by overall economic and population growth, environmental policy, 

energy effi ciency, technological changes and prices for natural gas and substitute energy sources such as oil, coal and 

electricity. In the short-term, demand stems from weather, 

economic activity and changing relationships between coal 

and natural gas prices. 

Weather

Weather is the most signifi cant factor affecting natural gas 

demand, which has historically been seasonal and weatherdriven. Natural gas demand can also swing considerably 

within a given day, especially during periods of extreme 

temperatures. Short-term changes in weather, such as heat 

waves and winter storms, can send demand and prices soar-
8 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

ing – or dropping – within the course of a day, sometimes 

unexpectedly. This unpredictability challenges suppliers 

and pipelines, especially when pipelines are already full. 

Economic Activity and Growth

Economic growth can increase the amount of natural gas 

used by industry, power plants and commercial entities as 

consumers want more of their products and services. During a recession, gas use usually declines. 

On the other hand, economic growth may raise personal 

incomes and consumption of electric-powered consumer 

goods. 

Structural changes in the economy can also affect natural 

gas demand. Declining manufacturing and growing service sectors result in changes in gas use, as does increased 

global competition. New markets for products and services 

may require additional natural gas; movement of operations offshore may reduce it.

Daily and weekly economic activity creates cyclical demand 

patterns. During the work day, demand rises as people get 

up and go to work or school. Similarly, it declines as they 

go to sleep. On the weekend, demand tends to vary less 

over the course of the day.

Prices of Natural Gas and Coal

To use natural gas for heat, a home needs to have an appropriate furnace and piping in place. To burn it in a power 

plant, the generator needs to make long-term investments 

in gas-fi red generators. These are decisions requiring longterm capital investments, and are cheapest and easiest to 

make at the time a home or power plant is being built, and 

are more complicated to change later. Thus, over the long 

term, demand for natural gas can be affected by the expected costs of alternative energy sources: the cost of a natural 

gas furnace versus an electric one; the cost of a coal-fi red 

generating plant versus one fueled by natural gas. 

In the short-term, the opportunity for fuel switching has 

been signifi cant in power generation. Electric grid operators have a choice as to which power plant to dispatch to 

meet increased electric demand. Dispatch is often based 

on the marginal cost of generation at each available plant 

in the generation fl eet. Plants with lower marginal costs, 

such as nuclear, typically dispatch before plants with higher 

marginal costs, such as natural gas.

As natural gas prices drop relative to coal prices, natural 

gas-fi red generation can get dispatched earlier than coalfi red generation, increasing natural gas demand from the 

power sector. 

Demographics and Social Trends

Long-term demand can also be affected by shifting demographics and social trends. Population growth in warmer 

climates and declines in the older industrial areas of the 

North have affected natural gas use. So has the trend toward larger houses.

Today, most households have a proliferation of electronic 

appliances and gadgets. Even as appliances become more 

energy effi cient, people fi nd more appliances to use. Thus, 

the result of greater effi ciency is not necessarily less use of 
 Energy Primer | 9

electricity. But one thing for sure is that a greater share of 

the electricity that is generated is fueled by natural gas.

Environmental Concerns and Energy Effi ciency

Natural gas has relatively fewer environmental problems 

compared with other fossil fuels, and, consequently, it is 

being increasingly used for power generation. In addition 

to helping urban areas meet air quality goals, natural gas 

generation has not experienced as much negative public 

sentiment as have nuclear and coal-fi red generators, making it feasible to site gas-fi red generators closer to load 

centers. Growth in wind and other intermittent generation technologies benefi t when coupled with natural gas 

generation, which is able to ramp up and down quickly to 

complement variable output by wind.

The natural gas emissions profi le has also encouraged some 

urban mass transit bus systems, West Coast port operations 

and other vehicle fl eets to shift to natural gas from gasoline or diesel fuel.

Customer Sectors and Demand

In 2007, natural gas used for electric generation overtook 

gas-for-industrial load to become the largest customer 

class for natural gas. In 2010, according to the EIA, power 

generation used 7.4 Tcf of the natural gas delivered to consumers; industrial, 6.6 Tcf; residential, 4.8 Tcf; and commercial, 3.2 Tcf.

Demand is seasonal. It rises and falls during a year as 

the seasons bring changing temperatures. Demand usually peaks in winter to meet heating load, with a second, 

smaller peak in summer to meet power generator load. The 

low months for gas consumption are during spring and 

fall, known as shoulder months. Natural gas use also varies 

with the time of day. The difference between peak winter 

and off-peak demand varies regionally, due to differences 

in winter temperatures and customer composition. 

Each customer sector contributes differently to overall demand, both in terms of the amount that demand varies 

over a cycle and whether its peak demand coincides with 

the overall system peak. Residential demand, for example, 

can be highly variable in colder climates, and its peak coincides with the overall system peak. Power generation’s peak 

does not coincide with the winter gas-demand peak, but 

in fact its growing use of natural gas to produce electricity 

for air conditioning has created robust summer demand, 

which competes with gas supply that traditionally would 

fl ow into underground storage for later use in the winter. 

Industrial demand stays relatively constant year-round. 

In the short term, residential and commercial natural gas 

use tends to be inelastic – consumers use what they need 

regardless of the price. Power plant demand, on the other 

hand, is more price-responsive as natural gas competes 

with other fuels, especially coal, in the production of electricity. Price inelasticity implies that a potential for price 

spikes exists during periods of supply constraint. 

Consequently, the mix of customers in a region can affect 

system operations and costs. Pipelines and other equipment need to be sized to account for peak demand. Demand that stays fairly constant presents fewer operational 

challenges and usually enjoys lower prices. Highly variable 

demand will result in pipelines and equipment being used 

at less than full capacity for much of the year, and prices 

for service may be more expensive, both because the pipelines may become constrained during peak times and because the capacity is not fully used throughout the year. 

Power Generation

Generation demand can soar at any time; gas-fi red generators can change their output quickly, and are frequently 

called on to change their output due to changes in de-
10 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

mand or when problems occur elsewhere in the power grid. 

United States natural gas demand for power generation 

increased from 5.5 Tcf in 2004 to 7.4 Tcf in 2010, according to the EIA. Generating plants tend to consume more 

natural gas in the summer to meet air conditioning loads, 

but power demand can also climb in the winter to provide 

electric heating and lighting. Generation demand can also 

be infl uenced by the relative prices for natural gas and other fuels, especially coal. Since late 2008, natural gas-fi red 

generators generally have been dispatched before some coal 

plants because of the decrease in natural gas prices. 

Industrial

Natural gas as a fuel is used to produce items such as steel, 

glass, paper, clothing and brick. It also is an essential raw 

material for paints, fertilizer, plastics, antifreeze, dyes, photographic fi lm, medicines and explosives. Industrial load 

tends to show the least seasonal variation of natural gas 

use, but the industry is sensitive to economic pressures. 

Gas use has been declining slowly due to effi ciency improvements and economic factors, such as the movement 

of manufacturing overseas. Still, EIA data show that industrial customers remain the second-largest consuming 

segment, using 6.6 Tcf in 2010, down from 7.2 Tcf in 

2004. This decline stemmed from both fewer customers 

and lower average use.

Residential

Despite population growth, natural gas used in the residential sector for home furnaces, water heaters, clothes dryers 

and stoves has remained fairly fl at over the past decade as 

appliances and homes have become more energy effi cient. 

Residential customers consumed 4.8 Tcf in 2010, compared 

to 4.9 in 2004. Much of the year-to-year demand variation in this sector can be attributed to the weather during 

a particular year. A year with a long, cold winter and hot 

summer will see higher gas demand than a year with a mild 

winter and summer. Demographics may also support this 

trend, as customers have moved from northern industrial 

centers to warmer parts of the country. Slightly more than 

half of the homes in the United States use natural gas as 

their main heating fuel. Residential customers typically 

show the greatest seasonal variability, especially in coldwinter regions where demand soars during winter months 

as consumers turn on their furnaces. 

Quick Facts: Resources and Proved Reserves

• Resources - Total gas estimated to exist in a particular area. The Potential Gas Committee’s latest 

biennial estimate showed 2,170 Tcf of future gas 

supply in the United States as of Dec. 31, 2010; 

that fi gure included 273 Tcf of proved dry gas 

reserves and 1,898 Tcf of total potential resources.

• Proved reserves - Estimated amount of natural gas that, based on analysis of geologic and 

engineering data gathered though drilling and 

testing, can be reasonably projected to be recoverable under existing economic and operating conditions. According to the EIA, as of Dec. 31, 2009, 

dry natural gas proved reserves totaled 273 Tcf. 

Proved reserves have been growing every year since 

1999.
 Energy Primer | 11

Commercial

Commercial demand has remained fairly constant at 3.2 

Tcf in 2010 as well as in 2004, and like the residential sector will see some year-to-year variation based on weather. 

Commercial consumers include hotels, restaurants, wholesale and retail stores and government agencies, which use 

natural gas primarily for heat. Consequently, its demand 

cycles over the seasons, weeks and days. 

Natural Gas Supply

Natural Gas Resources, Reserves and Production

The amount of natural gas in the ground is estimated by a 

variety of techniques, and it takes into account the technology available to extract the gas. According to the EIA, 

estimating the technically recoverable oil and natural gas 

resource base in the United States is an evolving process. 

Analysts use different methods and systems to make natural gas estimates. As detailed in the table below, natural 

gas supplies are characterized as resources, proved reserves 

and production. 

Resources is the largest category, which describes the total 

potential of natural gas supply. Proved reserves consider 

the feasibility and economics of extracting the natural gas. 

Lastly, production describes the amount of natural gas removed from the ground.

Natural gas is located underneath the surface of the earth. 

Natural gas is characterized by the type of basin or rock 

formation in which it lies. Conventional natural gas is 

found in porous rock formations, and in the United States 

is the traditional source of natural gas. 

Unconventional natural gas, on the other hand, is found 

in shale, coal seams and tight, low-permeability rock formations. In 2007, the National Petroleum Council (NPC) 

defi ned unconventional gas as “natural gas that cannot 

be produced at economic fl ow rates or in economic volumes of natural gas unless the well is stimulated by a large 

hydraulic fracture treatment, a horizontal wellbore or by 

using multilateral wellbores or some other technique to expose more of the reservoir to the wellbore.” 

In the past few years, improvements in drilling technology 

have enabled producers to access unconventional supplies, 

notably shale, yielding signifi cant increases in production 

and raising the estimate of proved reserves. Estimates of 

resources in 2011 amounted to approximately 2,170 Tcf 

(which included reserves).

This domestic growth in resources and reserves has translated into greater natural gas production, which has grown 

22 percent since 2005, to more than 60 billion cubic feet 

per day (Bcfd) in 2011. Most of the growth came from 

shale gas, which now accounts for 32 percent of natural 

gas resources.

New Field 

Discovery

Reserve Extensions and Revisions

Resource Base

Exploration 

Production 

Development 

Geologic Basin

Geological and 

Geophysical

•Seismic

•Exploration Drilling 

Land and Lease

Land and Lease

Delineation

Production

Gas Exploration and Development 

Process
12 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Worldwide, the United States accounts for one-third of 

global natural gas resources. Most of the natural gas resources are in the Middle East – Iran, Qatar and Saudi Arabia – followed by the United States and Russia.

Rig Count and Rig Productivity

A measure of exploration, the rig count measures the number of rotary drilling rigs actually drilling for oil and gas. 

These measures are done by several companies active in 

drilling operations. Rig counts are often used as a rough 

predictor of future production. The oil and gas rig count 

peaked at 4,530 on Dec. 28, 1981. More recently, in September 2008, the rig counted reached 2,500, before plunging to 1,200 in April 2009, according to Baker Hughes Inc. 

Rig counts recently have hovered around 1,900. 

Within the total rig count, the use of horizontal drilling 

rigs, capable of accessing natural gas and oil in shale formations, grew prior to the recession that began in 2008. 

Traditional vertical rigs remain well below their prerecession highs.

The adoption of horizontal drilling has signifi cantly increased production per rig, making comparison of rig 

counts over time problematic because horizontal rigs are 

considerably more productive than vertical rigs.

Conventional and Unconventional Natural Gas

Natural gas is a fossil fuel. Natural gas historically has 

been found in underground reservoirs made when organic 

material was buried and pressurized. The remains of that 

organic material were trapped in the surrounding rock as 

oil or natural gas. Natural gas and oil are often found 

together. The depth of the organic materials and the temperatures at which they are buried often determine whether 

the organic matter turns into oil or natural gas. Generally, 

oil is found at depths of 3,000 to 9,000 feet; organic materials at greater depths and higher temperatures result in

natural gas. 

Natural gas basins are frequently referred to as conventional or unconventional basins or plays. These basins differ in 

the geology of the basin and the depth at which gas can be 

found. The schematic at left illustrates differing geologic 

formations in which natural gas can be found.

Conventional Natural Gas

Natural gas historically has been produced from what is 

traditionally known as conventional natural gas resources, which provided most of the country’s supply needs for 

more than a century. Conventional gas is found in geological basins or reservoirs made of porous and permeable 

rocks, holding signifi cant amounts of natural gas in the 

spaces in the rocks. 

Conventional resources have been found both on land and 

offshore (see map of conventional fi elds, on next page), 

with the major fi elds in an arc from the Rocky Mountains to 

the Gulf of Mexico to Appalachia. The largest conventional 

fi elds reside in Texas, Wyoming, Oklahoma, New Mexico 

and the federal offshore area of the Gulf of Mexico. In 

2000, offshore natural gas production represented 24 percent percent of total U.S. production; by 2010 that amount 

had fallen to 10 percent. 
 Energy Primer | 13

Federal offshore natural gas wells are drilled into the ocean 

fl oor off the coast of the United States in waters that are 

jurisdictional to the federal government. Most states have 

jurisdiction over natural resources within three nautical 

miles of their coastlines; Florida and Texas claim nine nautical miles of jurisdiction. 

Roughly 4,000 oil and gas platforms are producing in federal waters at water depths approaching 7,500 feet (at total 

well depths of 25,000-30,000 feet) and at distances as far 

as 200 miles from shore, EIA reports. Most of these offshore wells are in the Gulf of Mexico. 

Offshore production has been going on for decades. As 

the easy pickings – close-in, shallow-water wells – became 

less economic to produce, companies looked to reserves at 

greater water depth. Technological improvements contributed to continuing production from deep offshore wells. 
14 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Unconventional Natural Gas 

In recent years, innovations in exploration and drilling 

technology have led to rapid growth in the production of 

unconventional natural gas. This term refers to three major types of formations where gas is not found in distinct 

basins, but is trapped in shale, tight sands or coal seam 

formations over large areas. 

The presence of natural gas in these unconventional plays 

has been common knowledge for decades, but it was not 

until the early 1990s, when after years of experimenting in 

the Barnett Shale in Texas, George Mitchell and Mitchell 

Energy Co. developed a new drilling technique that made 

production in these types of formations economically feasible. The new technology included horizontal and directional wells, which allow a producer to penetrate diverse 

targets and increase the productivity of a well. As shown 

below, directional wells allow the producer to tap these resources through multiple bores. The horizontal wells have 

a vertical bore, but then move horizontally through the 

rock to access more supply. These new drilling technologies greatly improved the likelihood of a successful well 

and the productivity of that well. 
 Energy Primer | 15

As of 2012, production from unconventional reserves supplied more than half of U.S. gas needs.

Tight sands gas is natural gas contained in sandstone, siltstone and carbonate reservoirs of such low permeability 

that it will not naturally fl ow when a well is drilled. To 

extract tight sands gas, the rock has to be fractured to 

stimulate production. There are about 20 tight sands basins in the United States (see map); as of 2009, annual 

production was about 6 Tcf, or about one-third of U.S. 

domestic production. 

Coalbed methane (CBM) is natural gas trapped in coal 

seams. Fractures, or cleats, that permeate coalbeds are 

usually fi lled with water; the deeper the coalbed, the less 

water is present. To release the gas from the coal, pressure in the fractures is created by removing water from the 

coalbed. 

The in-place coalbed methane resource of the United States 

is estimated to be more than 700 Tcf, but less than 100 

Tcf of that may be economically recoverable, according to 

the U.S. Geological Survey. Most CBM production in the 

United States is concentrated in the Rocky Mountain area, 

although there is signifi cant activity in the Midcontinent 

and the Appalachian area. 

Shale gas is found in fi ne-grained sedimentary rock with 

low permeability and porosity, including mudstone, clay 

stone and what is commonly known as shale. These rock 

conditions require a special technique known as hydraulic 

fracturing (fracking) to release the natural gas. This technique involves fracturing the rock in the horizontal shaft 

using a series of radial explosions and water pressure (see 

graphic). 

In the past decade the processes for fi nding geological formations rich in shale gas, or shale plays, have improved to 

the point that new wells almost always result in natural 

gas production. Improved exploration techniques coupled 

with improved drilling and production methods have lowered the cost of fi nding and producing shale gas, and have 

resulted in a signifi cant increase in production. In 2011, 

shale gas accounted for about 25 percent of total gas production, with expectations of signifi cant increases in the 

future.

The fi ve major shale plays in the United States include 

Barnett, Fayetteville, Woodford, Haynesville and Marcellus 

(see map on next page). Together, they hold an estimated 

3,420 Tcf of shale gas resources, according to Bentek Energy. Other shale formations, such as Eagle Ford, are seeing heavy exploration activity and are expected to become 

major contributors of natural gas supply in the near future. 

The shale plays are widely distributed through the country, which has the added advantage of putting production closer to demand centers, thus reducing transportation 

bottlenecks and costs.

Many shale reservoirs contain natural gas liquids (NGL), 

which can be sold separately, and which augment the economics of producing natural gas. Natural gas is rich or wet 

if it contains signifi cant liquids; lean or dry if is does not.

 Horizontal Well 
16 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

The Shale Revolution

The estimated resources, proven reserves and production 

of shale gas have risen rapidly since 2005, and shale is 

transforming gas production in the United States. In 2009, 

according to EIA, shale gas made up 13 percent of gross 

production of natural gas, and is expected to become the 

dominant source of domestically produced gas. By comparison, coalbed methane accounted for 8 percent of production, while 22 percent of the natural gas came from oil 

wells and 57 percent was produced from natural gas wells.

New shale plays have increased dry shale gas production 

from 1 Tcf in 2006 to 4.8 Tcf, or 2 percent of total United 

States natural gas production, in 2010. Wet shale gas reserves account for about 21 percent of the overall United 

States natural gas reserves. According to the EIA, shale gas 

will account for about 48 percent of United States natural 

gas production in 2035.

Shale gas can be produced at much lower costs, overall, 

-

2.0

4.0

6.0

8.0

10.0

12.0

14.0

Jan-05

Apr-05

Jul-05

Oct-05

Jan-06

Apr-06

Jul-06

Oct-06

Jan-07

Apr-07

Jul-07

Oct-07

Jan-08

Apr-08

Jul-08

Oct-08

Jan-09

Apr-09

Jul-09

Oct-09

Jan-10

Apr-10

Jul-10

Bcfd

Eagle Ford

Marcellus

Arkoma - Fayetteville

ARKLA - Haynesville

Barnett

Arkoma - Woodford

Source: Derived from Bentek Energy data.

Shale Gas Production by Region

than gas from conventional fi elds. Breakeven prices – the 

price that equals production cost – are below recent natural gas prices, making production of shale gas potentially 

profi table. The natural gas liquids add to the value of 

production. 
 Energy Primer | 17

Shale Wet Gas Breakeven Prices

Natural gas liquids are priced more like oil than natural gas, 

making them lucrative. A typical barrel of NGL might contain 40-45 percent ethane, 25-30 percent propane, 5-10 

percent butane and 10-15 percent natural gasoline. 

As a result, the higher value of the liquids coming up the 

well offset the lower market prices for the dry gas portion 

of the wellstream.

In addition to having lower fi nding and production costs, 

shale gas production is more fl exible than traditional production. Unless the well is plugged, a vertical well is always 

producing. Shale gas production, however, allows the producer to essentially turn off the well without endangering 

the well by slowing the pace of hydraulic fracturing along 

the horizontal bore hole. Therefore, producers are able to 

tailor shale production to market conditions.

The Marcellus Shale formation in Appalachia is of particular note because of its location, size and resource potential, according to the Potentail Gas Committiee at the 

Colorado School of Mines. Marcellus Shale has estimated 

gas resources reaching 549 Tcf, and it extends from West 

Virginia to New York, near the high population centers of 

the Northeast and Mid-Atlantic. Although Marcellus Shale 

has been producing signifi cant amounts of gas only since 

2008, production has been prolifi c with high initial well 

pressures and high production rates. 

Growing gas production in Marcellus has already made an 

impact on U.S. gas transportation. As more gas has fl owed 

out of Marcellus, less gas has been needed from the RockNatural Gas Import Entry Points

Source: Energy Information Administration
18 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

ies or the Gulf to serve the eastern United States. This new 

production has contributed to a reduction in natural gas 

prices and the long-standing price differentials between 

the Northeast and other parts of the United States. It has 

also caused imports from Canada to decrease.

Environmental concerns present the greatest potential challenge to continued shale development. One issue involves 

the amount of water used for hydraulic fracturing and 

the disposal of the effl uent used – chemicals and sand are 

combined with water to create a fracturing solution, which 

is then pumped into deep formations. Some companies 

recycle the returned water, which allows them to reuse such 

water. Concerns have also been raised regarding the potential risks and health hazards associated with wastewater 

(especially when stored at ground level in holding ponds) 

seeping into drinking water. 

FERC Jurisdiction

Section 1(b) of the NGA exempts production and gathering facilities from FERC jurisdiction. Moreover, the Wellhead Decontrol Act of 1989, Pub. L. No. 101-60 (1989); 15 

U.S.C. § 3431(b)(1)(A), completely removed federal controls 

on new natural gas, except sales for resale of domestic gas 

by interstate pipelines, LDCs or their affi liates. In Order 

No. 636, FERC required interstate pipelines to separate, or 

unbundle, their sales of gas from their transportation service, and to provide comparable transportation service to 

all shippers whether they purchase gas from the pipeline or 

another gas seller. 

Imports and Exports

Natural gas imports play an important role in regional U.S. 

markets, accounting for about 3,800 Bcf, or 11 percent, 

of the natural gas used in the United States in 2011. The 

natural gas pipeline systems of the United States and Canada are integrated, and about 90 percent of imports came 

from Canada, according to the EIA, while 10 percent was 

imported as liquefi ed natural gas (LNG). 

Imported natural gas fl ows into the United States via pipelines at numerous points along the U.S. border with Canada. Imports from Canada have been of strategic importance 

in the Northeast and the West, which were traditionally 

far from the major domestic production centers. However, 

Canadian exports to the United States have been declining as U.S. shale production has increased. Net U.S. gas 

imports have declined from a recent high of 3,785 Bcf in 

2007 to 1,948 Bcf in 2011. EIA estimates that imports will 

continue to decrease as shale-gas production increases. 

The United States also exports natural gas to Canada and 

Mexico, and it still occasionally exports LNG to Japan. 

Liquefi ed Natural Gas

Liquefi ed natural gas (LNG) is natural gas cooled to minus 

260 degrees Fahrenheit to liquefy it, which reduces its volume by 600 times. LNG may be transported in ships and 

trucks to locations not connected by a pipeline network. 

FERC Jurisdiction

The FERC has exclusive authority under the NGA to authorize the siting of facilities for imports or exports of LNG. 

This authorization, however, is conditioned on the applicant’s satisfaction of other statutory requirements for various aspects of the project. In addition, the Department of 

Energy has authority over permits to import and export.

The LNG Supply Chain

Natural gas is sent to liquefaction facilities for conversion 

to LNG. These facilities are major industrial complexes, 

typically costing $2 billion, with some costing as much as 

$20 billion.
 Energy Primer | 19

Once liquefi ed, the LNG is typically transported by specialized ships with cryogenic, or insulated, tanks. 

Once LNG reaches an import (regasifi cation) terminal, it is 

unloaded and stored as a liquid until ready for sendout. To 

send out gas, the regasifi cation terminal warms the LNG 

to return it to a gaseous state and then sends it into the 

pipeline transportation network for delivery to consumers. 

Currently, more than 80 Bcfd of regasifi cation capacity exists globally, more than double the amount of liquefaction 

capacity. Excess regasifi cation capacity provides greater 

fl exibility to LNG suppliers, enabling them to land cargoes 

in the highest-priced markets. This fl exibility has fostered a 

growing spot market for LNG. 

The cost of the LNG process is $2-$4 per million British 

thermal units (MMBtu), depending on the costs of natural gas production and liquefaction and the distance over 

which the LNG is shipped. Liquefaction and shipping form 

the largest portion of the costs. Regasifi cation contributes the least cost of any component in the LNG supply 

chain. The cost of a regasifi cation facility varies considerably; however, the majority of these costs arise from the 

development of the port facilities and the storage tanks. A 

700-MMcfd terminal may cost in the range of $500 million 

to $800 million. 

The various components of the LNG process are broken 

out below.

LNG in the United States

The United States is second to Japan in LNG regasifi cation capacity. As of 2011, there were 11 LNG receiving or 

regasifi cation terminals in the continental United States, 

with approximately 13 Bcfd of import capacity and 79 Bcf 

of storage capacity. All of these facilities are on the Gulf 

or East coasts, or just offshore. In addition, the United 

States imports regasifi ed LNG into New England from the 

Canaport LNG terminal in New Brunswick, Canada, and 

into Southern California from the Costa Azul LNG terminal 

in Mexico’s Baja California. 

Between 2003 and 2008, the United States met 1-3 percent of its natural gas demand through LNG imports, according to the EIA. LNG imports peaked at about 100 Bcf/

month in summer 2007. Growth in relatively low-cost U.S. 

shale gas production has trimmed U.S LNG imports, affecting Gulf Coast terminals the most. Today, most LNG enters 

Production 

&

Transmission 

Liquefaction 

Shipping 

Terminals & 

Regasification

Industrial 

Non-utility 

Generators 

Electric

Utilities

Supply Terminals Marketing & Distribution 

$0.50 - $1.00 $0.90 -

$1.30 $0.40 - $1.40 $0.40

$2.15 - $4.75 

Transport

Source: Drewry Shipping
20 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

the United States under long-term contracts (about half of 

the total) coming through the Everett (Boston) and Elba 

Island (Georgia) LNG terminals. The remainder of the LNG 

enters the United States under short-term contracts or as 

spot cargoes. LNG prices in the United States generally link 

to the prevailing price at the closest trading point to the 

import terminal. During 2011-12, the growth in shale gas 

production led to proposals to export signifi cant volumes 

of domestically produced LNG. Since 1969, small quantities of LNG have been shipped from Alaska to Pacifi c Rim 

countries.

Natural Gas Processing and Transportation

Most domestic natural gas production in the United States 

occurs in regions well away from major population centers. 

To get gas from wellhead to consumers requires a vast network of processing facilities and 2.4 million miles of pipelines. In 2010, this network delivered more than 22 Tcf of 

natural gas to millions of customers. The U.S. natural gas 

system can get natural gas to and from almost any location 

in the Lower 48 states.

Effi cient markets require that this network be robust and 

allow consumers access to gas from more than one production center. Supply diversity tends to improve reliability and 

moderate prices, while constraints increase prices. 

Processing

The midstream segment of the natural gas industry between the wellhead and pipelines is shown in the graphic 
 Energy Primer | 21

below. This segment involves gathering the gas from the 

wellhead, processing the gas to remove liquids and impurities and moving the processed (dry) natural gas to pipelines 

and the extracted liquids to a fractionator that separates 

the liquids into individual components. The liquids are 

used by the petrochemical industry, refi neries and other 

industrial consumers. There were about 500 gas processing 

plants operating in the United States in 2009.

The composition of raw, or wellhead, natural gas differs 

by region. Consequently, processing will differ depending 

on the quality of the natural gas. Natural gas may be dissolved in oil underground but separated out from the oil as 

it comes to the surface due to reduced pressure. In these 

instances, the oil and gas are sent to separate processing 

facilities. Where it does not separate naturally, processing 

is required.

Untreated natural gas usually contains liquids and is generally known as wet gas. Wet gas may contain water, 

water vapor, hydrogen, propane, butane, natural gasoline 

and other components, many of them valuable in other 

consumer and industrial applications. Gas varies widely in 

the amounts of these liquids it contains.

Once a well is completed and gas is fl owing, the gas moves 

into gathering pipelines, which typically are small-diameter 

lines that move the gas from the wellhead to either a processing plant or a larger pipeline.

Processing is required when the natural gas and oil do not 

separate naturally. At the processing plant, wet natural gas 

is dehydrated, and additional products and contaminants 

(such as sulfur and carbon dioxide) are extracted. The hydrocarbon liquids extracted are known as natural gas liquids (NGL). Many of these are high-value products used in 

petrochemical applications. Once processing extracts the 

NGL, the stream is separated into individual components 

by fractionation, which uses the different boiling points of 

the various hydrocarbons to separate them. Once processing is completed, the gas is of pipeline quality and is ready 

to be moved by intrastate and interstate pipelines.

FERC Jurisdiction

The Natural Gas Act (NGA), 15 U.S.C. § 717 et. seq., gives 

the FERC comprehensive regulatory authority over companies that engage in either the sale of natural gas for resale 

or its interstate transportation. The Commission regulates 

market entry through Section 7 of the NGA, 15 U.S.C. § 

717f, by issuing certifi cates of public convenience and 

necessity, subject to such conditions as the Commission 

deems appropriate, authorizing natural gas companies to 

transport or sell natural gas. To this end, the FERC reviews 

applications for the construction and operation of interstate natural gas pipelines. In its application review, the 

FERC ensures that the applicant has certifi ed that it will 

comply with Department of Transportation safety standards. The FERC has no jurisdiction over pipeline safety or 

security, but actively works with other agencies with safety 

and security responsibilities. The Commission regulates 

market exit through its authority to abandon certifi cated 

service, 15 U.S.C. § 717f(b).
22 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Natural Gas Transportation

Interstate pipelines account for 71 percent of the natural 

gas pipeline miles in the United States and carry natural 

gas across state boundaries. Intrastate pipelines account 

for the remaining 29 percent, and have similar operating 

and market characteristics. 

The interstate network moves dry natural gas from producing areas to local distribution companies (LDCs), large 

industrial customers, electric power plants and natural gas 

storage facilities. The pipelines, which range in diameter 

from 16 inches to as large as 48 inches, move gas between 

major hubs to lateral lines. Laterals, which range in diameter from 6 inches to 16 inches, distribute gas to retail 

customers. 

The large pipelines are known as mainline transmission 

pipelines. The line pipe used for major pipelines typically 

consists of strong carbon steel suffi cient to meet standards set by the American Petroleum Institute. Line pipe 

is coated to reduce corrosion. Smaller distribution lines, 

which operate under much lower pressures, may be made 

of plastic materials, which provide fl exibility and ease of 

replacement.

Nearly one-fi fth of all natural gas transmission pipelines, 

by mileage, are located in Texas. More than half are located in nine states: Texas, Louisiana, Kansas, Oklahoma, 

California, Illinois, Michigan, Mississippi and Pennsylvania.

Compressor stations, located every 50-100 miles along 

the pipe, add to or maintain the pressure of the natural 

gas, propelling it down the pipeline. Natural gas travels 

through pipelines at high pressures, from 200 pounds per 

square inch (psi) to 1,500 psi.

The gas is compressed by turbines, motors or engines. Turbines and reciprocating natural gas engines use some of 

the gas from the line to fuel their operations; electric motors rely on electricity. 

Metering stations are placed along the pipelines to measure 

the fl ow of natural gas as it moves through its system.

Movement of natural gas along a pipeline is controlled in 

part by a series of valves, which can be opened to allow 

the gas to move freely or closed to stop gas fl ow along a 

section of pipe. Large valves may be placed every 5 to 20 

miles along the pipeline.

Pipeline operators use supervisory control and data acquisition (SCADA) systems, to track the natural gas as it travels 

Natural Gas Infrastructure

The United States natural gas market is 

accommodated by extensive infrastructure:

• Roughly 306,000 miles of wide-diameter, high 

pressure inter- and intrastate pipelines make up 

the mainline pipeline transportation network, run 

by more than 210 companies. 

• More than 1,400 compressor stations maintain 

pressure on the natural gas pipeline network.

• More than 5,000 receipt points, 11,000 delivery 

points and 1,400 interconnection points implement the fl ow of gas across the United States.

• Nearly three dozen hubs or market centers provide 

addition interconnections.

• 400 underground natural gas storage facilities 

increase the fl exibility of the system.

• 49 locations enable natural gas to be imported or 

exported via pipelines.

• There are 11 LNG import facilities and100 LNG 

peaking facilities (stored gas held for peak demand periods).

• More than 1,300 local distribution companies 

deliver natural gas to retail customers.

Source: EIA
 Energy Primer | 23

Natural Gas Transportation System

through their systems. SCADA is a centralized communication system that collects, assimilates and manages the 

meter and compressor station data. SCADA also conveys 

this information to the centralized control station, allowing pipeline engineers to know what is happening on the 

system at all times.

As the product moves closer to the consumption areas, it 

may be stored in underground facilities. Plentiful storage capacity adds fl exibility to the pipeline and distribution 

systems and helps moderate prices by providing an outlet 

for excess gas during periods of low demand, and readily 

accessible supply in periods of high demand. Some natural 

gas can also be stored in the pipelines as linepack, in which 

more molecules of gas are held in a segment of pipeline 

under greater-than-normal pressure.

Hubs

A key part of the pipeline distribution network is the natural gas hub. Typically, a hub is a specifi c point where pipeline interconnections allow the transfer of gas from one 

pipeline to another. 

There are dozens of natural gas hubs in the country, with 

about 20 considered major hubs. Henry Hub is the dominant benchmark point in the physical natural gas market 

because of its strategic location in the Gulf Coast’s producing area and the number of pipeline connections to 

the East Coast and Midwest consumption centers. It sits in 

southcentral Louisiana, in the town of Erath, where more 

than a dozen major natural gas pipelines converge and exchange gas. The Henry Hub has 12 delivery points and 4 

major receipt points. 
24 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Gas as a physical product can be bought and sold at 

Henry Hub or other hubs around the country in daily and 

monthly markets. In addition, the New York Mercantile Exchange (Nymex) established a futures contract centered at 

the Henry Hub in 1990 that gained widespread acceptance 

and is generally used as the reference price for natural gas 

in the United States. 

Distribution lines typically take natural gas from the large 

transportation pipelines and deliver the gas to retail customers. While some large consumers – industrial and electric generation, for example – may take service directly off 

a transmission pipeline, most receive their gas through their 

local gas utility, or local distribution company (LDC). These 

companies typically purchase natural gas and ship it on behalf of their customers, taking possession of the gas from 

the pipelines at local citygates and delivering it to customers at their meters. This distribution involves a network of 

smaller pipelines – more than two million miles, according 

to the U.S. Department of Transportation.

