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

Commission or any Commissioner. 

Energy Primer

A Handbook of Energy Market Basics

November 2015

Energy Primer | i

Energy Primer

A Handbook of Energy Market Basics

Table of Contents

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

Physical Fundamentals ..............................................................................................1

Financial Markets and Trading ...................................................................................2

Market Manipulation .................................................................................................3

Additional Information ...............................................................................................3

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

Natural Gas .................................................................................................................5

Natural Gas Industry ..................................................................................................5

Natural Gas Demand ..................................................................................................7

Natural Gas Supply....................................................................................................10

	 Liquefied Natural Gas ...............................................................................................18

Natural Gas Processing and Transportation............................................................ 21

Natural Gas Storage..................................................................................................28

Natural Gas Markets and Trading.............................................................................32

Chapter 3 Wholesale Electricity Markets .............................................................................35

Electric Power Industry ........................................................................................... 36 

Electricity Demand....................................................................................................41

Electricity Supply and Delivery .................................................................................47

Wholesale Electricity Markets and Trading ............................................................ 56

RTO Markets and Features...................................................................................... 59

Regions..................................................................................................................... 66

Southeast Wholesale Market Region ..................................................................... 66

Western Wholesale Market Regions....................................................................... 68

CAISO.........................................................................................................................72

ISO-NE........................................................................................................................77

MISO..........................................................................................................................82

NYISO.........................................................................................................................87

PJM ........................................................................................................................... 93

SPP............................................................................................................................ 98
ii | Energy Primer Federal Energy Regulatory Commission

Chapter 4 U.S. Crude Oil and Petroleum Products Markets ............................................. 103

Petroleum ...............................................................................................................104

U.S. Crude Oil Supply...............................................................................................105

Petroleum Reserves ...............................................................................................106

	 Crude Oil Refining ...................................................................................................107

Crude Oil and Petroleum Products Transportation ...............................................109

Crude Oil and Petroleum Products Demand ..........................................................110

Crude Oil and Petroleum Products Markets and Trading ...................................... 111

Chapter 5 Financial Markets and Trading............................................................................113

Financial Markets and Mechanisms ........................................................................113

Physical Products .....................................................................................................119

Financial Products...................................................................................................120

Trading and Transacting ..........................................................................................121

Capital Markets ....................................................................................................... 123

Chapter 6 Market Manipulation ......................................................................................... 127

Manipulative Trading Techniques and Cross-Product Manipulations ..................128

Information-Based Manipulations .........................................................................129

Withholding..............................................................................................................119

Representative Matters..........................................................................................130

The Federal Energy Regulatory Commission retains rights to all photographic images included in the Energy Primer.
Energy Primer | 1

1. Introduction

Natural gas, electricity, and oil are forms of energy that are of particular interest to the Federal Energy Regulatory Commission pursuant to its authority under the Natural Gas Act, the Federal Power Act, and the Interstate Commerce Act. This primer 

explores the workings of the wholesale markets for these forms of energy, as well as energy-related financial 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, wind, or 

solar into a flow of electrons used to power modern life.

Crude oil and petroleum products are of interest to the Commission because it regulates the transport of oil by pipelines in 

interstate commerce.

Energy markets involve both physical and financial elements.

The physical markets contain the natural resources, infrastructure, institutions and market participants involved in producing energy and delivering it to consumers. They also include 

the trading of and payment for the physical commodity - e.g., 

natural gas. The financial markets include the buying and selling of financial products derived from the physical energy.

These financial markets also include market structures and

institutions, market participants, products and trading, and 

have their own drivers of supply and demand. In general, physical and financial 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 the energy. Physical market participants 

are those who are in the market to make or take delivery of 

the commodity. Financial products usually do not involve the 

delivery of natural gas, electricity, or oil; instead, they involve 

the exchange of money.

Physical markets can be further differentiated by:

• Location: regions, nodes, zones or hubs

• Time frames: hourly, daily, monthly, quarterly or yearly

• Types of products: natural gas molecules or electrons,

pipeline or transmission capacity and storage

• Nature of sales: retail sales involve most sales to end use

customers; wholesale sales involve everything else
2 | Energy Primer Federal Energy Regulatory Commission

Physical Fundamentals

Much of the wholesale natural gas and electric power 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 energy are 

physical fundamentals - the physical realities of how markets 

produce and deliver energy to consumers and how they form 

prices. These physical fundamentals will be covered in Chapter 2 (Wholesale Natural Gas Markets), Chapter 3 (Wholesale 

Electricity Markets), and Chapter 4 (U.S. Crude Oil and Petroleum Products Markets).

Wholesale natural gas and electricity 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 natural 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 electricity 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 benefits 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. 

Natural gas flows through a pipeline at velocities averaging 25

mph, depending on the pipeline and the configuration of related facilities, 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 technologies 

such as batteries and flywheels are 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 flow 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 light 

bulb is produced at the moment of illumination.
Energy Primer | 3

Financial Markets and Trading

The energy industries are capital intensive, requiring access 

to financial markets to support daily operations, trading and

investment programs. Access to financial markets requires

maintaining an investment grade credit rating to support activities ranging from daily transactions to long-term development of infrastructure.

Financial markets are where companies and individuals go if 

they need to raise or invest money. They are important to energy 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 financial 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 financial

products were derived from the physical 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 profit from changes

in price.

The market for natural gas and electricity derivatives has 

grown enormously within the past decade, as competitive 

natural gas and electricity markets matured and investors 

came to see energy commodities as investments. This trading 

affects the physical markets in a number of ways, and is discussed in Chapter 5, Financial Markets and Trading.
4 | Energy Primer Federal Energy Regulatory Commission

Market Manipulation

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

manipulate the markets for their own benefit. These practices

undermine the market’s ability to operate efficiently, reduce

other market participants’ confidence in the markets and distort market outcomes, including prices. Some of these practices are discussed in Chapter 6, Market Manipulation.

Additional 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 find the market oversight pages here:

http://www.ferc.gov/market-oversight/market-oversight.asp

Google search also provides a quick path to information on 

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

regulation of natural gas pipelines).
Energy Primer | 5

2. Wholesale Natural Gas Markets

Natural gas markets have a significant effect 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 27 percent of the energy used in the United States, or about 26.1 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 financial market in which physical natural gas is

bought and sold as a financial 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, which is made of one carbon atom and four hydrogen atoms (CH4), and is among the

materials known as hydrocarbons. Natural gas 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 significant crude oil. Natural gas is rich or

wet if it contains significant natural gas liquids (NGL) – e.g.,

ethane, propane and pentane – mixed in with the methane. In 

contrast, natural gas is lean or dry if it does not contain these 

liquids. Processors remove water, liquefiable 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.

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 liquefied natural gas, or LNG.

Natural Gas Industry

As noted, the markets of the natural gas industry are both 

physical and financial. This chapter focuses on the physical

natural gas markets, but it should be noted that financial markets can have significant impacts on the physical natural gas

market.

For this discussion, the natural gas industry has three segments. The first 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 
6 | Energy Primer Federal Energy Regulatory Commission

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 largediameter pipelines to storage facilities and a variety of consumers, including power plants, industrial facilities and local 

distribution companies (LDCs), which deliver the natural 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.

A natural gas hub can occur at the interconnection of two 

or more pipelines where natural gas is bought and sold. The 

benchmark hub used to reflect the U.S. natural gas market as

a whole is the Henry Hub in Louisiana. Prices at other locations

are frequently shown not as the actual price, but as the differential, or basis, to Henry Hub.

Regional differences in supply and demand result in different

prices for natural gas at various locations. Prices tend to be 

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. Transportation cost from supply to demand areas is also a factor in the regional price differentials.

The natural gas industry in the United States is 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 40 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 financial 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 financial natural gas prices are

often derived from the physical natural gas prices.

3. Natural gas demand for power generation is rising and 

is expected to increase significantly in the coming years.

Power plant demand for natural gas reflects the environmental benefits of the fuel, the operating flexibility of

natural gas-fired generators, and lower natural gas prices. Natural gas-fired 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
Energy Primer | 7

can increase or decrease output more flexibly 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 expansions linking the new supply regions to 

markets are changing 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 flow from traditional supply sources, and

enhanced the amount that can flow overall. This has reduced prices and tempered extreme price movements 

during periods of peak demand.

Natural Gas Demand

Natural gas is already the fuel of choice for many sectors of 

the U.S. economy and, in 2014 it met about 27 percent of U.S. 

primary energy needs. Natural gas demand, however, can 

fluctuate substantially.

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

efficiency, 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 competition from other fuel sources such as coal 

and oil.

Weather

Weather is the most significant factor affecting seasonal natural gas demand. 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 soaring – or dropping – within the course of a day, sometimes 

unexpectedly. This unpredictability challenges suppliers and 

pipelines, especially when pipelines are 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 natural gas use, as does increased 

global competition. New markets for products and services 

may require additional natural gas; movement of manufacturing overseas 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

Just as a home-owner may decide to invest in a furnace and 

associated piping to use natural gas for heat, so, too, a power 

producer may decide to make long-term investments in natural gas-fired generators. These decisions requiring long-term

capital investments are cheapest and easiest to make at the 

time a home or power plant is 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-fired generating plant versus

one fueled by natural gas.

In the short-term, the opportunity for fuel switching has been 
8 | Energy Primer Federal Energy Regulatory Commission

significant 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 fleet.

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-fired generation can get dispatched sooner than

coal-fired 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 appliances and 

devices that consume electricity, and continue to add more as 

they become more energy efficient. As the trend in generation of electricity is for a greater share to be fueled by natural 

gas, natural gas demand can increase from rises in electricity 

demand.

Environmental Concerns and 

Energy Efficiency

Natural gas has relatively fewer environmental problems compared with other fossil fuels, and, consequently, it is 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-fired generators, making it feasible to site gas-fired

generators closer to load centers. Growth in wind and other 

intermittent generation technologies benefit when coupled

with natural gas generation, which is able to ramp up and 

down quickly to complement variable output.

The natural gas emissions profile has also encouraged some

urban mass transit bus systems, West Coast port operations 

and other vehicle fleets to shift to natural gas from gasoline

or diesel fuel.

Customer Sectors and Demand

In 2007, natural gas used for electric generation overtook gasfor-industrial load to become the largest customer class for 

natural gas. In 2014, according to the EIA, power generation 

used 8.2 Tcf of the 24.6 Tcf of natural gas delivered to consumers. Industrial, residential, and commercial consumers used 

7.8 Tcf, 5.1 Tcf, and 3.5 Tcf, respectively. 

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 flow into underground

storage for later use in the winter. Industrial demand stays 

relatively constant year-round.
Energy Primer | 9

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-fired generators

can change their output quickly, and are frequently called on 

to change their output due to changes in demand or when 

problems occur elsewhere in the power grid. 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 influenced by the relative prices for

natural gas and other fuels, especially coal. Since late 2008, 

natural gas-fired 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 film, medicines and explosives. Industrial load tends

to show the least seasonal variation of natural gas use, but 

industry is sensitive to economic pressures. 