FERC Jurisdiction

The NGA, 15 U.S.C. § 717, et seq., requires that natural gas 

companies charge just and reasonable rates for the transportation and sale of natural gas. To promote compliance 

with this mandate, the NGA requires gas pipelines to fi le 

rate schedules with the FERC and to notify the FERC of any 

subsequent changes in rates and charges. On submission 

of a tariff revision, the FERC may hold a hearing to determine whether the pipeline has met its burden to show that 

the amended rates and charges are just and reasonable.

Under Sections 4 and 5 of the NGA, 15 U.S.C. §§ 717c 

and 717d, the Commission regulates the rates and other 

terms of jurisdictional sales and transportation, ensuring 

that rates and charges for such service, as well as all rules, 

regulations, practices, and contracts affecting those rates 

and charges, are just and reasonable and not the product 

of undue discrimination. 15 U.S.C. §§ 717c(a) and (b).
 Energy Primer | 25

Pipeline Services

Customers or shippers have a choice between two general types of service on interstate pipelines. The fi rst is 

fi rm transportation capacity, or primary market service, in 

which an agreement is executed directly between the pipeline and a customer for a year or more, relying on primary 

receipt and delivery points. Firm transportation service is 

not bumped for other classes of service, and it receives the 

same priority as any other class of fi rm service.

The second type of transportation service a shipper can 

contract for is interruptible transportation service. Interruptible transportation service is offered to customers under schedules or contracts on an as-available basis. This 

service can be interrupted on a short notice for a specifi ed 

number of days or hours during times of peak demand or 

in the event of system emergencies. In exchange for interruptible service, customers pay lower prices.

A secondary market for fi rm transportation rights enables 

shippers to sell their pipeline capacity to a third party 

through the FERC’s capacity release program. Services offered in the primary market can be offered in the secondary market by the holder of the primary service. Released 

capacity offers market participants the opportunity to buy 

and sell from each other as well as from the pipeline. This 

can be broken down into segments: holders of primary 

capacity can release segments rather than their full holdings, provided segmentation is operationally feasible on the 

interstate pipeline’s system. 

Interstate pipelines also provide “no-notice service” under 

which fi rm shippers may receive delivery up to their fi rm 

entitlements on a daily basis without penalty. If a shipper 

has fi rm storage and transportation service, that shipper 

can schedule in the day-ahead market and yet have the 

ability and the right to physically take a different quantity than what was scheduled without incurring imbalance 

penalties. No-notice service is particularly valuable during periods of high demand when transportation capacity 

may be completely used. This service is especially helpful 

to LDCs that must serve their load without knowing their 

exact load level each day. No-notice service is generally 

priced at a premium to fi rm transportation service. Shippers may temporarily release this service to other parties, 

using FERC-approved capacity release guidelines. 

Interstate Transportation Rates

Pipeline transportation rates can be priced on zones or 

miles, or be a fi xed postage stamp rate. In zonal pricing, 

the price of transportation varies by the location of the 

receipt and delivery points, across a series of zones. 

Under postage stamp rates, shippers pay the same rate 

for transportation regardless of how far the gas is moved, 

similar to the way a postage stamp costs the same amount 

regardless of whether a letter is sent to New York or California. Pipelines using postage stamp rates include Northwest Pipeline, Colorado Interstate Gas and Columbia Gas 

Transmission.

With mileage-based rates, shippers pay based on the distance between where the gas enters the pipeline and where 

it is taken out of the pipeline. The rate is designed to 

refl ect the distance involved in transporting the gas. Gas 

Transmission Northwest (GTN) uses mileage-based rates. 

Other pipelines use hybrid or mixed-rate systems. Northern 

Natural Gas, for example, uses a combination zonal rate 

for upstream receipts and a postage stamp rate for market 

area deliveries.

Scheduling

Pipelines have rigorous schedules that shippers must follow. 

Typically, shippers nominate gas in the day-ahead market, 
26 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

and may update their nominations at various points during 

the day in which the natural gas fl ows (see Pipeline Capacity Scheduling graphic below).

Pipeline Usage or Load Factor

Load factor measures the use of a pipeline network. It is 

the average capacity used at a given point or segment relative to a measurement of maximum or peak available capacity. Customers with a 100 percent load factor use their 

maximum capacity every day; one with a 50 percent load 

factor uses its capacity only half the time. Different types 

of customers use pipeline capacity differently. Historically, 

industrial customers have exhibited high load factors and 

residential customers that primarily rely upon seasonal gas 

to heat homes have had lower load factors. 

Pipelines are accustomed to serving different demands, 

which can affect how much of their capacity is used at 

various times. For example, Kern River Gas Transmission 

has operated at around 93 percent of capacity since 2005, 

while Algonquin Gas Transmission’s capacity factor is considerably less. Algonquin’s pipeline is used more seasonally 

than Kern River’s, refl ecting the seasonal demand in the 

Northeast.

Park and Loan Service

Park and loan service (PAL) is a way for shippers to balance 

their takes of gas with their supply, by providing a shortterm load-balancing service to help shippers meet their 

load. Using the PAL service, shippers can take less gas than 

scheduled, thus parking their excess supply in the pipeline 
 Energy Primer | 27

at times when the demand is lower than anticipated. If 

demand is higher than expected, shippers can adjust their 

take upward, in effect borrowing gas from the pipeline. 

PAL characteristics include:

• Park and loan services typically generate low revenue 

and are offered with the lowest service level priority 

among all pipeline services. 

• Rates are based on costs associated with providing the 

services, such as plant costs if the services are offered.

• Market centers, or hubs, routinely offer these services.

• Charges are usually commensurate with interruptible 

service rates.

• Pipelines earn minimal revenue from park and loan. 

Pipeline Constraints and Capacity Growth

Pipeline capacity limits the supply that can be delivered to 

a specifi c region and is, therefore, a key factor in regional 

prices.

In recent years, the natural gas pipeline network has expanded signifi cantly, removing bottlenecks and providing 

access to previously unreached supply areas. 

A considerable amount of new pipeline capacity has been 

added in recent years to the Northeast. In 2008 and 2009, 

the region added 5.6 Bcfd in pipeline capacity. In 2010, it 

added another 1.2 Bcfd. Much of this new capacity was 

targeted at improving access to shale gas. 

One of the largest additions to the natural gas infrastructure came with the completion of the 1.8-Bcfd Rockies Express Pipeline (REX) that moves natural gas from Wyoming 

to eastern Ohio. REX serves the dual role of relieving pipeline constraints that bottled up production in the Rockies 

and depressed prices there, while at the same time relieving constraints that increased prices in the East. Increased 

gas fl ows from the Rockies over REX, coupled with new 

shale supplies, have reduced prices in the Midcontinent and 

Northeast.

Meanwhile, Rockies producers saw a rise in prices. The 

Rockies gas fl owing eastward displaced gas from the Permian Basin. The Permian gas, in turn, began moving to the 

Southern California market. Consequently, regional price 

differences moderated. 

Other smaller projects had similar effects. New pipelines to 

increase the fl ow of Barnett Shale gas into the interstate 

network have had a secondary effect of reducing congestion across the Texas-Louisiana border. 

The Florida Panhandle and Northern California used to 

be some of the most frequently constrained regions of 

the country, but each has received signifi cant new pipeline 

capacity. Expansion of Florida Gas Transmission in 2011 

added about 800 MMcfd, a boost of 33 percent, of gas 

transmission capacity to peninsular Florida. The 680-mile, 

42-inch-diameter Ruby Pipeline, which began operations 

in 2011, now fl ows Rockies gas from Opal, Wyo., to Malin, 

Ore.

Local Distribution

Distribution lines typically take natural gas from the large 

interstate pipelines and deliver the gas to retail customers. While some large consumers – industrial and electric 

generators, for example – may take service directly off an 

interstate pipeline, most receive their natural gas through 

their LDC. LDCs typically purchase natural gas and ship 

it on behalf of their customers. They take possession of 

the natural gas from interstate pipelines at local citygates 

and deliver the natural gas to their customers at the customer’s meter. According to the United States Department 

of Transportation’s Pipeline and Hazardous Materials Safety Administration, this distribution involves a network of 
28 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

smaller pipelines totaling more than two million miles, as 

well as smaller scale compressors and meters.

Some states allow competition in natural gas service at the 

local level. In these circumstances, natural gas marketers 

purchase the natural gas and arrange for it to be shipped 

over both the interstate pipeline network and the local distribution pipeline system.

Storage

Natural gas production remains relatively unchanged dayto-day throughout the year, and recently has been around 

60 Bcfd. Demand, however, changes considerably with the 

seasons. Natural gas storage enables producers and purchasers to store gas during periods of relatively low demand – and low prices – then withdraw the gas during 

periods of relatively higher demand and prices.

Typically, the amount stored or withdrawn is the difference 

between demand and production. This differs from storage capacity – the maximum amount that can be stored at 

any point in time. Working gas storage capacity, as tracked 

by EIA, is more than 4,100 Bcf. Gas may be stored in 

underground facilities. Storage capacity adds fl exibility 

to pipeline and distribution systems and helps moderate 

prices by providing an outlet for excess gas during periods 

of low demand. Storage facilities also provide a readily accessible supply in periods of high demand. Some natural 

gas can also be stored in the pipelines as linepack, in which 

more molecules of gas are held in a segment of pipeline 

under greater-than-normal pressure.

EIA’s weekly storage report provides a low-resolution snapshot of the natural gas supply and demand balance. EIA 

releases its storage report at 10:30 a.m. on Thursdays. The 

price for natural gas futures can change dramatically within 

seconds when the report comes out. If the reported injection or withdrawal signifi cantly differs from market expectations, the price for natural gas futures may rise or fall.

Storage Facilities

The bulk of the storage capacity in the United States is below ground; differing cost and operational characteristics 

affect how each facility is used: 

• Deliverability rate is the rate at which inventory can be 

withdrawn. The faster the natural gas can be removed 

from storage, the more suitable the storage facility is 

to helping serve rapidly changing demand.

• Cycling capability is the ability of the resource to 

quickly allow injections and withdrawals, which is 

useful for balancing supply and demand. Salt caverns 

tend to have high withdrawal and injection rates, enabling them to handle as many as a dozen withdrawal 

and injection cycles each year. LNG storage also demonstrates these capabilities.

Natural gas in an underground storage facility is divided 

into two general categories, working gas and base gas. 

Base gas is the volume of natural gas, including native 

gas, needed as a permanent inventory in a storage reservoir 

to maintain adequate reservoir pressure and deliverability 

rates throughout the withdrawal season. Working gas is 

the volume of gas in the reservoir above the designed level 
 Energy Primer | 29

Types of Underground Storage Facilities

A. Salt Caverns

B. Mines

C. Aquifers

D. Depleted Reservoirs

E. Hard-rock Caverns Source: PB-KBB, Inc.

ity more sensitive to withdrawal and injection patterns, so 

inventory usually turns over just once a year. 

Salt cavern formations exist primarily in the Gulf Coast region. These air- and water-tight caverns are created by 

removing salt through solution-mining, leaving a cavern 

that acts as a pressurized vessel. Little base gas is required, 

which allows inventory to turn over as many as a dozen 

times during the year, and results in high injection and 

withdrawal rates. This fl exibility has attracted new development, resulting in salt cavern storage growth over the 

past decade. Salt caverns generally hold smaller volumes 

than do depleted-reservoir or aquifer gas storage facilities.

Natural gas may also be stored in above-ground tanks as 

LNG. There is LNG storage at all of the onshore LNGreceiving terminals, and there are about a hundred standalone LNG storage facilities in the United States, as well. 

Occasionally, LNG ships also provide storage. LNG storage 

of base gas and that can be extracted during the normal 

operation of the storage facility.

Most of the nation’s gas storage is in depleted reservoirs 

(former oil and gas fi elds). These facilities reuse the infrastructure – wells, gathering systems and pipeline connections – originally created to support the fi eld when it was 

producing. About 50 percent of total capacity goes to base 

gas used to maintain operating pressure at the facility, and 

inventory usually turns over once or twice a year.

Other storage facilities reside in aquifers that have been 

transformed into gas storage facilities. These are mostly 

in the Midwest. These aquifers consist of water-bearing 

sedimentary rock overlaid by an impermeable cap rock. 

Aquifers are the most expensive type of natural gas facility 

because they do not have the same retention capability as 

depleted reservoirs. Therefore, base gas can be well over 

50 percent of the total gas volume. This makes the facil-
30 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Storage Service and Uses

Approximately 120 entities – including interstate and intrastate pipeline companies, LDCs and independent storage service providers – operate the nearly 400 underground 

storage facilities active in the continental United States, 

the EIA says. Facilities operated by interstate pipelines and 

many others are operated on an open-access basis, with 

much of the working gas capacity available for lease on a 

nondiscriminatory basis.

The ability to store large quantities of natural gas improves 

reliability and usually has a moderating infl uence on natural 

gas prices. Storage inventory augments gas supply during 

the winter, but acts as an additional demand component 

during the summer injection season. The storage injection 

season typically starts April 1 and continues through Oct. 

31, when demand for gas heating is lowest. Storage withdrawals generally start in November and last throughout 

the winter. 

 

The ability to use storage to provide for winter peaks creates an intrinsic storage value. This is the value from 

buying during cheaper periods of the year for use during 

higher-cost seasons. Depleted reservoirs or aquifers – with 

limited ability to turn over inventory – support this type of 

use. Local distribution companies or pipelines store their 

gas in these facilities to ensure adequate supplies for peak 

seasons, balance load and diversify their resources.

Storage may be priced at cost-based or market-based rates. 

Pricing mechanisms for low-cycling depleted fi elds and 

aquifers may use a traditional cost-of-service structure, 

including:

• capacity charges for fi rm contract rights to physical 

storage capacity;

• deliverability charges for transportation to and from 

the storage facility;

is highly fl exible, allowing multiple inventory turns per year 

with high injection and withdrawal rates.

Regional Storage

For storage purposes, the EIA has divided the United States 

into three regions: producing, East and West. Just over 

half of the underground storage in the United States, 2,200 

Bcf, sits in the East, near population centers. Much of 

this is in aquifers and depleted fi elds. Almost 1,300 Bcf 

sits in the producing region, which has not only depleted 

fi elds but also the greatest concentration of more-fl exible 

salt cavern storage. The remaining 550 Bcf is in the West, 

primarily in depleted fi elds. Of this total working gas capacity of more than 4,100 Bcf, at the begining of winter 

there will be 3,900 Bcf or more of gas injected into storage, making it about 95 percent full as the winter heating 

season begins.
 Energy Primer | 31

• withdrawal charges for the removal of gas from storage; and

• injection charges for the injection of gas into storage.

A salt cavern, with its ability to turn over inventory frequently and quickly, allows for additional uses, enabling 

users to capture extrinsic value. Many salt dome facilities 

can cycle between injection and withdrawal at almost a 

moment’s notice, giving users greater fl exibility. Entities 

leasing storage capacity may move gas in and out of storage as prices change in attempts to maximize profi ts or 

minimize costs. Storage may be a component in producer 

or consumer hedging strategies, helping them to manage 

the risk of price movements. Further, storage helps shippers avoid system imbalances and associated penalties, and 

supports swing gas supply services, which are short-term 

contracts that provide fl exibility when either the supply of 

gas from the seller, or the demand for gas from the buyer, 

are unpredictable. Storage also facilitates title transfers 

and parking and lending services – interruptible service by 

which the customer injects or withdraws gas for a short period of time, usually a month. This helps shippers balance 

daily receipts and deliveries, manage their overall supply 

portfolio or take advantage of price movements. Consequently, storage operators have begun offering a more varied menu of services, and users have begun using storage 

as a commercial tool and as part of a comprehensive supply 

portfolio strategy. 

Merchant storage, frequently using salt caverns, uses market-based prices, recognizing the dynamics affecting value 

at any given point in time. Prices often take into account 

the prices at which the Nymex futures contracts are trading. They may also refl ect the storage volume, the number 

of times the gas will be cycled, the length of the contract 

and the timeframe it covers and the maximum daily quantity that may be injected or withdrawn. Energy marketers 

have increasingly used these facilities as they try to profi t 

from price volatility. It is also attractive to shippers, industrial consumers with uncertain loads and gas-fi red generators whose needs change rapidly.

Pipelines also offer storage service, both fi rm and interruptible, as part of their open access transportation service 

under FERC rules. Rates are rarely market-based. Instead, 

prices are based on cost of service, with rates containing 

reservation and usage components for fi rm service and a 

usage component for interruptible.

Market Effects

Storage can mitigate large seasonal price swings by absorbing natural gas during low demand periods and making it 

available when demand rises. 

Further, storage levels can affect the market’s expectations about prices during the coming winter high-demand 

season. The amount of gas in storage in November is a 

key benchmark of the gas industry’s ability to respond to 

changes in winter weather. Higher storage levels tend to 

reduce forward prices; lower storage levels tend to increase 

them, all other market conditions being equal. 

FERC Jurisdiction

The underground storage of natural gas has historically 

been critical in assuring that the needs of natural gas customers are met. The Energy Policy Act of 2005 added a 

new section to the Natural Gas Act stating that the Commission may authorize natural gas companies to provide 

storage and storage-related services at market-based rates 

for new storage capacity, even though the company cannot 

demonstrate it lacks market power. To make this authorization, the FERC must determine that market-based rates 

are in the public interest and are needed to encourage the 

construction of the capacity and that customers are adequately protected.
32 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Natural Gas Pricing and Trading

The natural gas industry in the United States is highly competitive, with thousands of producers, consumers and intermediate marketers. Some producers have the ability to 

market their natural gas and may sell it directly to local 

distribution companies (LDCs), to large industrial buyers 

and to power plants. Other producers sell their gas to marketers who aggregate natural gas into quantities that fi t 

the needs of different types of buyers and then transport 

the gas to their buyers. 

Most residential and commercial customers purchase natural gas from a LDC. In contrast, many industrial customers 

and most power plants have the option to purchase natural 

gas from a marketer or producer instead of from the LDC, 

thereby avoiding any LDC charges.

Interstate pipelines do not buy and sell natural gas and are 

limited to providing transportation services only, including 

storage. As noted, interstate pipelines transport natural 

gas at rates approved by the FERC. 

Natural Gas Marketers

Most gas trading in the United States is performed by 

natural gas marketers. Any party engaging in the sale of 

natural gas can be termed a marketer; however, marketers 

are usually specialized business entities dedicated solely to 

transacting in the physical and fi nancial energy markets. 

It is commonplace for natural gas marketers to be active 

in a number of energy markets, taking advantage of their 

knowledge of these markets to diversify their business.

Marketers can be producers of natural gas, pipeline marketing affi liates, LDC marketing affi liates, independent marketers or large-volume users of natural gas. Some marketing companies may offer a full range of services, marketing 

numerous forms of energy and fi nancial products, while 

others may be more limited in their scope. For instance, 

most marketing fi rms affi liated with producers do not sell 

natural gas from third parties; they are more concerned 

with selling their own production and hedging to protect 

their profi t margin from these sales.

There are fi ve classifi cations of marketing companies: major nationally integrated marketers, producer marketers, 

small geographically focused marketers, aggregators and 

brokers. 

The major nationally integrated marketers offer a full range 

of services, and market numerous different products. They 

operate on a nationwide basis, and have large amounts of 

capital to support their trading and marketing operations. 

Producer marketers are those entities generally concerned 

with selling their own natural gas production or the production of their affi liated natural gas production company. 

Smaller marketers target particular geographic areas and 

specifi c natural gas markets. Many marketing entities affi liated with LDCs are of this type, focusing on marketing gas 

for the geographic area in which their affi liated distributor 

operates. Aggregators generally gather small volumes from 

various sources, combine them and sell the larger volumes 

for more favorable prices and terms than would be possible selling the smaller volumes separately. Brokers are a 

unique class of marketers in that they never take ownership 

of natural gas themselves. They simply act as facilitators, 

bringing buyers and sellers of natural gas together.

All marketing companies must have, in addition to the 

core trading group, signifi cant backroom operations. These 

support staff are responsible for coordinating everything 

related to the sale and purchase of physical and fi nancial 

natural gas, including arranging transportation and storage, posting completed transactions, billing, accounting 

and any other activity that is required to complete the purchases and sales arranged by the traders. 
 Energy Primer | 33

In addition to the traders and backroom staff, marketing 

companies typically have extensive risk-management operations. The risk-management team is responsible for ensuring that the traders do not expose the marketing company 

to excessive risk. 

Market Hubs

Natural gas is priced and traded at different locations 

throughout the country. These locations, referred to as 

market hubs, exist across the country and are located at 

the intersection of major pipeline systems. There are more 

than 30 major market hubs in the United States, the principal one of which is known as the Henry Hub, located at 

Erath, in southern Louisiana. The price at which natural 

gas trades differs across the major hubs, depending on the 

supply and demand for natural gas at that particular point. 

The difference between the Henry Hub price and another 

hub is called the location differential, or basis. In addition to market hubs, other major pricing locations include 

citygates. Citygates are the locations at which distribution 

companies receive gas from a pipeline. Citygates at major metropolitan centers can offer another point at which 

natural gas is priced.

The most important market hub and pricing point in the 

United States is the Henry Hub, which is run by Sabine Pipe 

Line LLC and is a major intersection of pipelines. It has 12 

delivery points and 4 major receipt points, all at that one 

hub, making it a crossroads for signifi cant amounts of gas 

moving to locations across the country. The Henry Hub 

is also the delivery point for the New York Mercantile Exchange (Nymex) natural gas futures contract. Changes in 

price at Henry Hub provide a good indicator of how prices 

are generally changing across the country. 

Basis usually refl ects the variable cost to transport gas between Henry and another hub. Basis can change, sometimes dramatically, depending on local market conditions, 

and can widen considerably when pipelines between two 

points are congested. Basis in excess of transportation 

costs results from pipeline constraints and lack of pipeline competition. The gas price at a hub in Florida, for 

example, would be the price at Henry Hub and the basis to 

the Florida hub. 

Physical Trading

Physical trading contracts are negotiated between buyers 

and sellers. There are many types of physical trading contracts, but most share some standard specifi cations, including specifying the buyer and seller, the price, the amount 

of natural gas to be sold (usually expressed in a volume 

per day), the receipt and delivery point, the tenure of the 

contract (usually expressed in number of days beginning 

on a specifi ed day) and other terms and conditions. The 

special terms and conditions usually outline such things 

as the payment dates, quality specifi cations for the natural 

gas to be sold and any other specifi cations agreed to by 

both parties.

Physical contracts are negotiated between buyers and 

sellers over the phone or executed on electronic bulletin 

boards and e-commerce trading sites.
34 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

There are three main types of physical trading contracts: 

swing contracts, baseload contracts and fi rm contracts:

• Swing (or interruptible) contracts are usually shortterm contracts, and can be as short as one day and are 

usually not longer than a month. These contracts are 

the most fl exible, and are usually put in place when 

either the supply of gas from the seller, or the demand 

for gas from the buyer, are unreliable.

• Baseload contracts are similar to swing contracts. Neither the buyer nor seller is obligated to deliver or receive the exact volume specifi ed. However, it is agreed 

that both parties will attempt to deliver or receive the 

specifi ed volume, on a best-efforts basis. 

• Firm contracts are different from swing and baseload 

contracts in that both parties are legally obligated to 

either receive or deliver the amount of gas specifi ed in 

the contract. These contracts are used primarily when 

both the supply and demand for the specifi ed amount 

of natural gas are unlikely to change.

Price Discovery

Spot (Cash) Market

The U.S. natural gas marketplace has a highly competitive 

spot, or cash, market where brokers and others buy and 

sell natural gas daily. The daily spot market for natural 

gas is active, and trading can occur 24 hours a day, seven 

days a week. The map on the next page shows some of 

the points where natural gas for next-day physical delivery 

is actively traded on the IntercontinentalExchange (ICE). 

Some of these points are market centers, where brokers actively trade and prices are established. In addition to these 

market centers, natural gas is actively traded at many other 

locations, including segments of individual pipelines and 

locations where pipelines interconnect with LDCs.

Spot market transactions are normally conducted on electronic exchanges or by telephone, with the buyer agreeing 

to pay a negotiated price for the natural gas to be delivered 

by the seller at a specifi ed delivery point. Natural gas spot 

prices refl ect daily supply and demand balances and can 

be volatile. 

Bidweek

The largest volume of trading occurs in the last fi ve business days of a month, known as bidweek. This is the week 

when producers are trying to sell their core production and 

consumers are trying to buy for their core natural gas needs 

for the upcoming month. The core natural gas supply or 

demand is not expected to change; producers know they 

will have that much natural gas over the next month, and 

consumers know that they will require that much natural 

gas over the next month. The average prices set during bidweek are commonly the prices used in physical contracts.

Index Prices

Frequently the prices in longer-term contracts are indexed 

to prices that are regularly published in the trade press. 

Several publications, such as Gas Daily, Natural Gas Intelligence and Natural Gas Week, survey the market for daily 

transaction prices that are used to form and publish a daily 

index that is made available the night before or the morning of the next business day. Many market participants also 

report their bidweek prices to publications, which convert 

these prices into monthly locational price indexes that are 

available on the fi rst business day following the last day 

of bidweek. These daily and monthly indexes, in turn, are 

used as the basis for pricing for those fi rms that do not 

choose to enter into fi xed-price contracts (or are prohibited 

from using them by state or local regulators).
 Energy Primer | 35

The Financial Market

In addition to trading physical natural gas, there is a signifi cant market for natural gas derivatives and fi nancial 

instruments in the United States. In the fi nancial market, market participants are interested in profi ting from the 

movement of the price of natural gas rather than delivering 

or receiving natural gas. The pricing and settlement of 

these fi nancial products are tied to physical natural gas. It 

is estimated that the value of trading that occurs on the 

fi nancial market is at least a dozen times greater than the 

value of physical natural gas trading.

Derivatives are fi nancial instruments that derive their value 

from an underlying fundamental – in this case, the price of 

natural gas. Derivatives can range from being quite simple 

to being exceedingly complex. Traditionally, most derivatives are traded on the over-the-counter (OTC) market, 

which is essentially a group of market players interested in 

exchanging certain derivatives among themselves.

More information on fi nancial markets appears in Chapter 

4.

130 Hubs for Physical Trading on ICE

Source: IntercontinentalExchange Source: InterContinental Exchange

 Energy Primer | 37

Overview

Electricity is a physical product – the fl ow of electrons. 

It is a secondary energy source in that it results from the 

conversion of other energy forms such as natural gas, coal 

or uranium, or the energy inherent in wind, sunshine or the 

fl ow of water in a river. It may not be visible, but it can be 

turned on and off and measured. 

Quick Facts: Measuring Electricity

Electricity is measured in terms of watts,

typically in kilowatts (1,000 watts) or megawatts

(1,000 kilowatts).

A kilowatt (or watt or megawatt) is the amount

of energy used, generated or transmitted at

a point in time. The aggregation of kilowatts

possible at a point in time for a power plant,

for example, is its capacity. The aggregation of

kilowatts used at a point of time is the demand

at that point.

The number of kilowatts used in an hour

(kilowatt-hour or kWh) is the amount of

electricity a customer uses or a power plant

generates over a period of time. Kilowatt-hours

are used to bill customers.

Electric markets have retail and wholesale components. 

Retail markets involve the sales of electricity to consumers; wholesale markets typically involve the sales of electricity among electric utilities and electricity traders before 

it is eventually sold to consumers. This paper focuses 

on wholesale markets, although it addresses retail demand 

and other instances where retail markets strongly infl uence 

wholesale markets.

Much of the wholesale market and certain retail markets 

are competitive, with prices set competitively. Other prices 

are set based on the service provider’s cost of service. For 

wholesale markets, FERC either authorizes jurisdictional 

entities to sell at market-based rates or reviews and authorizes cost-based rates. 

In competitive markets, prices refl ect the factors driving 

supply and demand – the physical fundamentals. In markets where rates are set based on costs, these fundamentals 

matter as well. Supply incorporates generation and transmission, which must be adequate to meet all customers 

demand simultaneously, instantaneously and reliably. 

Consequently, key supply factors affecting prices include 

fuel prices, capital costs, transmission capacity and constraints and the operating characteristics of power plants. 

Sharp changes in demand, as well as extremely high levels 

of demand, affect prices as well, especially if less-effi cient, 

more-expensive power plants must be turned on to serve 

load. 
38 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Background

Electricity on Demand

In the United States and other developed countries, consumers expect electricity to be available whenever they 

need it. Electricity use has grown enormously as consumers now consider not only refrigerators, TVs and hair dryers but also computers, iPods and other electronic devices 

as necessities. Consumers also expect to pay reasonable 

prices for the electricity they use. 

Meeting these customer expectations is challenging. With 

few exceptions, electricity cannot be stored, in any appreciable quantities, and thus must be produced as needed. 

Further, unlike most other markets, electricity’s historical 

inelastic demand does not move with prices. To provide 

electricity on demand, electric system operations have to 

be planned and conducted with that goal in mind. Lacking storage and responsive demand, operators must plan 

and operate power plants and the transmission grid so that 

demand and supply exactly match, every moment of the 

day, every day of the year, in every location. 

The Drive for Enhanced Value

The electric industry has met this growing demand with increasing effi ciency. Between 1929 and 1967, the national 

average cost of electricity for residential customers plummeted from about 60¢/kWh to 10¢/kWh (in 2005 dollars), 

and remains around there today. How did the industry 

achieve such tremendous cost savings and then keep the 

real price of electricity fl at over the past 40 years? Part can 

be explained by greater effi ciency – power plants use less 

fuel, and new techniques make it cheaper to extract the 

coal and natural gas that fuels generators. Another part 

of the answer, though, stems from changes in the way the 

industry is organized and operated.

Economies of Scale

Electric power is one of the most capital intensive industries. Generation alone can account for roughly 65% of 

a customer’s electric bill. Spreading these relatively fi xed 

costs over more customers helps bring down the cost that 

each customer pays. 

Thomas Edison’s fi rst street lighting project in the 1880s 

grew to electrifying whole neighborhoods, towns and cities. 

Providing service over larger areas allowed utilities economies of scale in generating technology. The cost per unit 

of production dropped as power plants grew larger and 

larger. The companies building these facilities were basically self-contained – they owned and operated the generation, transmission and distribution facilities. Power lines 

were built from their generation to their population, or 

load, centers. These companies were vertically integrated.

One downside of larger generating units is that they are 

diffi cult to replace if they experience unexpected shutdowns. For a single utility building a new and larger unit, 

the only way to ensure reliable service is to build two units 

– creating a capacity reserve. When coal and nuclear unit 

sizes grew to 500 or 1,000 MW, building two units became 

very expensive for any individual company.

Reserve Sharing, Interconnection and Power Pools

The solution to high reserve costs was to share reserves 

with adjacent utilities. Instead of building two large units, 

utilities could buy from their neighbors in times of need, 

and cut their costs signifi cantly. To facilitate reserve sharing, utilities built major interconnecting transmission lines 

large enough to deliver power in case of a major generator 

outage. Today’s bulk power grid began as a way to maintain reliable service while lowering costs.

As more utilities share reserves, the smaller the reserves each 
 Energy Primer | 39

must carry, and the lower the costs. The value of reservesharing agreements led to the formation of power pools, 

the forerunners of today’s regional transmission organizations (RTOs).

Coordinating reserves also led to closer coordination of 

other utility functions, such as the process of determining 

which generating units to use, called unit commitment. 

Operators want to commit just enough capacity for the 

next day to ensure reliability but no more than needed, to 

minimize costs. This began a new phase of using economies of scale in system operations encompassing whole regions of the country.

Regional coordination also was spurred by special circumstances, particularly in the West. Large federally owned 

dams on the Columbia and Colorado rivers generate power 

from the spring runoff of melting mountain snow. When 

the reservoirs are full and the turbines are spinning, there 

is not enough local demand to use the power. Since the 

hydropower was cheaper than any alternative, long distance transmission lines were built to deliver the excess 

power from the Northwest and Southwest to load centers 

in California.

With the transmission interconnections in place, northwestern utilities found that they could get cheaper power 

from southern power generation at other times of the year. 

These seasonal and regional disparities in availability and 

price provide for a lively bilateral trading market.

In the 1960s, the electric industry created an informal, voluntary organization of operating staff to aid in coordinating the bulk power system. Then, in 1965, the largest 

power blackout until that time hit the northeastern United 

States – including New York – and southeastern Ontario, 

Canada, affecting 30 million people. The blackout led to 

the development in 1968 of the National Electric Reliability Council (NERC), shortly thereafter renamed the North 

American Electric Reliability Council. and nine regional reliability councils. Rather than serving as a pool or other 

entity for sharing resources, NERC focused on reliability. 

In 2006, using authority granted in the U.S. Energy Policy 

Act of 2005, FERC certifi ed NERC as the electric reliability 

organization for the United States, and reliability standards 

became mandatory and enforceable. 

Optimizing Unit Commitment and Economic Dispatch

The industry also reduced costs by using computers and 

communication technology to optimize system operations. 

Utilities use algorithms for optimizing the commitment of 

their generating units, while RTOs’ day-ahead market software does this for suppliers bidding into their markets.

In real time, demand is changing all the time. Without storage and responsive demand, the output of some generators 

must change to follow constantly changing demand. This 
40 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

is known as load following. Utilities use economic dispatch 

to optimize the use of these units and minimize real-time 

costs. 

Economy Energy Trade

Since transmission interconnections were built primarily for 

the rare need to deliver reserves in emergencies, the industry had excess transmission capacity. This allowed utilities 

to use the lines to trade power. Major utilities generally 

owned suffi cient capacity to meet their own peak power 

needs. However, sometimes the cost of operating their 

marginal generation was higher or lower than that of their 

neighbors. Transmission availability provided opportunities 

for utilities to save money by buying energy when it was 

cheaper than generating and selling energy to utilities with 

higher costs. This is called economy energy trading. 

Evolving Public Policies

Different public policy theories have shaped the electric 

power industry over its history. All of these public policies are still in play to some extent today. Five concepts 

that helped shape the electricity industry and markets are 

outlined below.

Not-for-Profi t Utilities

One of the fi rst approaches to ensuring customer value was 

to depend on nonprofi t electric providers. In the early days 

of the industry, electrifi cation started in towns and cities. 

In many places, this utility service was provided by the municipal government. The federal government stepped in to 

develop and market the nation’s signifi cant hydroelectric 

resources. The Depression-era rural electrifi cation program 

relied on customer-owned rural electric cooperatives and 

low-interest government loans. There are currently more 

than 1,700 municipal and almost 900 cooperative utilities 

in the United States.

Regulated Natural Monopolies

A second model for operating power systems was investorowned regulated monopolies. In the early days of the industry, while many cities went the municipal route, many 

investor-owned utilities were also starting up. These private utilities are regulated, typically by a state agency. Initially, they agreed to be regulated to overcome a lack of 

retail competition, and were granted exclusive service territories (franchise). Today, regulation focuses on mitigating 

market power, among other things, because many utility 

functions are seen as natural monopolies. 

State regulators approve a utility’s investments in generation and distribution facilities, either in advance of construction or afterwards when the utility seeks to include 

a facility’s costs in retail rates. Some states eventually developed elaborate integrated resource planning (IRP) processes to determine what facilities should be built. 

Power Pools

Power pools are multilateral arrangements with members 

ceding operational control over their generating units 

and transmission facilities to a common operator. Members provided incremental cost data about their units and 

system status data to the operator. The operator ran an 

energy management system that used the unit cost data 

to optimize on a multilateral basis unit commitment and 

economic dispatch.

PJM began in 1927 for utilities to share their generating 

resources, forming the world’s fi rst power pool. The New 

York Power Pool was formed in 1966 and the New England Power Pool in 1971 in response to the 1965 Northeast 

blackout. The Electric Reliability Council of Texas (ERCOT) 

and the Southwest Power Pool (SPP) formed in 1941 to 

pool resources for the war effort.
 Energy Primer | 41

Competition, Part 1: Competitive 

Generation and Open Access

The environmental movement and initiatives to open the 

airline and trucking industries to competition also helped 

shape the energy industry in the 1970s. A provision in President Carter’s energy plan led to passage of the Public Utility Regulatory Policies Act of 1978 (PURPA), which ushered 

in the next era.

PURPA established a program implemented by states and 

overseen by the FERC to encourage the use of effi cient 

cogeneration (using the heat from industrial or other processes to generate electricity) and small scale renewable 

generation. FERC’s role was to issue regulations for the 

program and certify that qualifying facilities (QFs) met 

statutory requirements. States administratively set the 

price to be paid to these generators at the cost the utilities 

would avoid by purchasing the power rather than generating it themselves. 

Most states set their avoided cost rate so low that they 

got little QF capacity. However, California, Texas and Massachusetts set very generous avoided cost rates and were 

overwhelmed with QF capacity, much of which received 

prices that turned out to be higher than the actual costs 

avoided by the purchasing utility. The rapid growth and 

size of the QF industry surprised many policymakers and 

entrepreneurs, and got them thinking about the viability of 

generation independent of regulated monopolies.

In 1988, FERC proposed rules to allow states to set their 

avoided-cost rate based on an auction. Instead of taking 

all capacity at a set rate, states could set the rate based on 

bids to supply a certain amount of needed capacity. The 

Commission also proposed to open the avoided-cost auction up to independent power producers (IPPs) that did 

not qualify as QFs. In this way, a regulatory program was 

transformed into a competitive initiative.

Under the regulated monopoly model, utilities owning and 

operating transmission lines had no obligation to allow 

others to use them. This posed a signifi cant barrier to the 

development of an independent power industry. The Commission started conditioning approval in merger cases with 

the voluntary provision of open transmission access. The 

Energy Policy Act of 1992 gave the Commission authority 

to grant transmission access on request. These approaches 

to open access resulted in patchwork transmission access.

By the mid-1990s, support for opening the transmission grid 

to all users encouraged the Commission to pursue a generic 

solution. Order 888 required mandatory open transmission 

access by all transmitting utilities and a reciprocity provision successfully extended open access to nonjurisdictional 

entities (municipal, cooperative and federal utilities).

Order 889 addressed matters needed to implement open 

access. The rule established the Internet-based Open Access Same-Time Information System (OASIS) for posting 

available transmission capacity and reserving transmission 

capacity. These rules required signifi cant changes to utility 

control room operations and limited the ability of companies to share transmission-related information with their 

own power marketing operating units.

Competition, Part 2: Integrating 

Markets and Operations – RTOs

Order Nos. 888 and 889 were designed for an industry of 

bilateral energy markets, in which parties negotiated transactions among themselves. The open-access transmission 

tariff and rules did not work well for multilateral power 

pools open to independent power producers. This led to 

the development of independent system operators (ISO) 

and, subsequently, regional transmission organizations 

(RTO). This primer uses RTO to stand for both RTOs and 

ISOs.
42 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

RTOs did more than operate the transmission system and 

dispatch generation, however. They developed markets in 

which buyers and sellers could bid for or offer generation. 

The RTOs used the bid-based markets to determine economic dispatch. 

Major parts of the country operate under more traditional 

market structures, notably the West (excluding California) 

and the Southeast. Notably, two-thirds of the nation’s 

electricity load is served in RTO regions.

Electricity Demand 

Americans use electricity for heat and light, to run machinery and to power a growing number of products such as 

televisions, radios, computers, hair dryers, cell phones and 

iPods. This use has been increasing, reaching 3,865 gigawatt-hours (GWh) of electricity in 2008. Demand dropped 

in 2009 with the recession, but has since regained its upward trend.

The bulk of the electricity generated is sold to consumers, 

known as end-users or retail customers. Some consumers 

generate some or all of the power they consume. Some 

of the electricity sold to retail consumers is generated by 

integrated investor-owned utilities, federal entities, municipally owned and co-operatively owned utilities that sell 

the power directly to consumers. The rest of the electricity 

ultimately consumed by retail customers is bought and sold 

through wholesale electric markets.

This primer focuses on wholesale markets, which generally 

involve the sale of electricity to entities that resell the power to retail customers. However, retail consumers’ electric 

use shapes demand and, therefore, the wholesale markets.

Demand Characteristics 

Demand is often characterized as baseload or peak. Baseload is demand that occurs throughout the day or throughout the year. Refrigerators, for example, may create baseload demand. Peak load is demand that shows up during 

part of the day or year, all at the same time – heating or air 

conditioning, for example. 

Demand for electricity follows cycles, throughout the day 

and year. Regionally, electric demand may peak in either 

the summer or the winter. Spring and fall are typically 

shoulder months, with lower peak demand. Seasonal peaks 

vary regionally, although the highest levels of power load 

in almost all regions of the United States occur during heat 

waves and are most acute during the daily peak load hours 

reached in the late afternoon. However, a minority of regions reach their peak load when the weather is extremely 

cold. These are primarily areas with signifi cant space-heating requirements and little summer air conditioning load. 

A majority of these systems are in the far northern areas of 

Quick Facts: Measuring Electricity

Electric use is described in terms of quantity and

time.

The unit of measure of the quantity used is the

kilowatt (kW), or 1,000 watts. The maximum

number of all the kilowatts used by consumers

on an electrical system at a point of time is peak

demand.

The amount of electricity a consumer uses over a

period of time is described as the number of the

kilowatt-hour (kWh) - 1,000 watts working for

one hour. Consumers pay based on the number

of kWh they consume in a billing period, typically

a month.

Source: EIA
 Energy Primer | 43

the United States, where air conditioning load is not signifi cant. South Florida’s seasonal peak also occurs during 

the winter, when the population and tourism surges and 

uses more power than native Floridians do in the summer. 

Daily demand typically peaks in the late afternoon, as commercial and domestic activities peak, and, in the winter, 

when lighting needs grow. 

Electricity use also varies between weekdays and weekends. 

Commercial and industrial activities are lower on weekends 

and peoples’ noncommercial activities change with their 

personal schedules. The load on different weekdays also 

can behave differently. For example, Mondays and Fridays, 

being adjacent to weekends, may have different loads than 

Tuesday through Thursday. This is particularly true in the 

summer.

Source: Energy Velocity

Because demand historically has not varied with price and 

because storage options are limited, generation must rise 

and fall to provide exactly the amount of electricity customers need. The cost of providing power typically rises as 

demand grows, and falls as demand declines, so wholesale 

power prices are typically highest during peaks. Consequently, system planners, power marketers and traders all 

carefully track weather trends, economic growth and other 

factors to forecast power demand. 

Demand Drivers

In general, the amount of electricity demanded is relatively 

insensitive to the price of electricity in the short-term (inelastic). One reason for this is that many customers – 

especially smaller customers – do not get price signals to 

which they can respond. Most residential customers are 

billed monthly on a preset rate structure. Large industrial 
44 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

customers, on the other hand, may receive real-time price 

signals.

Further, electricity is a necessity to most people and businesses. While they may be able to reduce their demand 

in the short-term – by turning down the thermostat or 

turning off lights, for example – electric consumers fi nd it 

diffi cult to do without electricity altogether. There is little 

storage for electricity now and few realistic substitutes. 

Consequently, demand tends to drive price, especially when 

the system is stressed. 

In the longer-term, options for reducing electricity use include switching to natural gas, installing insulation and 

implementing other energy effi ciency measures. Larger 

consumers may consider building their own generation facilities. 

Governments and businesses are also developing demandresponse programs, which provide plans in which customers 

agree to reduce load in exchange for compensation.

Factors driving demand include demographics, climate and 

weather, economic activity and policies and regulations.

Demographics

Population levels affect demand, with greater population 

levels tending to increase electric consumption. Shifts in 

population also affect regional demand. Population fl ight 

in the 1980s from northern industrial regions – the Rust 

Belt – to warmer climates in the South affected residential 

consumption patterns. In the 1990s, consumption in the 

South surpassed that in the Midwest, making it the region 

with the greatest electric use.

Climate and Weather

Weather is the biggest factor driving demand. General 

climatic trends drive consumption patterns and therefore 

the infrastructure needed to ensure reliable service. Cold 

weather and short days drive winter demand in northern 

regions. Southern regions rely more on electric space heating, and, thus, see demand rise in the winter, although 

demand typically peaks in the summer with air conditioning load. In the winter, lighting contributes to the occurrence of peaks during the seasonally dark early morning 

and early evening hours. 

Weather also can have extreme short-term effects on electricity usage. A sudden cold snap can drive heating use up 

quickly and a heat wave can push air conditioning loads. 

Other, less obvious weather patterns affect demand – rain 

and wind, for example, may result in sudden cooling, affecting heating or air conditioning. 

Economic Activity 

The pattern of socioeconomic life affects the cycle of electric use, with weekends and holidays showing a different 

pattern than weekdays. Demand typically rises as people 

wake up and go to work, peaking in the afternoon. 

The health of the United States and regional economies 

also affects power demand. During periods of robust acQuick Facts: 

Heating and Cooling Degree Days

In the United States, engineers developed the

concept of heating and cooling degree days to

measure the effects of temperature on demand.

Average daily temperatures are compared to a 65o

F standard - those in excess of 65o yield cooling

degree days; those below 65o

 yield heating degree

days. A day with an average temperature of 66o

would yield one cooling degree day.
 Energy Primer | 45

tivity, loads increase. Similarly, loads drop during recessions. These changes are most evident in the industrial 

sector, where business and plants may close, downsize or 

eliminate factory shifts. In addition to reducing overall 

demand, these changes may affect the pattern of demand; 

for example, a factory may eliminate a night shift, cutting 

baseload use but continuing its use during peak hours. In 

some cases these effects can be signifi cant. 

Energy Policies and Regulations

State regulatory agencies set prices and policies affecting 

retail customer service. Some states are considering changes that would enable customers to receive more accurate 

price signals. They include, among other things, changing 

rate structures so that the rate varies with the time of day, 

or is even linked to the cost of providing electricity.

Efforts to reduce overall demand by improving energy effi ciency are underway through several governmental and 

utility venues. 

Retail Customer Mix

Most electric utilities serve different types of customers: 

residential, commercial and industrial. Each class uses 

electricity differently, resulting in a differing load profi le, 

or the amount that each customer class uses and the daily 

shape of the load. If a consumer uses electricity consistently throughout the day and seasons, his load shape is 

fl at, and the load will be baseload. Another consumer may 

use more at some times than others, resulting in baseload 

and peaks. Greater variability in demand is typically more 

expensive to serve, especially if the peak occurs at the same 

time other customers’ use peaks. Consequently, the mix of 

customer types affects a region’s overall demand. 

Residential consumers form the largest customer segment 

in the United States at approximately 38 percent of electricty demand. Residential consumers use electricity for air 

conditioning, refrigerators, space and water hearing, lighting, washers and dryers, computers, televisions, cell phones 

and other appliances. Prices for residential service are 

typically highest, refl ecting both their variable load shape 

and their service from lower-voltage distribution facilities, 

meaning that more power lines are needed to provide service to them. 

Commercial use is the next largest customer segment at 

approximately 36 percent, and includes hotels and motels, 

restaurants, street lighting, retail stores and wholesale businesses and medical religious, educational and social facilities. More than half of commercial consumers’ electric use 

is for heating and lighting. 

Industrial consumers use about 26 percent of of the nation’s electricity. This sector includes, for example, manufacturing, construction, mining, agriculture and forestry 

operations. Industrial customers often see the lowest rates, 

refl ecting their relatively fl at load structure and their ability 

to take service at higher voltage levels.

Transportation demand for electricity stems primarily from 

trains and urban transportation systems. This is less then 1 

percent of electricty demand.

Load Forecasting

Demand is constantly changing, challenging grid operators and suppliers responsible for ensuring that supply will 

meet demand. Consequently, they expend considerable resources to forecast demand. Missed forecasts, where actual 

demand differs signifi cantly from the forecast, can cause 

wholesale prices to be higher than they otherwise might 

have been.

Forecasts are necessary as well for the variety of actions 

that must occur if suffi cient supply is to be available in 
46 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

the immediate or long term: planning the long-term infrastructure needs of the system, purchasing fuel and other 

supplies and staffi ng, for example. Load forecasts are also 

extremely important for suppliers, fi nancial institutions and 

other participants in electric energy generation, transmission, distribution and trading.

Load forecasting uses mathematical models to predict demand across a region, such as a utility service territory or 

RTO footprint. Forecasts can be divided into three categories: short-term forecasts, which range from one hour 

to one week ahead; medium forecasts, usually a week to 

a year ahead; and long-term forecasts, which are longer 

than a year. It is possible to predict the next-day load 

with an accuracy of approximately 1%-3% of what actually 

happens. The accuracy of these forecasts is limited by the 

accuracy of the weather forecasts used in their preparation 

and the uncertainties of human behavior. Similarly, it is 

impossible to predict the next year peak load with the similar accuracy because accurate long-term weather forecasts 

are not available.

The forecasts for different time horizons are important for 

different operations within a utility company. Short-term 

load forecasting can help to estimate transmission system 

power fl ows and to make decisions that can prevent overloading of transmission systems. Timely implementation 

of such decisions leads to the improvement of network 

reliability and to the reduced occurrences of equipment 

failures and blackouts. Forecasted weather parameters are 

the most important factors in short-term load forecasts; 

temperature and humidity are the most commonly used 

load predictors.

The medium- and long-term forecasts, while not precise, 

take into account historical load and weather data, the 

number of customers in different customer classes, appliances used in the area and their characteristics, economic 

and demographic data, and other factors. For the nextyear peak forecast, it is possible to provide an estimated 

load based on historical weather observations. Long-term 

forecasts are used for system infrastructure planning and 

are meant to ensure that there are suffi cient resources 

available to meet the needs of the expected future peak 

demand. These forecasts are made for periods extending 

10 to 20 years into the future.

Demand Response

Electric demand is generally insensitive to price, meaning that demand does not typically fall signifi cantly when 

wholesale prices rise. However, some utilities and grid operators are developing ways to stimulate a response from 

consumers through demand-response programs.

Demand response (DR) is the ability of customers to respond to either reliability or price triggers by forgoing 

power use for short periods, by shifting some high energy 

use activities to other times or by using onsite generation. 

The programs may use price signals or incentives to prompt 

customers to reduce their loads. The signals to respond 

to electric power system needs or high market prices may 

come from a utility or other load-serving entity, a regional transmission organization (RTO) or an independent DR 

provider. These programs are administered by both retail 

and wholesale entities. 
 Energy Primer | 47

DR has the potential to lower systemwide power costs and 

assist in maintaining reliability. It can be used instead of 

running power plants or to relieve transmission congestion 

There can also be environmental benefi ts because peaking 

units tend to be costly - and dirty - to run.

Demand response rewards consumers for reducing load 

during certain market conditions and at specifi c times. 

However, it is diffi cult to measure and quantify this reduction. Measuring and verifying the reduction requires 

development of consumers’ baseline usage, against which 

their actual use is measured to determine the reduction in 

the event they are called to lessen their load. An accurate 

measure of their typical usage is important to prevent (or 

detect) gaming by participants. 

Demand-Response Programs

Programs generally fall into three categories: curtailing, 

shifting or on-site generation.

Curtailing, or forgoing, involves reducing power use (load) 

during times of high prices or threats to reliability without 

making up the use later. For example, residential customers might turn off lights or raise thermostats during hot 

weather. Commercial facilities may turn off offi ce equipment, lower building lighting or change thermostat settings by a few degrees. 

Shifting involves moving or rescheduling high energy-use 

activities in response to high prices or DR program events to 

off-peak periods – evenings, nights or weekends. Industrial 

customers might reschedule batch production processes to 

evening hours or the next day. Commercial establishments 

may delay high-energy operations. Residential customers 

may wait until evening or night to use high-energy consuming appliances, such as clothes dryers or dishwashers. 

In shifting, the lost amenity or service is made up at a 

subsequent time.

On-site generation is when some customers may respond 

by turning on an on-site or backup emergency generator 

to supply some or all of their electricity needs. Although 

customers may have little or no interruption to their electrical usage, their net load and requirements from the power 

system are reduced. The ability to use on-site generation is 

most common for institutional customers, such as hospitals, large schools or data centers. 

DR programs can be further distinguished by whether they 

are controlled by the system operator (dispatchable) or the 

customer (nondispatchable). Dispatchable demand response refers to programs that reduce customer energy use, 

such as direct load control of residential appliances or directed reductions to industrial customers. Dispatchable DR 

is used for reliability or economic reasons. Nondispatchable 

demand response lets the retail customer decide whether 

and when to reduce consumption in response to the price 

of power. It includes time-sensitive pricing programs based 

on rates that charge higher prices during high-demand 

hours and lower prices at other times.

As a result of technology innovations and policy directions, 

new types and applications of DR are emerging that encompass the use of smart appliances that respond in near 

real-time to price or other signals. These models may allow customers to respond more easily as they require little 

customer monitoring or interaction.

Demand Response in Retail Markets

Many states require utilities to use energy effi ciency, DR or 

renewable resources. Energy Effi ciency Resource Standards 

(EERS) in more than half of the states (plus Washington, 

D.C.) require utilities to achieve electric energy savings; 

many of these standards include peak load reduction targets. These mandates provide incentives for utilities to reduce customers’ energy consumption, such as mechanisms 

that decouple profi ts from the amount of electricity sold, 
48 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

or performance bonuses for utilities that meet or exceed 

reduction targets. 

Some states are implementing dynamic pricing, in which 

retail rates change frequently to better refl ect system costs. 

Time-based rates depend on advanced meters at customer 

premises that can record usage. In time-of-use programs, 

customers are charged different prices at different times, 

with hours of peak demand costing more than off-peak 

hours. 

In real-time pricing (RTP) programs, customers are charged 

prices refl ecting the immediate cost of power. Industrial or 

very large commercial customers are often on RTP tariffs. 

Critical peak pricing (CPP) uses real-time prices at times of 

extreme system peak, and is restricted to a small number 

of hours annually but features prices higher than time-ofuse prices during the critical peak. Consumers do not know 

in advance when a critical peak might be called. A CPP 

program for residential customers uses a carrot without the 

stick: critical-peak rebates. Participating customers get rebates on their bills for responding to utility price-signals, 

but are not penalized if they do not lower use in those 

hours.

Wholesale Market Programs

Retail programs may aid RTOs, although the RTO may not 

be able to invoke them or even see specifi cally the amount 

of response that occurs. Wholesale-level DR occurs in the 

RTOs, which differ in how demand-response resources 

(DRR) may participate in their markets. Some RTOs permit 

DRR to participate in their markets as voluntary reliability resources. For example, NYISO has an emergency demand-response program, which permits DRR to participate 

through an aggregator or other interface party, and receive 

energy payments for providing curtailments when called. 

DRR also can participate in wholesale markets as capacity resources and receive advance reservation payments in 

return for their commitment to participate when called. 

Resources that fail to perform when called are penalized.

Finally, DRR can bid into RTO day-ahead (DA) markets as 

energy resources, specifying the hours, number of megawatts and price at which they are willing to curtail. ISOs 

set minimum bid values – NYISO’s program has a $75/

MWh fl oor. In New York, a resource scheduled in the DA 

market is obligated to curtail, and failure to perform results 

in a penalty.

Some of the RTO DR comes from individual entities; the 

rest is accumulated through third-party aggregators, or 

curtailment service providers (CSPs), who recruit customers too small to participate on their own, such as schools, 

commercial chains or groups of residential customers. In 

aggregating small customers, CSPs have increased customer 

participation in many wholesale reliability and emergency 

programs. In NYISO’s two incentive-based programs, CSPs 

increased their share of subscribed DRR to 77 percent in 

2008 from 44 percent in 2003. CSPs were responsible for 

more than 60 percent of total DRR capacity, and 70 percent of new DRR in ISO-NE.

Demand-Response Use in Planning and Operations

Different DR programs can be used at various times to 

support planning and operations (see graphic, page 50). 

Energy effi ciency programs that reduce baseload or peak 

demand over the long-term are incorporated into system 

planning. Dispatchable programs that are quickly implemented and targeted for short-term peak reductions – such 

as direct load control – lie on the other end of the spectrum, and are used in the moment of operation.
 Energy Primer | 49

Electricity Supply and Delivery

Unlike many other products, electricity cannot be stored in 

any appreciable quantities. Further, electricity is a necessity for most consumers, whose use responds little to price 

changes. Finally, electric equipment and appliances are 

tuned to a very specifi c standard of power, measured as 

voltage. Deviations in voltage can cause devices to operate poorly or may even damage them. Consequently, the 

supply side of the electric market must provide and deliver 

exactly the amount of power customers want at all times, 

at all locations. This requires constant monitoring of the 

grid and close coordination among industry participants.

Electricity service relies on a complex system of infrastructure that falls into two general categories: generation and 

the delivery services of transmission and distribution. Together, the power generation and high-voltage transmission 

lines that deliver power to distribution facilities constitute 

the bulk power system. Transmission and distribution facilities are also referred to as the power grid. These are 

coordinated and at times operated by a grid coordinator.

Nationally, the grid is split into three main sections – the 

Western, Eastern and Texas Interconnections. These sections operate independently and have limited interconnections between them.

The nation, along with Canada and a small part of Mexico, 

is also divided into regional entities, (see map, page 51). 

The regional reliability entities fall under the purview of 

the North American Electric Reliability Corp. (NERC), which 

was designated by FERC as the nation’s energy reliability 

organization and which develops standards, among other 

things, to ensure the grid’s reliability. The standards, once 

issued by FERC, must be met by all industry participants 

– the standards are mandatory and enforceable. Consequently, the grid is designed and operated to meet these 

standards.

Source: DOE

Demand-Response Program Use in Electric System Planning and Operations
50 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

NERC’s regions include:

• Florida Reliability Coordinating Council (FRCC),

• Midwest Reliability Organization (MRO), 

• Northeast Power Coordinating Council (NPCC), 

• Reliability First Corporation (RFC),

• SERC Reliability Corp. (SERC),

• Southwest Power Pool (SPP), 

• Texas Reliability Entity (TRE) and 

• Western Electricity Coordinating Council (WECC)

Generation

Power generators are typically categorized by the fuel they 

use and subcategorized by their specifi c operating technology. The United States has more than 1,000 gigawatts 

(GW) of total generating capacity. Coal, natural gas and 

nuclear dominate the power generation market.

Power plants each have differing costs and operational 

characteristics, both of which determine when, where and 

how plants will be built and operated.

Plant costs fall into two general categories: capital investment costs, which are amounts spent to build the plant, 

and operational costs, the amounts spent to maintain and 

run the plant. In general, there is a trade-off between 

these expenses: the most capital intensive plants are the 

cheapest to run – they have the lowest variable costs – and, 

conversely, the least capital intensive are more expensive 

to run – they have the highest variable cost. For example, 

nuclear plants produce vast amounts of power at low variable costs, but are quite expensive to build. Natural gasfi red combustion turbines are far less expensive to build, 

but are more expensive to run.

Electricity Service Schematic

Source: National Energy Education Development Project

NERC Regions
 Energy Primer | 51

Grid operators dispatch plants – or, call them into service 

– with the simultaneous goals of providing reliable power 

at the lowest reasonable cost. Because various generation technologies have differing variable costs, plants are 

dispatched only when they are part of the most economic 

combination of plants needed to supply the customers on 

the grid. For plants operating in RTOs, this cost is determined by the price that generators offer. In other areas, it 

is determined by the marginal cost of the available generating plants.

Construction of different generating technologies is subject to a number of issues, including community concerns, 

regional emission restrictions and the availability of fuels or 

other necessary resources:

• Wind plants are generally built in areas with the appropriate meteorological conditions. In most cases, these 

sites are located in rural areas with limited transmission 

access. For example, in West Texas, the transmission 

lines connecting wind farms with consumer centers in 

Dallas and Houston can become overloaded, requiring 

generators to curtail production.

• Coal plants have environmental characteristics that 

limit both their siting and operations. Specifi cally, 

they emit NOx

, SOx, particulates, mercury and substantially higher levels of CO2

 than gas-fi red plants. This 

has made fi nancing these plants and siting them near 

urban centers diffi cult.

• There have been virtually no new nuclear plants built 

in the United States in the past 30 years. The technology of older plant designs became a source of concern 

following the accident at the Three Mile Island plant in 

the United States in 1977, the Chernobyl plant meltdown in Ukraine in 1986 and the Japanese earthquake, 

tsunami and nuclear plant destruction in 2011. New 

plant designs have been put forward over the past 

few years and are expected to be very expensive and 

controversial to build. Further, the disposition of highlevel radioactive waste remains an unresolved problem, 

and the waste remains at plant locations.

Conventional Generation

Natural gas power plants: These feature three major technologies, each with its distinct set of market advantages 

and limitations. They are steam boilers, gas turbines and 

combined cycle generators. Natural gas fuels nearly a third 

of electricity generation.

Steam boiler technology is an older design that burns gas 

in a large boiler furnace to generate steam at both high 

pressure and a high temperature. The steam is then run 

through a turbine that is attached to a generator, which 

spins and produces electricity. Typical plant size ranges 

from 300 MW to 1,000 MW. Because of their size and the 

limited fl exibility that is inherent in the centralized boiler 

design, these plants require fairly long start-up times to 

become operational and are limited in their fl exibility to 

produce power output beyond a certain range. Furthermore, these plants are not as economical or easy to site as 

newer designs – which explains why none has been built 

in recent years.

Gas turbines (GT) are small, quick-start units similar to an 

aircraft jet engine. These plants are also called simple cycle 

turbines or combustion turbines (CT). GTs are relatively inexpensive to build, but are expensive to operate because 

they are relatively ineffi cient, providing low power output 

for the amount of gas burned, and have high maintenance 

costs. They are not designed to run on a continuous basis 

and are used to serve the highest demand during peak periods, such as hot summer afternoons. GTs also run when 

there are systemwide shortages, such as when a power line 

or generator trips offl ine. GTs typically have a short operational life due to the wear-and-tear caused by cycling. The 

typical capacity of a GT is 10-50 MW and they are usually 

installed in banks of multiple units. 
52 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Combined cycle power plants (CCPPs) are a hybrid 

of the GT and steam boiler technologies. Specifi cally, this 

design incorporates a gas-combustion turbine unit along 

with an associated generator, and a heat recovery steam 

generator along with its own steam turbine. The result is 

a highly effi cient power plant. They produce negligible 

amounts of SO2

 and particulate emissions and their NOx

and CO2

 emissions are signifi cantly lower than a conventional coal plant. CCPPs, on average, require 80 percent 

less land than a coal-fi red plant, typically 100 acres for 

a CCPP versus 500 acres for comparable coal plant, and 

CCPPs also use modest amounts of water, compared to 

other technologies.

Coal plants: These generate more than one-third of the 

electricity in the United States. These facilities tend to 

be large, baseload units that run continuously. They have 

high initial capital costs and are also somewhat complex in 

their design and operations. However, coal plants have low 

marginal costs and can produce substantial amounts of 

power. Most of the coal-fi red plants in the United States 

are owned by traditional utility companies and located in 

the Southeast and Midwest.

Oil-fi red plants: These play a minor role in U.S. power 

markets. These facilities are expensive to run and also 

emit more pollutants than gas plants. These plants are 

frequently uneconomic and typically run at low capacity 

factors. Like gas-fi red generators, there are several types of 

units that burn oil; primarily, these are steam boilers and 

combustion turbines.

Generally, two types of oil are used for power generation: 

number 2 and number 6 (bunker) fuel oil. Number 2 is a 

lighter and cleaner fuel. It is more expensive, but because 

it produces fewer pollutants when burned, it is better for 

locations with stringent environmental regulations such as 

major metropolitan areas. Conversely, number 6 fuel oil is 

cheaper, but considered dirty because of its higher emissions. It is highly viscous (thick and heavy) and it comes 

from the bottom of the barrel in the refi ning process.

Nuclear plants. These provide roughly 20 percent of the 

nation’s electricity; there are 104 operating plants with a 

total capacity of 100 GW. These plants are used as baseload units, meaning that they run continuously and are not 

especially fl exible in raising or lowering their power output. 

Nuclear plants have high capital and fi xed costs, but low 

variable costs, which includes fuel cost. They typically run 

at full power for 18 month, which is the duration of a unit’s 

fuel cycle. At that point, they are taken off-line for refueling and maintenance. Outages typically last from 20 days 

to signifi cantly longer, depending on the work needed.

Following the Three Mile Island plant accident in 1977, 

there was a cessation in the development of new plants. 

Most projects under construction in 1977 were fi nished, 

albeit with tremendous cost overruns. The last unit built in 

the United States came online in 1996. 

Renewable Generation

Renewable resources use fuels that are not reduced or used 
 Energy Primer | 53

up in the process of making electricity. They generally 

include biomass, geothermal, hydropower, solar, onshore 

and offshore wind, hydrokinetic projects, fuel cells using 

renewables and biogas.

Renewable generation provides a small percent of total U.S. 

capacity and generation. Even in 2009, when total U.S. 

electric output fell, average renewable generation grew 

12% and wind output grew 28%, spurred by state regulations and federal tax credits. As renewable generation 

becomes a larger percentage of generation resources, integrating them into the operating power grid has presented 

challenges.

Capacity: Wind and solar capacity have grown faster than 

other renewable resources in recent years. Geothermal has 

more installed capacity than solar, but is growing more 

slowly. Wind added the second highest amount of capacity 

after gas-fi red generation in 2009 and 2010. 

Additions are usually reported in megawatts of nameplate 

capacity. Actual capability varies from the nameplate for 

any unit type due to age, wear, maintenance or ambient 

conditions. But as renewable resources are often weatherdependent, their capacity factors – the ratio of average 

generation to the nameplate capacity for a specifi c period 

– have been much lower (as low as 30 percent) than for 

fossil-fuel-fi red generation. Markets care about the difference between nameplate and capacity factor values when 

they evaluate capacity available to cover expected load. 

Prior to suffi cient operating experience with a renewable 

technology, markets usually estimate capacity value conservatively. 

Average capacity factors for new renewable resources in 

early 2010 were 34-35 percent for large wind projects, 74 

percent for geothermal, 15-21 percent for commercial solar photovoltaic (PV), 35 percent for concentrating solar 

power (CSP) without storage (or 43-45 percent with storage technology) and 63 percent for biomass. Capacity factors have risen with technological innovation and improved 

manufacturing processes.

Characteristics: Wind power is the fastest-growing renewable resource, in part due to earlier cost declines and technology improvements as well as earlier receipt of federal 

tax credits. A 1.5-MW wind turbine was the most frequently installed size in 2009, although 2.3-MW turbines 

later became more common. Wind is largely pollution-free 

and can be located on farms and ranches. 

Because the best wind resources are often far from load 

centers, insuffi cient transmission presents a challenge to 

delivering its output. Other market challenges for future 

wind development include its variable output, which is often inversely correlated to demand (seasonally and daily); 

system operators’ inability to dispatch wind resources to 

meet load increases; diffi culties related to accurately forecasting its ramping; and the need for companion generation (usually fossil-fueled) to be available to balance wind 

generation when the wind is not blowing. 

Geothermal energy taps into reservoirs of steam and hot 

water deep beneath the earth’s surface to produce power. 

The best resources are in the intermountain West. Geothermal potential is determined by thermal conductivity, 

thickness of sedimentary rock, geothermal gradient, heat 

fl ow and surface temperature. While geothermal power 

was less than 0.4 percent of U.S. generation in 2009, it was 

11 percent of nonhydro renewable output in April 2010. 

California hosts more than 80 percent of U.S. operating 

capacity. The fi ve states with the most geothermal capacity 

in development are California, Nevada, Oregon, Utah and 

Idaho.

Solar energy transforms sunlight into electricity using one 
54 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

of two technologies: photovoltaic (PV) or concentrating 

solar power (CSP). PV modules, or panels, transform sunlight directly into power using silicon wafers or nonsilicon 

thin-fi lm technologies. They can be installed on roofs of 

buildings or at ground-level PV farms. CSP plants use a 

two-step process to transform the sun’s energy. First, mirrors direct sunlight towards a receiver that captures the 

heat. CSP then employs a thermal process to create steam, 

driving an engine or turbine to produce electricity. CSP 

plants, which are dispatchable, can include low-cost energy 

storage that extends their availability later in peak hours.

PV growth has been highly concentrated as a result of 

state policy incentives: 10 states have 95% of PV capacity; California alone has more than 50 percent. Annual PV 

additions rose to more than 100 MW beginning in 2006, 

spurred by tax incentives in the Energy Policy Act of 2005. 

More recent growth was spurred by falling costs, technology innovation, expanded federal tax benefi ts and an increase in state policies promoting investment. 

In 2010, 432 MW of CSP was operational and 81 MW was 

under construction. Seven western and southwestern states 

have extensive CSP potential: Utah, New Mexico, Arizona, Nevada, Texas, California and Colorado. Developing 

that potential will require overcoming challenges of siting, 

transmission and the need for extensive water supplies to 

clean mirrors.

Hydroelectric power is created when the kinetic energy of 

falling water drives turbine generators, which convert the 

energy into electricity. There are two types of hydroelectric 

projects: conventional and pumped storage. Conventional 

projects, which use a dam in a waterway, can operate in a 

run-of-river mode, in which water outfl ow from the project 

approximates infl ow, or in a peaking mode, in which the 

reservoir is mostly drained to generate power during peak 

periods when energy is more valuable. Pumped storage 

projects use bodies of water at two different elevations. 

Water is pumped into elevated storage reservoirs during 

off-peak periods when pumping energy is cheaper; the water is then used to generate power during peak periods as it 

fl ows back to the lower elevation reservoir. Pumped storage is the only signifi cant commercially deployed electricity 

storage technology available today.

Biomass includes many waste byproducts, such as agricultural residues, landfi ll gas, municipal solid waste and wood 

resources. The largest biomass category is wood waste, 

burned for heat and power in the lumber, pulp and paper 

industries. Challenges to biomass production include impacts on food supplies (for example, converting corn into 

ethanol), conserving natural resources and minimizing water pollution. State policies on renewable generation differ 

on eligibility of biomass technologies. 