Residential

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

and stoves has remained fairly flat over the past decade as

appliances and homes have become more energy efficient.

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 will see higher gas demand than a year 

with a mild winter, especially in cold-winter regions where demand soars during winter months as consumers turn on their 

furnaces. Slightly more than half of the homes in the United 

States use natural gas as their main heating fuel.
10 | Energy Primer Federal Energy Regulatory Commission

Commercial

Like the residential sector, commercial consumption experiences 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 varies 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, taking into account the technology available to extract the gas. 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. Natural gas supplies are characterized as resources, proved reserves and production (See

Quick Facts box).

Quick Facts: Resources and Proved Reserves

• Resources - Total natural gas estimated to exist in 

a particular geological area. The estimated size of

resources is different from the amount of natural

gas that can or will be produced from that area.

• 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. Since 

economic and operating conditions change constantly, the estimates for proven reserves also 

changes often. 

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) defined

unconventional gas as “natural gas that cannot be produced 

at economic flow 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 significant increases in production

and raising the estimate of proved reserves. Estimates of re-
Energy Primer | 11

sources in 2014 amounted to approximately 2,853 Tcf (which 

included reserves).

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

more than 35 percent since 2005, to more than 70 billion cubic 

feet per day (Bcfd) in 2014. Most of the growth came from 

shale gas, which now accounts for 50 percent of natural gas 

resources.

Gas Exploration and Development Process

Source: FERC staff 

Worldwide, the United States accounts for one-tenth of global natural gas technically recoverable 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 compiled by several companies active in drilling operations. Historically, rig counts were used as a rough

predictor of future production. However, improvements in

drilling technology and practices have caused a decoupling 

between rig count and production. The oil and gas rig count 

peaked at 4,530 on Dec. 28, 1981. Since then, rig count has 

decreased by over 80 percent while rig productivity has increased substantially, according to Baker Hughes Inc. Within

the total rig count, the use of horizontal drilling rigs, used in

the production of natural gas and oil in shale formations, has 

been growing for years, while the traditional vertical rig count 

has steadily declined.

The adoption of horizontal drilling has significantly 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.

Schematic Geology of Natural Gas Resources

Source: EIA
12 | Energy Primer Federal Energy Regulatory Commission

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 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 significant amounts of natural gas in the spaces in the rocks.

Conventionalresources have been found both on land and offshore (see map), with the major fields in an arc from the Rocky

Mountains to the Gulf of Mexico to Appalachia. The largest 

conventional fields 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

of total U.S. production; by 2013 that amount had fallen to less 

than 5 percent.

Federal offshore natural gas wells are drilled in the ocean floor

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 

Gas Production in Conventional Fields, Lower 48 States

Source: EIA
Energy Primer | 13

miles from shore, the EIA reports. Most of these offshore

wells are in the Gulf of Mexico.

Offshore production has been going on for decades. As closein, 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.

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 

Source: EIA

Source: EIA
14 | Energy Primer Federal Energy Regulatory Commission

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. 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.

As of 2014, production from unconventional reserves supplied 

nearly two-thirds 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 flow 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 2012, annual production was about 5 Tcf, or about 

one-fifth of U.S. domestic production.

Coalbed methane (CBM) is natural gas trapped in coal seams. 

Fractures, or cleats, that permeate coalbeds are usually filled

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 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 significant activity in the Midcontinent and the Appalachian area.

Shale gas is found in fine-grained sedimentary rock with low

permeability and porosity, including mudstone, clay stone and

Coalbed Methane Fields, Lower 48 States

Source: EIA
Energy Primer | 15

Source: Geology.com

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 finding 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 finding and producing shale gas, and have resulted in a

significant increase in production. In 2014, shale gas accounted for about 45 percent of total gas production, with expectations of significant increases in the future.

As of 2014, the six major shale plays in the United States are 

Barnett, Fayetteville, Woodford, Haynesville, Eagle Ford, and

Marcellus (see map on next page). Other shale formations 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 

Source: EIA
16 | Energy Primer Federal Energy Regulatory Commission

and costs.

Many shale reservoirs contain natural gas liquids, which can 

be sold separately, and which augment the economics of producing natural gas. 

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 2013, according to 

EIA, shale gas made up 40 percent of gross production of natural gas, and has become the dominant source of domestically 

produced gas. By comparison, coalbed methane accounted 

for 5 percent of production, while 18 percent of the natural 

gas came from oil wells and 38 percent was produced from 

natural gas wells.

New shale plays have increased dry shale gas production from 

1 Tcf in 2006 to over 12 Tcf in 2014. Wet shale gas reserves, 

those rich in oil and/or natural gas liquids account for about 20

percent of the overall United States natural gas reserves. According to the EIA, shale gas will account for about 53 percent 

of United States natural gas production in 2040.

Shale Gas Production by Region

Source: Derived from EIA data

Shale gas well productivity has improved considerably over 

the past 10 years, with technological advances in drilling and 

fracking technology reducing exploration, drilling, and producing costs. Rising well productivity and falling costs have 

resulted in larger amounts of shale gas production at lower 

natural gas prices. 

The presence of NGL in many shale gas plays adds to shale 

gas well profitability. NGL prices are more closely linked to oil

prices than natural gas prices and natural gas wells with high 

liquids content are therefore more profitable than wells producing natural gas alone. 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. This can make 

shale gas wells less sensitive to natural gas prices than wells 

producing just natural gas.

The Marcellus Shale formation in Appalachia is of particular note because of its location, size and resource potential,

according to the Potential Gas Committee 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 

significant amounts of gas only since 2008, production has

been prolific 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 flowed

out of Marcellus, less gas has been needed from the Rockies or the Gulf Coast 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 effluent used – chemicals and sand are combined with

water to create a fracturing solution, which is then pumped 
Energy Primer | 17

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 Natural Gas Act (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 natural gas by interstate pipelines, LDCs or their affiliates. 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 natural gas from the pipeline or 

another gas seller.

Imports and Exports

Net natural gas imports play an important role in regional U.S. 

markets, accounting for about 1,181 Bcf, or 4 percent, of the 

natural gas used in the United States in 2012. The natural gas 

pipeline systems of the United States and Canada are integrated, and about 98 percent of imports came from Canada, according to the EIA, while 2 percent was imported as liquefied

natural gas (LNG).

Imported natural gas flows 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, imports from

Canada have been declining as U.S. shale production has increased. Net U.S. gas imports fell from a high of 3,785 Bcf in 

2007 to 1,181 Bcf in 2014. 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.

Natural Gas Import Entry Points

Source: Derived from Velocity Suite, ABB
18 | Energy Primer Federal Energy Regulatory Commission

Liquefied Natural Gas

Liquefied 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 not administered by 

FERC for various aspects of the project. In addition, the Department of Energy has authority over permits to import and 

export.

Source: BP

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 $50 billion.

Once liquefied, the LNG is typically transported by specialized

ships with cryogenic, or insulated, tanks. 

When LNG reaches an import (regasification) terminal, it is unloaded and stored as a liquid until ready for sendout. To send 

out gas, the regasification 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, over 

95 Bcfd of regasification capacity exists globally, more than

2.5 times the amount of liquefaction capacity. Excess regasification capacity provides greater flexibility to LNG suppliers,

enabling them to land cargoes in the highest-priced markets.

The cost of the LNG process is $2-$5 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. Regasification contributes the least cost of any

component in the LNG supply chain. The cost of a regasification facility varies considerably; however, the majority of 

these costs arise from the development of the port facilities 

and the storage tanks. A 700-MMcfd regasification terminal

may cost in the range of $500 million to $800 million.

The various components of the LNG process are broken out 

on the following page.
Energy Primer | 19

Source: CEE based on industry and government reports

LNG in the United States

The United States is second to Japan in LNG regasification

capacity. As of 2014, there were 11 LNG receiving or regasification terminals in the continental United States, with approximately 19 Bcfd of import capacity and 100 Bcf of storage 

capacity. All of these facilities are on the Gulf or East coasts, 

or just offshore. In addition, the United States can import regasified 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.

Source: FERC staff
20 | Energy Primer Federal Energy Regulatory Commission

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 the summer of 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 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 2011-14, 

the growth in shale gas production led to proposals to export 

significant volumes of domestically produced LNG. As of January 2015, several LNG export facilities have been approved, 

but none have yet begun operations. Since 1969, small quantities of LNG have been shipped from Alaska to Pacific Rim

countries.

Source: FERC staff
Energy Primer | 21

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 the wellhead to consumers requires a vast network of processing facilities and 2.5 million miles of pipelines. 

In 2014, this network delivered more than 26 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.

Efficient 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. 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, refineries and other industrial consumers. There

were about 500 gas processing plants operating in the United 

States in 2010.

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.

Once a well is completed and production starts, the natural 

gas moves into gathering pipelines, typically 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 as natural gas liquids, 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 complete, the gas is of pipeline quality and is ready to be 

moved by intrastate and interstate pipelines.

Source: EIA
22 | Energy Primer Federal Energy Regulatory Commission

FERC Jurisdiction

The NGA 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 certificates 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 certified 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 certificated service, 15 U.S.C. § 717f(b).

Natural Gas Transportation

Interstate pipelines account for 63 percent of the natural gas 

pipeline miles in the United States and carry natural gas across 

state boundaries. Intrastate pipelines account for the remaining 37 percent, and have similar operating and market characteristics.

The interstate network moves dry natural gas from producing areas to 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 pipe used for major pipelines typically consists of 

strong carbon steel sufficient to meet standards set by the

American Petroleum Institute. The pipe is coated to reduce 

corrosion. Smaller distribution lines, which operate under 

much lower pressures, may be made of plastic materials, 

which provide flexibility and ease of replacement.

Nearly one-sixth 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 natural 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.

Natural Gas Infrastructure

The United States natural gas market is accommodated 

by extensive infrastructure:

• Roughly 303,000 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 flow of gas across the United States.

• Nearly three dozen hubs or market centers provide

addition interconnections.

• Over 400 underground natural gas storage facilities 

increase the flexibility of the system.

• 49 locations enable natural gas to be imported or 

exported via pipelines.

• There are 9 LNG import facilities and 100 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

Metering stations are placed along the pipelines to measure 

the flow of natural gas as it moves through the 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 flow 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 

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 flexibility 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.

Natural Gas Transportation System

Source: Derived from Velocity Suite, ABB
24 | Energy Primer Federal Energy Regulatory Commission

Source: Sabine Pipeline, LLC

Hubs

A key part of the pipeline distribution network is the natural 

gas hub. Typically, a hub is a specific 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 over

20 major hubs. The 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 is located in south central 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.