Biogas energy is created through the anaerobic (without oxygen) bacterial decomposition of manure, which is 

turned into a gas containing 60-70 percent methane. Biogas recovery can be installed at farms anywhere, used to 

run farm operations and reduce methane emissions from 

natural manure decomposition.
 Energy Primer | 55

Renewable Energy Policies

Renewable development is frequently tied to policies promoting their use because of their higher cost relative to 

other technologies. Financial incentives include tax credits, low-cost loans, rebates or production incentives. Federal funding of research and development (R&D) has played 

an important role in lowering costs or reducing the time it 

takes for renewable technologies to become commercially 

viable. 

Congress has passed tax incentives to spur renewable resource investments. Wind, biomass, geothermal, marine 

and hydrokinetic project developers can receive federal production tax credits (PTC) based on a facility’s production. 

It is an infl ation-adjusted credit that runs for 10 years from 

the date a facility goes online. Initially set at 1.5¢/kilowatt 

hour (kWh), its value in 2010 was 2.1¢/kWh. To qualify, a 

facility has to be operational before the PTC expires. 

Unlike other renewables projects, solar projects are eligible 

for a federal investment tax credit (ITC), worth 30 percent 

of a project’s equipment and construction costs. The ITC 

begins the year a project starts commercial operation and 

depreciates over fi ve years. The Emergency Economic Stabilization Act (2008), the legislation enacted to help shore 

up the U.S. fi nancial system, extended the solar ITC for 

eight years, through 2016. It also expanded both the PTC 

and ITC to include utilities, which were previously ineligible 

for these credits. This change created the impetus for a 

model of utility owned and operated renewable generation, 

and led to a fl urry of project announcements.

Provisions of the American Reinvestment and Recovery Act 

(ARRA) of 2009 extended the PTC and gave developers new 

options. It extended the credit for wind to 2012 and for 

other eligible technologies to 2013, and gave PTC-qualifi ed developers the option to claim the 30 percent ITC on 

a project-by-project basis for the PTC’s current duration. 

Due to the economic crisis, ARRA gave developers another 

option for projects that began construction by the end of 

2010 – they could apply for Treasury-administered cash 

grants, which monetized the ITC’s value up front. ARRA 

funds helped support renewable energy research and development and aided capacity growth in 2009, despite the 

economic downturn. 

State renewable portfolio standards (RPS) and renewable 

energy standards (RES) have been signifi cant drivers in the 

growth of investment in renewable generation. An RPS requires a certain percentage of energy sales (MWh) to come 

from renewable resources. Percentages usually increase 

incrementally from a base year to an ultimate target. Currently, 29 states plus Washington, D.C., have an RPS and 

six states have renewable goals without fi nancial penal-
56 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

ties for nonachievement. As utilities build more renewablepowered generation, the markets in which they participate 

continue to address the integration of renewable output 

into their day-ahead and real-time operations and model 

expected growth as part of their long-term transmissionplanning processes. 

To encourage the development of distributed generation 

(DG), or the production of electricity at the site of consumption, and solar power, 16 states plus Washington, 

D.C., created RPS carve-outs or set-asides to give an extra 

boost to these resources, which are not yet cost-competitive with other renewables. 

Renewable energy certifi cates (RECs) allow state regulators 

to track compliance with mandatory RPS targets or verify 

progress in voluntary state renewable programs. They also 

allow compliance entities to purchase credits – subject to 

state imposed limits on amount and price - if they have 

not generated or bought enough renewable energy to meet 

their annual requirements. Each reported megawatt-hour 

(MWh) of eligible generation results in a system-issued REC 

with a unique identifi cation number to prevent doublecounting. Each REC includes attributes such as generator 

location, capacity, fuel-type and source, owner and the 

date when operations began.

States and local utilities offer a variety of fi nancial incentives for renewable energy to complement policy mandates. 

These include tax credits for in-state manufacture of renewable energy equipment, consumer rebates for purchase 

and installation of renewable generation or production incentives. Production incentives include extra credits for solar output based on RPS solar set-asides and feed-in tariffs.

Five states, two municipal utilities and Ontario, Canada, 

adopted or expanded feed-in tariffs (FITs) in 2009 to support their energy and environmental goals. Also called feedin rates or advanced renewable incentives, these programs 

typically are designed to encourage development of new 

small- and medium-sized renewable generation projects by 

residential and independent commercial developers.

FITs require utilities to buy the renewable generation at a 

fi xed rate that is higher than that provided to other generators, under multiyear contracts. This enables smaller 

distributed renewable generators to avoid having to participate in renewable portfolio standard (RPS) auctions or 

other competitive procurements and compensates them for 

more expensive technologies. The utility passes the costs of 

the program to its customers.

Transmission

The alternating current (AC) power grid operates like an 

interconnected web, where, with a few exceptions, the fl ow 

of power is not specifi cally controlled by the operators on 

a line-by-line basis. Instead, power fl ows from sources 

of generation to consumers across any number of lines 

simultaneously, following the path of least resistance. 

There are a limited number of direct current (DC) lines, 

which are set up as specifi c paths with defi nite beginning 

and end points for scheduling and moving power. These 

lines are controllable by operators and have other characteristics that make them attractive to grid planners and 

operators, such as providing greater grid stability and lower 

line losses. However, DC lines cost signifi cantly more than 

AC lines to construct. Consequently, DC lines are typically 

built for certain specialized applications involving moving 

large amounts of power over long distances, such as the 

Pacifi c Intertie, which extends between the Northwest and 

California.

Transmission lines provide a certain amount of resistance to 

the fl ow of power as electricity travels through them. This 

resistance is not unlike the wind resistance that a car must 

overcome as it travels along a highway. The resistance in 

power lines creates losses: the amount of power injected 
 Energy Primer | 57

into a power line diminishes as it travels through the line. 

The amount of these losses is contingent on many factors, 

but typically equals several percent of the amount put into 

the system.

Transmission Service

FERC requires that public utilities that own transmission 

lines used in interstate commerce offer transmission service on a nondiscriminatory basis to all eligible customers. 

The rates and terms of service are published in each utility’s Open Access Transmission Tariff (OATT). One type 

of service is point-to-point service. This service involves 

paying for and reserving a fi xed quantity of transmission 

capacity and moving power up to the reservation amount 

from one location, the point of receipt (POR), to another 

location, the point of delivery (POD). Depending on availability, customers may purchase point-to-point service for 

durations of one hour to multiple years. The price for the 

service is cost-based and published in the OATT. In cases 

where there are multiple parties desiring transmission, it is 

allocated to the party willing to purchase it for the longest 

period of time. Capacity reassignment is the term for the 

resale of point-to-point transmission capacity in the secondary market.

Transmission holders may want to sell capacity in the secondary market because it is unneeded, or to make a profi t. 

Capacity reassignment has been permitted since 1996. Beginning in 2007, resellers have been permitted to charge 

market-based prices for capacity reassignments, as opposed 

to the original cost-based price at which they purchased the 

capacity. The number of capacity reassignments increased 

from around 200 in 2007 to almost 32,000 in 2009. Most 

of the transactions were hourly, although capacity can also 

be reassigned on a daily, monthly or yearly basis.

If the market price of energy is greater at the POD than 

at the POR, the transmission has value. The transmission 

holder can capture this value by using the transmission – 

buying energy at the POR, moving it to the POD and selling 

it. Alternatively, the transmission holder can sell the transmission through a capacity reassignment. Thus, the price 

of a capacity reassignment should be equal to the expected 

price differential between the POD and the POR.

Grid Operations

Grid operators dispatch their systems using the least costly 

generation consistent with the constraints of the transmission system and reliability requirements. The dispatch process occurs in two stages: day-ahead unit commitment, or 

planning for the next day’s dispatch, and economic dispatch, or dispatching the system in real time.

Day-Ahead Unit Commitment

In the unit commitment stage, operators decide which generating units should be committed to be online for each 

hour, typically for the next 24-hour period. This is done 

in advance of real-time operations because some generating units require several hours lead time before they are 

brought online. In selecting the most economic generators to commit, operators take into account forecast load 

requirements and each unit’s physical operating characteristics, such as how quickly output can be changed, maximum and minimum output levels and the minimum time a 

generator must run once it is started. Operators must also 

take into account generating unit cost factors, such as fuel 

and nonfuel operating costs and the cost of environmental 

compliance.

Also, forecast conditions that can affect the transmission 

grid must be taken into account to ensure that the optimal dispatch can meet load reliably. This is the security 

aspect of commitment analysis. Factors that can affect 

grid capabilities include generation and transmission facility outages, line capacities as affected by loading levels 
58 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

and fl ow direction and weather conditions. If the security 

analysis indicates that the optimal economic dispatch cannot be carried out reliably, relatively expensive generators 

may have to replace less-expensive units.

System and Unit Dispatch 

In the system dispatch stage, operators must decide in 

real time the level at which each available resource from 

the unit commitment stage should be operated, given 

the actual load and grid conditions, so that overall production costs are minimized. Actual conditions will vary 

from those forecast in the day-ahead commitment, and 

operators must adjust the dispatch accordingly. As part of 

real-time operations, demand, generation and interchange 

(imports and exports) must be kept in balance to maintain 

a system frequency of 60 hertz. This is typically done by 

automatic generation control (AGC) to change the generation dispatch as needed.

The chart below is a depiction of the supply curve of the 

power plants for the New York ISO (NYISO). This is also 

commonly called the supply stack. In it, all of the plants 

in the NYISO system are shown sorted according to their 

marginal cost of production. Their cost of production is 

shown on the vertical axis. The cheapest ones to run are to 

the left and the most expensive to the right.

Dispatch in the NYISO, for example, fi rst calls on wind 

plants, followed successively by hydro, nuclear and coal-, 

gas- and oil-fi red generators. This assumes that the plants 

have suffi cient resources – enough wind for the wind powered generators or enough river fl ow for the hydroelectric 

plants, for example – and that suffi cient transmission capability exists to deliver plant output and meet reliability 

needs. 

In addition, transmission fl ows must be monitored to ensure that fl ows stay within voltage and reliability limits. 

New York ISO Supply Stack

Source: Ventyx
 Energy Primer | 59

If transmission fl ows exceed accepted limits, the operator 

must take corrective action, which could involve curtailing 

schedules, changing the dispatch or shedding load. Operators may check conditions and issue adjusted dispatch 

instructions as often as every fi ve minutes.

Ancillary Services

Ancillary services maintain electric reliability and support 

the transmission of electricity. These services are produced 

and consumed in real-time, or in the very near term. NERC 

and regional entities establish the minimum amount of 

each ancillary service that is required for maintaining grid 

reliability. 

Regulation matches generation with very short-term 

changes in load by moving the output of selected resources up and down via an automatic control signal, typically 

every few seconds. The changes are designed to maintain 

system frequency at 60 hertz. Failure to maintain a 60-

hertz frequency can result in collapse of an electric grid. 

Operating reserves are needed to restore load and generation balance when a generating unit trips off line. Operating reserves are provided by generating units and demand 

resources that can act quickly, by increasing output or reducing demand, to make up a generation defi ciency. There 

are three types:

1. are primary. To provide spinning Spinning reserves

reserve a generator must be on line (synchronized to 

the system frequency) with some unloaded (spare) capacity and be capable of increasing its electricity output within 10 minutes. During normal operation these 

reserves are provided by increasing output on electrically synchronized equipment or by reducing load on 

pumped storage hydroelectric facilities. Synchronized 

reserve can also be provided by demand-side resources.

2. come from generating units Nonspinning reserves

that can be brought online in 10 minutes. Nonspinning reserve can also be provided by demand-side 

resources.

3. come from generating units Supplemental reserves 

that can be made available in 30 minutes and are not 

necessarily synchronized with the system frequency. 

Supplemental reserves are usually scheduled in the 

day-ahead market, allowing generators to offer their 

reserve energy at a price, thus compensating cleared 

supply at a single market clearing price. This only applies to ISO/RTOs, and not all reliability regions have a 

supplemental reserve requirement. 

Black start generating units have the ability to go from a 

shutdown condition to an operating condition and start 

delivering power without any outside assistance from the 

electric grid. Hydroelectric facilities and diesel generators have this capability. These are the fi rst facilities to be 

started up in the event of a system collapse or blackout to 

restore the rest of the grid.

Reactive power. Electricity consists of current, the fl ow 

of electrons, and voltage, the force that pushes the current through the wire. Reactive power is the portion of 

power that establishes and maintains electric and magnetic 

fi elds in AC equipment. It is necessary for transporting AC 

power over transmission lines, and for operating magnetic 

equipment, including rotating machinery and transformers. 

It is consumed by current as it fl ows. As the amount of 
60 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

electricity fl owing on a line increases, so does the amount 

of reactive power needed to maintain voltage and move 

current. Power plants can produce both real and reactive 

power, and can be adjusted to change the output of both. 

Special equipment installed on the transmission grid is also 

capable of injecting reactive power to maintain voltage.

Weather

Weather is the single greatest driver of electric demand 

and, thus, is a major factor in grid operations. System operators therefore rely heavily on weather forecasts to ensure 

they have the right generation in the right locations to run 

the grid reliably. 

Weather affects grid operations in other ways, as well. Primary among these is on the productivity of certain types of 

power generators: wind and hydroelectric. Wind turbines’ 

power output changes with wind availability and speed, 

which affects cost of wholesale power. 

Hydroelectric plants rely on rain and snowfall to provide 

the river fl ow needed for their output. Geographically, this 

is most important in the Pacifi c Northwest, where seasonal 

hydro plant output is a critical source of power. Rain and 

the melting of winter snowpack feed the Columbia and 

Snake river systems. Surplus power from these generators 

is typically exported to California to help meet summer 

peak demand and provide a combination of increased reliability and lower prices.

Temperature can also affect the output of other power 

plants and capacity of transmission lines. Specifi cally, 

thermal plants that use a turbine – coal, gas, oil and nuclear plants – become less effi cient at higher temperatures. 

Additionally, the capacity of transmission lines is limited by 

heat because the conductive material used in fabrication 

becomes more electrically resistant as they heat up, limiting their throughput.

Markets and Trading

Overview

Markets for delivering power to consumers in the United 

States are split into two systems: traditional regulated markets and market-regulated markets run by regional transmission organizations (RTOs), which include independent 

system operators (ISOs).

In general, RTOs use their markets to make operational decisions, such as generator dispatch. Traditional systems rely 

on management to make those decisions, usually based on 

the cost of using the various generation options.

Trading for power is also split into over-the-counter (OTC) 

or bilateral transactions, and RTO transactions. Bilateral 

transactions occur in both traditional systems and in RTO 

regions, but in different ways.

Pricing in both RTO and traditional regions incorporate 

both cost-of-service and market-based rates.

Bilateral Transactions

Bilateral or OTC transactions between two parties do not 

occur through an RTO. In bilateral transactions, buyers and 

sellers know the identity of the party with whom they are 

doing business. 

Bilateral deals can occur through direct contact and negotiation, through a voice broker or through an electronic 

brokerage platform, such as the IntercontinentalExchange 

(ICE). The deals can range from standardized contract 

packages, such as those traded on ICE, to customized, 

complex contracts known as structured transactions.

Whether the trade is done on ICE, directly between parties 

or through another type of broker, the trading of standard 
 Energy Primer | 61

physical and fi nancial products, such as next-day on-peak 

fi rm or swaps, allows index providers to survey traders and 

publish price indexes. These indexes provide price transparency.

Physical bilateral trades involving the movement of the 

energy from one point to another require that the parties reserve transmission capacity to move the power over 

the transmission grid. Transmitting utilities are required 

to post the availability of transmission capacity and offer 

service on an Open Access Same-Time Information System 

(OASIS) website. Traders usually reserve transmission capacity on OASIS at the same time they arrange the power 

contract.

When it comes time to use the reservation to transfer power between balancing authorities, one of the parties to the 

transaction submits an eTag electronically to Open Access 

Technology International (OATI), NERC’s eTag contractor. 

OATI will process the tag and send it to all parties named 

on the eTag. This ensures the orderly transfer of energy 

and provides transmission system operators the information they need to institute curtailments as needed. Curtailments may be needed when a change in system conditions reduces the capability of the transmission system to 

move power and requires some transactions to be cut or 

reduced. 

Bilateral physical transactions conducted in RTOs are settled fi nancially. Generators offer their power into the RTO 

markets, and load is served through the power dispatched 

by the RTO. The RTO then settles bilateral transactions 

based on the prices in the contracts and the prices that occurred in the RTO markets. 

Source: Energy Velocity
62 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Cost-Based Rates

Cost-based rates are used to price most transmission services and some electricity when the Commission determines 

that market-based rates are not appropriate, or when an 

entity does not seek market-based rate authority. Costbased rates are set to recover costs associated with providing service and give a fair return on capital. Cost-based 

rates are typically listed in a published tariff.

The following are major inputs to setting cost-based electricity rates:

• Determining used-and-useful electricity plants. This 

may include generation facilities, transmission facilities, 

distribution plants and offi ce and related administration facilities.

• Determining expenses from the production, transmission and distribution of electricity, including fuel and 

purchased power, taxes and administrative expenses.

• Establishing a fair return on capital, known as the cost 

of capital. This includes determining the cost of debt, 

common equity, preferred stock and commercial paper 

and other forms of short-term borrowing such as lines 

of credit used to fi nance projects and provide cash for 

day-to-day operations.

• Allocating electric plant and other expenses among 

various customer classes and setting the rate structure 

and rate levels.

Market-Based Rates

Under market-based rates, the terms of an electric transaction are negotiated by the sellers and buyers in bilateral 

markets or through RTO market operations. The Commission grants market-based rate authority to electricity sellers 

that demonstrate that they and their affi liates lack or have 

adequately mitigated horizontal market power (percent of 

generation owned relative to total generation available in 

a market), and vertical market power (the ability to infl uence the cost of production for competitive electricity 

suppliers). Wholesale sellers who have market-based rate 

authority and who sell into day-ahead or real-time markets 

administered by a RTO do so subject to the specifi c RTO 

market rules approved by the Commission and applicable 

to all market participants. Thus, a seller in such markets 

not only must have an authorization based on analysis of 

that individual seller’s market power, but it must abide by 

additional rules contained in the RTO tariff.

Supplying Load

Suppliers serve customer load through a combination of 

self-supply, bilateral market purchases and spot purchases. 

In addition to serving load themselves, load-serving entities (LSEs) can contract with others to do so. The choices 

are:

• Self-supply means that the supplying company generates power from plants it owns to meet demand.

• Supply from bilateral purchases means that the loadserving entity buys power from a supplier. 

• Supply from spot RTO market purchases means the 

supplying company purchases power from the RTO.
 Energy Primer | 63

LSEs’ sources of energy vary considerably. In ISO-NE, NYISO and CAISO, the load-serving entities divested much or 

all of their generation. In these circumstances, LSEs supply 

their customers’ requirements through bilateral and RTO 

market purchases. In PJM, MISO and SPP, load-serving 

entities may own signifi cant amounts of generation either 

directly or through affi liates and therefore use self-supply 

as well as bilateral and RTO market purchases.

Traditional Power Markets

Traditional wholesale electric markets exist primarily in 

the Southeast, Southwest and Northwest. About 40 percent 

of all retail customers are in traditional wholesale markets 

where utilities are responsible for system operations and 

management, and, typically, for providing power to retail 

consumers. Utilities in these markets are frequently vertically integrated – they own the generation, transmission 

and distribution systems used to serve electric consumers. 

They may also include federal systems, such as the Bonneville Power Administration, the Tennessee Valley Authority and the Western Area Power Administration. Utilities in 

traditional regions have the following responsibilities:

• Generating or obtaining the power needed to serve 

customers (this varies by state);

• ensuring the reliability of its transmission grid;

• balancing supply and demand instantaneously;

• dispatching its system resources as economically as 

possible;

• coordinating system dispatch with neighboring 

balancing authorities;

• planning for transmission requirements within the 

utility’s footprint; and 

• coordinating its system development with neighboring 

systems.

Wholesale physical power transactions occur through bilateral markets.

Regional Markets

Introduction

Two-thirds of the population of the United States and 

more than one-half of Canada’s population are served by 

electricity markets run by regional transmission organizations or independent system operators (RTOs/ISOs). There is 

little practical distinction between a RTO and an ISO. The 

main distinction between RTO/ISO markets and their predecessors (such as vertically integrated utilities, municipal 

utilities and co-ops) is that RTO/ISO markets deliver reliable 

electricity through competitive market mechanisms. 

The basic functions of a RTO or ISO include the following:

• Ensure the reliability of the transmission grid;

• operate the grid in a defi ned geographic footprint; 

• balance supply and demand instantaneously;

• operate competitive nondiscriminatory electricity markets; 

• provide nondiscriminatory interconnection service to 

generators; and

• plan for transmission expansion on a regional basis.

In performing these functions, RTOs have operational control of the transmission system, are independent of their 

members, coordinate the maintenance of generation and 

transmission system, and oversee a transmission planning 

process to identify needed upgrades in both the near- and 

long-term.

RTOs/ISOs do not own transmission or generation assets; 

perform the actual maintenance on generation or transmission equipment; or directly serve end use customers.

Currently, seven RTOs/ISOs operate in the United States, 
64 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

listed below in order of the size of their peak load: 

• PJM Interconnection (PJM); 145 GW (summer)

• Midwest ISO (MISO); 137 GW (summer)

• Electric Reliability Council of Texas (ERCOT); 63 GW 

(summer)

• California ISO (CAISO); 50 GW (summer)

• Southwest Power Pool (SPP); 47 GW (summer)

• New York ISO (NYISO); 34 GW (summer)

• New England ISO (ISO-NE); 27 GW (summer)

Market Operations

RTO operations encompass multiple services that are needed to provide reliable and economically effi cient electric 

service to customers. Each of these services has its own 

parameters and pricing. The RTOs use markets to determine the provider(s) and prices for many of these services. These markets include the day-ahead energy market 

(sometimes called a Day 2 market), real-time energy market 

(sometimes called a Day 1 or balancing market), capacity 

markets (designed to ensure enough generation is available 

to reliably meet peak power demands), ancillary services 

markets, fi nancial transmission rights (contracts for hedging the cost of limited transmission capability) and virtual 

trading (fi nancial instruments to create price convergence 

in the day-ahead and real-time markets).

RTO Energy Markets

All but one RTO (i.e., SPP) electricity market has day-ahead 

and real-time markets. The day-ahead market schedules 

electricity production and consumption before the operating day, whereas the real-time market (also called the 

balancing market) reconciles any differences between the 

schedule in the day-ahead market and the real-time load 

while observing reliability criteria, forced or unplanned outages and the electricity fl ow limits on transmission lines.

The day-ahead energy market produces fi nancially binding 

schedules for the production and consumption of electricity one day before its production and use (the operating 

day). The purpose of the day-ahead market is to give generators and load-serving entities a means for scheduling 

their activities suffi ciently prior to their operations, based 

on a forecast of their needs and consistent with their business strategies.

In day-ahead markets, the schedules for supply and usage of energy are compiled hours ahead of the beginning 

of the operating day. The RTO then runs a computerized 

market model that matches buyers and sellers throughout 

the geographic market footprint for each hour throughout 

the day. The model then evaluates the bids and offers of 

the participants, based on the power fl ows needed to move 

the electricity throughout the grid from generators to consumers. Additionally, the model must account for changing system capabilities that occur based on weather and 

equipment outages, plus rules and procedures that are used 

to ensure system reliability. The market rules dictate that 

generators submit supply offers and loads submit demand 

bids to the RTO by a deadline that is typically in the morning of the day-ahead scheduling. Typically, 95 percent 

of all energy transactions are scheduled in the day-ahead 

market, and the rest scheduled in real-time.

Generation and demand bids that are scheduled by the dayahead market are settled at the day-ahead market prices. 

Inputs into setting a day-ahead market schedule include:

• Generator offers to sell electricity each hour;

• bids to buy electricity for each hour submitted by loadserving utilities;

• demand-response offers by customers to curtail usage 

of electricity;

• virtual demand and supply offers; and

• operational information about the transmission grid 

and generating resources, including planned or known 
 Energy Primer | 65

transmission and generator outage, the physical characteristics of generating resources including minimum 

and maximum output levels and minimum run time 

and the status of interconnections to external markets.

The real-time market is used to balance the differences 

between the day-ahead scheduled amounts of electricity 

based on day-ahead forecast and the actual real-time load. 

The real-time market is run hourly and in 5-minute intervals and clears a much smaller volume of energy and ancillary services than the day-ahead market, typically accounting for only 5 percent of scheduled energy. For generators, 

the real-time market provides additional opportunities for 

offering energy into the market. Megawatts over- or under-produced relative to the day-ahead commitments are 

settled at real-time prices. 

Real-time market prices are signifi cantly more volatile than 

the day-ahead market prices. This stems from demand uncertainty, transmission and generator forced outages and 

other unforeseen events. Because the day-ahead market 

generally is not presented with these events, it produces 

more stable prices than in real-time. Also, because the 

volumes in the real-time market are much smaller, there is 

an increased likelihood of supply and demand imbalances, which lead to both positive and negative price movements. 

RTOs use markets to deal with transmission constraints 

through locational marginal pricing (LMP).

The RTO markets calculate a LMP at each location on the 

power grid. The LMP refl ects the marginal cost of serving load at the specifi c location, given the set of generators that are being dispatched and the limitations of the 

transmission system. LMP has three elements: an energy 

charge, a congestion charge and a charge for transmission 

system energy losses. 

If there are no transmission constraints, or congestion, 

LMPs will not vary signifi cantly across the RTO footprint. 

Transmission congestion occurs when there is not enough 

transmission capacity for all of the least-cost generators 

to be selected. The result is that some more expensive 

generation must be dispatched to meet demand, units that 

might not otherwise run if more transmission capacity were 

available.
66 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

When there are transmission constraints, the highest variable cost unit that must be dispatched to meet load within 

transmission-constrained boundaries will set the LMP in 

that area. All sellers receive the LMP for their location and 

all buyers pay the market clearing price for their location.

The primary means used for relieving transmission congestion constraints is by changing the output of generation 

at different locations on the grid. The market-based LMP 

sends price signals that refl ect congestions costs to market 

participants. That is, LMPs take into account both the impact of specifi c generators on the constrained facility and 

the cost to change (redispatch) the generation output to 

serve load. This change in dispatch to is known as security 

constrained redispatch (see chart).

This redispatch could be implemented by using nonmarket 

procedures such as transmission loading relief (TLR). North 

American Electric Reliability Corp. (NERC) established the 

TLR process for dealing with reliability concerns when the 

transmission network becomes overloaded and power fl ows 

must be reduced to protect the network. A TLR is used to 

ration transmission capacity when the demand for transmission is greater than the available transmission capacity 

(ATC). The rationing is a priority system that cuts power 

fl ows based on size, contractual terms and scheduling. 

Scarcity pricing is a mechanism used by RTOs and ISOs to 

send price signals in the real-time market when there is a 

systemwide shortage of power reserves. These events occur 

when there is a shortage of power to meet system requirements to meet load and provide suffi cient backup reserves. 

This can be caused by unexpectedly high power loads, supply disruptions or both.

RTOs follow one of four approaches to ensure that the 

market price for energy accurately refl ects the value of energy during shortage periods: 

• ncrease the allowed bidding price of energy supply I

above normal levels during an emergency;

• Increase bid caps above the current level during an 

emergency for demand bids, while keeping generation 

offer caps in place; 

• Establish a pricing structure for operating reserves that 

would raise prices as operating reserves grow short 

(demand curve); and

• Set the market-clearing price during an emergency for 

all supply and demand response resources dispatched 

equal to the payment made to participants in an emergency demand-response program. 

Reliability must-run (RMR) units are generating plants that 

would otherwise retire but the RTO has determined they are 

needed to ensure reliability. They could also be units that 

have market power due to their location on the grid. RTO/

ISOs enter into cost-based contracts with these generating 

units and allocate the cost of the contract to transmission 

customers. In return for payment, the RTO may call on the 

owner of an RMR generating unit to run the unit for grid 

reliability. The payment must be suffi cient to pay for the 

cost of owning and maintaining the unit even if it does 

not operate. 
 Energy Primer | 67

The reason for developing capacity markets (described below) is in part to compensate generation owners for keeping these units in service where necessary, in addition to 

prompting the construction of new generation and use of 

demand response by consumers. Transmission upgrades 

can also reduce the need for RMR units by increasing generation deliverability throughout the RTO.

RTO Capacity Markets 

RTOs, like other electric systems, are required to maintain adequate generation reserves to ensure that suffi cient 

generation and demand-resource capacity are available to 

meet load and reliability requirements. LSEs have typically 

satisfi ed their reserve obligations with owned generation 

or bilateral contracts with other suppliers. Some RTOs have 

mechanisms to obtain capacity commitments, such as capacity auctions and capacity payments.

Most RTOs run a capacity market to allow LSEs a way to 

satisfy their reserve obligation. These markets cover shortterm capacity, such as a month, season or year. PJM and 

ISO-NE run capacity auctions up to three years prior to 

when the capacity is needed. The near-term focus is consistent with providing payments to existing generation, or 

generation such as combustion turbines that can be sited 

and built within three years. 

Financial Transmission Rights

Financial transmission rights (FTRs) are contracts that give 

market participants an offset, or hedge, against transmission congestion costs in the day-ahead market. They protect the holder from costs arising from transmission congestion over a specifi c path on the grid.

FTRs were originally developed in part to give native loadserving entities in the nascent RTOs price certainty similar 

to that available to traditional vertically integrated utilities 

operating in non-RTO/ISO markets. This practice continues, 

as FTRs are allocated to load-serving entities, transmission 

owners or fi rm transmission right holders in RTOs based on 

historical usage, and to entities that fund the construction 

of specifi c new transmission facilities. The details of the 

programs vary by RTO.

FTRs allow customers to protect against the risk of congestion-driven price increases in the day-ahead market in 

the RTOs and ISOs. Congestion costs occur as the demand 

for scheduled power over a transmission path exceeds that 

path’s fl ow capabilities. For example, if the transmission 

capacity going from Point A (the source) to Point B (the 

sink) is 500 MW, but the RTO seeks to send 600 MW of 

power from Point A to Point B when calling on the leastcost generators to serve load, the path will be congested. 

This will cause the price at the source to decline or the 

price at sink to increase, or both, causing the congestion 

cost of serving point B from Point A to increase. By buying an FTR over the path from Point A to Point B, the FTR 

holder is paid the difference of the congestion prices at 

the sink and source, thus allowing it to hedge against the 

congestion costs incurred in the day-ahead market. 

FTRs are acquired through allocations and purchases. 

FTRs can be purchased in the RTO-administered auctions 

or in the secondary market.

Allocations may stem from a related product, auction revenue right (ARR). ARRs provide the fi rm transmission capacity holders, transmission owners or LSEs with a portion of 

the money raised in the FTR auctions. In general, they are 

allocated based on historic load served and, in some RTOs, 

can be converted to FTRs. As with FTRs, ARRs, too, give 

eligible members an offset or hedge against transmission 

congestion costs in the day-ahead market. If converted to 

FTRs, the holder gets revenue from congestion. If kept as 

ARRs, the holder gets revenue from the FTR auction.
68 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

The main method for procuring FTRs is through an auction, 

which typically includes an annual (or multiyear) auction 

of one-year FTRs and monthly (or semiannually) auctions 

of shorter-term FTRs provided by existing FTR holders or 

made available by the RTO. The auctions are scheduled 

and run by the RTO, which requires bidding parties to post 

credit to cover the positions taken. FTR auction revenues 

are used to pay the holders of ARRs and assist the funding 

of future congestion payments to FTR holders. There is 

also a secondary market for FTRs (such as PJM’s eFTR), but 

only a small number of transactions have been reported.

The quantity of FTRs made available by the RTO is bounded by the physical limits of the grid, as determined by a 

simultaneous feasibility test across all potential fl owgates. 

This test is performed by the RTO prior to making FTRs 

available at auction, and takes into account existing FTR 

positions and system constraints. The resulting portfolio of 

FTRs allocated or offered at auction represents an absolute 

constraint on the size of the net positions that can be held 

by the market. Participants in FTR auctions can procure 

counterfl ow FTRs, which directly offset prevailing fl ow FTR 

capacity, thereby allowing the value at risk on a given path 

to exceed the physical limits of the line. However, such 

bids are physically constrained, as the net position held on 

the path must always conform to the simultaneous feasibility test.

Although FTRs are used by transmission providers and loadserving entities as a hedge, they can be purchased by any 

creditworthy entity seeking their fi nancial attributes either 

as a hedge or as a speculative investment. In this regard, 

FTRs are similar to fi nancial swaps that are executed as 

a contract for differences between two day-ahead LMPs 

(swaps are explained in the chapter on fi nancial markets). 

However, FTRs are substantially different from swaps in 

that the quantity of FTRs is linked to physical constraints 

in the transmission grid, while the quantity of swaps is 

not. Further, FTRs are procured by allocation or FTR auction, while swaps are procured through fi nancial over-thecounter markets or exchanges.

Variation in RTO FTRs

Five of the six FERC-jurisdictional RTOs trade FTRs or FTR 

equivalent products, with SPP planning to use FTRs in its 

future market design. However, the types and qualities of 

the rights traded across the organized markets vary, as do 

differences in the methods used to allocate, auction and 

transfer these rights. These attributes of the FTR markets 

are discussed below.

Flow Type: Prevailing Flow and Counterfl ow. A prevailing 

fl ow FTR generally has a source in an historic generationrich location and a sink that is in a historic load-heavy 

location. Alternatively, the source of a prevailing fl ow FTR 

is on the unconstrained side of a transmission interface and 

the sink on the constrained side. Auction clearing prices 

for prevailing fl ow FTRs are positive. Conversely, a counterfl ow FTR often has a source in an historic load-heavy 

location and a sink that in an historic generation-rich location. As a result, auction clearing prices for counterfl ow 

FTRs are negative.

Peak Type: On-peak, Off-peak, 24-hour. FTRs can be purchased for either 16-hour on-peak blocks, 8-hour off-peak 

blocks or around-the-clock. Only PJM offers all three peak 

type products, whereas ISO-NE, MISO and CAISO offer onpeak and off-peak products. NYISO offers only the 24-hour 

product. 

Allocated Rights. The fi ve RTOs allocate transmission rights 

to transmission owners or load-serving entities within their 

markets. In PJM, MISO and ISO-NE, these are allocated 

as auction revenue rights (ARRs), which give their holders the right to receive a share of the funds raised during 

the FTR auctions. The CAISO allocates congestion revenue 

rights (CRR), which provide their holders a stream of pay-
 Energy Primer | 69

ments based on the actual congestion occurring on associated paths. Finally, NYISO allocates both auction-based 

and congestion-based rights through multiple instruments. 