Gas as a physical product can be bought and sold at the Henry

Hub or other hubs around the country in daily and monthly

markets. In addition, the New York Mercantile Exchange (Nymex) established a natural gas 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 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 requires that interstate natural gas pipelines charge 

just and reasonable rates for the transportation and sale of 
Energy Primer | 25

natural gas. To promote compliance with this mandate, the 

NGA requires gas pipelines to file 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 transportation and sales, ensuring that rates and 

charges for such services, 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)).

Pipeline Services

Customers or shippers may choose among a variety of services on interstate pipelines. One is firm 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. Shippers 

with firm transportation service generally receive priority to

ship for the contracted quantity.

A 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 specified 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 firm 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. 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 firm shippers may receive delivery up to their firm entitlements on a daily basis without penalty. If a shipper has firm

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 firm 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 fixed 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 reflect 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.
26 | Energy Primer Federal Energy Regulatory Commission

Source: Bentek Energy LLC

Scheduling

Pipelines have rigorous schedules that shippers must follow. 

Typically, shippers nominate gas in the day-ahead market, and 

may update their nominations at various points during the day 

in which the natural gas flows. The Pipeline Capacity Scheduling graphic illustrates a particular schedule.

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, reflecting 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 short-term 

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 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.
Energy Primer | 27

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 

specific region and is,therefore, a key factorin regional prices.

In recent years, the natural gas pipeline network has expanded significantly, 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. As Northeast production ramped up in 2008 and 2009, annual pipeline capacity additions in the region rose to 2.6 Bcfd in 2009 along with the 

production increases. Pipeline capacity additions moderated 

in 2010 and 2011 until surging again to reach annual additions 

of 2.9 Bcfd in 2012 and 2.6 Bcfd in 2013. Much of this new capacity was targeted at improving access to shale gas.

Building a pipeline project requires careful planning, as the 

projects typically entail significant costs that must be recovered over years of operations. However, unanticipated

changes in supply and demand patterns can have unexpected 

effects on even the best-planned projects. For example, one

of the largest additions to the natural gas infrastructure came 

when the 1.8-Bcfd Rockies Express Pipeline (REX) was completed in 2009. REX was designed to move natural gas from 

Wyoming to eastern Ohio in order to relieve pipeline constraints that bottled up production and depressed prices in 

the Rockies, while at the same time providing needed supplies 

into the East. When REX first went into service, Rockies producers saw a rise in prices. The Rockies gas flowing eastward

displaced gas from the Permian Basin. Permian natural gas, in 

turn, began moving to the Southern California market. Consequently, regional price differences moderated. However, the

rapid increase in Marcellus Shale production pushed Rockies 

supplies away from the Northeast and caused flows on REX

to decrease sharply, putting the pipeline at financial risk. In

2014, REX began the process of reversing flows on parts of the

pipeline to move natural gas from the east to the Midwest. 

This development is making more Rockies natural gas available to Western Markets, and more midcontinent production 

available for the Gulf Coast and Southeast states. 

Other projects are operating as designed. New pipelines to 

increase the flow of Barnett Shale gas into the interstate network have reduced 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 significant 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 flows 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 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 
28 | Energy Primer Federal Energy Regulatory Commission

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 LDC system.

Natural Gas Storage

Although natural gas production rose steadily from 2005 

through 2014 because of the increase in shale gas production, 

day-to-day production remains relatively steady throughout 

the year. 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.

Working gas storage capacity, as tracked by EIA, was more 

than 4,100 Bcf in 2014. The amount injected or withdrawn is 

the difference between demand and production. Storage capacity adds flexibility 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 high-level 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 of the 

report’s release. Ifthe reported injection or withdrawal significantly 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.
Energy Primer | 29

Underground Natural Gas Storage Facilities in the Lower 48 States

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 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 fields). These facilities reuse the infrastructure

– wells, gathering systems and pipeline connections – originally created to support the field 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 facility more sensitive to withdrawal and injection patterns, so inventory usually turns over 

just once a year.

Types of Underground Storage Facilities
30 | Energy Primer Federal Energy Regulatory Commission

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 

flexibility attracted new development, resulting in the growth

of salt cavern storage through 2008. 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 LNG-receiving terminals, and there are about a hundred standalone LNG storage 

facilities in the United States, as well. LNG ships can also serve 

as storage, depending on timing and economics. LNG storage 

is highly flexible, allowing multiple inventory turns per year

with high injection and withdrawal rates.

Regional Storage

The EIA divides the United States into three storage 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 

fields. Almost 1,500 Bcf sits in the producing region, which has

not only depleted fields but also the greatest concentration

of more-flexible salt cavern storage. The remaining 600 Bcf is

in the West, primarily in depleted fields, for total working gas

capacity of almost 4,300 Bcf. Depending on storage levels at 

the end of the previous winter, and the temperatures over the 

injection season, U.S. working gas in storage will generally be 

between 80 and 90 percent full when the official winter season begins on November 1.

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, according to 

the EIA. 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 influence on natural gas

prices. Storage inventory augments natural gas supply during 

the winter, and 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 fields and aquifers may use a traditional cost-of-service structure, including:

• Capacity charges for firm contract rights to physical storage capacity

• Deliverability charges for transportation to and from the 

storage facility

• Withdrawal charges for the removal of gas from storage

• 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 flexibility. Entities leasing storage capacity may move gas in and out of storage as prices change in 

attempts to maximize profits or minimize costs. Storage may

be a component in producer or consumer hedging strategies, helping them to manage the risk of price movements. 
Energy Primer | 31

Further, storage helps shippers avoid system imbalances and 

associated penalties, and supports swing gas supply services, 

which are short-term contracts that provide flexibility 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. 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 marketbased 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 reflect 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 profit from price volatility. It is also attractive to shippers, industrial consumers with uncertain loads 

and gas-fired generators whose needs change rapidly.

Pipelines also offer storage service, both firm 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 firm 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 (15 U.S.C. § 717c(f)). 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 

new capacity, and that customers are adequately protected.
32 | Energy Primer Federal Energy Regulatory Commission

Natural Gas Markets 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 LDCs, to large industrial buyers and to power plants. Other producers sell their 

gas to marketers who aggregate natural gas into quantities 

that fit 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 and storage services only. 

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 financial 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 affiliates, LDC marketing affiliates, independent marketers, financial institutions, or large-volume users of natural gas.

Some marketing companies may offer a full range of services,

marketing numerous forms of energy and financial products,

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

most marketing firms affiliated with producers do not sell natural gas from third parties; they are more concerned with selling their own production and hedging to protect their profit

margin from these sales.

Generally speaking, there are five categories 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 

affiliated natural gas production company. Smaller marketers target particular geographic areas and specific natural gas

markets. Many marketing entities affiliated with LDCs are of

this type, focusing on marketing gas for the geographic area 

in which their affiliated 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 because 

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 significant backroom

operations in addition to the core trading group. These support staff are responsible for coordinating everything related

to the sale and purchase of physical and financial 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.

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.
Energy Primer | 33

Market Hubs

Natural gas is priced and traded at differentlocations throughout the country. These locations, referred to as market hubs, 

exist across the country and are located at the intersections of 

major pipeline systems. The price at which natural gas trades 

differs across the major hubs, depending on the supply and

demand for natural gas at the particular points. 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.

In addition to being the country’s benchmark hub, the Henry

Hub is also the delivery point for the Nymex natural gas futures contract. Changes in price at the Henry Hub provide a

good indicator of how prices are generally changing across 

the country.

Basis usually reflects the variable cost to transport gas between the Henry Hub 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 the Henry Hub and the basis to the Florida hub.

Physical Trading of Natural Gas

Natural gas contracts are negotiated between buyers and sellers. There are many types of natural gas contracts, but most 

share some standard specifications, 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 specified day) and other terms

and conditions. The special terms and conditions usually outline such things as the payment dates, quality of the natural 

gas to be sold, and any other specifications agreed to by both

parties.

Natural gas contracts are negotiated between buyers and sellers over the phone or executed on electronic bulletin boards 

and e-commerce trading sites.

There are three main types of natural gas contracts: swing

contracts, baseload contracts, and firm contracts:

• Swing (or interruptible) contracts are usually short-term 

contracts between one day and a month in length. These 

contracts are the most flexible, 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 specified. However, it is agreed that both

parties will attempt to deliver or receive the specified

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 specified in the contract. These contracts are used primarily when both the 

supply and demand for the specified amount of natural

gas are unlikely to change.
34 | Energy Primer Federal Energy Regulatory Commission

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 specified delivery point on the next day. Natural gas

spot prices reflect daily supply and demand balances and can

be volatile.

Bidweek

Bidweek is the name given to the last five business days of a

month. This is the week when producers sell their core production and consumers buy natural gas for their core needs 

for the upcoming month. 

Index Prices

Several publications, such as Platts 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 first business day following the last day of bidweek.

These daily and monthly indexes, in turn, are used as the basis 

for pricing for those firms that do not choose to enter into

fixed-price contracts (or are prohibited from using them by

state or local regulators).

The Financial Market

In addition to trading physical natural gas,there is a significant

market for natural gas derivatives and financial instruments in

the United States. In the financial market, market participants

are interested in profiting from the movement of the price of

natural gas rather than delivering or receiving natural gas. The 

pricing and settlement of these financial products are tied to

physical natural gas. It is estimated that the value of trading 

that occurs on the financial market is at least a dozen times

greater than the value of physical natural gas trading.

Derivatives are financial 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 financial markets appears in Chapter 5.

Hubs for Physical Trading on ICE

Source: Derived from Intercontinental Exchange data
Energy Primer | 35

3. Wholesale Electricity Markets

Electricity is a physical product – the flow 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 flow 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 and, in larger quantities, megawatt-hour or MWh) 

is the amount of electricity a customer uses or a power 

plant generates over a period of time.

Electricity 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. Because FERC has jurisdiction over 

the wholesale markets, and not the retail markets, this paper 

focuses on wholesale electricity markets, although it addresses retail demand and other instances where retail markets 

strongly influence 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 costbased rates.

In competitive markets, prices reflect the factors driving supply and demand – the physical fundamentals. Where rates 

are set based on costs, market fundamentals matter as well 

because changes in supply and demand will affect consumers

by influencing the cost and reliability of electricity. Supply incorporates generation and transmission, which must be adequate to meet all customers demand simultaneously, instantaneously and reliably.

Consequently, key supply factors that affect 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-efficient, more-expensive power plants must be turned on to serve load.
36 | Energy Primer Federal Energy Regulatory Commission

Electric Power Industry

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 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 efficiency. 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 flat over the past 40 years? Part can be explained by greater

efficiency – 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 percent of a 

customer’s electric bill. Spreading these relatively fixed costs

over more customers helps bring down the cost that each customer pays.

Thomas Edison’s first 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 selfcontained – 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 difficult 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 significantly. 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 amount of 

reserves each must carry, and the lower the costs. The value 

of reserve-sharing agreements led to the formation of power 
Energy Primer | 37

pools, the forerunners of today’s regional transmission organizations.