PJM and MISO allow ARR holders to convert all of these 

rights to FTRs; NYISO allows only a portion of ARR-equivalent instruments to be converted to its version of FTRs, 

called transmission congestion credits (TCCs). ISO-NE does 

not allow such conversions, while the CAISO’s allocation is 

already in a form equivalent to an FTR. Converted ARRs are 

fully fungible in PJM, the MISO and NYISO; CAISO only 

allows the sale of allocated CRRs in its secondary market, 

and ISO-NE has no converted instruments to sell. 

Auctioned Rights. All RTOs provide FTRs (or equivalent 

CRRs or TCCs) for sale to the public through two or more 

auctions held at various times of the year. The products 

sold vary by market and by auction, with some products 

made available only at specifi c auctions. 

Secondary Markets. With the exception of the NYISO, each 

of the markets that auction FTRs also operates a bulletin 

board or similar venue designed to enable a secondary trading platform for FTRs. However, none of these platforms 

has had signifi cant volume. NYISO offered to create a bulletin board for its participants if requested, but received no 

requests. The CAISO is the only market that requires the 

reporting of secondary FTR transactions; such transactions 

have not occurred despite the inability of CRR holders to 

resell their positions through the auction process.

Virtual Transactions 

Virtual bids and offers (collectively, virtuals) are used by 

traders participating in the RTO markets to profi t from 

differences between day-ahead and real-time prices. The 

quantity of megawatts (MW) purchased or sold by the 

trader in the day-ahead market is exactly offset by a sale or 

purchase of an identical quantity of MW in the real-time, 

so that the net effect on the market quantity traded is zero. 

Virtual trading is allowed in the fi ve RTOs with day-ahead 

and real-time markets.

Although a trader does not have to deliver power, the 

transaction is not strictly fi nancial. Virtual transaction can 

physically set the LMPs, the basis for payments to generators or from load. 

For each hour, net virtual trades are added to the demand 

forecast for load if virtual demand is greater than virtual supply. This has the effect of raising the price in the 

day-ahead market and, more importantly, increasing the 

amount of generation resources procured by the RTO/ISO. 

Since these resources will be available to the real-time market, the failure of the virtual load to materialize will decrease the real-time demand below forecast, thus placing 

downward pressure on real-time prices. The placement of 

virtuals affects the dispatch of physical capacity.

The primary benefi ts of virtual transactions are achieved 

through their fi nancial impact on the markets. Virtuals 

sometimes are referred to as convergence bidding, as a 

competitive virtual market should consistently cause the 

day-ahead and real time prices to converge in each hour.

The convergence of day-ahead and real-time prices within 

the RTOs is is intended to mitigate market power and improve the effi ciency of serving load. Thus, virtuals have a 

physical impact upon the operations of the RTO, as well as 

on market participants that physically transact at the LMPs 

set in the day-ahead and real-time markets.

Transmission Operations 

Each RTO’s Open Access Transmission Tariff (OATT) specifi es the transmission services that are available to eligible 

customers. Customers submit requests for transmission 

service through the Open Access Same-Time Information 

System (OASIS). RTOs evaluate each transmission-service 
70 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

request using a model of the grid called a state estimator. 

Based on the model’s estimation of the effects on the system, the request for transmission service is either approved 

or denied. 

Transmission operators, including RTOs, offer two major 

types of transmission service: point-to-point service and 

network service. Network service generally has priority 

over point-to-point service. RTOs work with transmission 

owners to plan and coordinate the operation, maintenance 

and expansion of transmission facilities in order to provide 

network and point-to-point customers with transmission 

service.

Network transmission service is used for the transmission 

of energy from network generating resources to an RTO’s 

network loads.

• Network transmission service enables network customers to use their generation resources to serve their 

network loads in a RTO. 

• Network customers also can use the service to deliver 

economy energy purchases to their network loads. 

Point-to-point transmission service uses an RTO’s system for the transmission of energy between a point of receipt and a point of delivery, which can be into, out of, or 

through the RTO’s Control Area. RTOs offer fi rm and nonfi rm point-to-point transmission service for various lengths 

of time.

• Firm service has reservation priority over nonfi rm 

point-to-point service.

• Nonfi rm point-to-point transmission service is provided 

PJM MISO ISO-NE NYISO CAISO

 

Name for Allocated Transmission Rights ARRs ARRs ARRs Multiple CRR 

 

Convertible to Congestion Rights? Yes Yes No Some - 

Name for Auctioned Congestion Rights FTRs FTRs FTR TCCs CRRs 

 

Congestion Right Auction Format 

 Annual Yes Yes Yes No Yes 

 Semiannual No No No Yes No 

 Monthly Yes Yes Yes Yes Yes 

 

Congestion Right Auction Products: 

 Multiyear Yes No No No No 

 Annual Yes No Yes Yes No 

 Semiannual No No No Yes No 

 Quarterly Yes Yes No No Yes 

 Monthly Yes Yes Yes Yes Yes 

Auction Allows Participant Resale? Yes Yes Yes Yes No 

Congestion Right Options Yes No No No No 

 

Formal Secondary FTR Market? Yes Yes Yes No Yes 

Transmission Rights by Transmission Grid
 Energy Primer | 71

from the available transmission capability beyond network and fi rm point-to-point transmission service.

Transmission Planning

RTOs have systemwide or regional planning processes that 

identify transmission system additions and improvements 

needed to keep electricity fl owing. Studies are conducted that test the transmission system against mandatory 

national reliability standards as well as regional reliability 

standards. The North American Electric Reliability Corp. 

(NERC) is the organization responsible for setting national 

reliability standards. 

RTO transmission planning studies may look 10-15 years 

into the future to identify transmission overloads, voltage 

limitations and other reliability problems. RTOs then develop transmission plans in collaboration with transmission 

owners to resolve potential problems that could otherwise 

lead to overloads and blackouts. This process culminates in 

one recommended plan for the entire RTO footprint. 

 

Financial Policies

Financial settlement is the process through which payments 

due from customers and to generators are calculated. Market settlements depend on day-ahead schedules, real-time 

metering, interchange schedules, internal energy schedules, 

ancillary service obligations, transmission reservations, energy prices, FTR positions and capacity positions. For each 

market participant a customer invoice of charges and credits includes the costs of services used to serve load.

Generally, customers receive weekly or monthly invoices 

stating their charges and credits. Weekly invoices must be 

settled within a few days of being issued, while monthly 

invoices must be paid within either one or two weeks depending on the policies of each RTO. All payments are 

made electronically. Disbursements are made within several days of the date payments are due. 

Credit Policies

Defaults by market participants in RTOs have generally 

been socialized, meaning that the cost is spread across the 

market. To minimize this risk, RTOs have credit policies 

in their tariffs, which contain provisions related to credit 

evaluations, credit limits, forms of collateral and the consequences of violations or defaults.

Regions

Markets vary around the United States by market type 

– traditional or RTO – generation types, customer use, 

climate, fuel costs, political and regulatory conditions, and 

other factors. Consequently, prices vary, driven by these 

market factors. 

Southeast Wholesale Market

The Southeast electric market is a bilateral market that 

includes all or parts of Florida, Georgia, Alabama, Mississippi, Louisiana, Arkansas, Tennessee, North Carolina, South 

Carolina, Texas, Missouri and Tennessee. It encompasses 

all or part of two NERC regions: the Florida Reliability 

Coordinating Council (FRCC) and the Southeastern Electric 

Reliability Council (SERC). Major hubs include Entergy, 

Southern and TVA. 

Southeastern power markets have their roots in the 1960s. 

In the wake of the Northeast Blackout of 1967, the Southeast began to build out its electric transmission grid; there 

now are several large transmission lines connecting large 

power plants to the grid. This was primarily to ensure 

reliability, but it also had economic consequences. 

Increased integration allowed utilities to more effectively 

share reserves, as well as the costs and risks of new plant 

construction. 
72 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Southeast Electric Regions 

If a utility were building a large nuclear or coal- fi red generating facility, it would be cost-effective to have reserve 

sharing agreements with neighboring systems that provided the backup or capacity reserves, rather than building 

reserves individually. In addition, a stronger grid allowed 

the output of large power plants to be deliverable throughout the region, thus allowing more than one utility to share 

in the ownership and the costs of building large new plants. 

This reduced the fi nancial risks associated with ownership 

of large new generating facilities to any single utility, thus 

making ownership of large base-load coal and nuclear units 

more affordable to the utilities and less risky. 

A stronger transmission system also allowed for more economic transactions, including both spot transactions and 

long-term fi rm power deliveries. External sales resulted in 

more effi cient use of grid resources and reduced costs to 

both buyers and sellers.

Resource Base

Within the Southeast, the resource mix varies between the 

two NERC subregions. The FRCC uses more gas- and oilfi red generation than the rest of the Southeast, and it is 

the only area where oil is signifi cantly employed. Gas is 

the marginal fuel in almost all hours in the FRCC. Within 

SERC, the Southern subregion has historically generated 

as much as 85 percent of its electricity from baseload coal 

and nuclear plants. In recent years, natural gas used for 

generating electricity has become increasingly popular. The 
 Energy Primer | 73

pattern began to change as gas supplies increased and 

prices fell and natural gas-fi red power plants began to 

displace older, less-effi cient coal-fi red generation.

The Entergy subregion uses gas to a much greater extent 

than the regional average; it is the marginal fuel more than 

70 percent of the time. The TVA subregion has a signifi cant 

amount of hydro and nuclear capacity and output, and 

very little dependence on gas. The VACAR subregion has 

the highest utilization of nuclear generation in the Southeast; 94 percent of this subregion’s output is from baseload 

coal and nuclear facilities.

Trading and Markets

Physical and fi nancial electricity products are traded using 

Entergy, Southern, TVA, VACAR and Florida price points. 

Volumes for these products remain low, especially in 

Florida, where merchant power plant development is 

restricted by a state statute. 

Virtually all the physical sales in the Southeast are done 

bilaterally. Long-term energy transactions appear to be a 

hallmark of the Southeast; wholesale electricity transactions for a year or more outweigh spot transactions. Many 

long-term agreements involve full-requirements contracts 

or long-term purchase power agreements. Spot transactions accounted for less than one percent of overall supply 

and tend to occur during periods of system stress, usually 

summer heat waves or winter cold snaps. Even for a large 

company such as Southern Co., spot transactions occurred 

less than 30 percent of the time.

Wholesale spot power markets in the Southeast have little spot trading and lack transparency. The relative lack 

of spot trades yields little data on which to base price 

reporting. ICE reports no electric power price for Florida. 

And while another publisher reports one spot electric power price for Florida, on most days, there are no reported 

volumes. Given the bilateral nature of wholesale power 

transactions in the Southeast, and the small spot market, 

interest in fi nancial power products in the Southeast is 

weak. As a result, ICE does not provide a fi nancial swap 

product in the Southeast.

Despite the bilateral nature of the wholesale trade and 

the small size of the spot market, marketers do have some 

presence in the Southeast. For example, Constellation Energy Commodities Group contributes to the trading in the 

Southern region, being a participant in 41 percent of total marketer related sales. While Constellation does not 

own generation in Southern, it does have several multiyear 

agreements with generating units.

Unique Market Features

Southern Co. Auction

Since April 23, 2009, Southern Co. has been holding daily 

and hourly auctions for power within its balancing area. 

This balancing area encompasses the service territories of 

Southern Co. utilities: Georgia Power, Alabama Power, Mississippi Power and Gulf Power.

According to the auction rules, Southern must offer all of 

its available excess generation capacity into the auction, 

after regulation and contingency reserves are met. The 
74 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

offer prices are capped because the auction is intended to 

mitigate any potential ability of Southern to withhold its 

generation resources within its balancing area.

The products auctioned are day-ahead power and real-time 

power (an auction takes place an hour ahead of when the 

energy is scheduled to fl ow). 

Offers to sell energy and bids to purchase energy are evaluated using the simple method of sorting offers in ascending order and bids in descending order. 

The auction matches parties to facilitate a bilateral transaction that is ultimately independent of the auction. Thus, 

there is no collateral requirement necessary to participate 

in the auction. However, credit screening rules dictate that 

matches are made only between entities willing and able 

to do business with one another. The selection process 

is based on information that each entity submits to the 

auction administrator.

When the auction began in 2009, Southern Co. was the 

only participant that could sell into it. On Jan. 3, 2010, 

other entities were allowed to sell into the auction, and 

Southern became eligible to make purchases in the auction 

as well as sales. However, activity in the auction has been 

sparse since its inception. 

Entergy Independent Coordinator of Transmission

Southwest Power Pool (SPP) serves as the independent coordinator of transmission (ICT) for Entergy Services. In this 

role, SPP oversees the operations of the Entergy transmission system and produces regional planning assessments. 

Florida IPP rule

The Florida Public Service Commission’s (PSC) competitive 

bidding rules require investor-owned utilities (IOUs) to issue requests for proposals for any new generating project 

of 75 MW or greater, exclusive of single-cycle combustionturbines. The bidding requirement can be waived by the 

PSC if the IOU can demonstrate that it is not in the best 

interests of its ratepayers. 

Western Regions

The power markets in the western United States are bilateral markets except in most of California. The West includes 

the Northwest Power Pool (NWPP), the Rocky Mountain 

Power Area (RMPA) and the Arizona, New Mexico, Southern Nevada Power Area (AZ/NM/SNV) within the Western 

Electricity Coordinating Council (WECC), a regional entity. These areas contain many balancing authorities (BAs) 

responsible for dispatching generation, procuring power, 

operating the transmission grid reliably and maintaining 

adequate reserves. Although the BAs operate autonomously, some have joint transmission-planning and reservesharing agreements. 

Physical sales in western states are almost entirely bilateral 

sales, with a small amount sold into the California ISO’s 

market. Trading in the western states differs from the rest 

of the country because fi nancial players are active in the 

physical markets, as well as having a robust fi nancial electricity market. 

The volume of fi nancial sales on ICE is roughly as large as 

physical sales. Physical sales in WECC are dominated by 

fi nancial and marketing companies.

The NWPP is composed of all or major portions of the 

states of Washington, Oregon, Idaho, Wyoming, Montana, 

Nevada and Utah, a small portion of Northern California 

and the Canadian provinces of British Columbia and Alberta. This vast area covers 1.2 million square miles. It is made 

up of 20 BAs. The peak demand is 54.5 GW in summer and 
 Energy Primer | 75

63 GW in winter. There is 80 GW of generation capacity, 

including 43 GW of hydroelectric generation.

Resources

The NWPP has a unique resource mix. Hydro generation 

is more than 50 percent of power supply, compared to the 

U.S. average of only 6 percent of power supply. The hydro 

generation is centered around many dams, mostly on the 

Columbia River. The largest dam, the Grand Coulee, can 

produce as much power as six nuclear plants. Due to the 

large amount of hydroelectric generation, the Northwest 

typically has cheap power and exports power to neighboring regions, especially California, to the extent that there is 

transmission capacity to carry the power to more expensive 

markets.

The amount of hydropower produced depends on a 

number of factors, some natural and some controllable. 

On a seasonal basis, the intensity and duration of the 

water fl ow is driven by snowpack upriver in the mountains, 

the fullness of the reservoirs and rainfall. On a short-term 

basis, the power generation is infl uenced by decisions to 

release water locally and upstream to generate power, as 

well as local water-use decisions that have nothing to do 

with the economics of power generation, but are made for 

recreation, irrigation and wildlife considerations. The peak 

generation begins in the spring, when the snow melts, and 

may last into early summer.

When there is less water available, the Northwest may 

rely more on its coal and natural gas generation. It will 

Northwest Electric Market
76 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

occasionally import power from neighboring regions when 

loads are high.

Trading and Markets

The water forecast affects the forward market for electricity 

in the Northwest. The daily water fl ow as well as weather 

conditions infl uence the prices in the daily physical market. When there is an abundance of hydro generation, the 

Northwest will export as much as possible on the transmission lines leading into California. Sometimes in off-peak 

hours there is so much generation that power prices are 

negative because the transmission lines are full and there is 

not enough local load to take all of the power. 

The largest seller of wholesale power is the Bonneville 

Power Administration (BPA), a federal agency that markets 

the output from federally owned hydroelectric facilities and 

owns 75% of the region’s high-voltage transmission. It 

meets approximately one-third of the region’s fi rm energy 

supply, mostly with power sold at cost. BPA gives preference to municipal and other publicly owned electric systems in allocating its output.

Both the Alberta IESO and British Columbia Hydro are members of the NWPP. Net interchange between these two BAs 

and the United States tends to result in net exports from 

the United States into Canada. Net interchange between 

U.S. and Canadian balancing authorities represents about 

one percent of total NWPP load.

The IntercontinentalExchange (ICE) has four trading points 

Southwest Electric Regions
 Energy Primer | 77

in the Northwest: Mid-Columbia (Mid-C), CaliforniaOregon Border (COB), Nevada-Oregon Border (NOB) and 

Mona (Utah). Mid-C has the most traded volume by far, 

averaging more than 6,700 MW of daily on-peak physical 

trades in 2009. COB had almost 600 MW, NOB had 100 

MW and Mona had 32 MW. Mid-C also has a fairly active 

physical forward market.

The Southwest electric market encompasses the Arizona, 

New Mexico, southern Nevada (AZ/NM/SNV) and the Rocky 

Mountain Power Area (RMPA) subregions of the Western 

Electric Coordinating Council (WECC). Peak demand is 

approximately 41 GW in summer and 29 GW in winter. 

There is 52 GW of generation capacity, composed mostly 

of gas and coal units. 

The Southwest relies on nuclear and coal generators for 

baseload electricity, with gas units used as peaking resources. The coal generators are generally located in close 

proximity to coal mines, resulting in low delivered fuel 

costs. Some generation is jointly owned among multiple 

nearby utilities, including the Palo Verde nuclear plant, a 

4,000-MW unit, which has owners in California and the 

Southwest. 

The AZ/NM/SNV region is summer-peaking and experiences 

high loads due to air conditioning demand. The daily high 

temperatures average above 100 degrees in June through 

August in Phoenix. However, power prices tend to be the 

highest when there is also hot weather in Southern California, creating competition for the generation resources.

CAISO

California Independent System Operator

Market Profi le

Geographic Scope

CAISO is a California nonprofi t public benefi t corporation 

started in 1998 when the state restructured its electric industry. The CAISO manages wholesale electricity markets, 

centrally dispatching electricity generation and facilities. 

In managing the grid, CAISO provides open access to the 

transmission system and performs long-term transmission 

planning. It manages energy and ancillary markets in dayahead and real-time markets and is responsible for regional 

reliability.

Peak Demand

CAISO’s all-time peak load was 50 GW in summer 2006. 

Import and Exports

About 25 percent of CAISO’s energy is supplied by imports, 

principally from two primary sources: the Southwest (Arizona, Nevada and New Mexico) and the Pacifi c Northwest 

(Oregon, Washington and British Columbia). Imports from 

the Pacifi c Northwest generally increase in the late spring 

when hydroelectric production peaks from increases in 

winter snowmelt and runoff. 
78 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Market Participants

CAISO’s market participants include generators, retail 

marketers and utility customers, ranging from the three big 

investor-owned utilities (IOUs), which include Pacifi c Gas 

& Electric (PG&E), Southern California Edison (SCE) and 

San Diego Gas &Electric (SDG&E), to municipalities and 

fi nancial participants.

Membership and Governance

The CAISO has a board of governors that consists of fi ve 

members appointed by the governor and confi rmed by the 

California Senate. The board’s role is to provide corporate direction, review and approve management’s annual 

strategic plans and approve CAISO’s operating and capital 

budgets.

CAISO uses an informal stakeholder process to propose solutions to problems that may ultimately require a fi ling at 

FERC. Unlike other RTOs, which have a formal committee 

structure, CAISO’s stakeholder process generally consists of 

rounds of dialogue with stakeholders on major policy issues. 

Transmission

Owners

The Participating Transmission Owners (PTOs) in the CAISO 

control area include: 

• Pacifi c Gas and Electric Co., 

• Southern California Edison, 

• San Diego Gas and Electric, and 

• Municipalities such as Vernon, Anaheim and Riverside. 

Chronic Constraints

Areas of the system that are chronically constrained include 

the Humboldt region in the northwest corner of the state, 

import lines from the Southwest and Southern California 

(including San Diego).

Transmission Planning

CAISO conducts an annual transmission planning process 

with stakeholders that includes both short-term and longterm projects.

Supply Resources

Generating Mix

By plant capacity, the generating mix includes these sources:

California Independent 

System Operator (CAISO)

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Natural Gas Nuclear Hydro and Renewables Coal Oil

Share of Regional Total (%)
 Energy Primer | 79

Demand Response

Demand-resource participation in the wholesale energy 

market is currently limited to a small amount of demand 

associated with water pumping loads. However, the market 

allows end-use loads that can be curtailed when directly 

dispatched in the real-time market to participate in the 

real-time energy and ancillary service (nonspinning reserve) 

markets. The California Public Utilities Commission is 

considering rules for allowing more retail demand-resource 

participation in the CAISO market. 

Other demand response in California consists of programs 

for managing peak summer demands developed by the 

state’s three major investor owned utilities. These demandresponse programs are triggered based on criteria that are 

internal to the utility and not necessarily tied to market 

prices, although in early 2012 CAISO had a proposal pending at the Commission to integrate these reliability-based 

retail programs into its wholesale market.

Market Features and Functions

Energy Markets

Day-Ahead Market

The day-ahead market allows participants to secure prices 

for electric energy the day before the operating day and 

hedge against price fl uctuations that can occur in real 

time. One day ahead of actual dispatch, participants 

submit supply offers and demand bids for energy. These 

bids are applied to each hour of the day and for each 

pricing location on the system.

From the offers and bids, CAISO constructs aggregate supply and demand curves for each location. The intersection 

of these curves identifi es the market-clearing price at each 

location for every hour. Supply offers below and demand 

bids above the identifi ed price are said to clear, meaning they are scheduled for dispatch. Offers and bids that 

clear are entered into a pricing software system along with 

binding transmission constraints to produce the locational 

marginal prices (LMP) for all locations.

Generator offers scheduled in the day-ahead settlement 

are paid the day-ahead LMP for the megawatts accepted. 

Scheduled suppliers must produce the committed quantity 

during real-time or buy power from the real-time market 

to replace what was not produced.

Likewise, wholesale buyers of electricity whose bids clear in 

the day-ahead market settlement pay for and lock in their 

right to consume the cleared quantity at the day-ahead 

LMP. Electricity use in real time that exceeds the day-ahead 

purchase is paid for at the real-time LMP.

Hour-Ahead Market

CAISO has an hour-ahead market for buying and selling 

imports and exports that it calls the hour-ahead scheduling 

process (HASP). HASP is designed to allow the ISO to reoptimize the market, given changes to internal supply and 

demand after the close of the day-ahead market. 

In HASP, imports and exports between the ISO and neighboring regions are pre-dispatched 45 minutes before the 

start of each operating hour. These imports and exports 

are scheduled at a fi xed level for the entire hour. However, resources within the CAISO and dynamic resources in 

neighboring regions (or balancing authority areas) can be 

dispatched every fi ve minutes within each operating hour 

to meet real-time loads. A dynamic resource is a resource 

that is physically located in a neighboring region or balancing authority areas, yet is controllable by the CAISO 

market. 
80 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Real-Time Market

CAISO must coordinate the dispatch of generation and 

demand resources to meet the instantaneous demand for 

electricity. While the day-ahead energy market produces 

the schedule and fi nancial terms of energy production and 

use for the operating day, a number of factors can change 

that schedule. Thus, to meet energy needs within each 

hour of the current day the CAISO operates a spot market 

for energy called the real-time market,

The real-time market uses fi nal day-ahead schedules for 

resources within the ISO and fi nal hour-ahead schedules for imports and exports as a starting point. It then 

re-dispatches resources every fi ve minutes to balance 

generation and loads. 

Prices resulting from the real-time market are only applicable to incremental adjustments to each resource’s dayahead schedule. Real-time bids can be submitted up to 75 

minutes before the start of the operating hour.

Ancillary and Other Services

Ancillary services are those functions performed by electric 

generating, transmission, and system-control equipment 

to support the reliability of the transmission system. RTOs 

procure or direct the supply of ancillary services. 

CAISO procures four ancillary services in the day-ahead and 

real-time markets:

• Regulation up: Units providing regulation up must be 

able to move quickly above their scheduled operating 

point in response to automated signals from the ISO 

to maintain the frequency on the system by balancing 

generation and demand.

• Regulation down: Units providing regulation down 

must be able to move quickly below their scheduled 

operating point in response to automated signals from 

the ISO.

• Spinning reserve: Resources providing spinning reserves must be synchronized with the grid (online, or 

spinning) and be able to respond within 10 minutes. 

This is more reliable than nonspinning reserves because 

it is already online and sychronized.

• Nonspinning reserve: Resources providing nonspinning 

reserves must be able to synchronize with the grid and 

respond within 10 minutes. 

Regulation up and regulation down are used continually 

to maintain system frequency by balancing generation and 

demand. Spinning and nonspinning resources are used to 

maintain system frequency and stability during emergency 

operating conditions (such as unplanned outage of generation or transmission facilities) and major unexpected 

variations in load. Spinning and nonspinning resources are 

often referred to collectively as operating reserves. 

Capacity Markets

Capacity markets provide a means for load-serving entities (LSEs) to procure capacity needed to meet forecast 

load, or resource adequacy (RA) requirements, and to allow 

generators to recover a portion of their fi xed costs. They 

also provide economic incentives to attract investment in 

new and existing supply-side and demand-side capacity 

resources needed to maintain bulk power system reliability 

requirements.

The CAISO does not operate a formal capacity market, but 

it does have a mandatory RA requirement. The program 

requires that LSEs procure 115 percent of their aggregate 

system load on a monthly basis, unless a different reserve 

margin is mandated by the LSE’s local regulatory authority. 

The program provides deliverability criteria each LSE must 

meet, as well as system and local capacity requirements. 
 Energy Primer | 81

Resources counted for RA purposes must make themselves 

available to the CAISO day-ahead and real-time markets 

for the capacity for which they were counted. 

Market Power Mitigation

In electric power markets, mainly because of the largely 

non-storable nature of electricity and the existence of 

transmission constraints that can limit the availability of 

multiple suppliers to discipline market prices, some sellers 

from time to time have the ability to raise market prices. 

Market power mitigation is a market design mechanism to 

ensure competitive offers even when competitive conditions are not present.

Market power may need to be mitigated systemwide or locally when the exercise of market power may be particularly 

a concern for a local area. For example, when a transmission constraint creates the potential for local market power, 

the RTO may apply a set of behavioral and market outcome 

tests to determine if the local market is competitive and if 

generator offers should be adjusted to approximate price 

levels that would be seen in a competitive market – close 

to short-run marginal costs. 

Reliability Must-Run

A reliability must-run (RMR) contract acts as an insurance 

policy, assuring that the CAISO has dispatch rights in order to reliably serve load in local import constrained areas. 

RMR contracts also help to mitigate any local market power 

that one or more units may have. The amount of generation capacity under RMR contracts dropped when local RA 

requirements were introduced. With more local resources 

being procured through RA contracts, the CAISO was able 

to signifi cantly decrease its RMR designations in much of 

the system. Remaining generators with RMR contracts are 

located primarily in San Francisco and San Diego. 

Financial Transmission Rights

As mentioned above, fi nancial transmission rights (FTRs) 

give market participants an offset or hedge against transmission congestion costs in the day-ahead market. An FTR 

is a fi nancial contract protecting the holder from costs arising from transmission congestion over a path or a sourceand-sink pair of locations on the grid. An FTR provides 

the holder with revenue, or charges, equal to the difference in congestion prices in the day-ahead market across 

the specifi c FTR transmission path. FTRs were originally 

formulated to protect LSEs from price uncertainty while redistributing excess congestion charges due to constrained 

conditions. 

A related product is an auction revenue right (ARR). ARRs 

provide the holders with an upfront portion of the money 

raised in the FTR auctions. In general, they are allocated 

based on historical load served and, in some RTOs, can be 

converted to FTRs. As with FTRs, ARRs give transmission 

owners and eligible transmission service customers an offset or hedge against transmission congestion costs in the 

day-ahead market.

FTRs in California are referred to as congestion revenue 

rights (CRRs). Other than the name, the products are identical. CRRs are monthly or quarterly products. CRRs can be 
82 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

bought at auction or allocated by CAISO. Allocated CRRs 

receive the congestion value for a specifi c path, similar to a 

converted FTR. CAISO also allocates open market CRR auction revenue to LSEs based on their physical participation 

in the market, similar to an ARR in other markets. Given 

that both allocated CRRs and allocated auction revenues 

are based on physical market presences, LSEs often receive 

both. Finally, CRR revenue insuffi ciency is not possible as 

LSEs will be charged uplift if any shortfall is present.

Virtual Transactions

CAISO implemented convergence bidding, or virtual bidding, on Feb. 1, 2011. With the virtual bidding market 

feature, market participants can take fi nancial positions in 

the day-ahead market that are liquidated in the real-time 

market. Virtual bidding is unique in CAISO because virtual 

positions taken on the export and import interties settle 

against the hour-ahead price, while internal virtual positions settle against the real-time dispatch price. Market 

participants can engage in either virtual demand or virtual 

supply transactions. A virtual demand transaction is a bid 

to buy at the day-ahead price and offer to sell at the realtime price. A virtual supply transaction is a bid to sell at 

the day-ahead price and buy at the real-time price.

Virtual supply and virtual demand may be submitted at 

any eligible pricing node in the CAISO system and there is 

no requirement for physical generation or load. The fi nancial outcome for a particular participant is determined by 

the difference between the hourly day-ahead and real-time 

LMPs at the location at which the offer or bid clears. Thus, 

through this fi nancial arbitrage opportunity, virtual transactions in theory help to narrow the difference between the 

day-ahead and real-time prices.

Credit Requirements

Credit requirements are important in organized electricity 

markets in which RTOs must balance the need for market 

liquidity against corresponding risk of default. Defaults 

within these markets are particularly troubling because 

losses due to default are spread among all market participants. Thus, each RTO’s tariff specifi es credit rules needed 

to participate in the markets. These requirements provide 

for credit evaluations, credit limits, allowed forms of collateral and the consequences of violations or defaults. 

Settlements

RTOs must invoice market participants for their involvement in their markets. Settlements is the process by which 

the RTO determines the amounts to be paid associated with 

buying and selling energy, capacity and ancillary services, 

and paying administrative charges. 

The CAISO calculates, accounts for and settles all charges 

and payments based on received settlement quality meter 

data. The CAISO settles the following charges: grid management charge, bid cost recovery, energy and ancillary 

services, CRR charges and payments, among others. The 

CAISO settles for three periods: the day-ahead market, the 

HASP and the real-time markets.

ISO-NE

New England Independent System Operator

Market Profi le

Geographic Scope

As the RTO for New England, ISO-NE is responsible for 

operating wholesale power markets that trade electricity, 

capacity, transmission congestion contracts and related 

products, in addition to administering auctions for the sale 

of capacity.

ISO-NE operates New England’s high-voltage transmission 
 Energy Primer | 83

network and performs long-term planning for the New 

England system. ISO-NE serves six New England states: 

Connecticut, Maine, Massachusetts, New Hampshire, Rhode 

Island and Vermont. 

Peak Demand

New England’s all-time peak load was 28 GW in 2006.

Import and Exports

ISO-NE is interconnected with the New York Independent 

System Operator (NYISO), TransEnergie (Québec) and the 

New Brunswick System Operator. 

ISO-NE imports 12 percent of its annual energy needs from 

Québec. ISO-NE imports energy from and exports energy 

to NYISO.

New England receives imports from Québec and New 

Brunswick in most hours. Between New England and New 

York, power fl ows in alternate directions depending on 

market conditions.

Market Participants

The New England Power Pool (NEPOOL) consists of six 

sectors: (1) end-user sector; (2) publicly owned entities; 

(3) supplier sector; (4) transmission sector; (5) generation 

sector; and (6) alternative resources.

Membership and Governance

ISO-NE is a not-for-profi t entity governed by a 10-member, independent, nonstakeholder board of directors. The 

sitting members of the board elect people to fi ll board 

vacancies. 

Independent System Operator of New England (ISO-NE)
84 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Transmission

Owners

ISO-NE’s transmission owners include:

• Bangor Hydro-Electric Co., 

• Central Maine Power Co., 

• New England Power Co., 

• Northeast Utilities System Cos., 

• NSTAR Electric Co., 

• Transmission Sector Provisional Group Member, 

• The United Illuminating Co., and 

• Vermont Electric Power Co. Inc.

Chronic Constraints

In 2009, New England completed a series of major transmission projects to improve reliability, including projects 

serving Boston, southwestern Connecticut and southeastern Massachusetts. 

Transmission Planning

Each year, ISO-NE prepares a comprehensive 10-year regional system plan (RSP) that reports on the results of ISO 

system planning processes. Each plan includes forecasts of 

future loads (i.e., the demand for electricity measured in 

megawatts) and addresses how this demand may be satisfi ed by adding supply resources; demand resources, including demand response and energy effi ciency; and new or 

upgraded transmission facilities. Each year’s plan summarizes New England needs, as well as the needs in specifi c 

areas, and includes solutions and processes required to ensure the reliable and economic performance of the New 

England power system.

Supply Resources

Generating Mix

By plant capacity, the generating mix includes these sources:

Demand Response

Currently, ISO-NE administers fi ve load-response programs 

for the New England wholesale electricity market. These 

include:

• Real-Time 30-Minute Demand-Response Program: 

These resources are required to respond within 30 minutes of the ISO’s instructions.

• This Real-Time 2-Hour Demand Response Program: 

program requires demand resources to respond within 

two hours of the ISO’s instructions.

• These re- Real-Time Profi led-Response Program:

sources may be interrupted for anticipated capacity 

defi ciencies within a specifi ed time period and receive 

payment for a minimum of two hours.

• These resources Real-Time Price-Response Program: 

may interrupt (but are not required to do so) when 

they receive notice on the previous day. If they interrupt, they receive payment for the eligibility period.

• An optional Day-Ahead Load-Response Program: 

program that allows a participant in any of the realtime programs to offer interruptions concurrent with 

the day-ahead energy market. The participant is paid 

the day-ahead LMP for the cleared interruptions, and 

real-time deviations are charged or credited at the realtime LMP.

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Natural Gas Natural Gas-Oil Oil Nuclear Coal Hydro Wind Other

Share of Regional Total (%)
 Energy Primer | 85

Market Features and Functions

Energy Markets

Day-Ahead

The day-ahead energy market allows market participants to 

secure prices for electric energy the day before the operating day and hedge against price fl uctuations that can occur 

in real time. One day ahead of actual dispatch, participants 

submit supply offers and demand bids for energy. These 

bids are applied to each hour of the day and for each pricing location on the system.

In the day-ahead energy market, incremental offers and 

decremental bids (virtual supply offers and demand bids) 

can also be submitted, which indicate prices at which supply or demand are willing to increase or decrease their injection or withdrawal on the system. These INCs and DECs 

are tools market participants can use to hedge their positions in the day-ahead energy market.