Coordinating exchanges of energy and 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 

to ensure reliability, but no more than is needed. 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 power 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, shortly thereafter renamed the North American Electric Reliability 

Council (NERC) 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 certified 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 day-ahead market software does this 

for suppliers bidding into regional transmission organization

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 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 
38 | Energy Primer Federal Energy Regulatory Commission

had excess transmission capacity. This allowed utilities to use 

the lines to trade power. Major utilities generally owned sufficient 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 next.

Not-for-Profit Utilities

One of the first approaches to ensuring customer value was

to depend on nonprofit electric providers. In the early days

of the industry, electrification 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 significant hydroelectric resources.

The Depression-era rural electrification 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 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.
Energy Primer | 39

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 first 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.

Competition, Part 1: Competitive Generation 

and Open Access

The environmental movement and initiatives to open the airline and trucking industries to competition 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 efficient 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 significant 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 No. 888 required mandatory open transmission access by all transmitting utilities and a reciprocity provision successfully extended open access to non-jurisdictional 

entities (municipal, cooperative and federal utilities).

Order No. 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 significant changes to utility control

room operations and limited the ability of companies to share 

transmission-related information with their own power marketing operating units.
40 | Energy Primer Federal Energy Regulatory Commission

Competition, Part 2: Integrating Markets 

and Operations – RTOs

While the industry had historically traded electricity through 

bilateral transactions and power pool agreements, Order No. 

888 promoted the concept of independent system operators 

(ISO). Along with facilitating open-access to transmission, an 

ISO would operate the transmission system independently 

of, and foster competition for electricity generation among, 

wholesale market participants. Several groups of transmission owners formed ISOs, some from existing power pools. 

Close on the heels of Order No. 888, the Commission, in Order 

No. 2000, encouraged utilities to join regional transmission 

organizations (RTO) which, like an ISO, would operate the

transmission systems and develop innovative procedures to 

manage transmission equitably. The Commission’s proceedings in Orders Nos. 888 and 2000, along with the efforts of

the states and the industry, led to the voluntary organization

of ISOs and RTOs. Each of the ISOs and RTOs subsequently 

developed a full scale energy and ancillary service market in 

which buyers and sellers could bid for or offer generation. The

ISOs and RTOs used the bid-based markets to determine economic dispatch. Throughout the subsequent sections of the 

primer, the term RTO is used to stand for both ISOs and RTOs.

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.

Source: Velocity Suite, ABB

North American Independent System Operators and Regional Transmission Organizations
Energy Primer | 41

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, and cell phones. This 

use has been increasing, reaching over 3,860 gigawatt-hours 

(GWh) of electricity in 2014. Demand dropped in 2009 with the 

recession, but has since recovered. Subsequent to the recession, the trend in use has been flatter.

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 

electricity 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.

The amount of electricity consumed (demand) is continuously 

varying and 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, which are most acute 

during the daily peak load hours that occur during the late afternoon. However, a minority of regions reach their peak load

when the weather is extremely cold. These are primarily areas 

with significant space-heating requirements and little summer

air conditioning load. A majority of these systems are in the 

far northern areas of the United States, where air conditioning load is not significant. South Florida’s seasonal peak also

occurs during the winter, when the population and tourism 

surges.

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.

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, because higher levels of demand 

require activation of increasingly more expensive sources of 

power generation, and reductions as demand declines. As a 

result, power prices are typically highest during periods of 

peak demand. This causes system planners, power marketers 

and traders to 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 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
42 | Energy Primer Federal Energy Regulatory Commission

lights, for example – electricity consumers find it difficult 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 efficiency measures. Larger consumers may

consider building their own generation facilities. 

Governments and businesses are also developing demand-response programs, which may provide reduced rates or other 

compensation to customers who agree to reduce load in periods of electric system stress.

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 electricity consumption. Shifts in 

population also affect regional demand. Population flight 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 electricity use.

Climate and Weather

Weather is one of the primary factors 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 electricity 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 overall level of economic activity also affects power demand. During periods of robust activity, 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 significant.

Quick 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 65°F standard - those in excess of 65° 

yield cooling degree days; those below 65° yield heating 

degree days. A day with an average temperature of 66° 

would yield one cooling degree day.
Energy Primer | 43

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 efficiency 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 profile, 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, the load shape is flat, 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 37 percent of electricity 

demand. Residential consumers use electricity for air conditioning, refrigerators, space and water heating, lighting, washers and dryers, computers, televisions and other appliances. 

Prices for residential service are typically highest, reflecting

both their variable load shape and their service from lowervoltage 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 office buildings, hotels

and motels, restaurants, street lighting, retail stores and 

wholesale businesses and medical, religious, educational and 

social facilities.

More than half of commercial consumers’ electricity use is for 

heating and lighting.

Industrial consumers use about 27 percent of the nation’s 

electricity. This sector includes, for example, manufacturing, 

construction, mining, agriculture and forestry operations. Industrial customers often see the lowest rates, reflecting their

relatively flat 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 than 1 

percent of electricity 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 significantly 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 sufficient supply is to be available in the immediate or long term: planning the long-term infrastructure needs

of the system, purchasing fuel and other supplies and staffing,

for example. Load forecasts are also extremely important for 

suppliers, financial 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 to 3 percent 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 
44 | Energy Primer Federal Energy Regulatory Commission

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 

flows 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 next-year 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 sufficient 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

Electricity demand is generally insensitive to price, meaning 

that demand does not typically fall when wholesale prices 

rise. This occurs for several reasons, including that most end 

use consumers of electricity are not exposed to real-time electricity prices. However, some utilities and grid operators are

developing ways to stimulate a response from consumers 

through demand-response programs. 

Demand response (DR) is the reduction in consumption of 

electricity by customers from their expected consumption in 

response to either reliability or price triggers where the customer forgoes power use for short periods, shifts some high 

energy use activities to other times, or uses 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, an RTO or an independent DR provider. These programs are administered by 

both retail and wholesale entities.

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 benefits because peaking units tend to

be costly - and dirty - to run.

Demand response rewards consumers for reducing load during certain market conditions and at specific times. However,

itis difficultto 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.
Energy Primer | 45

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 office 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 realtime 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 efficiency, DR or

renewable resources. Energy Efficiency Resource Standards

(EERS) in more than half of the states 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 profits from the

amount of electricity sold, 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 reflect system costs. Timebased 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 reflecting 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-of-use 

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: criticalpeak 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 specifically the amount

of response that occurs. Wholesale-level DR occurs in the 
46 | Energy Primer Federal Energy Regulatory Commission

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. 

DRR also can participate in wholesale electricity 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. Additionally, some DRR bids into RTO day-ahead (DA) markets as 

energy resources, specifying the hours, number of megawatts 

and price at which they are willing to curtail. RTOs set minimum bid values.

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. 

Demand-Response Use in Planning and 

Operations

Different DR programs can be used at various times to support planning and operations (see graphic). Energy efficiency

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.

Demand-Response Program Use in Electric System Planning and Operations

Source: U.S. Department of Energy
Energy Primer | 47

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 specific 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 electricity 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.

Electricity Supply and Delivery

Source: National Energy Education Development Project

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. The regional reliability entities fall under the purview of 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 approved 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.

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)

• Western Electricity Coordinating Council (WECC)

NERC Regions 

Source: North American Electric Reliability Corporation

Generation

Power generators are typically categorized by the fuel they

use and subcategorized by their specific 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 
48 | Energy Primer Federal Energy Regulatory Commission

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 gas-fired combustion turbines are far

less expensive to build, but are more expensive to run.

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. Specifically, they emit

NOx, SOx, particulates, mercury and substantially higher 

levels of CO2 than gas-fired plants. This has made financing

these plants and siting them near urban centers difficult.

• 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 and a few are under construction. The disposition of high-level radioactive waste remains an unresolved problem, and the waste remains at plant locations.

Conventional Generation

Natural gas power plants 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 flexibility

that is inherent in the centralized boiler design, these plants

require fairly long start-up times to become operational and 

are limited in their flexibility to produce power output beyond

a certain range. Furthermore, these plants are generally not 

as economical or easy to site as some newer technologies – 

which explains why few have 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 inefficient, 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 system-wide shortages, such as when a power line or generator 

trips offline. GTs typically have a short operational life due to

the wear-and-tear caused by cycling. The typical capacity of a 
Energy Primer | 49

GT is 10-50 MW and they are usually installed in banks of multiple units.

Combined cycle power plants (CCPPs) are a hybrid of the GT 

and steam boiler technologies. Specifically, 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 efficient power

plant. They produce negligible amounts of SO2 and particulate 

emissions and their NOx and CO2 emissions are significantly

lower than a conventional coal plant. CCPPs, on average, require 80 percent less land than a coal-fired 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 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-fired

plants in the United States are located in the Southeast and 

Midwest.

Oil-fired plants generally produce only a small amount of the 

total electricity generated in the 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-fired 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 refining process.

Nuclear plants provide roughly 20 percent of the nation’s 

electricity; there are close to 100 operating units with a total 

capacity of approximately 100 GW. These plants are used as 

baseload units, meaning that they run continuously and are 

not especially flexible in raising or lowering their power output. Nuclear plants have high capital and fixed costs, but low

variable costs, which includes fuel cost. They typically run at 

full power for 18 or 24 months, 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 significantly longer, depending on the work needed.

Renewable Generation

Renewable resources use fuels that are not reduced or used 

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, an important part of total U.S. capacity and generation, accounted for 13 percent of 2014 electricity generation. As total generation from all fuels has remained 

relatively constant in the recent years, renewable generation’s share has risen, spurred by state regulations and federal 

tax credits. As renewable generation becomes a larger per-
50 | Energy Primer Federal Energy Regulatory Commission

centage of generation resources, integrating them into the 

operating power grid has presented challenges.

Wind and solar capacity have grown faster than other renewable resources in recent years. Wind capacity grew ten-fold 

(from approximately 6 GW to 65 GW) between 2003 and 2014. 

Utility-scale solar capacity more than tripled (from approximately 3.1 GW to 10 GW) between 2012 and 2014. 

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 weather-dependent, their capacity factors – the ratio of average generation 

to the nameplate capacity for a specific period – have been

lower (for example, approximately 30 percent), depending 

on the technology type, than for fossil-fuel-fired generation.

Markets care about the difference between nameplate and

capacity factor values when they evaluate capacity available 

to cover expected load. Capacity factors have risen with technological innovation and improved manufacturing processes.

Wind generation is among the fastest-growing renewable resources, in part due to cost declines and technology improvements as well as earlier receipt of federal tax credits. Increases in average hub heights and rotor diameters have increased 

average wind turbine capacity. 