From the offers and bids, the RTO constructs aggregate 

supply and demand curves for each location. The intersection of these curves identifi es the market-clearing price 

at each location for every hour. Supply offers below and 

demand bids above the identifi ed price are cleared and 

are scheduled. Offers and bids that clear are entered into 

a pricing software system along with binding transmission constraints to produce the locational marginal prices 

(LMPs) for all locations.

Hour-Ahead

None.

Real-Time

ISO-NE must coordinate the dispatch of generation and 

demand resources to meet the instantaneous demand for 

electricity. Supply or demand for the operating day can 

change for a variety of reasons, including unforeseen generator or transmission outages, transmission constraints or 

changes from the expected demand. While the day-ahead 

energy market produces the schedule and fi nancial terms of 

energy production and use for the operating day, a number 

of factors can change that schedule. Thus, ISO-NE operates a spot market for energy, the real-time energy market, 

to meet energy needs within each hour of the current day.

ISO-NE clears the real-time energy market using supply 

offers, real-time load and offers and bids to sell or buy 

energy over the external interfaces. For generators, the 

market provides additional opportunities to offer supply to 

help meet incremental supply needs. Load-serving entities 

(LSEs) whose actual demand comes in higher than that 

scheduled in the day-ahead energy market may secure additional energy from the real-time energy market.

The real-time energy market fi nancially settles the differences between the day-ahead scheduled amounts of load 

and generation and the actual real-time load and generation. Differences from the day-ahead quantities cleared are 

settled at the real-time LMP. 

In real time, ISO-NE will issue dispatch rates and dispatch 

targets. These are fi ve-minute price and megawatt signals 

based on the aggregate offers of generators, which will 

produce the required energy production. Market participants are, throughout the day, allowed to offer imports or 

request exports of electricity from neighboring control areas with at least one hour’s notice. 

Must-Offer Requirements

Market rules in RTOs include must-offer requirements for 

certain categories of resources for which withholding, a 

form of the exercise of market power, may be a concern. 

Where such rules apply, sellers must commit, or offer, the 
86 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

generators, and schedule and operate the facilities, into the 

applicable market.

Ancillary and Other Services

Ancillary services are those functions performed by electric 

generating, transmission and system-control equipment to 

support the transmission of electric power from generating 

resources to load while maintaining the reliability of the 

transmission system. RTOs procure or direct the supply of 

ancillary services.

ISO-NE procures ancillary services via the forward reserve 

market and its regulation market. The forward reserve 

market compensates generators for making available their 

unloaded operating capacity that can be converted into 

electric energy within 10 or 30 minutes when needed to 

meet system contingencies, such as unexpected outages. 

The Regulation Market compensates resources that ISONE instructs to increase or decrease output moment by 

moment to balance the variations in demand and system 

frequency to meet industry standards. The specifi c ancillary services ISO-NE procures in its markets include the 

following:

• Ten-Minute Spinning Reserves: provided by resources 

already synchronized to the grid and able to generate 

electricity within 10 minutes.

• Ten-Minute Nonspinning Reserves: provided by resources not currently synchronized to the grid but 

capable of starting and providing output within 10 

minutes.

• Thirty-Minute Nonspinning Reserves: provided by 

resources not currently synchronized to the grid but 

capable of starting and providing output within 30 

minutes.

• Regulation: provided by specially equipped resources 

with the capability to increase or decrease their generation output every four seconds in response to signals 

they receive from ISO-NE to control slight changes on 

the system.

Specialized ancillary services that are not bought and sold 

in these ancillary service markets include voltage support 

and black-start capability. Voltage support allows the New 

England control area to maintain transmission voltages. 

Black-start capability is the ability of a generating unit 

to go from a shutdown condition to an operating condition and start delivering power without assistance from a 

power system. ISO-NE procures these services via costbased rates.

Capacity Markets

In ISO-NE’s annual forward capacity auctions (FCA), both 

generator and demand resources offer capacity three years 

in advance of the period for which capacity will be supplied. The three-year lead time is intended to encourage 

participation by new resources and allow the market to 

adapt to resources leaving the market. Resources whose 

capacity clears the FCA acquire capacity supply obligations 

(CSOs). ISO-NE held its fi rst two FCAs in 2008 for the 

2010-11 and 2011-12 delivery years. The fi rst full year of 

capacity market commitments began on June 1, 2010. A 

third auction was held in December 2009 for the 2011-13 

delivery years. The FCA process includes the modeling of 

transmission constraints to determine if load zones will be 

import- or export-constrained. 

Market Power Mitigation

In ISO-NE, mitigation may be applied for physical withholding, economic withholding, uneconomic production, 

virtual transactions or other conduct if the conduct has a 

material effect on prices or uplift payments. The market 

monitor uses defi ned thresholds to identify physical and 

economic withholding and uneconomic generation, as well 
 Energy Primer | 87

as defi ned thresholds to determine whether bids and offers 

would, if not mitigated, cause a material effect on LMPs 

or uplift charges.

Reliability Must-Run

None.

Financial Transmission Rights

New England FTRs are monthly and annual products. 

ISO-NE holds FTR auctions and then allocates the auction 

revenue to LSEs based on historical load. ISO-NE is the 

only RTO to settle accounts weekly but revenue insuffi -

ciency is possible. Month-to-month surplus is carried over 

and used to fund any defi ciencies, and the true-up period 

for accounts occurs once a year.

Virtual Transactions

In ISO-NE, any market participant may submit INCs or 

DECs into the day-ahead market. 

MISO

Midwest Independent System Operator

Market Profi le

Geographic Scope

MISO operates the transmission system and a centrally dispatched market in portions of 13 states in the Midwest, 

extending from western Pennsylvania to eastern Montana 

and from the Canadian border to the southern extremes of 

Midwest Independent System Operator (MISO)
88 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Illinois and Missouri. The system is operated from a primary control center in Carmel, Ind., and a second control 

center in St. Paul, Minn., for the western region. MISO 

also serves as the reliability coordinator for additional systems outside of its market area, primarily to the north and 

northwest of the market footprint.

MISO was not a power pool before organizing as an ISO in 

December 2001. It began market operations in April 2005. 

In January 2009, MISO started operating an ancillary services market and combined its 24 separate balancing areas 

into a single balancing area.

Demand

MISO’s peak demand was 116 GW in 2006.

Import and Exports

MISO has interconnections with the PJM and Southwest 

Power Pool (SPP) RTOs. It is also directly connected to 

TVA, the Western Area Power Administration and the electric systems of Manitoba and Ontario, plus several smaller 

systems. MISO is a net importer of power overall, but the 

interchange with some areas can fl ow in either direction, 

depending on the relative loads and prices in the adjoining 

regions. Manitoba Hydro supplies a large part of MISO’s 

load with its excess capacity, particularly in the summer.

Market Participants

MISO includes 34 transmission owners, whose assets defi ne 

the MISO market area. MISO’s market participants include 

generators, power marketers, transmission-dependent utilities and load-serving entities. 

Membership and Governance

An independent board of directors of eight members, including the president, governs MISO. Directors are elected 

by the MISO membership from candidates provided by the 

board.

An advisory committee of the membership provides advice 

to the board and information to the MISO stakeholders. 

Membership includes entities with an interest in MISO’s 

operation, such as state regulators and consumer advocates, as well as transmission owners, independent power 

producers, power marketers and brokers, municipal and cooperative utilities and large-volume customers.

Transmission

Owners

The transmission owners in MISO include:

• Alliant Energy

• American Transmission Co.

• Ameren (Missouri and Illinois)

• American Transmission Systems

• Cinergy Services (Duke)

• Indianapolis Power and Light

• ITC

• Michigan Public Power Agency

• NSP Companies (Xcel)

• Northern Indiana Public Service Co.

• Otter Tail Power

• MidAmerican Energy

Chronic Constraints

MISO has certain pathways that are more likely to become 

congested, but the likelihood and pattern of congestion 

in any area is subject to weather patterns, wind production and interchange with external regions. When load is 

high in the eastern part of MISO and to the east in PJM, 

constraints occur on pathways from the Minnesota and 

Wisconsin areas through Chicago and across Indiana and 

Ohio. A particular congestion point with this pattern is 

northern Indiana. When colder weather hits Minnesota 

and the Dakotas, there is often congestion in the northern direction, particularly in Iowa. Higher wind production can cause localized constraints in some areas and can 
 Energy Primer | 89

cause congestion in pathways from southern Minnesota 

and western Iowa moving eastward.

Transmission Planning

The main vehicle MISO uses for transmission planning is 

the Midwest ISO Transmission Expansion Plan developed 

by the MISO planning department in collaboration with 

transmission owners and other stakeholders who form the 

planning advisory committee. The plan is for two years. 

Once approved by the board, the plan becomes the responsibility of the transmission owners.

Supply Resources

Generating Mix

By plant capacity, the generating mix includes these sources:

Demand Response

Demand-side resources are able to participate in MISO’s 

markets in providing capacity, energy in both the dayahead and real-time markets and ancillary services. 

Market Features and Functions

Energy Markets

Day-Ahead Market

The day-ahead market allows market participants to secure 

prices for electric energy the day before the operating day 

and hedge against price fl uctuations that can occur in real 

time. One day ahead of actual dispatch, participants submit supply offers and demand bids for energy. These bids 

are applied to each hour of the day and for each pricing 

location on the system. 

In the day-ahead market, incremental offers and decremental bids (virtual supply offers and demand bids) can 

also be submitted, although they are not associated with 

physical resources or actual load. These INCs and DECs are 

tools market participants can use to hedge their real time 

commitments or to arbitrage the day-ahead to real-time 

price spread.

From the offers and bids, the RTO constructs aggregate supply and demand curves for each location. The intersection 

of these curves identifi es the market-clearing price at each 

location for every hour. Supply offers below and demand 

bids above the identifi ed price are scheduled. Offers and 

bids that clear are entered into a pricing software system 

along with binding transmission constraints to produce the 

locational marginal prices (LMPs) for all locations.

Generators and offers scheduled in the day-ahead settlement are paid the day-ahead LMP for the megawatts accepted. Scheduled suppliers must produce the committed 

quantity during real-time or buy power from the real-time 

marketplace to replace what was not produced.

Likewise, wholesale buyers of electricity and virtual demand whose bids to buy clear in the day-ahead market 

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Coal Natural Gas Nuclear Wind Oil Hydro and Other

Share of Regional Total (%)
90 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

settlement pay for and lock in their right to consume the 

cleared quantity at the day-ahead LMP. Electricity use in 

real-time that exceeds the day-ahead purchase is paid for 

at the real-time LMP.

Hour-Ahead Market

Not applicable for MISO.

Real-Time Market

MISO must coordinate the dispatch of generation and 

demand resources to meet the instantaneous demand 

for electricity. Supply or demand for the operating day 

can change for a variety of reasons, including unforeseen 

generator or transmission outages, transmission constraints 

or changes from the expected demand. While the dayahead energy market produces the schedule and fi nancial 

terms for the bulk of the physical transactions, a number of 

factors usually change the day-ahead result. Thus, MISO 

operates a spot market for energy, the real-time energy 

market, to meet actual energy needs within each hour of 

the operating day.

The real-time market is prepared for at the conclusion of 

the day-ahead market on the day before the operating 

day. MISO clears the real-time energy market using supply 

offers, real-time load and external offers. For generators, 

the market provides additional opportunities to offer supply to help meet incremental needs. LSEs whose actual 

demand comes in higher than what was scheduled in the 

day-ahead market may secure additional energy from the 

real-time market.

The real-time energy market fi nancially settles the differences between the day-ahead scheduled amounts of load 

and generation and the actual real-time load and generation. Participants either pay or are paid the real-time LMP 

for the amount of load or generation in megawatt-hours 

that deviates from their day-ahead schedule. 

In real-time, MISO issues dispatch rates and dispatch 

targets. These are fi ve-minute price and megawatt 

signals based on the aggregate offers of generators, which 

will produce the required energy production. Market participants are, throughout the day, allowed to offer imports 

or request exports of electricity from neighboring control 

areas by submitting transmission schedules into or out of 

MISO. 

In real-time, generators can also deviate from the dayahead clearing schedule by self-scheduling, which means 

that MISO will run a given unit without regard to the unit’s 

economics unless running the unit presents a reliability 

concern.

During the operating day, the real-time market acts as a 

balancing market for load with physical resources used to 

meet that load. A market price for energy and for each 

of the ancillary services is calculated for each fi ve-minute 

dispatch interval and the resulting fi ve-minute prices are 

rolled into hourly prices for billing and payment. Differences in the real-time operation from the day-ahead 

clearing, including all virtual transactions, are settled at the 

real-time price.

Must-Offer Requirements

Market rules in RTOs include must-offer requirements 

for certain categories of resources for which withholding, 

which could be an exercise of market power, may be a 

concern. Where such rules apply, sellers must commit, or 

offer, the generators, and schedule and operate the facilities, in the applicable market.

In MISO, generators who supply capacity to meet the RTO 

resource adequacy requirement for load are required to 

offer into the day-ahead and real-time markets for energy 

and the ancillary services for which they are qualifi ed.
 Energy Primer | 91

Ancillary and Other Services

Ancillary services are those functions performed by electric 

generating, transmission and system-control equipment to 

support the transmission of electric power from generating 

resources to load while maintaining the reliability of the 

transmission system. RTOs procure or direct the supply of 

ancillary services.

MISO procures ancillary services via the co-optimized energy and ancillary services market and includes the following services:

• Spinning Reserves: provided by resources already 

synchronized to the grid and able to provide output 

within 10 minutes.

• Supplemental (nonspinning) Reserves: provided by 

resources not currently synchronized to the grid but 

capable of starting and providing output within 10 

minutes.

• Regulation: provided by specially equipped resources 

with the capability to increase or decrease their generation output every four seconds in response to signals 

they receive to control slight changes on the system.

Capacity Markets

Capacity markets are a construct to provide assurance to 

government entities and to NERC a means for load-serving 

entities (LSEs) to prove they have procured capacity needed 

to meet forecast load and to allow generators to recover a 

portion of their fi xed costs. They also provide economic 

incentives to attract investment in new and existing supply-side and demand-side capacity resources.

MISO maintains a monthly capacity requirement on all 

LSEs based on the load forecast plus reserves. LSEs are 

required to specify to MISO what physical capacity, including demand resources, they have designated to meet their 

load forecast. This capacity can be acquired either through 

bilateral purchase or self-supply. Additionally, MISO conducts a monthly auction to provide an opportunity for load 

that has not arranged all of its capacity to procure its needs 

from uncommitted resources.

Market Power Mitigation

In electric power markets, mainly because of the largely 

nonstorable nature of electricity and the existence of transmission constraints that can limit the availability of multiple suppliers to discipline market prices, some sellers from 

time to time have the ability to raise market prices. Market 

power mitigation is a market design mechanism to ensure 

competitive offers even when competitive conditions are 

not present.

Reliability Must-Run

None.

Financial Transmission Rights

Financial transmission rights (FTRs) give market participants an offset or hedge against transmission congestion 

costs in the day-ahead market. An FTR is a fi nancial contract protecting the holder from costs arising from transmission congestion over a path or a source-and-sink pair 

of locations on the grid. An FTR provides the holder with 

revenue, or charges, equal to the difference in congestion 

prices in the day-ahead market across the specifi c FTR 

transmission path. FTRs were originally formulated to protect LSEs from price uncertainty while redistributing excess 

congestion charges due to constrained conditions. Other 

market participants such as fi nancial-only participants may 

purchase FTRs through the RTO’s auctions or through secondary market purchases.

MISO FTRs are monthly and annual products. 
92 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Virtual Transactions

A virtual transaction allows a participant to buy or sell 

power in the day-ahead market without requiring physical generation or load. Cleared virtual supply (increment 

or virtual offers, or INCs) in the day-ahead energy market 

at a particular location in a certain hour creates a fi nancial 

obligation for the participant to buy back the bid quantity in the real-time market at that location in that hour. 

Cleared virtual demand (decrement or virtual bids, or DECs) 

in the day-ahead market creates a fi nancial obligation to 

sell the bid quantity in the real-time market. The fi nancial outcome for a particular participant is determined by 

the difference between the hourly day-ahead and real-time 

LMPs at the location at which the offer or bid clears. Thus, 

through this fi nancial arbitrage opportunity, virtual transactions in theory help to narrow the difference between the 

day-ahead and real-time prices. 

MISO allows virtual bids and offers into its day-ahead energy market where the bids and offers are included in the 

determination of the LMP along with physical resource offers and actual load bids. Market participants whose virtual transactions clear in the day-ahead market, have their 

positions cleared in the real-time market at the real-time 

price. Virtual bids and offers are allowed in MISO at any 

pricing node or aggregate of pricing nodes.

Credit Requirements

Credit requirements are important in markets in which 

RTOs must balance the need for market liquidity against 

corresponding risk of default. Defaults within these markets are particularly troubling because losses due to default are borne among all market participants. Thus, each 

RTO’s tariff specifi es credit rules needed to participate in 

the markets. These requirements provide for credit evaluations, credit limits, allowed forms of collateral and the 

consequences of violations or defaults. 

Settlements

RTOs must invoice market participants for their involvement in their markets. 

The RTO determines the amount owed associated with 

buying and selling energy, capacity and ancillary services 

and paying various administrative charges. 

Settlements for market activity in MISO are fi nalized seven 

days after the operating day and payable after 14 days.

NYISO

New York Independent System Operator

Market Profi le

Geographic Scope

Prior to restructuring of the electric industry in the 1990s, 

New York’s private utilities and public power authorities 

owned and operated New York’s electric system. Operation 

of the electric grid was coordinated by a voluntary collaboration of the utilities and power authorities as the New 

York Power Pool (NYPP). The creation of the New York 

Independent System Operator (NYISO) was authorized by 

FERC in 1998. The formal transfer of the NYPP’s responsibilities to the NYISO took place on Dec. 1, 1999.

The NYISO footprint covers the entire state of New York. 

NYISO is responsible for operating wholesale power markets that trade electricity, capacity, transmission congestion 

contracts, and related products, in addition to administering auctions for the sale of capacity. NYISO operates New 

York’s high-voltage transmission network and performs 

long-term planning. 
 Energy Primer | 93

Demand

NYISO’s all-time peak load was 34 GW in 2006. 

Imports and Exports

NYISO imports and exports energy through interconnections 

with ISO-NE, PJM, TransEnergie (Quebec) and Ontario.

Market Participants

NYISO’s market participants include generators, transmission owners, fi nancial institutions, traditional local utilities, 

electric co-ops and industrials.

Membership and Governance

NYISO is governed by an independent 10-member board of 

directors and management, business issues and operating 

committees. Each committee oversees its own set of working groups or subcommittees. These committees comprise 

transmission owners, generation owners and other suppliers, consumers, public power and environmental entities. 

Tariff revisions on market rules and operating procedures 

fi led with the Commission are largely developed through 

consensus by these committees. The members of the 

board, as well as all employees, must not be directly associated with any market participant or stakeholder.

Transmission

Transmission Owners 

NYISO’s transmission owners include:

• Central Hudson Gas & Electric Corp.

• Consolidated Edison Co. of New York (ConEd)

• Long Island Power Authority (LIPA)

• New York Power Authority (NYPA)

• New York State Electric and Gas Corp. (NYSEG) 

• National Grid

• Orange & Rockland Utilities

• Rochester Gas and Electric Corp.

New York Independent System Operator (NYISO)
94 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Chronic Constraints

The chronic transmission constraints in NYISO are in the 

southeastern portion of the state, leading into New York 

City and Long Island. As a result of their dense populations, New York City and Long Island are the largest consumers of electricity. Consequently, energy fl ows from 

the west and the north toward these two large markets, 

pushing transmission facilities near their operational limits. 

This results in transmission constraints in several key areas, 

often resulting in higher prices in the New York City and 

Long Island markets. 

Supply Resources

Generating Mix

By plant capacity, the generating mix includes these sources:

Demand Response

NYISO has four demand-response (DR) programs: the 

emergency demand-response program (EDRP), the installed 

capacity (ICAP) special case resources program (SCR), the 

day-ahead demand-response program and the demandside ancillary services program.

Both the emergency and special cases programs can be deployed in energy shortage situations to maintain the reliability of the bulk power grid. Both programs are designed 

to reduce power usage by shutting down businesses and 

large power users. Companies, mostly industrial and commercial, sign up to take part in the programs. The companies are paid by NYISO for reducing energy consumption 

when asked to do so. Reductions are voluntary for EDRP 

participants. SCR participants are required to reduce power 

usage and as part of their agreement are paid in advance 

for agreeing to cut power usage on request.

NYISO’s day-ahead DR program allows energy users to bid 

their load reductions into the day-ahead market. Offers 

determined to be economic are paid at the market clearing 

price. Under day-ahead DR, fl exible loads may effectively 

increase the amount of supply in the market and moderate 

prices. 

The ancillary services program provides retail customers 

that can meet telemetry and other qualifi cations the ability 

to bid their load curtailment capability into the day-ahead 

market or real-time market to provide reserves and regulation service. Scheduled offers are paid the marketing clearing price for reserves or regulation.

Market Features and Functions 

Energy Markets

Day-Ahead Market

The day-ahead market allows market participants to secure 

prices for electric energy the day before the operating day 

and hedge against price fl uctuations that can occur in real 

time. One day ahead of actual dispatch, participants submit supply offers and demand bids for energy. These bids 

are applied to each hour of the day and for each pricing 

location on the system.

In the day-ahead market, virtual supply offers and demand 

bids can also be submitted. These are tools market participants can use to hedge their positions in the day-ahead 

market.

From the offers and bids, the RTO constructs aggregate 

supply and demand curves for each location. The intersection of these curves identifi es the market-clearing price 

at each location for every hour. Supply offers below, and 

demand bids above, the identifi ed price are scheduled. Offers and bids that clear are then entered into a pricing software system along with binding transmission constraints 

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Natural Gas Natural Gas-Oil Oil Nuclear Coal Hydro Wind Other

Share of Regional Total (%)
 Energy Primer | 95

to produce the locational marginal prices (LMPs) for all 

locations. The NYISO refers to these as locational based 

marginal prices, or LBMPs.

Generators and offers scheduled in the day-ahead settlement are paid the day-ahead LBMP for the megawatts accepted. Scheduled suppliers must produce the committed 

quantity during real-time or buy power from the real-time 

marketplace to replace what was not produced.

Likewise, wholesale buyers of electricity and virtual demand 

whose bids to buy are accepted in the day-ahead market pay for and lock in their right to consume the cleared 

quantity at the day-ahead LBMP. Electricity used in realtime that exceeds the day-ahead purchase is paid for at the 

real-time LBMP.

Hour-Ahead Market

The hour-ahead market allows buyers and sellers of electricity to balance unexpected increases or decreases of 

electricity use after the day-ahead market closes. Bids and 

offers are submitted an hour ahead of time. Prices are set 

based on those bids and offers, generally for use in matching generation and load requirements, but those prices are 

advisory only. Hour-ahead scheduling is completed at least 

45 minutes prior to the beginning of the dispatch hour after NYISO reviews transmission outages, the load forecast, 

reserve requirements and hour-ahead generation and fi rm 

transaction bids, among other things.

Real-Time Market

NYISO must coordinate the dispatch of generation and 

demand resources to meet the instantaneous demand for 

electricity. Supply or demand for the operating day can 

change for a variety of reasons, including unforeseen generator or transmission outages, transmission constraints or 

changes from the expected demand. While the day-ahead 

market produces the schedule and fi nancial terms of energy production and use for the operating day, a number 

of factors can change that schedule. Thus, NYISO operates 

a spot market for energy, the real-time energy market, to 

meet energy needs within each hour of the current day.

Real-time energy market outcomes are based on supply 

offers, real-time load and offers and bids to sell or buy 

energy. LSEs whose actual demand comes in higher than 

that scheduled in the day-ahead market may secure additional energy from the real-time market. For generators, 

the market provides additional opportunities to offer supply to help meet additional needs. 

The real-time energy market fi nancially settles the differences between the day-ahead scheduled amounts of load 

and generation and the actual real-time load and generation. Those who were committed to produce in the dayahead are compensated at (or pay) the real-time LBMP for 

the megawatts under- or over-produced in relation to the 

cleared amount. Those who paid for day-ahead megawatts 

are paid (or pay) the real-time LBMP for megawatts underor over-consumed in real-time.

Real-time dispatch of generators occurs every fi ve minutes, 

as does the setting of the real-time prices used for settlement purposes. Market participants may participate in the 

day-ahead, hour-ahead, and the real-time market.

Must-Offer Requirements

Under the NYISO capacity auction rules, entities that offer 

capacity into an auction that is subsequently purchased by 

load are required to offer that amount of capacity into the 

day-ahead energy market. This rule ensures that capacity 

sold through the capacity auctions is actually delivered into 

the market. 
96 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Ancillary and Other Services

Ancillary services are those functions performed by electric 

generating, transmission and system-control equipment to 

support the transmission of electric power from generating 

resources to load while maintaining the reliability of the 

transmission system. RTOs procure or direct the supply of 

ancillary services. 

NYISO administers competitive markets for ancillary services that are required to support the power system. The two 

most important types of ancillary services are operating 

reserves and regulation. Operating reserves and regulation 

are typically provided by generators, but NYISO allows demand-side providers to participate in these markets as well. 

Operating reserve resources can either be spinning (online 

with additional ramping ability) or nonspinning (off-line, 

but able to start and synchronize quickly). NYISO relies on 

regulating resources that can quickly adjust their output 

or consumption in response to constantly changing load 

conditions to maintain system balance. 

The NYISO relies on the following types of ancillary services:

• Ten-Minute spinning reserves: provided by resources 

already synchronized to the grid and able to provide 

output within 10 minutes.

• Ten-Minute nonspinning reserves: provided by resources not currently synchronized to the grid but capable 

of starting and providing output within 10 minutes.

• Thirty-Minute nonspinning reserves: provided by 

resources not currently synchronized to the grid but 

capable of starting and providing output within 30 

minutes.

• Regulation: provided by resources with the capability 

to increase or decrease their generation output within 

seconds in order to control changes on the system.

Capacity Markets

Capacity markets provide a means for load-serving entities 

(LSEs) to procure capacity needed to meet forecast load 

and to allow generators to recover a portion of their fi xed 

costs. They also provide economic incentives to attract investment in new and existing supply-side and demand-side 

capacity resources in New York as needed to maintain bulk 

power system reliability requirements.

In NYISO’s capacity market, LSEs procure capacity through 

installed-capacity (ICAP) auctions, self-supply and bilateral 

arrangements based on their forecasted peak load plus a 

margin. The NYISO conducts auctions for three different 

service durations: the capability period auction (covering 

six months), the monthly auction and the spot market 

auction.

New York has capacity requirements for three zones: New 

York City, Long Island and New York-Rest of State. The resource requirements do not change in the monthly auctions 

and ICAP spot market auctions relative to the capability period auction. The shorter monthly auctions are designed to 

account for incremental changes in LSE’s load forecasts. 

Market Power Mitigation

In electric power markets, mainly because of the largely 

nonstorable nature of electricity and the existence of transmission constraints that can limit the availability of multiple suppliers to discipline market prices, some sellers from 

time to time have the ability to raise market prices. Market 

power mitigation is a market design mechanism to ensure 

competitive offers even when competitive conditions are 

not present.

Market power may need to be mitigated on a systemwide 

basis or on a local basis. When a transmission constraint 

creates the potential for local market power, the RTO may 
 Energy Primer | 97

apply a set of behavioral and market outcome tests to determine if the local market is competitive and if generator 

offers should be adjusted to approximate price levels that 

would be seen in a competitive market. 

The categories of conduct that may warrant mitigation by 

NYISO include physical withholding, economic withholding 

and uneconomic production by a generator or transmission 

facility to obtain benefi ts from a transmission constraint. 

Physical withholding is not offering to sell or schedule energy provided by a generator or transmission facility capable of serving a NYISO market. Physical withholding 

may include falsely declaring an outage, refusing to offer 

or schedule a generator or transmission facility; making an 

unjustifi able change to operating parameters of a generator that reduces its availability; or operating a generator in 

real-time at a lower output level than the generator would 

have been expected to produce had the generator followed 

NYISO’s dispatch instructions. Economic withholding is 

submitting bids for a generator that are unjustifi ably high 

so that the generator is not dispatched.

NYISO will not impose mitigation unless the conduct 

causes or contributes to a material change in prices, or substantially increases guarantee payments to participants. 

Virtual bidding is subject to mitigation under certain circumstances as well. NYISO may limit the hourly quantities of virtual bids for supply or load that may be offered 

in a zone by a market participant whose virtual bidding 

practices are determined to contribute to an unwarranted 

divergence of LBMPs (location-based marginal prices) between the day-ahead and real-time markets. If the NYISO 

determines that the relationship between zonal LBMPs in a 

zone in the day-ahead market and the real-time market is 

not what would be expected under conditions of workable 

competition, and that the virtual bidding practices of one 

or more market participants has contributed to this divergence, then a mitigation measure may be imposed. 

Price Caps 

NYISO does not have price caps. It employs a bid cap of 

$1,000/MWh for its day-ahead and real-time markets. 

ICAP for New York City is subject to offer caps and fl oors. 

Offer caps in New York City are based on reference levels or 

avoided costs. Capacity from generators within New York 

City must be offered in each ICAP spot market auction, 

unless that capacity has been exported out of New York or 

sold to meet ICAP requirements outside New York City. 

Local Market Power Mitigation

Generators in New York City are subject to automated market power mitigation procedures because New York City 

is geographically separated from other parts of New York; 

plus, generators in New York City have been deemed to 

have market power. 

These automated procedures determine whether any dayahead or real-time energy bids, including start-up costs 

bids and minimum generation bids, but excluding ancillary 

services bids, exceed the tariff’s thresholds for economic 

withholding, and, if so, determine whether such bids would 

cause material price effects or changes in guarantee payments. If these two tests are met, mitigation is imposed 

automatically. 

For example, the threshold for economic withholding regarding energy and minimum generation bids is a 300 

percent increase or an increase of $100/MWh over the applicable reference level, whichever is lower. Energy or minimum generation bids below $25/MWh are not considered 

economic withholding. Regarding operating reserves and 

regulation bids, a 300 percent increase or an increase of 

$50/MW over the applicable reference level, whichever is 

lower, is the threshold for determining whether economic 
98 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

withholding has occurred. In this instance, bids below $5/

MW are not considered economic withholding. If an entity’s bids meet these thresholds, the applicable reference 

level is substituted for the entity’s actual bid to determine 

the clearing price.

Reliability Must-Run

NYISO has no reliability must-run provisions.

Financial Transmission Rights

Financial transmission rights (FTRs) give market participants an offset, or hedge, against transmission congestion 

costs in the day-ahead market. The NYISO refers to FTRs 

as transmission congestion contracts (TCCs). Other than 

the name, FTRs and TCCs are essentially the same. An FTR 

is a fi nancial contract protecting the holder from costs arising from transmission congestion over a path or a sourceand-sink pair of locations (or nodes) on the grid. An FTR 

provides the holder with revenue, or charges, equal to the 

difference in congestion prices in the day-ahead market 

across the specifi c FTR transmission path. FTRs were originally formulated to protect LSEs from price uncertainty. 

Other market participants, including fi nancial-only participants, may purchase FTRs through the RTO’s auctions.

A related product is an auction revenue right (ARR), which 

provides the holders with an upfront portion of the money 

raised in the TCC auctions. In general, they are allocated 

based on historical load served. As with FTRs, ARRs give 

transmission owners and eligible transmission service customers an offset, or hedge, against transmission congestion costs in the day-ahead market.

Virtual Transactions

A virtual transaction is a specifi c kind of transaction that 

allows a participant to buy or sell power in the day-ahead 

market without requiring physical generation or load. 

Cleared virtual supply (virtual offers) in the day-ahead energy market at a particular location in a certain hour creates a fi nancial obligation for the participant to buy back 

the bid quantity in the real-time market at that location in 

that hour. Cleared virtual demand (virtual bids) in the dayahead market creates a fi nancial obligation to sell the bid 

quantity in the real-time market. The fi nancial outcome 

is determined by the difference between the hourly dayahead and real-time LBMPs at the location at which the 

offer or bid clears. Thus, through this fi nancial arbitrage 

opportunity, virtual transactions in theory help to narrow 

the difference between the day-ahead and real-time prices. 

Virtual bidding in NYISO takes place on a zonal level, not 

a nodal level. 

Credit Requirements

Credit requirements are important in organized electricity 

markets in which RTOs must balance the need for market 

liquidity against corresponding risk of default. Losses due 

to default are borne among all market participants. Thus, 

each RTO’s tariff specifi es credit rules needed to participate in the markets. These requirements provide for credit 

evaluations, credit limits, allowed forms of collateral and 

the consequences of violations or defaults. 

Settlements

RTOs must invoice market participants for their involvement in their markets. Settlements is the process by which 

the RTO determines the amounts owed and to be paid associated with buying and selling energy, capacity, ancillary 

services and paying various administrative charges. 

NYISO uses a two-settlement process for its energy markets. The fi rst settlement is based on day-ahead bids and 

offers, which clear the market and are scheduled. The second settlement is based on the real-time bids and the corresponding real-time dispatch.
 Energy Primer | 99

PJM

The PJM Interconnection

Market Profi le

Geographic Scope

The PJM Interconnection operates a competitive wholesale 

electricity market and manages the reliability of its transmission grid. PJM provides open access to the transmission 

and performs long-term planning. In managing the grid, 

PJM centrally dispatches generation and coordinates the 

movement of wholesale electricity in all or part of 13 states 

(Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, 

New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, 

Virginia and West Virginia) and the District of Columbia. 

PJM’s markets include energy (day-ahead and real-time), 

capacity and ancillary services.

PJM was founded in 1927 as a power pool of three utilities serving customers in Pennsylvania and New Jersey. In 

1956, with the addition of two Maryland utilities, it became the Pennsylvania-New Jersey-Maryland Interconnection, or PJM. PJM became a fully functioning ISO in 1996 

and, in 1997, it introduced markets with bid-based pricing 

and locational market pricing (LMP). PJM was designated 

an RTO in 2001.

Demand

PJM’s all-time peak load of 159 GW occurred in summer 

2006.

Imports and Exports

PJM has interconnections with Midwest ISO and New York 

ISO. PJM also has direct interconnections with the Tennessee Valley Authority (TVA), Progress Energy Carolinas 

PJM Regional Transmission Organization
100 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

and the Virginia and Carolinas Area (VACAR), among other 

systems. PJM market participants import energy from, and 

export energy to, external regions continuously. At times, 

PJM is a net importer of electricity and, at other times, 

PJM is a net exporter of electricity.

Market Participants

PJM’s market participants include power generators, 

transmission owners, electric distributors, power marketers, 

electric distributors and large consumers.

Membership and Governance

PJM has a two-tiered governance model consisting of a 

board of managers and the members committee. PJM is 

governed by a 10-member board, nine of whom PJM members elect. The board appoints the tenth, the president 

and CEO, to supervise day-to-day operations. The board is 

generally responsible for oversight of system reliability, operating effi ciency and short and long-term planning. The 

board ensures that no member or group of members exerts 

undue infl uence. 

The members committee, which advises the board, is composed of fi ve voting sectors representing power generators, 

transmission owners, electric distributors, power marketers 

and large consumers. 

Transmission

Transmission Owners 

The largest transmission owners in PJM include:

• AEP, 

• First Energy, 

• PSE&G, 

• Dominion,

• Philadelphia Electric, and 

• Commonwealth Edison.

Chronic Constraints

In general, transmission paths extending from generation 

sources in western PJM to load centers in eastern PJM tend 

to become constrained, particularly during peak load conditions. PJM’s Mid-Atlantic markets rely on generation in 

the western part of PJM due to the retirements of eastern 

units and the location of new generation capacity in western areas, such as western Pennsylvania, West Virginia and 

eastern Ohio. Eastern PJM relies on transmission across 

Pennsylvania and up from southwestern PJM to import 

power from sources west and southwest. Eastern PJM relies on transmission capability to replace retired generation 

and to meet demand growth.

Congestion on the eastern interface also constrains power fl ows from the District of Columbia, Baltimore and 

Northern Virginia to New Jersey, Delmarva Peninsula 

and Philadelphia load centers. The high-voltage, bulk 

power transmission pathway within portions of the states 

of Pennsylvania, West Virginia, Virginia and Maryland serve 

the densely populated load centers of the metropolitan 

areas of Baltimore, the District of Columbia and Northern 

Virginia. The electricity needs of Washington-BaltimoreNorthern Virginia are supplied not only by local generation 

but also by signifi cant energy transfers to those areas.

Transmission Planning

PJM’s regional transmission expansion plan (RTEP) 

identifi es transmission system additions and improvements 

needed to keep electricity fl owing within PJM. Studies 

are conducted to test the transmission system against national and regional reliability standards. These studies look 

forward to identify future transmission overloads, voltage 

limitations and other reliability standards violations. PJM 

then develops transmission plans to resolve violations that 

could otherwise lead to overloads and blackouts.
 Energy Primer | 101

Supply Resources

Generation Mix 

By plant capacity, the generating mix includes these sources:

Demand Response

End-use customers providing demand response have the 

opportunity to participate in PJM’s energy, capacity, synchronized reserve and regulation markets on an equal basis 

with generators. All demand-response programs can be 

grouped into emergency or economic programs. The emergency program compensates end-use customers who reduce their usage during emergency conditions on the PJM 

system. Participation in the emergency program may be 

voluntary or mandatory and payments may include energy 

payments, capacity payments or both. There are three options for emergency program registration and participation: 

energy only, capacity only and capacity-plus-energy. 

The economic program allows end-use customers to reduce 

electricity consumption in the energy markets and receive 

a payment when LMPs are high. Under this program, all 

hours are eligible and all participation is voluntary. Participation in the program takes three forms: submitting a sell 

offer into the day-ahead market that clears; submitting a 

sell offer into the real-time market that is dispatched; and 

self-scheduling load reductions while providing notifi cation to PJM. End-use customers participate in demand response in PJM through members called curtailment service 

providers, or CSPs, who act as agents for the customers. 

CSPs aggregate the demand of retail customers, register 

that demand with PJM, submit the verifi cation of demand 

reductions for payment by PJM and receive the payment 

from PJM. The payment is divided among the CSP and 

its retail customers based on private agreements between 

them. 

Market Features and Functions

Energy Markets

Day-Ahead Market

The day-ahead market allows market participants to secure prices for electric energy the day before the operating 

day and hedge against price fl uctuations that can occur in 

real-time. One day ahead of actual dispatch, participants 

submit supply offers and demand bids for energy. These 

bids are applied to each hour of the day and for each pricing location on the system. 

In the day-ahead market, incremental offers and decremental bids (virtual supply offers and demand bids) can 

also be submitted, which indicate prices at which supply or 

demand are willing to increase or decrease their injection 

or withdrawal on the system. These INCs and DECs are 

tools market participants can use to hedge their positions 

in the day-ahead market.

From the offers and bids, the RTO constructs aggregate 

supply and demand curves for each location. The intersection of these curves identifi es the market-clearing price 

at each location for every hour. Supply offers below and 

demand bids above the identifi ed price are said to clear, 

meaning they are scheduled. Offers and bids that clear are 

entered into a pricing software system along with binding 

transmission constraints to produce the locational marginal 

prices (LMPs) for all locations.

Generators and offers scheduled in the day-ahead settlement are paid the day-ahead LMP for the megawatts accepted. Scheduled suppliers must produce the committed 

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Coal Natural Gas Nuclear Oil Hydro Wind Other

Share of Regional Total (%)
102 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

quantity during real-time or buy power from the real-time 

marketplace to replace what was not produced.

Likewise, wholesale buyers of electricity and virtual demand whose bids to buy clear in the day-ahead market 

settlement pay for and lock in their right to consume the 

cleared quantity at the day-ahead LMP. Electricity use in 

real-time that exceeds the day-ahead purchase is paid for 

at the real-time LMP.

Hour-Ahead Market

Not Applicable for PJM.

Real-Time Market

PJM must coordinate the dispatch of generation and demand resources to meet the instantaneous demand for 

electricity. Supply or demand for the operating day can 

change for a variety of reasons, including unforeseen generator or transmission outages, transmission constraints or 

changes from the expected demand. While the day-ahead 

energy market produces the schedule and fi nancial terms of 

energy production and use for the operating day, a number 

of factors can change that schedule. Thus, PJM operates a 

spot market for energy, called the real-time energy market, 

to meet energy needs within each hour of the current day.

PJM clears the real-time energy market using supply offers, 

real-time load and offers and bids to sell or buy energy over 

the external interfaces. Real-time LMPs are calculated at 

fi ve-minute intervals based on actual grid operating conditions as calculated in PJM’s market systems. Generators 

that are available but not selected in the day-ahead scheduling may alter their bids for use in the real-time energy 

market during the generation rebidding period from 4 p.m. 

to 6 p.m.; otherwise, their original day-ahead market bids 

remain in effect for the real-time energy market. 

Ancillary and Other Services

Ancillary services are those functions performed by electric 

generating, transmission and system-control equipment to 

support the transmission of electric power from generating 

resources to load while maintaining the reliability of the 

transmission system. RTO/ISOs procure or direct the supply 

of ancillary services.

PJM operates the following markets for ancillary services:

• Regulation: corrects for short-term changes in electricity use that might affect the stability of the power 

system.

• Synchronized reserves: supplies electricity if the grid 

has an unexpected need for more power on short 

notice. 

• Day-ahead scheduling reserves (DASR): allows PJM 

to schedule suffi cient generation to preserve reliability 

during unanticipated system conditions throughout the 

operating day. 

Regulation service matches generation with very short-term 

changes in load by moving the output of selected resources 

up and down via an automatic control signal. In addition, 

PJM schedules operating reserves in the day-ahead market, 

and resources that provide this service are credited based 

on their offer prices. Reserve consists of 10-minute and 

30-minute products.

Synchronized reserves are the equivalent of what is commonly referred to as spinning reserves, providing 10-minute 

reserves from a generator that is synchronized to the grid. 

The DASR is the primary market mechanism for procuring 

the 30-minute reserves. A resource will only be assigned 

as amount of DASR corresponding to that amount of energy it could provide within 30 minutes of a request. If 

the DASR market does not result in procuring adequate 
 Energy Primer | 103

scheduling reserves, PJM is required to schedule additional 

operating reserves.

Futhermore, two ancillary services are provided on a cost 

basis: (1) blackstart service, which helps ensure the reliable restoration of the grid following a blackout; and (2) 

reactive power, which supports the voltages that must be 

controlled for system reliability, are provided at cost.

Capacity Markets

Capacity markets provide a means for load-serving entities 

(LSEs) to procure capacity needed to meet forecast load 

and to allow generators to recover a portion of their fi xed 

costs. They also provide economic incentives to attract 

investment in new and existing supply-side and demandside capacity resources in PJM as needed to maintain bulk 

power system reliability.

PJM’s capacity market is called the reliability pricing model 

(RPM). The RPM market was implemented in 2007 and is 

designed to ensure the future availability of capacity resources, including demand-resources and energy-effi ciency 

resources that will be needed to keep the regional power 

grid operating reliability. RPM market design is based on 

three-year, forward-looking annual obligations for locational capacity under which supply offers are cleared against 

a downward sloping demand curve, called the variable resource requirement (VRR) curve. The VRR curve establishes 

the amount of capacity that PJM requires its LSE customers to purchase, and the price for that capacity, in each 

capacity zone (locational delivery area). Under RPM, when 

a locational delivery area is transmission-constrained in the 

auction (i.e., limited in the amount of generation that can 

be imported into those areas), capacity prices generally rise 

in that area relative to the overall PJM footprint.

Annual auctions are referred to as base residual auctions 

(BRAs). LSEs that are able to fully supply their own capacity need can choose not to participate in the auctions. 

Most capacity is procured through self-supply and contracted (bilateral) resources and the auctions procure any 

remaining needed capacity. To mitigate the exercise of 

market power, the RPM market rules provide a test to determine whather each capacity seller has market power. If 

the seller fails that test, that seller’s bid id capped so as to 

replicate that seller’s avoidable or opportunity costs. 

Market Power Mitigation

In electric power market, mainly because of the largely 

nonstorable nature of electricy and the existence of tranmission constraints that can limit the availability of multiple suppliers to discipline markets, some sellers have the 

ability to raise market prices. Market power mitigation is 

a market design mechanism to ensure competitive offers 

even when competitive conditions are not present.

Market power may need to be mitigated on a systemwide 

basis or on a local basis where the exercise of market power 

may be a concern for a local area. For example, when 

a transmission constraint creates the potential for local 

market power, the RTO may apply a set of behavioral and 

market outcome tests to determine if the local market is 

competitive and if generator offers should be adjusted to 

approximate price levels that would be seen in a competitive market – close to short-run marginal costs. 

The structural test for implementing offer capping in PJM 

is called the three pivotal supplier test. Generation is subject to offer caps when transmission constraints occur such 

that generators are run out of merit order, which means 

that a higher-priced generator must be run due to a transmission constraint that prevents the use of available lowerpriced generation. When units are dispatched out of merit, 

PJM imposes offer capping for any hour in which there are 

three or fewer generation suppliers available for redispatch 
104 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

that are jointly pivotal, meaning they have the ability to 

increase the market price above the competitive level. 

Price Caps

PJM has a $1,000/MWh offer cap in the energy markets. 

Financial Transmission Rights

Financial transmission rights (FTRs) give market participants an offset or hedge against transmission congestion 

costs in the day-ahead market. An FTR is a fi nancial contract protecting the holder from costs arising from transmission congestion over a path or a source-and-sink pair 

of locations on the grid. An FTR provides the holder with 

revenue, or charges, equal to the difference in congestion 

prices in the day-ahead market across the specifi c FTR 

transmission path. FTRs were originally formulated to protect LSEs from price uncertainty while redistributing excess 

congestion charges due to constrained conditions. Other 

market participants such as fi nancial-only participants may 

purchase FTRs through the RTO’s auctions or through secondary market purchases.

A related product is an auction revenue right (ARR). ARRs 

provide the holders with an upfront portion of the money 

raised in the FTR auctions. In general, they are allocated 

based on historical load served and can be converted to 

FTRs. As with FTRs, ARRs, too, give transmission owners 

(and eligible transmission service customers) an offset or 

hedge against transmission congestion costs in the dayahead market.

Virtual Transactions

A virtual transaction allows a participant to buy or sell 

power in the day-ahead market without requiring physical generation or load. Cleared virtual supply (increment 

or virtual offers, or INCs) in the day-ahead energy market 

at a particular location in a certain hour creates a fi nancial 

obligation for the participant to buy back the bid quantity in the real-time market at that location in that hour. 

Cleared virtual demand (decrement or virtual bids, or DECs) 

in the day-ahead market creates a fi nancial obligation to 

sell the bid quantity in the real-time market. The fi nancial outcome for a particular participant is determined by 

the difference between the hourly day-ahead and real-time 

LMPs at the location at which the offer or bid clears. Thus, 

through this fi nancial arbitrage opportunity, virtual transactions in theory help to narrow the difference between the 

day-ahead and real-time prices. 

Credit Requirements

Credit requirements balance the need for market liquidity against corresponding risk of default. Defaults within 

these markets are particularly troubling because losses due 

to default are borne by all market participants. PJM’s tariff 

spells out the details for credit evaluations, credit limits, 

allowed forms of collateral and the consequences of violations or defaults. 

To reduce fi nancial risk, PJM’s settlement cycle is seven 

days. The amount of unsecured credit allowed is $50 million for a member company and $150 million for an affi liated group. PJM does not allow unsecured credit in the 

FTR market.

Settlements

RTOs must invoice market participants for their involvement in their markets, including the amounts owed for 

buying and selling energy, capacity and ancillary services, 

and for paying administrative charges. 

PJM has a two-settlement system, one each for the dayahead and real-time energy markets. 
 Energy Primer | 105

SPP

Southwest Power Pool

Market Profi le

Geographic Scope

The Southwest Power Pool Inc. (SPP) began operating in 

its real-time energy imbalance service (EIS) market on Feb. 

1, 2007. Based in Little Rock, Ark., SPP manages transmission in nine states: Arkansas, Kansas, Louisiana, Mississippi, 

Missouri, Nebraska, New Mexico, Oklahoma and Texas.

In addition to operating its EIS market and managing openaccess transmission facilities, SPP is the reliability coordinator for the NERC regional entity. As such, SPP enforces 

NERC-approved reliability standards for users, owners and 

operators of the bulk power system; coordinates reliability 

within and with neighboring areas; and ensures adequate 

reserves are procured within the SPP region. The reliability 

area is larger than the market area. 

SPP’s EIS market footprint includes 16 balancing authorities. Its members include investor-owned utilities, municipal systems, generation and transmission cooperatives, state 

authorities, independent power producers, power marketers and independent transmission companies. 

Demand

SPP’s record peak demand of 48 GW occurred in August 

2011.

Import and Exports

SPP has alternate-current (AC) interties with the Midwest 

Southwest Power Pool (SPP)
106 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

ISO, PJM Interconnection, Tennessee Valley Authority and 

Entergy Inc., among other systems. Additionally, SPP has 

two direct-current (DC) interties with ERCOT and seven DC 

interties to the western interconnect through New Mexico, 

Kansas and Nebraska. At times, SPP is a net importer of 

electricity and, at other times, SPP is a net exporter of 

electricity.

Market Participants

SPP’s market participants include cooperatives, independent power producers, investor-owned utilities, power marketers, municipals, state agencies and transmission owners. 

SPP considers a participant in the EIS market to be an entity that has a legal and fi nancial obligation to SPP in the 

market. Market participants must have generation assets 

to participate in the EIS market, or must directly represent 

an asset owner. Asset owners include generation companies and load-serving entities.

Membership and Governance

SPP is governed by a seven-member board of directors, 

with six elected by the members to serve three-year terms, 

plus the SPP president, who is elected by the board. 

Supporting the board is the members committee, which 

provides input to the board through straw votes on all actions pending before the board. The members committee 

is composed of up to 15 people, including four representatives from investor-owned utilities; four representatives of 

cooperatives; two representing municipal members; three 

representing independent power producers and marketers; 

and two representing state and federal power agencies. 

The board is required to consider the members committee’s 

straw vote as an indication of the level of consensus among 

members in advance of taking any actions.

Transmission

Owners

SPP transmission owners (TOs) are investor-owned utilities, 

municipals, cooperatives, state agencies and independent 

transmission companies. Some of the larger balancing authorities by installed capacity include: 

• Southwestern Electric Power Co. (AEP West) 

• OG&E Electric Services 

• Westar Energy Inc. 

• Southwestern Public Service Co. (Xcel Energy)

• Kansas City Power & Light Co. (Great Plains Energy)

• Omaha Public Power District 

• Nebraska Public Power District

• KCP&L Greater Missouri Operations (Great Plains Energy)

• Empire District Electric Co.

• Western Farmers Electric Cooperative

Supply Resources

Generating Mix

By plant capacity, the generating mix includes these sources:

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Coal Natural Gas Oil Nuclear Wind Hydro Other

Share of Regional Total (%)
 Energy Primer | 107

Market Features and Functions

Energy Markets

Day-Ahead

Not applicable.

Hour-Ahead

Not applicable.

Real-Time

SPP must coordinate the dispatch of generation and demand resources to meet the instantaneous demand for 

electricity. 

SPP’s EIS market provides market participants the opportunity to buy and sell wholesale electricity in real time. If 

a utility requires more energy than it scheduled, the market 

provides the utility another option to buy the additional 

energy at real-time prices to make up the difference and 

meet its demand. Thus, participants use the EIS market 

to obtain energy available and offered from other utilities. 

Entities wishing to provide energy will submit offers to the 

market.

SPP uses a security constrained economic dispatch (SCED) 

to determine the lowest cost increment of energy that can 

be delivered to each location, considering the submitted 

offers, transmission limitations and system topology. EIS 

market dispatch instructions are calculated for dispatchable 

resources, and locational imbalance prices (LIPs) are calculated for each settlement location (generation resource or 

load) on the system. 

Resources are settled based on the LIP associated with their 

settlement location. Resources are only settled nodally. 

Load may choose to be settled either zonally or nodally. 

The LIPs are based on the resource offers and are locational. 

Must-Offer Requirements

Not applicable.

Ancillary and Other Services

Ancillary services are those functions performed by electric 

generating, transmission and system-control equipment to 

support the transmission of electric power from generating 

resources to load while maintaining the reliability of the 

transmission system. 

SPP does not offer an ancillary service market. However, it 

does require each transmission owner to provide or arrange 

for all of these services.

Capacity Markets

SPP does not offer a capacity market. However, it requires 

each market participant to have suffi cient energy supply 

(capacity) to cover its energy obligations. SPP performs a 

supply adequacy analysis for each market participant based 

on a load forecast, resource plan, ancillary service plan and 

schedules received from market participants. This analysis 

is performed for each hour of the next operating day, with 

results available by 3 p.m. of the day prior to the operating day.

Market Power Mitigation

In electric power markets, mainly because of the largely 

nonstorable nature of electricity and the existence of transmission constraints that limit the availability of multiple 

suppliers to discipline market prices, some sellers have the 

ability to raise market prices. Market power mitigation is 

a market design mechanism to ensure competitive offers 

even when competitive conditions are not present.

Market power may need to be mitigated systemwide basis 

or locally.
108 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Price Caps

Offers by market participants may not exceed $1,000/MWhour. This limit remains in effect until such time as SPP 

demonstrates in a fi ling with the Commission that suffi -

cient demand response exists in the EIS market to allow a 

higher offer curve price limit or removal of the safety-net 

price limit.

Local Market Power Mitigation

When any transmission constraint is binding in the EIS 

market, SPP will screen the offer curve associated with resources on the importing side of each constraint. If the 

resource’s offer is greater than the offer cap, then SPP will 

substitute the resource’s offer with its offer cap.

Additionally, there is no mitigation for physical withholding in the EIS market, as the market is voluntary. The 

market monitor monitors determines whether the decisions 

to participate in the EIS market have a signifi cant adverse 

impact on market outcomes.

FTRs

Not applicable.

Virtual Transactions

Not applicable.

Credit Requirements

RTOs must balance the need for market liquidity against 

corresponding risk of default. Defaults within these markets are troubling because losses due to default are borne 

by all market participants. SPP’s tariff specifi es credit rules 

needed to participate in the markets. These requirements 

provide for credit evaluations, credit limits, allowed forms of 

collateral and the consequences of violations or defaults. 

Settlements

RTOs must invoice market participants for their involvement in their markets. Settlement is the process by which 

the RTO determines the amounts owed associated with 

buying and selling energy, capacity and ancillary services, 

and paying administrative charges. 

The SPP settlement process calculates the quantity of 

energy imbalance for each asset (generation resource or 

load), calculates invoice dollars for energy imbalances and 

allocates over-and under-collection of revenues to asset 

owners. Settlement statements are published for each operating day. The market is facilitated so that SPP remains 

revenue neutral.
 Energy Primer | 109

Introduction

Financial markets affect physical natural gas and electric 

markets in key ways. In the past decade, the commodity 

markets associated with natural gas and electricity expanded dramatically, both in terms of volumes traded and the 

types of products offered. One result from this expansion 

has been to revamp the traditional relationship between 

physical and fi nancial markets. The traditional view was 

that physical markets affect fi nancial; fi nancial products 

derive their value from physical products. Today, this is no 

longer the case. Physical markets continue to affect fi nancial markets, but now, fi nancial markets can affect physical 

markets – including prices – as well.

This chapter explores natural gas and electric commodity 

and capital markets.

Markets and Mechanisms

Financial markets are amorphous. These markets are not 

physical locations like grocery stores, or sites on the Web 

such as Amazon.com, where one can go to experience the 

fi nancial marketplace. Instead, they are an array of products, mechanisms and participants that together fl esh out 

the marketplace.

As mentioned, fi nancial markets differ from physical markets in that no physical delivery occurs. This does not mean 

fi nancial markets contain only investors and speculators; 

physical market participants enter the fi nancial market to 

hedge. Similarly, it does not mean that fi nancial markets 

involve only contracts that contain fi nancial payout instead 

of physical delivery. Financial traders may use longer term 

physical contracts, but in a way that ensures no delivery 

will be required. Physical and fi nancial markets are often 

closely intertwined and use the same market mechanisms.

Consequently, the best way to understand fi nancial 

markets is to look at the market participants, products, 

market mechanisms and trading that together constitute 

the market.

Market Mechanisms

Transactions in both physical and fi nancial markets are 

conducted through exchanges or over-the-counter (OTC). 

In the power market, trades may also be conducted in 

regional transmission organizations (RTOs, addressed in 

Chapter 3). 

Exchanges

Exchanges are standardized. Trading on exchanges is 

subject to the rules of the exchange as well as law and 

regulation. The products traded are established in advance 

by the exchange, with no room for modifi cation. The contracts specify pre-set locations, product types, quantities 

and trading mechanisms. Exchange rules typically permit 

bidirectional trading, or the ability to buy or sell with equal 

ease.

Trading in exchanges is conducted through electronic 
110 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

platforms, websites on which traders can buy and sell, or 

through trading pits where traders actively call out orders 

to buy and sell, known as open outcry. 

On exchanges, buyers are not matched to specifi c sellers. 

Instead, exchanges are multilateral; buyers’ needs may be 

met by a number of sellers, but the buyers and sellers do 

not interact or transact with each other.

Exchanges for gas and electricity are commodity exchanges, such as the New York Mercantile Exchange (Nymex), 

the world’s largest physical commodity futures exchange. 

Nymex handles physical and fi nancial natural gas products 

as well as fi nancial power contracts.

Margin is the ability to trade without having to pay cash 

for the full value of the trade. Effectively, someone who 

trades on margin borrows much of the money used to buy 

or sell from the exchange or brokerage house. The trader 

posts collateral by putting down a certain amount of money or percentage of the trade value in cash or other items 

of value acceptable to the exchange.

Over-the-Counter (OTC) Markets

OTC markets are any markets that are not exchanges or 

RTOs. Transactions range from complicated individual 

negotiations for one-off structured contracts to standardized products traded through an electronic brokerage 

platform. The ability to tailor a contract to the exact needs 

of the counterparties is one of the chief benefi ts of OTC 

contracts.

OTC power transactions can occur in either traditional or 

RTO power markets.

OTC transactions are conducted through direct negotiations between parties or through brokers. Brokers range 

from voice brokers to electronic brokerage platforms such 

as that offered by the IntercontinentalExchange (ICE). Unlike an exchange, an electronic brokerage platform matches 

specifi c buyers and sellers, and is not anonymous. 

 

Products may be negotiated individually or may be standardized. Many negotiations start with a standardized 

contract, such as that developed by the Edison Electric Institute (EEI) for power trading, and then modify it. Others 

start from scratch. Individually negotiated deals are called 

structured contracts

To be tradable, a contract must include terms and conditions that make it attractive to more than one entity. 

Consequently, complicated, one-off contracts negotiated 

to meet the need of an individual seller and buyer may 

have little or no resale value. Typically, the standardized 

contracts traded on exchanges or electronic brokerage 

platforms are designed to be of interest to many market 

participants.

In general, when referring to transactions for physical and 

fi nancial natural gas and power products, bilateral and 

over-the-counter mean the same thing.

The IntercontinentalExchange Inc. (ICE) operates as a global, electronic marketplace for trading both futures and OTC 

energy contracts. ICE’s markets offer access to a range of 

contracts based on crude oil and refi ned products, natural 

gas, power and emissions, as well as soft commodities including cocoa, coffee, cotton, ethanol, orange juice, wood 

pulp and sugar, in addition to currency and index futures 

and options. 

Regional Transmission Organizations

Electricity is also bought and sold through RTOs. In general, RTOs operate their markets to support the physical 

operation of the electric grid under their control, including making decisions about what generation to dispatch 
 Energy Primer | 111

to meet customer demand. RTO markets are multilateral; 

buyers and sellers are not matched individually against 

each other. RTOs allow for bilateral physical transactions, 

although each RTO handles these differently. RTOs provide 

settlement, although this differs from the settlement offered by exchanges. 

Also, RTOs use the word clearing to refer to the matching 

of supply and demand – to clear the market means the RTO 

accepts suffi cient generation offers to meet demand. If a 

generator’s offer in the day-ahead market clears, it means 

that generation was offered at or below the market clearing price and was chosen to generate the next day. RTOs 

do not take title to contracts and do not step into the 

middle of transactions, although they do maintain credit 

policies and allocate the costs of defaults or other performance failures across market participants. 

RTO markets may have fi nancial elements. One of these 

is virtual transactions. For example, a trader may offer 

generation in the day-ahead market, and the generation 

does not show up in the real time market. As a result, the 

trader is paid for his generation offer in the day-ahead 

market, based on day-ahead prices, but effectively has to 

pay to replace his power in the real-time market, paying 

the real-time price. Financial participants can be involved 

in virtuals; they use the physical product (generation offers or demand bids) in a way that results in no physical 

delivery. Virtuals are fi nancial contracts, directly integrated 

into the RTO’s operation of its physical market; they affect 

physical supply and demand, and prices. RTOs use them 

to add liquidity in an attempt to improve the effi ciency of 

their physical markets.

RTOs may also offer fi nancial transmission rights (FTRs) 

programs. Typically, a transmission owner that turns over 

operation of its transmission to the RTO wants certainty 

over its ability to fl ow electricity and about the cost of 

transmission. Because the RTOs operate using markets, this 

certainty cannot be provided directly. FTRs and similar 

instruments are designed to provide some degree of fi nancial certainty to these transmission owners and fi rm rights 

holders. FTRs are linked to the physical operation of the 

RTO’s system; transmission owners would be more reluctant to turn their transmission over to the RTO if they were 

going to experience signifi cant costs due to transmission 

congestion resulting from other RTO members.

FTRs compensate the transmission owners or fi rm rights 

holders in a couple of ways. First, the RTOs auction off 

additional FTRs to others in the market, including fi nancial participants who have no interest in buying, selling 

or transmitting physical power. The proceeds of the auction are returned to some of transmission owners or fi rm 

rights holders. The auction also determines a value for any 

FTRs held by the transmission owners or fi rm rights holders. FTRs can be bought and sold; the auction price gives 

an indication of their value for price discovery. 

Other Market Mechanisms and Concepts

Leverage is the use of a small position to control or benefi t a larger position. It increases the potential return, but 

also increases risk. Leverage can occur when a trader uses 

margin to trade. 
112 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Leverage can be used in other ways. As discussed in Chapter 5, some traders may try to use leverage to manipulate 

the market. For example, traders may use a smaller position in the physical market to benefi t a larger position in 

the fi nancial market. They may buy a fi nancial product 

whose price is derived from a physical product. Then, they 

may try to buy or sell or otherwise infl uence the price of 

the physical product. If they succeed, their fi nancial position benefi ts. 

Liquidity refers to the trading and volumes occurring in a 

market. A market is said to be liquid if trading and volumes are such that any trader can liquidate his position at 

any time, and do so without affecting the prices. A market 

is thin if it has little trading or volume; in these instances, 

trading may affect prices. The benefi ts of liquidity are 

often used to justify practices that increase trading or volumes. However, not all trading or volumes are uniformly 

benefi cial to markets and other market dynamics need to 

be taken into account. 

Markets may not be uniformly liquid. For example, the 

market for the Nymex natural gas futures contract (NG) is 

generally thought to be liquid. However, when the United 

States Natural Gas Fund (UNG) became extremely large, 

its monthly process of getting out of the current contract 

and into the next involved selling and buying an extremely 

large volume of contracts at one time. If these transactions 

affected prices, then the market was affected. 

Open interest is the total number of futures contracts in 

a delivery month or market that has been entered into and 

not yet liquidated by an offsetting transaction or fulfi lled 

by delivery. Thus, as the clock is winding down during 

the settlement period, the open interest contracts (both 

in terms of the total number of contracts and the number 

of counterparties) are rapidly decreasing, so that a given 

number of contracts will represent an increasing share of 

the outstanding prompt-month contracts.

Clearing is a process in which fi nancial or physical transactions are brought to a single entity, the clearing house, 

which steps into the middle of the transaction and 

becomes the counterparty to each buyer and seller. The 

clearing house assumes the risk that either the buyer or 

seller will fail to perform its obligations. Generally, clearing 

is used to manage counterparty risk. Clearing houses maintain rules about the creditworthiness of traders, collateral 

that must be posted and, of course, fees that must be paid 

for the service.

Settlement occurs at the end of a trading period, when 

the contract expires. At this time, delivery is to be made 

for a physical contract (physically settled) or a fi nancial 

payout made for a fi nancial contract (fi nancially settled). 

Settlement occurs both in exchanges and in OTC trades. In 

OTC transactions, settlement occurs under the terms agreed 

upon by the parties. On exchanges, settlement occurs in 

a documented process and timeframe established by the 

exchange. 

For example, every day at the close of Nymex trading, 

the NG contracts for forward months settle. Also, three 

business days prior to the start of the month of delivery 

(the prompt month), the contract expires and the last-day 

settlement (LD settlement) occurs in the last half-hour of 

trading. LD settlement is the fi nal price for that particular 

futures contract term. Thus, the fi nal settlement of natural 

gas futures prices on Nymex occurs on the third business 

day before the end of the calendar month in the last halfhour.

Most market participants avoid trading during the settlement period. As the time to termination approaches, price 

risk and volatility may increase, while market liquidity and 

the remaining open positions (open interest) are decreas-
 Energy Primer | 113

ing. For the Nymex natural gas futures contract (NG), most 

market participants either liquidate or roll their open long 

or short positions well before the settlement period. Rolling is the process of liquidating the current month’s contract before it expires and purchasing a comparable position in the upcoming month. The trader holds the same 

number of contracts, but the contract month held changes 

as time passes and contracts expire.

Daily settlement prices are used to revalue traders’ position to the current market price, for accounting and for 

margin calculations. Daily and LD settlement prices are 

also reported in publications and indexes, and are used for 

price discovery. 

Mark-to-market (MTM) provides that at the end of each 

trading day, all trading positions are revalued to current 

market prices. This results in fi nancial and accounting 

gains and losses. Traders can remove money resulting from 

gains from their accounts or use them for further trading; 

they do not have to liquidate their positions to get the 

money. Losses reduce the value of a trader’s position, and 

may reduce the amount of collateral the trader needs to be 

able to trade on margin. If so, this may result in a margin 

call from the exchange or broker.

Mark-to-market is also an accounting transaction, in that a 

company’s or trader’s accounts are revalued daily to refl ect 

changes in asset price. Losses can reduce the book value of 

a company or trader, and can affect its creditworthiness.

Trading is the buying and selling of contracts. Trades and 

transactions are virtually synonymous. Both refer to the 

buying and selling of power or natural gas.

Short selling is the selling of contracts a trader does not 

own, on the assumption that the trader will buy offsetting contracts prior to the contracts’ expiration. This can 

be done on an exchange or other market that allows for 

bidirectional trading. Short selling has been of concern for 

potential market manipulation – traders sell a contract to 

drive the price down, and then buy when the price is low. 

Short selling is one of the ways market participants can 

trade futures fi nancially – they sell the future, then buy it 

before the contract expires so the contracts net out and the 

trader faces no delivery obligation.

A position is the net holdings of a participant in a market. 

A trader’s position in a specifi c instrument is combined 

purchases and sales of that contract. A trader’s overall 

position is the combination of all positions in all contracts 

the trader owns. A trader’s position is often referred to as 

the trader’s commitment in the market. 

Liquidating a position is the process of getting rid of a 

position. A trader who owns a contract will sell it to liquidate it. A trader who has sold a contract short will buy a 

contract to liquidate it. After liquidation, the trader holds 

no contracts.

Position limits have been imposed by ICE and Nymex, and 

are being developed for certain contracts by the CFTC. The 

position limits may restrict the number of shares a trader 

may hold in a particular investment at any point in time, 

during the month the contract expires, or during some period closer to settlement. For example, CME imposes accountability levels for any one month and for all months, 

and has limits for expiration-month positions. CME’s limits for the Nymex NG contract are12,000 contracts for all 

months, 6,000 contracts for one month and 1,000 contracts in the expiration month. Trading entities can petition to have these waived or modifi ed.

Volumes give an indication as to the nature of the activity 

occurring in the market at any point in time. Volume can 

be expressed in a number of ways. It can be the number of 
114 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

transactions executed during a specifi ed period of time or 

the volume of the product contained in the contracts.

Volumes give market participants information about what 

is going on in the market. For example, if many Nymex 

contracts are traded, and the number of trades is relatively 

few, market participants know that a relatively few traders are making high-volume trades. Conversely, if a high 

number of Nymex contracts are traded and the number of 

trades is also high, then at least some of the trading is being done in small volumes. This could result from broad 

interest in the market – lots of active traders – or it can 

result from relatively few traders making a lot of trades.

Market Participants

Financial markets are used by many types of participants. 

These markets represent an opportunity for physical players, producers and marketers to buy or sell some physical products or to hedge physical supplies and obligations 

with physical or fi nancial products. Investors, speculators 

and investment funds also use these physical and fi nancial 

products for fi nancial gain. 

Products

Products, for purposes of trading, are contracts — also 

known as securities or instruments — that can be bought 

and sold. Contracts for physical trading in natural gas or 

electric markets provide for the delivery of natural gas or 

electricity. The actual molecules of gas or electrons may be 

delivered as a result of the contract. Financial contracts do 

not provide for delivery of a product; instead, they provide 

a fi nancial payout.

Consequently, what traders buy and sell are contracts 

giving them a right or obligation. For physical contracts, 

this is the obligation to deliver or take delivery of natural 

gas or electricity in exchange for payment. For fi nancial 

contracts, it is the right to a payout in exchange for payment.

Other physical and fi nancial products give traders rights to 

buy or sell a contract in the future at a given price – an 

option to buy or sell. 