Because the best wind resources are often far from load centers, obtaining sufficient 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; difficulties 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 generation 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 flow and surface temperature. Geothermal generation increased 14 percent from 2006 to 2014, but it decreased from 15 to 6 percent 

of non-hydro renewable output, due to the growth of other 

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

Solar generation transforms sunlight into electricity using 

one 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-film

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 increased greatly as a result of policy incentives 

and cost declines. Annual PV installations increased nearly 
Energy Primer | 51

tenfold from 2009 to 2013 as PV system costs decreased. PV 

growth has been relatively concentrated; 10 states had 90 

percent of PV capacity in 2014, while California alone had over 

half.

By the end of 2014, 1,760 MW of CSP was operational. 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 generation is powered by the kinetic energy 

of falling water that 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 outflow from the project

approximates inflow, 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 flows back to the lower

elevation reservoir. Pumped storage is the only significant

commercially deployed electricity storage technology available today.

Biomass generation includes production from many waste byproducts, such as agricultural residues, landfill 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.

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 provided tax incentives to spur renewable resource investments. Originally enacted in 1992, wind, biomass, 

geothermal, and other forms of renewable generation have 

been able to receive federal production tax credits (PTC) 

based on a facility’s production. An inflation-adjusted credit,

the PTC generally has a duration of 10 years from the date the 

facility goes online. The credit was initially set at 1.5¢/kilowatt

hour (kWh) and its value in 2013 was 2.3¢/kWh or 1.1¢/kWh,

depending on the type of qualifying resource. The PTC has 

been renewed and expanded numerous times, most recently 

at the end of 2014.

Another form of tax credit for renewables, including solar and 

other select renewable energy projects, has been a federal investment tax credit (ITC). The ITC has generally been for 30 

percent of a project’s equipment and construction costs. 

Following the financial crisis of 2008, the American Reinvestment and Recovery Act (ARRA) provided developers with 

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 significant drivers in the
52 | Energy Primer Federal Energy Regulatory Commission

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 eight 

states have renewable goals without financial penalties for

nonachievement. As utilities build more renewable-powered 

generation, the markets in which they participate continue to 

address the integration of renewable output into their dayahead and real-time operations and model expected growth 

as part of their long-term transmission-planning 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 certificates (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 

identification number to prevent double-counting. Each REC

includes attributes such as generator location, capacity, fueltype and source, owner and the date when operations began.

States and local utilities offer a variety of financial 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.

Seven states mandate feed-in-tariffs (FITs) to support their

energy and environmental goals. Also called feed-in 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 fixed

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 flow of

power is not specifically controlled by the operators on a lineby-line basis. Instead, power flows 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 specific

paths with definite beginning and end points for scheduling

and moving power. These lines are controllable by operators 
Energy Primer | 53

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 significantly 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 Pacific Intertie, which extends between the Northwest

and California.

Transmission lines provide a certain amount of resistance to 

the flow 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 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 pointto-point service. This service involves paying for and reserving 

a fixed 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 profit. 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 

350 in 2007 to 30,000 in 2012. 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.
54 | Energy Primer Federal Energy Regulatory Commission

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 and flow 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 market supply curve of 

the power plants for the New York Independent System Operator (NYISO). This is also commonly called the supply stack. 

In it, all of the plants in the New York market 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 New York, for example, first calls on wind plants,

followed successively by hydro, nuclear and coal-, gas- and oilfired generators. This assumes that the plants have sufficient

resources – enough wind for the wind powered generators 

or enough river flow for the hydroelectric plants, for example

– and that sufficient transmission capability exists to deliver

plant output and meet reliability needs.

Market Supply Curve for NYISO (Illustrative)
Energy Primer | 55

In addition, transmission flows must be monitored to ensure

that flows stay within voltage and reliability limits. If transmission flows 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 five 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 deficiency. There are three

types:

• Spinning reserves are primary. To provide spinning 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.

• Nonspinning reserves come from generating units that 

can be brought online in 10 minutes. Nonspinning reserve 

can also be provided by demand-side resources.

• Supplemental reserves come from generating units 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 first 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 flow 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 fields 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 
56 | Energy Primer Federal Energy Regulatory Commission

by current as it flows. As the amount of electricity flowing 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 electricity 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 flow needed for their output. Geographically, this is most

important in the Pacific 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. Specifically, thermal plants

that use a turbine – coal, gas, oil and nuclear plants – become 

less efficient 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.

Wholesale Electricity 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 RTOs.

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 physical and financial products, such as next-day on-peak firm or

swaps, allows index providers to survey traders and publish 

price indexes. These indexes provide price transparency.
Energy Primer | 57

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 

financially. 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.

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. Cost-based 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 office 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 finance projects and provide cash for dayto-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 affiliates 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 erect barriers to entry or influence the cost of production for competitive electricity suppliers). Wholesale sellers who have marketbased rate authority and who sell into day-ahead or real-time 

markets administered by a RTO do so subject to the specific

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 selfsupply, 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:
58 | Energy Primer Federal Energy Regulatory Commission

• Self-supply means that the supplying company generates 

power from plants it owns to meet demand.

• Supply from bilateral purchases means that the load-serving entity buys power from a supplier.

• Supply from spot RTO market purchases means the supplying company purchases power from the RTO.

Source: PJM Interconnection

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 significant amounts of generation either directly or

through affiliates and therefore use self-supply as well as bilateral and RTO market purchases.

Traditional Wholesale Electricity Markets

Traditional wholesale electricity markets exist primarily in 

the Southeast, Southwest and Northwest 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 electricity consumers. They may also include federal systems, such as the Bonneville Power Administration, the Tennessee Valley Authority and the Western Area Power Administration. Wholesale physical power trading typically occurs 

through bilateral transactions. 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

• Coordinating its system development with neighboring 

systems

Regional Electricity Markets

Two-thirds of the population of the United States is served by 

electricity markets run by regional transmission organizations

or independent system operators (this primer uses RTO to 

stand for both RTOs and ISOs). The main distinction between 

RTO markets and their predecessors (such as vertically integrated utilities, municipal utilities and co-ops) is that RTO markets deliver reliable electricity through competitive market 

mechanisms.

The basic functions of an RTO include the following:

• Ensure the reliability of the transmission grid

• Operate the grid in a defined geographic footprint

• Balance supply and demand instantaneously

• Operate competitive nondiscriminatory electricity markets

• Provide nondiscriminatory interconnection service to 

generators

• 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, transparently manage transmission congestion, coordinate the maintenance of generation and transmission system, 
Energy Primer | 59

and oversee a transmission planning process to identify needed upgrades in both the near- and long-term.

RTOs 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 operate in the United States, listed below in order of the size of their peak load:

• PJM Interconnection (PJM), 165 GW (summer of 2011)

• Midcontinent ISO (MISO), 126 GW (summer of 2011)

• Electric Reliability Council of Texas (ERCOT), 68 GW (summer of 2011)

• California ISO (CAISO), 50 GW (summer of 2006)

• Southwest Power Pool (SPP), 48 GW (summer of 2011)

• New York ISO (NYISO), 34 GW (summer of 2013)

• New England ISO (ISO-NE), 28 GW (summer of 2006)

RTO Markets and Features

RTO market operations encompass multiple services that are 

needed to provide reliable and economically efficient 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, financial transmission rights (contracts for hedging the cost of limited transmission capability) and virtual trading (financial instruments

to create price convergence in the day-ahead and real-time 

markets).

RTO Energy Markets

All RTO electricity markets have 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 flow limits on

transmission lines.

The day-ahead energy market produces financially 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 sufficiently 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 flows 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 dayahead 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 bids and supply offers

• Operational information about the transmission grid and 

generating resources, including planned or known transmission and generator outage, the physical characteristics 
60 | Energy Primer Federal Energy Regulatory Commission

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 realtime 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.

Source: ISO New England

Real-time market prices are significantly 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 realtime 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 

reflects the marginal cost of serving load at the specific location, given the set of generators that are 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 significantly 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.

Source: ISO New England

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 reflect congestion costs to market participants.

That is, LMPs take into account both the impact of specific

generators on the constrained facility and the cost to change 

(redispatch) the generation output to serve load. This change 
Energy Primer | 61

in dispatch is known as security constrained redispatch.

This redispatch could be implemented by using nonmarket 

procedures such as transmission loading relief (TLR). NERC 

established the TLR process for dealing with reliability concerns when the transmission network becomes overloaded 

and power flows 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 

flows based on size, contractual terms and scheduling.

Source: PJM Interconnection

Scarcity pricing is a mechanism used by RTOs 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 sufficient 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 reflects the value of energy during

shortage periods:

• Increase the allowed bidding price of energy supply 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)

• 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. RTOs 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 sufficient to pay for the cost of owning and maintaining the unit even if it does not operate.

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 sufficient generation and demand-resource capacity are available to meet load 

and reliability requirements. LSEs have typically satisfied 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 short-term 

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.
62 | Energy Primer Federal Energy Regulatory Commission

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 

specific 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 markets. This practice continues, as FTRs 

are allocated to load-serving entities, transmission owners or 

firm transmission right holders in RTOs based on historical

usage, and to entities that fund the construction of specific

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. Congestion costs occur as the demand for scheduled 

power over a transmission path exceeds that path’s flow

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 least-cost 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, the auction 

revenue right (ARR). ARRs provide the firm 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.

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 flowgates. 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 counterflow FTRs, which
Energy Primer | 63

directly offset prevailing flow 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 financial attributes either as

a hedge or as a speculative investment. In this regard, FTRs 

are similar to financial swaps that are executed as a contract

for differences between two day-ahead LMPs (swaps are explained in the chapter on financial 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 financial over-the-counter markets or exchanges.

Variation in RTO FTRs

All six FERC-jurisdictional RTOs trade FTRs or FTR equivalent 

products. 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 Counterflow. A prevailing flow

FTR generally has a source in an historic generation-rich location and a sink that is in a historic load-heavy location. Alternatively, the source of a prevailing flow FTR is on the unconstrained side of a transmission interface and the sink on the 

constrained side. Auction clearing prices for prevailing flow

FTRs are positive. Conversely, a counterflow FTR often has a

source in an historic load-heavy location and a sink in an historic generation-rich location. As a result, auction clearing prices 

for counterflow 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. NYISO offers only the 24-hour product. The other RTOs

offer on-peak and off-peak products.

Allocated Rights: The RTOs allocate transmission rights to

transmission owners or load-serving entities within their markets. In PJM, MISO, SPP, 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 payments 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 specific 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

significant 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 profit from differ-
64 | Energy Primer Federal Energy Regulatory Commission

ences 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 thatthe net effect

on the market quantity traded is zero.