The word derivative is used for a category of contracts 

whose value is derived from some other physical or fi nancial product or contract. Standardized derivative contracts 

trade on exchanges such as Nymex. Financial contracts are 

derivatives. A common fi nancial derivative used in natural 

gas and electric markets is the swap. 

The CFTC also considers futures contracts to be derivatives. 

As futures contracts approach expiration, their price should 

begin to mirror spot prices – to derive their price from 

spot prices. However, at other times, futures contracts are 

simply the price parties are willing to pay for natural gas at 

some point in the future and do not derive their value from 

any other product or contract. In fact, expiring futures 

contracts may affect spot prices, as well.

Instrument Basics

Each instrument is traded in its own market and is identifi ed by the market name, such as spot or futures. Each 

market and instrument has characteristics such as timeframe, location, contract type, product conveyed by the 

contract and, for swaps, the mechanism for determining 

the payout. 

Product conveyed: Each contract specifi es what it is that is 

being bought and sold. For physical contracts, this would 

be natural gas or electricity. For derivatives, it may be a 

payout derived from natural gas or electricity. All contracts 

conveying or derived from natural gas, for example, would 

be in natural gas markets.

Time: Each contract has a number of time elements. 
 Energy Primer | 115

The trade date is the date on which the contract is written 

(typically the date the trade is executed). 

The expiration day is the last day for a contract, after which 

it is no longer available to be bought and sold; it is often 

the same day as the settlement day. Exchanges and electronic brokerage platforms may also impose a termination 

date, the last date on which a contract may be traded. 

Physical contracts also specify the delivery day(s) or month 

– the day(s) or month during which the product is to be 

delivered.

For physical products, begin and end dates are the dates 

for which a physical product (natural gas or electricity) is 

to be delivered. For fi nancial products, these dates address 

the contracts whose prices are used to set the payout. For 

example, a next-day physical gas deal may have a trade 

date of Aug. 7, a begin date of Aug. 8 and an end date of 

Aug. 8. A monthly product may trade on Aug. 7, its trade 

date; the fl ow of natural gas would have a begin date of 

Sept. 1 and an end date of Sept. 30.

For the Nymex NG contract, the termination day and settlement day are the third-to-last business day of the month 

before the month in which the gas is to be delivered. The 

settlement period occurs from 2 p.m. to 2:30 p.m. on the 

termination day.

Short-term or spot contracts provide for delivery or payout 

during the current or next day; the price for these contracts 

is known as the spot price. 

Daily physical contracts are for delivery on a given day or 

set of days. 

Electric physical and fi nancial contracts may also specify 

peak or off-peak delivery, with the peak or off-peak hours 

defi ned by the contract. 

Contracts for delivery a month or more into the future are 

forward contracts, or if they are traded on exchanges, futures contracts. The Nymex NG contract, for example, provides for the delivery of 10,000 MMBtu of natural gas in 

the month specifi ed by the contract. Contracts are offered 

for every month over the next 12 years. 

Monthly contracts are referred to by how close they are to 

expiring. Spot month is the current month. Prompt month 

is the month after the spot month or current month – it is 

the next trading month. For trading in January, February 

is the prompt month. 

Another time element is the delivery or payout period, such 

as daily, next day or monthly. Monthly contracts generally 

are for delivery in equal parts over a month at a specifi ed 

price for gas and for the contracted amount in each hour 

for power. 

Location: All physical contracts specify the location where 

the natural gas is to be delivered, such as the Henry Hub in 

Louisiana. Financial contracts also have a locational element, determined by the underlier. For example, if a fi nancial derivative uses the Nymex gas contract as its underlier, 

the derivative’s locational element is the Henry Hub.

For natural gas, the locations are referred to as market hubs, 

which are located at the intersection of major pipeline systems. For power, contracts are often based on locations 

known as nodes, zones or hubs. For gas, the principal hub 

and pricing point is the Henry Hub, which is used for all 

Nymex gas futures contracts and is the reference point for 

overall prices in the United States. Prices for other locations are often references as a difference from Henry Hub, 

known as basis.

Products traded on exchanges and preset products traded 

on OTC electronic brokerage platforms such as ICE use 

standardized locations or pricing points. Locations for 
116 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

other OTC transactions use whatever location the counterparties to the contract desire. For physical contracts, the 

location must be physically viable. For fi nancial products, 

it can be whatever the parties desire (although complicated 

locations make pricing more diffi cult due to the lack of 

reference points for price discovery).

Quantity: All physical contracts specify the amount of 

natural gas or electricity to be delivered. For contracts 

traded on an exchange or for preset contracts traded on 

an OTC electronic brokerage platform, the quantity is predetermined and specifi ed in the contract. For bilateral 

contracts traded in OTC markets, the quantity contained 

in the contract can be anything the parties want it to be. 

For standardized products traded on electronic brokerage 

platforms, the quantity is fi xed.

Price: The price paid for a contract is usually that set by 

the market and is usually known at the time the contract 

is bought or sold. 

Fixed prices are known at the time the transaction is entered into – it is the price at which the seller agrees to sell 

and the buyer agrees to buy. Contracts sold at fi xed prices 

are typically paid for at the time of purchase. 

Floating prices are set by formulas pegged to something 

whose price is not currently known but which will be at the 

time the contract expires, such as an index. For example, 

a price may be tied to the average of the all of the daily 

prices at a location over the course of a month, typically as 

published in an index. An index contract is a commonly 

traded instrument based on major trading points, such as 

the Houston Ship Channel or the Henry Hub. 

Spot price is a cash market price for a physical commodity 

that is available for immediate (next day) delivery, and may 

be reported to publishers for indexes.

Standardized forward contracts and futures contracts are 

traded for every month, years into the future; the NG contract is traded 12 years into the future. Each of those contracts for which trading has occurs has a price. Together, 

the prices for future contract months creates a trajectory of 

prices known as forward or futures curves. 

The settlement price is effectively the fi nal offi cial reported 

price for certain contracts and is an average of prices for 

trades occurring during the settlement period. The settlement price forms the basis for payout in fi nancial derivatives that use the contract as its underlier, for margin calls 

and for reporting to index publishers and other entities. 

For example, the natural gas futures contract settlement 

price is the weighted average price of all sales made during 

the contract’s 30-minute settlement period – the last 30 

minutes of trading on the contract’s termination day. The 

gas futures fi nal settlement price sets, in whole or in part, 

the payout for fi nancial derivatives that use the contract as 

its underlier.

Physical Products

Physical products involve physical delivery. Power products 

include energy, transmission (fi rm and nonfi rm) and ancillary services. Electric energy products include spot transactions, full requirements sales and bundled services, among 

other things. Natural gas products include the natural gas 

molecules themselves, transportation and storage. 

Forward products are contracts for delivery in future months 

traded through the OTC market (including electronic brokerage platforms). If the product is traded on an exchange, 

it is known as a futures contract. 

A futures contract is a standardized forward contract traded on a regulated exchange. Each contract represents the 

same quantity and quality of the underlying physical com-
 Energy Primer | 117

modity, valued in the same pricing format, to be delivered 

and received at the same delivery location. In addition, the 

date of delivery and receipt is the same for all contracts 

traded for a particular calendar month. The only element 

of futures contract that is subject to change when it is 

bought or sold is the price. 

For the natural gas industry, the dominant futures contract is the Nymex NG contract. For the NG contract, the 

standard contract specifi cations are the delivery location 

– Sabine Pipeline Hub at the Henry Hub in Louisiana; the 

term – monthly; and the quantity – 10,000 MMBtu delivered equally over the course of the month. Not all forward 

contracts have fi xed prices. Some involve trades executed 

now to buy or sell at some point in the future, at a price 

to be set in the future. One example of this is a forward 

physical index contract. This OTC contract obligates one 

party to buy the underlying commodity or security and 

the other party to sell it, for a delivery price to be determined when a specifi c index sets at some known date in 

the future. Many natural gas purchases are made under 

forward physical index contracts; among other things, it 

may provide state regulators with some assurance that the 

price paid is reasonable. 

Forward and futures contracts with fi xed prices can be used 

for price discovery, hedging or speculating. They may be 

traded by any of the participants listed earlier. Physical 

participants may use forwards or futures to obtain gas or 

electricity for delivery in some future month, or may use 

them to manage the risk of – or, hedge – their physical 

positions. Futures contracts that go to delivery lose their 

anonymity at settlement. However, only a small fraction 

– often, less than one percent – of futures contracts go to 

delivery.

Financial traders may buy or sell futures contracts for 

fi nancial purposes, as exchanges have bidirectional trading – markets in which trader can buy and sell contracts 

with equal ease. Bidirectional trading allows the sale of 

contracts a trader does not own, known as short sales. A 

fi nancial trade may buy a forward or future, then either sell 

the contract later or neutralize it by obtaining an offsetting 

contract. Because the two offset, the trader has no physical delivery obligation. Most Nymex natural gas futures 

contracts do not go to delivery.

Physical products can be combined to create different 

physical positions for use in physical and fi nancial trading. A price spread can be created using forwards priced 

at indexes for two different hubs. The trader would buy 

physical natural gas at one index and sell at another. For 

example, the trader buys gas priced at the Houston Ship 

Channel index (and would have to take delivery of the gas 

there) and sells gas at the Texas East M-3 index (and would 

have to deliver it there). The trader earns the difference between the two contracts. A physical spread carries with it 

the obligation to make or take physical delivery of natural 

gas at both points, so pipeline capacity would be required 

to actually move gas between these points. 

A fi nancial trader could also execute this trade, but would 

have to unwind both positions before delivery.

Indexes
118 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

Indexes are formally published for both natural gas and 

power using a methodology posted by the publisher. An 

index may be used to set the price for settlement of fl oating price contracts. Indexes are also used by a variety of 

market participants to inform their decisions in the many 

steps in the electric or natural gas supply chain or in trading, known as price discovery. Data used in indexes are 

submitted voluntarily by fi rms involved in trading. 

Indexes are commonly formed using volume-weighted average prices.

Financial Products

Financial contracts do not provide for the delivery of a 

product, but instead provide a fi nancial payout. This is 

often based on the value of some physical or fi nancial 

product specifi ed by the contract, called the underlier. The 

value of these fi nancial contracts is derived from the value 

of the physical or fi nancial instrument specifi ed in the contract as the basis for payout; as such, they are derivatives. 

A key benefi t of fi nancial products is that they have no 

physical delivery and they are self-liquidating. Speculators 

who trade futures have to undo their position to eliminate 

the delivery obligation. One who trades derivatives, on the 

other hand, does not bear the complications of unwinding 

positions; he can simply wait for expiration and receive or 

pay the contract’s payout. 

Swaps

A key fi nancial contract structure used in natural gas and 

electric markets is the swap, or contract for differences. 

The CFTC defi nes a swap as an “exchange of one asset 

or liability for a similar asset or liability ... it may entail 

buying ... on the spot market and simultaneously selling 

it forward. Swaps may also involve exchanging income 

fl ows...” Effectively, a swap is the exchange of like for 

like. Consequently, physical instruments cannot be swaps 

because parties to physical goods pay or receive money in 

exchange for delivery of the physical good. However, the 

exchange of money in terms of payment and payout constitutes a swap. 

Options 

An options contract conveys a right (but not the obligation) to buy or sell something else. It comes in two forms: 

the right to buy or the right to sell something at a specifi ed price at or before a specifi ed date. The buyer buys the 

right – the option – to buy or sell in the future; the seller 

(or writer) sells the obligation to sell or buy if the buyer 

exercises his right.

An option to buy is known as a call option; an option to 

sell is a put option. The price paid to buy or sell the option 

is known simply as the option’s price. The price at which 

the option may be exercised is the strike price. Electing to 

buy or sell the underlying commodity or security is known 

as exercising the option.

Options traded on exchange or electronic trading platforms 

may be traded up to their expiration. Consequently, the 

owner of an option may sell it rather than exercising the 

option or letting it expire. 

Traders buy and sell options for a number of reasons. First, 

they provide a risk management tool akin to insurance. 

Second, traders may use options traded on exchanges or 

electronic trading platforms to speculate. For example, a 

speculator may trade an option and hope to gain from price 

movements, akin to how they might trade other contracts, 

such as futures. If a trader buys an option, he can sell it 

up to expiration and pocket the difference between the 

purchase price and the sales price. Further, as in futures, 

the seller of an option traded on an exchange can offset 

his obligation by purchasing the offsetting option, thereby 
 Energy Primer | 119

eliminating the risk of the contract going to delivery. 

Finally, traders may use options to boost their trading income or to reduce the volatility of their returns. Options require less money up-front than a futures contract or swap, 

which can be a benefi t to traders with limited funds.

Trading and Transacting

Trading Mechanics

Market prices are the collective result of individual trades. 

Open interest is the aggregation of traders’ positions. 

Trading is the buying and selling of contracts. A trade is 

a single purchase or sale. A position is the accumulated 

unexpired contracts purchased or sold, at a point in time. 

Traders may have positions in each contract, as well as an 

overall position refl ecting all their contracts. 

Trading requires a buyer and a seller, each willing to transact for a price. A buyer bids a price he is willing to pay to 

purchase a contract; this is the bid price. A seller offers his 

product for sale; the price at which he offers it is the offer 

price. 

These prices may or may not be the same. When they 

differ, the distance between them is the bid-offer or bidask spread. This spread is the difference between the highest price at which buyers are currently willing to buy (the 

highest bid) versus the lowest price at which sellers are 

currently willing to sell (the lowest offer). For example, if 

a buyer bids $7 and the seller offers at $10, the bid-ask 

spread is $3.

Trading Concepts

Traders need to know how their trades and positions will 

be affected by market changes. One way this is done is 

by considering whether a trade or position benefi ts or loses 

when prices go up or down. A position is long if it benefi ts 

from increases in price. It is short if it benefi ts from falling 

prices. If it is neutral, benefi tting from neither a rise nor a 

fall in prices, it is said to be fl at.

For example, a trader who purchases an NG contract is going long; that contract will benefi t from increases in price. 

A trader who sells the contract is going short; the trader 

will benefi t from falling prices. 

The concept of being long or short applies to other forms 

of transactions. Absent anything else, a generator is long 

electricity; a consumer short electricity. If the generator 

obtains a contract to sell electricity to the consumer at its 

cost of generating, the generator is fl at.

The task of identifying long or short is not always easy. A 

trader may have a variety of positions in a number of contracts, some long and some short. How the overall position benefi ts from swings in prices depends on each of the 

components and how they interact with each other. 

Trading Strategies

Traders decide what products to trade, how to trade them 

and in which combinations. Their strategies will depend 

on their objectives. Broadly, market participants trade to 

accomplish any of three objectives: to buy or sell physical products, such as natural gas or electricity; to manage 

the risk of their physical positions, or hedge; or to make 

money.

Hedging

Market participants who are in the market to buy and sell 

natural gas and electricity are interested in making money 

through their physical operations. These physical operations determine their individual risks and hedging needs. 

Thus, each physical market participant’s risks depend on 
120 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

his role in the physical delivery and consumption of natural 

gas and electricity. A natural gas producer has different 

risks and therefore different hedging objectives than an 

LDC that needs to purchase gas to resell to retail consumers.

An LDC, for example, is concerned with obtaining suffi -

cient volumes to serve variable customer demand and in 

the price paid for those volumes. A producer may be concerned about selling all his output (unless he can store it), 

and about the price he will be paid for the gas. Physical 

market participants may have other concerns as well. Producers may need a predictable cash fl ow to support their 

fi nancing. LDCs may be concerned with state regulators 

determining that their gas purchasing practices were imprudent.

Such concerns drive both procurement and sales decisions 

as well as risk management decisions. The two are often 

closely interconnected. For example, an LDC needs to buy 

enough gas to meet extremely variable retail demand, but 

not too much. He also wants a price that regulators and 

consumers will see as reasonable. Consequently, this LDC 

develops a procurement and risk management – hedging – 

strategy taking these factors into account. 

To purchase suffi cient quantities, the LDC may create a 

portfolio of supplies, with a block of fi rm supply to meet 

minimum daily needs. He may also decide to buy in the 

spot market to meet demand peaks. He may diversify the 

sources of gas, both to improve reliability of supply but 

also to diversify its price.

He can also manage his risk fi nancially. In the commodities 

and securities market, a hedge is a transaction entered into 

for the purpose of protecting the value of the commodity 

or security from adverse price movement by entering into 

an offsetting position in a related commodity or security. 

Hedging is used when describing the purpose of entering 

into a transaction with the intent of offsetting risk from 

another related transaction. 

Speculation

Traders seeking to make money fall into a couple of categories: investors and speculators. These categories are 

distinguished by the strategies they use to profi t from the 

market. Investors are relatively passive; they are in the 

market to benefi t from long-term price movements and to 

diversify a broader portfolio. Speculators actively seek to 

gain from price movements. 

Trading Analysis

In deciding whether to trade, both hedgers and speculators pay attention to what is going on in the market, and 

develop their own view of where the market is likely go. 

They may develop complicated forecasts as the basis for 

decisions on a number of transactions: whether, when and 

where to build a merchant power plant, how to hedge natural gas production, and of course, when to buy and sell 

in the markets.

Two general schools infl uence traders’ thinking when 

analyzing markets for trading opportunities. The fi rst is 

fundamental analysis, which takes into account physical 

demand and supply fundamentals including production, 
 Energy Primer | 121

pipeline and transmission capacity, planned and unplanned 

outages, weather and economic and demographic changes. 

Changes in information about fundamentals (or changes 

in perceptions of fundamentals) alters traders’ view of the 

supply-demand balance, and therefore, of prices. Fundamental analysis is used often to determine the impacts of 

longer term trends in the physical market – the development of shale gas supplies, for example.

The second school of thought is technical analysis, which 

forecasts price movements based on patterns of price 

changes, rates of change, changes in trading volumes and 

open interest, without regard to the underlying fundamental conditions. Instead of looking at the market for 

a physical good, technical analysis looks at trading and 

price changes. These quantitative methods have become 

a dominant part of market analysis. Technical analysis is 

used most often to determine short-term movements and 

trends, helping traders time their buys and sells.

Capital Markets

Capital markets provide the money to make investments in 

infrastructure such as power plants or natural gas pipelines, 

to operate plants and companies and to trade or conduct 

transactions. Access to capital depends both on the health 

of capital markets and also on the perceived riskiness of 

the entity seeking the capital. To measure relative riskiness, many providers of capital look at different measures, 

including credit ratings assigned by the three major crediting rating fi rms: Standard and Poor’s (S&P), Moody’s and 

Fitch.

Capital Expenditures

One effect capital markets have on energy markets is in 

capital spending – undertaking work or investments that 

require capital. The recent recession and shake-up in capital markets took a toll on capital spending as fi nancial 

commitments to infrastructure in 2009 fell for the fi rst 

time in years but then rose again (see bar chart).

The electric industry makes up the bulk of the capital expenditures expected by the energy companies, as compiled 

by SNL between 2010 and 2012 (see pie chart, page 123). 

These capital additions lie primarily in generation, transmission and distribution. In the past couple of years, investment decisions on new big-dollar projects have been 

delayed. 

Types of Capital

Capital comes from two general sources of fi nancing – 

equity and debt.

Debt fi nancing involves borrowing money to be repaid 

over time, along with interest at a fi xed or variable interest 

rate. With debt, the investor does not become an owner of 

the company. Some common types of debt include bonds 

– securities that companies issue in fi nancial markets with 

maturities (when the loan has to be repaid) of more than 

a year; shorter term debt issued by companies through 
122 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

fi nancial markets; and bank loans, such as lines of credit. A 

revolving line of credit is an assurance from a bank or other 

institution that a company may borrow and repay funds up 

to some limit at any time. Municipal and cooperative utilities typically use debt; they have no ownership to sell.

Characteristics of debt include:

• Capital obtained through debt must be repaid or refi -

nanced.

• Debt may be short-term, such as lines of credit from 

banks or corporate paper, or it may be long-term. 

• Companies must make their interest payments and 

repayment on schedule, or the debt holders can take 

action, including forcing the company into bankruptcy. 

A company must generate suffi cient cash through its 

operations or through other fi nancing to make these 

payments.

• Interest gets paid before equity dividends.

• Interest payments are tax deductible.

• Debt gives lenders little or no control of the company 

(unless it gets into fi nancial trouble).

• Debt can leverage company profi ts; similarly, it can 

magnify losses.

• Lenders are typically conservative, wanting to minimize 

downside risks.

• Borrowers may be required to pay collateral to secure 

debt. Debt without collateral is known as unsecured 

debt. 

Equity fi nancing is money provided in exchange for a 

share in the ownership of the business. A company does 

not have to repay the capital received, and shareholders are 

entitled to benefi t from the company’s operations, perhaps 

through dividends. 

• Equity capital can be kept by the company indefi nitely.

• Companies can issue shares in the company – stock – 

through fi nancial markets. They may also use private 

equity – money from venture capital fi rms or private 

investment companies that buy into a company and 

which may or may not take an active role in operating 

the company. 

• The most common form of stock is common stock, 

which does not require regular payments, but it may 

receive dividends; investor-owned utilities typically pay 

dividends. 

• Equity does not provide a tax deduction to the company; dividends and other payouts are not tax deductible.

• Stockholders and private equity investors get a say in 

how the company is operated and may impose restrictions.

• Equity investors may be more willing to assume higher 

risks in return for a higher potential returns. Utilities 

are typically considered fairly conservative investments. 

Natural gas producers attract a more risk-inclined 

investor.

• The return required to attract equity is higher than the 

interest paid to debt holders.

• Equity capital does not require collateral; it gets a 

share in the company.

• Additional equity capital infusions may dilute, or reduce, the value of existing shares.
 Energy Primer | 123

Companies often try to match the type of fi nancing with 

the investment they are making. Pipelines, power plants 

and transmission facilities are long-lived assets. They are 

typically fi nanced using long-term capital, such as stock 

and long-term bonds, which can have 30-year maturities. 

Other capital is needed to conduct day-to-day operations. 

Some of the cash needed to fund operations comes from 

a company’s revenues. However, revenues do not always 

come in when payments are due. Consequently, companies also rely on working capital. This can include some 

long-term capital from stocks and medium- and long-term 

bonds. Short term investments and day-to-day operations 

also rely on commercial paper and bank loans to cover 

day-to-day cash needs. If a company faces signifi cant 

problems, it may have to issue especially high-priced debt 

– junk bonds – to obtain fi nancing. These are bonds issued by entities lacking investment grade credit ratings (see 

below).

In the past few years, private equity investors and hedge 

funds – individuals or funds seeking to take ownership positions in companies or even buy companies – have taken 

an interest in the energy industry, and have provided another source of equity fi nancing. Private equity fi rms have 

bought energy companies, including Puget Sound Energy, 

Energy Transfer Partners and Mountaineer Gas Co. Two 

of the larger private equity fi rms interested in the energy 

sector include Kohlberg Kravis Roberts & Co. (KKR) and 

Macquarie Group.

Credit Ratings

Not all companies (or governments) present the same riskiness to investors. Investors, traders and others consider the 

risks their counterparty may present, including the risk of 

default. One standardized tool used to assess relative risk is 

the credit rating. Credit rating agencies, such as Standard 

and Poor’s, Moody’s and Fitch, assess a company’s riskiness every time it wants to issue bonds. A credit rating 

represents the likelihood that an issuer will default on its 

fi nancial obligations and the capacity and willingness of a 

borrower to pay principal and interest in accordance with 

the terms of the obligations. Many organizations, including RTOs, consider bond ratings, among other things, when 

setting their credit policies, which determine with whom 

companies may transact and whether the counterparty will 

need to post collateral. Each credit rating agency has its 

own way of assessing risk, refl ected in the rating system 

they use.

Ratings by Industry Sector

Electric utilities largely are rated investment grade, with 

ratings of BBB or better.

Merchant generators include generating companies that 

are completely unaffi liated with integrated utilities (and are 

known as independent power producers, or IPPs) and those 

that are affi liated but which receive at least half their cash 

fl ow from competitive power sales. The affi liated companies typically have higher ratings; S&P views the integrated 

merchants’ business profi le scores as strong or satisfactory. 

S&P typically rates IPPs fair or weak. 

The midstream sector of the natural gas industry, which 

contains pipelines, processing plants and storage facilities, 

is also typically rated investment grade. Midstream companies’ ratings average BBB and are said by rating agencies 

to have a stable outlook.

 Energy Primer | 125

Energy markets can be manipulated. Following the energy 

crisis in the western United States early last decade, Congress granted the Federal Energy Regulatory Commission 

new authority to address this threat to the integrity of its 

regulated markets. At Congress’s direction, the Commission enacted a catch-all antifraud rule that is modeled on 

the Securities and Exchange Commission’s (SEC’s) decadesold rule protecting the securities markets. Recognizing 

that other regulators have long prohibited manipulation 

of other markets such as securities and commodities, the 

Commission draws from the experience of sister federal 

agencies in implementing the Commission’s anti-manipulation authority. 

Manipulation comes in many varieties. As a federal court 

of appeals has stated in the context of commodities manipulation, “We think the test of manipulation must largely be a practical one.... The methods and techniques of 

manipulation are limited only by the ingenuity of man.” 

The Commission recognized this reality by framing its AntiManipulation Rule broadly, rather than articulating specifi c 

conduct that would violate its rules. While manipulative 

techniques may be “limited only by the ingenuity of man,” 

the following are broad categories of manipulations that 

have surfaced in the securities and commodities markets 

(including the energy markets) over the years. The borders 

of these categories are not clearly defi ned and some can 

belong to multiple categories, such as wash trading (i.e., 

buying and selling identical stocks or commodities at the 

same time and price, or without economic risk). Traders 

may also combine elements of various schemes to effect a 

manipulation.

Withholding

Withholding is the removal of supply from the market and 

is one of the oldest forms of commodities manipulation. 

The classic manipulation of a market corner involves taking 

a long contract position in a deliverable commodity and 

stockpiling physical supply to force those who have taken 

a short position to buy back those positions at an infl ated 

price.

Withholding played an important role in the western power 

crisis that engulfed California in 2000. Market participants, 

particularly Enron, exploited supply-demand imbalances 

and poor market design. Generation operators scheduled 

maintenance outages during peak demand periods, which is 

an example of physical withholding. In addition, transmission lines were overscheduled to create the appearance of 

congestion in an effort to reduce the supply of electricity. 

The result of these efforts in combination with economic 

withholding and information-based schemes discussed below was that wholesale electricity prices soared. Utilities 

such as Pacifi c Gas & Electric (PG&E) and Southern California Edison were unable to pass on these high prices to 

their retail customers because of state price caps. The crisis led to widespread blackouts, heavy losses to the state’s 

economy and the bankruptcy, in April 2001, of PG&E.

Economic withholding, which also contributed to the 

western power crisis, is similar to physical withholding, but 

rather than turning off a generator or stockpiling a physical commodity, the manipulator sets an offer price for a 
126 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

needed resource that is so high that the resource will not 

be selected in the market. For example, a generator in a 

constrained market such as New York City could purposely 

set its offer price high enough that it would not be called 

on to run. This scheme would create a shortage of generation and, thus, would raise prices for the benefi t of the rest 

of its generation fl eet or its fi nancial positions. If done to 

benefi t fi nancial positions, this scheme would be a crossproduct manipulation similar to the ones discussed later.

Information-Based Manipulations

Many manipulative schemes rely on spreading false information, which involves knowingly disseminating untrue information about an asset’s value in order to move its price. 

A well-known scheme is the pump and dump, in which a 

participant spreads a rumor that drives the price up and 

then sells the shares after the price rises. In the energy 

markets, a common way to misrepresent a commodity’s 

value is to misrepresent the price of the commodity or its 

level of trading activity. False reporting and wash-trading

schemes were well-documented information-based manipulations that took place in the early 2000s and contributed 

to the western energy crisis. False reporting occurs when 

a market participant submits fi ctitious transactions to a 

price-index publisher to affect the index settlement price. 

Similarly, wash trading involves actual but offsetting trades 

for the same (possibly nonmarket) price and volume between the same market participants such that no economic 

exchange takes place; however, it falsely infl ates trading 

volumes at a price level and gives the impression of greater 

trading activity. False reporting and wash trading have resulted in a number of criminal prosecutions by the Department of Justice. A variation on these practices is roundtrip trading, in which a trader sells an asset but agrees to 

buy it back at the same time.

Manipulative Trading Techniques

A number of manipulative trading techniques that have 

arisen in securities and commodities trading may be subject to the Commission’s Anti-Manipulation Rule. Traders 

may seek to infl ate trading volumes or trade at off-market 

prices to serve purposes such as maintaining market confi dence in a company’s securities or to move a security’s 

price to trigger an option. Marking the close is a manipulative practice in which a trader executes a number of 

transactions near the close of a day’s or contract’s trading 

to affect the closing or settlement price. This may be done 

to obtain mark-to-market marks for valuation, to avoid 

margin calls or to benefi t other positions in related instruments, the latter of which was done by both Brian Hunter 

and Constellation Energy Commodities Group (discussed 

in the next section). Banging the open is a similar practice in which a trader buys or sells a large quantity at the 

opening of trading to induce others to trade at that price 

level and to signal information on fundamentals. Other 

manipulative trading techniques exist, and previously discussed practices like wash and round-trip trading fi t under 

this description as well.

FERC Investigation and 

Prosecution of Cross-Product Manipulations

Manipulators have grown more sophisticated with the expanded use of derivative products, whose value is set by the 

price of transactions in a related product.

Many of the manipulative schemes that staff has investigated and prosecuted are cross-product schemes in which 

an entity engages in price-making trades in the physical 

market, often at a loss, to affect the settlement price of 

price-taking derivative instruments. 
 Energy Primer | 127

Brian Hunter and Amaranth Advisors

In 2010, a FERC administrative law judge (ALJ) found that 

Brian Hunter, a trader with Amaranth Advisors LLC, manipulated the settlement price of the March, April and May 

2006 New York Mercantile Exchange natural gas futures 

contracts (Nymex NG contract). Hunter bought large long 

positions in Nymex NG contracts, which he sold rapidly 

during the contract’s fi nal settlement period with the intent of pushing down the settlement price. He engaged in 

this behavior while he concurrently held larger short positions in fi nancial look-alike contracts, principally on the 

IntercontinentalExchange (ICE), which benefi ted from a 

lower Nymex NG price.

The Commission affi rmed the ALJ’s fi ndings and imposed 

a $30 million civil penalty on Hunter. His appeal of this 

decision was pending at the time of this printing. Other 

Amaranth parties had previously settled.

Energy Transfer Partners

In 2007, the Commission issued an order to Energy Transfer Partners LP (ETP), directing it to show cause why the 

Commission should not fi nd that ETP violated the Commission’s market behavior rule that prohibited manipulative practices. The order charged that ETP manipulated the 

Houston Ship Channel (HSC) market for natural gas. FERC 

charged that ETP entered into fi nancial and physical positions at HSC that profi ted from a lower HSC index price. 

ETP’s fi nancial positions were mostly basis swaps that exchanged the Henry Hub price for the HSC index price with 

a differential. ETP’s physical positions were mostly purchases of natural gas at the HSC index price. 

The HSC index was set by physical fi xed-price trades made 

during bidweek, which is trading during the last few days 

of one month for gas to be delivered every day of the 

following month. These trades were reported to Platts, a 

news and price-reporting service, and calculated according to Platts’s methodology. The FERC order charged that 

ETP entered into bidweek physical trades at less than competitive prices with the intent to drive down the HSC index 

price. ETP’s trading volumes were so great that it dominated the HSC index. On the eve of trial, ETP agreed to 

pay $30 million to settle the allegations.

Constellation Energy Commodities Group

In 2012, the Commission approved a settlement with Constellation Energy Commodities Group (CCG) in which CCG 

agreed to disgorge $110 million in unjust profi ts and pay a 

civil penalty of $135 million. FERC staff had alleged that 

CCG entered into signifi cant loss-generating physical and 

virtual day-ahead transactions in electricity markets in and 

around New York state with the intent to move day-ahead 

price settlements to benefi t fi nancial swap positions that 

received their prices from those settlements. 

Details of FERC Jurisdiction

The Energy Policy Act of 2005 added anti-manipulation 

provisions to the Federal Power Act, 16 U.S.C. § 824v 

(2006), and the Natural Gas Act, 15 U.S.C. § 717c-1 (2006), 

which the Commission implemented in Order No. 670. 

This rule has been codifi ed as 18 C.F.R. § 1c (2011) (AntiManipulation Rule). 
128 | Energy Primer FEDERAL ENERGY REGULATORY COMMISSION

The Anti-Manipulation Rule prohibits anyone from (1) using a fraudulent device, scheme or artifi ce, or making any 

untrue statement of a material fact or omitting to state a 

material fact necessary to make a statement that was made 

not misleading, or engaging in any act, practice or course 

of business that operates or would operate as a fraud or deceit upon any entity; (2) with the requisite scienter (that is, 

an intentional or reckless state of mind) (3) in connection 

with a transaction subject to FERC jurisdiction. The Commission need not show reliance, loss causation or damages 

to prove a violation. The Anti-Manipulation Rule applies 

to any person, entity or form of organization, regardless of 

its legal status, function or activities.

The prohibition is intended to deter or punish fraud in 

wholesale energy markets.

The Commission defi nes fraud in general terms, meaning 

that fraud includes any action, transaction or conspiracy 

for the purpose of impairing, obstructing or defeating a 

well-functioning market. Fraud is a question of fact that is 

to be determined by all the circumstances of a case. In Order No. 670, the Commission found it appropriate to model its Anti-Manipulation Rule on Securities and Exchange 

Commission (SEC) Rule 10b-5 in an effort to prevent (and 

where appropriate, remedy) fraud and manipulation affecting the markets the Commission is entrusted to protect, 

while providing a level of certainty to market participants 

that is beyond that which the Commission would be otherwise required to provide. Like SEC Rule 10b-5, FERC’s 

Anti-Manipulation Rule is intended to be a broad antifraud 

catch-all clause.

The Commission made clear in Order No. 670 that a duty 

to speak to avoid making untrue statements or material 

omissions would arise only as a result of a tariff or Commission order, rule or regulation. However, the Anti-Manipulation Rule extends to situations where an entity has 

either voluntarily or pursuant to a tariff or Commission 

directive provided information but then misrepresents or 

omits a material fact such that the information provided is 

materially misleading. 

A fact is material if there is a substantial likelihood that a 

reasonable market participant would consider it in making 

its decision to buy or sell because the material fact signifi -

cantly altered the total mix of information available.

To violate the Anti-Manipulation Rule, one must act with a 

suffi cient state of mind, that is, level of intent. As with violations of SEC Rule 10b-5, intentional conduct or recklessness (known as scienter) are enough to satisfy the Rule. 

The Commission also stated that for conduct to violate the 

“in connection with” element of the Rule, there must be 

a suffi cient nexus between an entity’s fraudulent conduct 

and a jurisdictional transaction. In committing fraud, the 

entity must have intended to affect, or have acted recklessly to affect, a jurisdictional transaction.