Although a trader does not have to deliver power, the transaction is not strictly financial. Virtual transactions 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. Since these resources 

will be available to the real-time market, the fact that virtual 

load does not carry forward into the real-time market 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 benefits of virtual transactions are achieved

through their financial impact on the markets. Virtuals sometimes are referred to as convergence bidding, as a competitive virtual market should theoretically 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 intended to mitigate market power and improve the 

efficiency 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) specifies

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 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 Rights by Transmission Grid

PJM MISO ISO-NE NYISO CAISO SPP

Name for Allocated Transmission Rights ARR ARR ARR Multiple CRR ARR

Convertible to Congestion Rights? Yes Yes No Some - Yes

Name for Auctioned Congestion Rights FTR FTR FTR TCC CRR TCR

Congestion Right Auction Format:

 Annual Yes Yes Yes No Yes Yes

 Semiannual No No No Yes No No

 Monthly Yes Yes Yes Yes Yes Yes

Congestion Right Auction Products:

 Multiyear Yes No No No No No

 Annual Yes No Yes Yes No Yes

 Semiannual No No No Yes No No

 Quarterly Yes Yes No No Yes Yes

 Monthly Yes Yes Yes Yes Yes Yes

Auction Allows Participant Resale? Yes Yes Yes Yes No Yes

Congestion Right Options Yes No No No No No

Formal Secondary FTR Market? Yes Yes Yes No Yes Yes
Energy Primer | 65

Transmission operators, including RTOs, offertwo majortypes

of transmission service: point-to-point service and network

service. Network service generally has priority over point-topoint service. RTOs work with transmission owners to plan 

and coordinate the operation, maintenance and expansion of 

transmission facilities in order to provide network and pointto-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 firm and nonfirm point-topoint transmission service for various lengths of time.

• Firm service has reservation priority over nonfirm pointto-point service.

• Nonfirm point-to-point transmission service is provided

from the available transmission capability beyond network and firm 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 flowing. Studies are conducted that

test the transmission system against mandatory national reliability standards as well as regional 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 settlements is the process through which payments 

due from customers and to generators are calculated. Such 

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

Credit requirements are important in organized electricity

markets in which RTOs must balance the need for market liquidity against corresponding risk of default. 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.
66 | Energy Primer Federal Energy Regulatory Commission

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 Region 

The Southeast electricity market is a bilateral market that includes all or parts of Florida, Georgia, Alabama, Mississippi, 

North Carolina, South Carolina, 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 Into 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.

If a utility were building a large nuclear or coal-fired 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 

financial 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 longterm firm power deliveries. External sales resulted in more efficient use of grid resources and reduced costs to both buyers

and sellers.

Resources

Within the Southeast, the resource mix varies between the 
Energy Primer | 67

two NERC subregions. The FRCC uses more natural gas- and 

oil-fired generation than the rest of the Southeast, and it is

the only Southeast area where oil is significantly employed.

Natural 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 pattern 

began to change as gas supplies increased and prices fell and 

natural gas-fired power plants began to displace older, lessefficient coal-fired generation.

The TVA sub-region has a majority of its capacity and output 

in coal and nuclear, while the VACAR sub-region has the highest utilization of nuclear generation in the Southeast. Over 70

percent of this subregion’s output is from baseload coal and 

nuclear facilities.

Trading and Market Features

Physical and financial electricity products are traded using

Into 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 

Southeast Electric Region

Source: Velocity Suite, ABB
68 | Energy Primer Federal Energy Regulatory Commission

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 20 percent of the 

time.

Wholesale spot power markets in the Southeast have relatively 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 financial

power products in the Southeast is weak. As a result, ICE does 

not provide a financial 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, marketers contribute to 

the trading, as they have entered into multiyear agreements 

with generating units.

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 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 flow).

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.

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 combustion-turbines. 

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 Wholesale Market Regions

The power markets in the western United States are primarily bilateral markets. A key exception is most of California 

and portions of Nevada, which operate under CAISO. 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 reserve-sharing agreements.
Energy Primer | 69

Trading in the western states differs from the rest of the country because financial players are active in the physical markets,

as well as having a robust financial electricity market. The volume of financial sales on ICE is roughly as large as physical

sales. Physical sales in WECC are dominated by financial and

marketing companies.

Northwest Electric Region

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 63 GW in winter. 

There are 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 or feeding 

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 less expensive 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.

Northwest Electric Region

Source: Velocity Suite, ABB
70 | Energy Primer Federal Energy Regulatory Commission

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 flow is driven

by snowpack in the mountains, the fullness of the reservoirs, 

and rainfall. On a short-term basis, the power generation is 

influenced 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 occasionally import power from neighboring regions when loads are 

high.

Trading and Market Features

The water forecast affects the forward market for electricity

in the Northwest. The daily water flow as well as weather conditions influence 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 

percent of the region’s high-voltage transmission. It meets 

approximately one-third of the region’s firm 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 Electric System Operator 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 ICE has four trading points in the Northwest: Mid-Columbia (Mid-C), California-Oregon Border (COB), Nevada-Oregon 

Border (NOB) and Mona (Utah). Mid-C has the most traded 

volume by far, averaging more than 6,200 MW of daily onpeak physical trades in 2013. COB had nearly 1,000 MW, NOB 

had over 800 MW and Mona had 530 MW. Mid-C also has a 

fairly active physical forward market.

Southwest Electric Region

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 42 GW in summer. There are approximately 50 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 generally 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 plant with three 

units totaling approximately 4,000 MW, which has owners in 

California and the Southwest.
Energy Primer | 71

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. 

Southwest Electric Region

Source: Velocity Suite, ABB
72 | Energy Primer Federal Energy Regulatory Commission

CAISO

California Independent System Operator

Source: Velocity Suite, ABB

Market Profile

Geographic Scope

CAISO is a California nonprofit public benefit corporation

started in 1998 when the state restructured its electric power 

industry. The CAISO manages wholesale electricity markets, 

centrally dispatching electricity generation 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 day-ahead and realtime markets and is responsible for regional reliability.

Peak Demand

CAISO’s all-time peak load was 50 GW in summer 2006. 

Import and Exports

Up to about one-third of CAISO’s energy is supplied by imports, principally from two primary sources: the Southwest

(Arizona, Nevada and New Mexico) and the Pacific Northwest

(Oregon, Washington and British Columbia). Imports from 

the Pacific Northwest generally increase in the late spring

when hydroelectric production peaks from increases in winter 

snowmelt and runoff.

Market Participants

CAISO’s market participants include generators, retail marketers and utility customers, ranging from investor-owned utilities (IOUs), which include Pacific Gas & Electric (PG&E), Southern California Edison (SCE), San Diego Gas & Electric (SDG&E), 

and others such as the Valley Electric Association, to some 

municipal utilities and financial participants.

Membership and Governance

The CAISO has a board of governors that consists of five members appointed by the governor and confirmed 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 filing 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:

• Pacific Gas and Electric Co.

• Southern California Edison
Energy Primer | 73

• San Diego Gas and Electric,

• Valley Electric Association

• Municipal utilities such as Vernon, Anaheim and Riverside

Chronic Constraints

Load pockets that are chronically constrained include San Diego, Los Angeles Basin, and North Coast/North Bay (San Francisco).

Transmission Planning

CAISO conducts an annual transmission planning process with 

stakeholders that includes both short-term and long-term 

projects.

Supply Resources

By plant capacity, the generating mix includes these sources:

Generation Mix

Source: Velocity Suite, ABB

Demand Response

Demand response participation in the wholesale energy market is currently limited to a small amount of demand associated with water pumping loads. Other demand response in 

California consists of programs for managing peak summer 

demands operated by the state’s electric utilities. In general, 

these demand-response programs may be triggered based on 

criteria that are internal to the utility or when CAISO issues a 

Flex Alert. Flex Alerts also inform consumers how and when 

to conserve electricity usage. 

Market Features

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 fluctuations 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 identifies the market-clearing price at each location for every hour. Supply offers below and demand bids

above the identified 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.

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 financial terms of energy production and use for

the operating day, a number of factors can change that sched-
74 | Energy Primer Federal Energy Regulatory Commission

ule. 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 final day-ahead schedules for resources within the ISO and imports and exports as a starting 

point. It then operates a fifteen minute market to adjust resource schedules, and then a five minute market to balance

generation and loads.

Prices resulting from the real-time market are only applicable 

to incremental adjustments to each resource’s day-ahead 

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 synchronized.

• 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 LSEs to procure capacity needed to meet forecast load, or resource adequacy (RA) 

requirements, and to allow generators to recover a portion of 

their fixed costs. They also provide economic incentives to attract investment in new and existing supply-side and demandside 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. 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 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 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 
Energy Primer | 75

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.

Special Provisions for Resources Needed to 

Ensure Grid Reliability

An 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 significantly decrease its RMR designations in much of the system. Remaining generators with RMR 

contracts are located primarily near the San Francisco and Los 

Angeles areas.

Financial Transmission Rights

As discussed earlier in this chapter, FTRs provide market participants with a means to offset or hedge against transmission

congestion costs in the day-ahead market. In California, FTRs 

are referred to as Congestion Revenue Rights (CRR). A CRR is 

an instrument that entitles the CRR holder to a payment for 

costs that arise with transmission congestion over a selected 

path, or source-and-sink pair of locations on the grid. The CRR 

also requires its holder to pay a charge for those hours when 

congestion occurs in the opposite direction of the selected 

source-and-sink pair. CRRs are monthly or quarterly products. 

CRRs can be bought at auction or allocated by CAISO. Allocated CRRs receive the congestion value for a specific 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.

Virtual Transactions

CAISO’s market includes a virtual transactions feature, termed 

convergence bidding, that allows more participation in the 

day-ahead price-setting process, allows participants to manage risk, and enables arbitrage that promotes price convergence between the day-ahead and real-time energy markets. 

CAISO’s convergence bidding includes both virtual supply and 

virtual demand transactions. A virtual supply transaction is an 

offer to sell at the day-ahead price and a bid to buy at the realtime price. A virtual demand transaction is a bid to buy at the 

day-ahead price and an offer to sell at the real-time price. The

virtual supply offer and the virtual demand bid may be submitted at any eligible pricing node in the CAISO system and there 

is no requirement for physical generation or load. The financial 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.

Credit Requirements

CAISO’s tariff includes credit requirements that a market participant needs to meet in order to participate in the market. 

The credit requirements assist in mitigating the effects of defaults that would otherwise be borne among all market participants. CAISO assesses and calculates the required credit dollar amounts for the segments of the market in which an entity 

requests to participate. The market participant may request 

an unsecured credit allowance subject to certain restrictions 
76 | Energy Primer Federal Energy Regulatory Commission

– e.g., CAISO must review the entity’s request relative to various creditworthiness-related specifications such as tangible

net worth, net assets, and credit rating.

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 conducts settlements for a grid management 

charge, bid cost recovery, energy and ancillary services, CRR 

charges and payments, among other charges. The CAISO settles for both the day-ahead market and the real-time market.

CAISO – PacifiCorp Energy Imbalance 

Market

On Nov. 1, 2014, CAISO began operation of an energy imbalance market (EIM) with PacifiCorp’s two balancing authority

areas, PacifiCorp East (PACE) and PacifiCorp West (PACW). 

CAISO extended its existing real-time market into the PacifiCorp to automatically dispatch resources to meet intra-hour 

changes in energy demand and supply. Resources participate 

in the EIM voluntarily and only resources that register to participate may actually bid into the EIM for the 15- and 5- minute market runs. Load buys imbalance energy directly from 

the EIM. For example, PacifiCorp, the largest LSE in PACE and

PACW areas, buys imbalance energy through the EIM. Other 

entities that may purchase imbalance energy include wind 

generators that seek to match their generation supply with 

contracted demand. 

The three balancing authorities – CAISO, PACE, and PACW – 

may transfer imbalance energy through a limited amount of 

transmission capability. Consequently, prices and supply are 

largely determined by resources within each area. CAISO’s Department of Market Monitoring serves as the market monitor 

for the EIM. While the CAISO’s operations remain under the 

CAISO Board of Governors, an EIM Transitional Committee advises CAISO’s board of governors and is developing a proposal 

forlong-term EIM governance. Among other benefits,the EIM

may provide a broader footprint for incorporating renewable 

generation and an opportunity to improve the economic efficiency of generation dispatch. 
Energy Primer | 77

ISO-NE

New England Independent System Operator

Source: Velocity Suite, ABB

Market Profile

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 

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 summer 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 around 15 

percent of its annual energy needs from Québec, NYISO, and 

New Brunswick. New England receives imports from Québec 

and New Brunswick in most hours. Between New England and 

New York, power flows 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-profit entity governed by a 10-member,

independent, non-stakeholder board of directors. The sitting 

members of the board elect people to fill board vacancies.

Transmission Owners

ISO-NE’s transmission owners include:

• Central Maine Power Co.

• New England Power Co.

• Northeast Utilities System Cos.

• NSTAR Electric Co.

• The United Illuminating Co.

• Vermont Electric Cooperative Inc.

Chronic Constraints

Constraints in the ISO-NE are concentrated in the Northeast 

Massachusetts-Boston zone. However, New England completed a series of major transmission projects in 2009 to 

improve reliability, including projects serving Boston, southwestern Connecticut and southeastern Massachusetts. Fur-
78 | Energy Primer Federal Energy Regulatory Commission

thermore, it continues to assess and bolster its transmission 

system.

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 satisfied by adding

supply resources; demand resources, including demand response and energy efficiency; and new or upgraded transmission facilities. Each year’s plan summarizes New England

needs, as well as the needs in specific areas, and includes solutions and processes required to ensure the reliable and economic performance of the New England power system.

Supply Resources

By plant capacity, the generating mix includes these sources:

Generation Mix

Source: Velocity Suite, ABB 

Demand Response

Currently, ISO-NE administers the following demand-response 

programs for the New England wholesale electricity market:

• Real-Time Demand Response Resources (RTDR): These

resources are required to respond within 30 minutes of 

the ISO’s instructions.

• Real-Time Emergency Generation Resources (RTEG): Resources that the ISO calls on to operate during a 5 percent 

voltage reduction that requires more than 10 minutes to 

implement. They must begin operating within 30 minutes 

of receiving a dispatch instruction.

• Transitional Price-Response Demand: An optional program

that allows market participants with assets registered 

as RTDRs to offer load reductions in response to dayahead LMP. The participant is paid the day-ahead LMP 

for the cleared interruptions, and real-time deviations are 

charged or credited at the real-time LMP.

Market Features

Energy Markets

Day-Ahead Market

The day-ahead energy market allows market participants to 

secure prices for electric energy the day before the operating 

day and hedge against price fluctuations 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 dayahead energy market.

From the offers and bids, the RTO constructs aggregate supply and demand curves for each location. The intersection of 

these curves identifies the market-clearing price at each location for every hour. Supply offers below and demand bids

above the identified 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 LMPs for all locations.

Real-Time Market

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 
Energy Primer | 79

transmission outages, transmission constraints or changes 

from the expected demand. While the day-ahead energy market produces the schedule and financial 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. 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 financially 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 five-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 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 ISO-NE instructs to increase or decrease output moment by moment to balance the 

variations in demand and system frequency to meet industry 

standards. The specific 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
80 | Energy Primer Federal Energy Regulatory Commission

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. Blackstart 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 cost-based rates.

Capacity Markets

In ISO-NE’s annual Forward Capacity Auction (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 first two FCAs in 2008 for the 2010-11 and 2011-12 delivery

years. The first full year of capacity market commitments began on June 1, 2010. 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 defined thresholds to identify physical and economic withholding and uneconomic generation, as well as defined thresholds

to determine whether bids and offers would, if not mitigated,

cause a material effect on LMPs or uplift charges.

Special Provisions for Resources Needed to 

Ensure Grid Reliability

When a resource owner requests to withdraw from the capacity market (termed a “delist bid”) or to retire the resource 

(termed a “non-price retirement request”), the ISO evaluates 

whether the resource is needed for reliability, such as when a 

resource’s withdrawal could lead to a violation of a reliability 

requirement – e.g., inadequate reserve margins or a loss of 

electric system stability.

In New England, the resource owner has the option to retire 

the unit or continue to operate it while the ISO works with 

regional stakeholders to find alternate supply or engineering

solutions that could allow the resource to retire and still maintain grid reliability. Alternative solutions might include obtaining emergency sources of generation or more expensive 

generation from outside the region. If no other alternative is 

available, the ISO may compensate the unit through certain 

payment provisions of the capacity market or by entering into 

a cost of service agreement with the resource owner while 

other options are pursued.

Financial Transmission Rights

New England FTRs are monthly and annual products that 

provide market participants with a means to offset or hedge

against transmission congestion costs in the day-ahead energy 

market. An FTR is an instrument that entitles the FTR holder 

to a payment for costs that arise with transmission congestion 

over a selected path, or source-and-sink pair of locations on 

the grid. The FTR also requires its holder to pay a charge for 

those hours when congestion occurs in the opposite direction 

of the selected source-and-sink pair. The RTO holds FTR auctions to allow market participants the opportunity to acquire 

FTRs or to sell FTRs they currently hold. In New England, ARRs 

represent the right to receive revenues from the FTR auctions. 

ISO-NE allocates ARRs to both LSEs, in relation to historic load, 

and to entities who make transmission upgrades that increase 

the capability of the transmission system.
Energy Primer | 81

Virtual Transactions

New England’s market includes a virtual transaction feature. 

Virtual transactions allow for more participation in the dayahead price setting process, allow participants to manage 

risk, and enables arbitrage that promotes price convergence 

between the day-ahead and real-time markets. In ISO-NE’s terminology, virtual transactions consist of market participants 

submitting increment offers and decrement bids in the dayahead energy market. An increment offer is an offer to sell

energy at a specific location in the day-ahead energy market

which is not associated with a physical supply. An accepted increment offer results in scheduled generation at the specified

location in the day-ahead energy market. A decrement bid is a 

bid to purchase energy at a specific location in the day-ahead

energy market which is not associated with a physical load. 

An accepted decrement bid results in scheduled load at the 

specified location in the day-ahead energy market. The participant receives the day-ahead LMP for each megawatt of 

virtual supply that clears in the day-ahead energy market and 

is financially obligated to pay the real-time LMP at the same

location. Conversely, the participant pays the day-ahead LMP 

for each megawatt of cleared virtual demand and receives the 

real-time LMP at that location.

Credit Requirements

ISO-NE’s tariff includes credit requirements that a market participant needs to meet in order to participate in the market. 

The credit requirements assist in mitigating the effects of defaults that would otherwise be borne among all market participants. ISO-NE assesses and calculates the required credit 

dollar amounts for the segments of the market in which an 

entity requests to participate. ISO-NE establishes a credit limit 

for each market participant in accordance with tariff formulas

that include various creditworthiness-related specifications

such as tangible net worth and total amounts due and owing 

to the ISO-NE market.

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.

ISO-NE calculates, accounts for and settles all charges and 

payments based on received settlement quality meter data. 

The RTO conducts settlements for transactions related to the 

various wholesale electricity markets, market products, and 

other services including energy, capacity, ancillary services, 

FTR charges and payments, among other charges. The RTO 

settles for both the day-ahead and real-time markets.
82 | Energy Primer Federal Energy Regulatory Commission

MISO

Midcontinent Independent System Operator

Source: Velocity Suite, ABB 

Market Profile

Geographic Scope

MISO operates the transmission system and a centrally dispatched market in portions of 15 states in the Midwest and 

the South, extending from Michigan and Indiana to Montana 

and from the Canadian border to the southern extremes of 

Louisiana and Mississippi. The system is operated from three 

control centers: Carmel, Indiana; Eagan, Minnesota; and Little

Rock, Arkansas. 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. In 2013, the RTO began operations in 

the MISO South region, including the utility footprints of Entergy, Cleco, and South Mississippi Electric Power Association, 

among others, in parts of Arkansas, Mississippi, Louisiana, and 

Texas.

Peak Demand

MISO’s all-time peak load was 126 GW in summer 2011, prior 

to the MISO South integration and prior to the move of Duke 

Energy Ohio and Kentucky to PJM.

Import and Exports

MISO has interconnections with the PJM and Southwest Power Pool (SPP) RTOs. It is also directly connected to Southern 

Co., TVA, the Western Area Power Administration, 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 flow 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 approximately 40 transmission owners, whose 

assets define 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.
Energy Primer | 83

Transmission Owners

The transmission owners in MISO include:

• Alliant Energy

• American Transmission Co.

• Ameren (Missouri and Illinois)

• American Transmission Systems

• Duke

• Cleco

• Entergy

• 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. 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

cause congestion in pathways from southern Minnesota and 

western Iowa moving eastward. New Orleans and east Texas 

are also two constrained areas in MISO South. Additionally, 

constraints arise between Missouri and Arkansas, which connects the MISO Midwest with MISO South.

Transmission Planning

The main vehicle MISO uses for transmission planning is the 

MISO 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

By plant capacity, the generating mix includes these sources:

Generation Mix

Source: Velocity Suite, ABB 

Demand Response

Demand-side resources are able to participate in MISO’s markets in providing capacity, energy in both the day-ahead and 

real-time markets and ancillary services.
84 | Energy Primer Federal Energy Regulatory Commission

Market Features

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 fluctuations 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 identifies the market-clearing price at each location for every hour. Supply offers below and demand bids

above the identified 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 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.

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 day-ahead market produces the 

schedule and financial 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 realtime 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 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 market financially 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 dayahead schedule. In real-time, MISO issues dispatch rates and 

dispatch targets. These are five-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 day-ahead 

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 
Energy Primer | 85

is calculated for each five-minute dispatch interval and the resulting five-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 qualified.

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 LSEs to prove they 

have procured capacity needed to meet forecast load and to 

allow generators to recover a portion oftheir fixed costs. They

also provide economic incentives to attract investment in new 

and existing supply- side and demand-side capacity resources.

MISO maintains an annual 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 an annual capacity auction, bilateral purchase, or self-supply. 

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.

Special Provisions for Resources Needed to 

Ensure Grid Reliability 

In MISO, a power plant owner seeking to retire or suspend a 

generator must first obtain approval from MISO. MISO evaluates plant retirement or suspension requests for reliability 

need, and System Support Resource (SSR) designations are 

made where reliability is threatened. Once an agreement has 

been reached, SSRs receive compensation associated with remaining online and available.

Financial Transmission Rights

MISO FTRs provide market participants with a means to offset or hedge against transmission congestion costs in the 
86 | Energy Primer Federal Energy Regulatory Commission

day-ahead market. An FTR is an instrument that entitles the 

FTR holder to a payment for costs that arise with transmission congestion over a selected path, or source-and-sink pair 

of locations on the grid. The FTR also requires its holder to pay 

a charge for those hours when congestion is in the opposite 

direction of the selected source-and-sink pair. Payments, or 

charges, are calculated relative to the difference in congestion

prices in the day-ahead market across the selected FTR transmission path. MISO FTRs are monthly and annual products.

The RTO holds FTR auctions to allow market participants the 

opportunity to acquire FTRs, sell FTRs they currently hold, or 

to convert ARRs to FTRs. ARRs provide LSEs, and entities who 

make transmission upgrades, with a share of the revenues 

generated in the FTR auctions. MISO allocates ARRs to transmission customers relative to historic usage, or upgraded capability, of the transmission system.

Virtual Transactions

MISO’s market includes a virtual transaction feature that allows a participant to buy or sell power in the day-ahead market without requiring physical generation or load. Virtual 

transactions allow for more participation in the day-ahead 

price setting process, allow participants to manage risk, and 

enables arbitrage that promotes price convergence between 

the day-ahead and real-time markets. 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 financial 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 financial obligation to sell the

bid quantity in the real-time market. The financial 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.

MISO allows virtual bids and offers into its day-ahead 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 realtime 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

MISO’s tariff includes credit requirements that a market participant needs to meet in order to participate in the market. 

The credit requirements assist in mitigating the effects of defaults that would otherwise be borne among all market participants. The RTO assesses and calculates the required credit 

dollar amounts for the segments of the market in which an 

entity requests to participate. The market participant may request an unsecured credit allowance subject to certain restrictions – e.g., the RTO must review the entity’s request relative 

to various creditworthiness-related specifications such as tangible net worth and credit scores.

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 finalized seven days after the operating day and payable after 14 days.
Energy Primer | 87

NYISO

New York Independent System Operator

Source: Velocity Suite, ABB

Market Profile

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.

Peak Demand

NYISO’s all-time peak load was 34 GW in summer 2013.

Imports and Exports

NYISO imports and exports energy through interconnections 

with ISO-NE, PJM, TransEnergie (Quebec) and Ontario. Under 

a long-term agreement, approximately 1,000 MW of electricity regularly flows from the Consolidated Edison (Con Ed) territory in upstate New York through PSEG territory in PJM, to 

New York City utilizing phase angle regulator-controlled lines.

This is commonly referred to as the Con Ed-PSEG Wheel and is 

an important source of power for NYISO.

Market Participants

NYISO’s market participants include generators, transmission 

owners, financial 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 filed 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 Owners

NYISO’s transmission owners include:

• Central Hudson Gas & Electric Corp.

• Consolidated Edison Co. of New York

• Long Island Power Authority (LIPA)

• New York Power Authority (NYPA)
88 | Energy Primer Federal Energy Regulatory Commission

• New York State Electric and Gas Corp. (NYSEG)

• National Grid

• Orange & Rockland Utilities

• Rochester Gas and Electric Corp.

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 flows 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.

Transmission Planning

NYISO conducts a biennial transmission planning process with 

stakeholders that includes both short-term and long-term 

projects.

Supply Resources

By plant capacity, the generating mix includes these sources:

Generation Mix

Source: Velocity Suite, ABB

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 (DADRP) and the Demand-Side Ancillary Services Program (DSASP).

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 DADRP 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 dayahead DR, flexible loads may effectively increase the amount

of supply in the market and moderate prices.

The DSASP provides retail customers that can meet telemetry 

and other qualifications the ability to bid theirload 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

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 fluctuations 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. 
Energy Primer | 89

From the offers and bids, the RTO constructs aggregate supply and demand curves for each location. The intersection of 

these curves identifies the market-clearing price at each location for every hour. Supply offers below, and demand bids

above, the identified price are scheduled. Offers and bids that

clear are then entered into a pricing software system along 

with binding transmission constraints to produce the LMPs 

for all locations. The NYISO refers to LMPs 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 real-time 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 afterthe 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. Hourahead 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 firm 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 financialterms 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 market outcomes are based on supply offers, realtime 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 realtime market. For generators, the market provides additional 

opportunities to offer supply to help meet additional needs.

The real-time market financially 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 day-ahead 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 under- or over-consumed in real-time.

Real-time dispatch of generators occurs every five minutes, as

does the setting of the real-time prices used for settlement 

purposes. Market participants may participate in the dayahead, 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.

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 trans-
90 | Energy Primer Federal Energy Regulatory Commission

mission 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 LSEs to procure capacity needed to meet forecast load and to allow generators to 

recover a portion of their fixed 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 four zones: New York

City, Long Island, Lower Hudson Valley, 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 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 benefits 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 unjustifiable change to operating

parameters of a generator that reduces its availability; or operating a generator in real-time at a lower output level than 
Energy Primer | 91

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 unjustifiably 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.

Price Caps

NYISO has an offer cap of $1,000/MWh for its day-ahead and

real-time markets.

Capacity for New York City is subject to offer caps and floors.

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 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.

Special Provisions for Resources Needed to 

Ensure Reliability 

 Generation owners within New York seeking to retire or suspend a generator must first obtain approval from state regulators. After an assessment, if the generator is found to be 

necessary for reliability purposes, the local transmission owner can be compelled to reach a contract (Reliability Support 

Services Agreement) with the generator where compensation 

provisions are included to continue operation of the plant until the reliability need is resolved. 

Financial Transmission Rights

FTRs provide market participants with a means to offset or

hedge against transmission congestion costs in the day-ahead 

market. The NYISO refers to FTRs as Transmission Congestion 

Contracts (TCCs). A TCC is an instrument that entitles the holder to a payment for costs that arise with transmission congestion over a selected path, or source-and-sink pair of locations 

(or nodes) on the grid. The TCC also requires its holder to pay 

a charge for those hours when congestion is in the opposite 

direction of the selected source-and-sink pair. Payments, or 

charges, are calculated relative to the difference in congestion prices in the day-ahead market across the selected FTR 

transmission path. 

A related product, ARRs, provide their holders with a share of 

the revenue generated in the TCC auctions. In general, ARRs 

are allocated based on historical load served. As with TCCs, 

ARRs provide transmission owners and eligible transmission 

service customers an offset or hedge against transmission

congestion costs in the day-ahead market.
92 | Energy Primer Federal Energy Regulatory Commission

Virtual Transactions

NYISO’s market includes a virtual transaction feature that allows a participant to buy or sell power in the day-ahead market 

without requiring physical generation or load. Virtual transactions allow for more participation in the day-ahead price setting process, allow participants to manage risk, and enables 

arbitrage that promotes price convergence between the dayahead and real-time markets. Cleared virtual supply (virtual offers) in the day-ahead energy market at a particular location in 

a certain hour creates a financial 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 day-ahead market creates a financial obligation to sell the

bid quantity in the real-time market. The financial outcome is

determined by the difference between the hourly day-ahead

and real-time LBMPs at the location at which the offer or bid

clears. Virtual bidding in NYISO takes place on a zonal level,

not a nodal level.

Credit Requirements

NYISO’s tariff includes credit requirements that a market participant needs to meet in order to participate in the market. 

The credit requirements assist in mitigating the effects of defaults that would otherwise be borne among all market participants. NYISO assesses and calculates the required credit 

dollar amounts for the segments of the market in which an 

entity requests to participate. The market participant may request an unsecured credit allowance subject to certain restrictions – e.g., NYISO must review the entity’s request relative to 

various creditworthiness-related specifications such as investment grade or equivalency rating and payment history.

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 first 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 | 93

PJM

The PJM Interconnection

Source: Velocity Suite, ABB

Market Profile

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.

Peak Demand

PJM’s all-time peak load was 165 GW in summer 2011.

Imports and Exports

PJM has interconnections with Midcontinent ISO and New 

York ISO. PJM also has direct interconnections with the Tennessee Valley Authority (TVA), Progress Energy Carolinas 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 efficiency and short

and long-term planning. The board ensures that no member 

or group of members exerts undue influence.

The members committee, which advises the board, is composed of five voting sectors representing power generators,

transmission owners, electric distributors, power marketers 

and large consumers.

Transmission Owners

The largest transmission owners in PJM include:

• AEP

• First Energy

• PSE&G

• Dominion

• Philadelphia Electric

• Commonwealth Edison
94 | Energy Primer Federal Energy Regulatory Commission

Chronic Constraints

The largest constraints are in the Eastern Hub of PJM (New

Jersey, Southeast Pennsylvania, and Delaware) and Northern 

Ohio. 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 and thus on transmission across 

Pennsylvania and up from southwestern PJM to import power 

from sources west and southwest. 

Congestion on the eastern interface also constrains power 

flows 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-Baltimore- Northern Virginia are supplied not 

only by local generation but also by significant energy transfers to those areas. 

In recent years, transmission congestion has not been as severe, due to upgrades to the transmission system, including 

construction of new transmission lines. Additionally, the availability of lower-cost natural gas has helped reduce the need 

for the eastern portion of PJM to import power from the west.

Transmission Planning

PJM’s Regional Transmission Expansion Plan identifies transmission system additions and improvements needed to keep 

electricity flowing 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.

Supply Resources

By plant capacity, the generating mix includes these sources:

Generation Mix

Source: Velocity Suite, ABB

Demand Response

End-use customers providing demand response have the opportunity to participate in PJM’s energy, capacity, synchronized reserve and regulation markets. PJM’s DR 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 an offer into the

day-ahead market that clears; submitting an offer into the

real-time market that is dispatched; and self-scheduling load 

reductions while providing notification 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 

verification 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.
Energy Primer | 95

Market Features

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 fluctuations that can occur in realtime. 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, the RTO constructs aggregate supply and demand curves for each location. The intersection of 

these curves identifies the market-clearing price at each location for every hour. Supply offers below and demand bids

above the identified 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 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 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.

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 financial 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 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 five-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 market during the generation rebidding 

period from 4 p.m. to 6 p.m.; otherwise, their original dayahead market bids remain in effect for the real-time 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.

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 sufficient 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.
96 | Energy Primer Federal Energy Regulatory Commission

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 an 

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 scheduling reserves, 

PJM is required to schedule additional operating reserves.

Furthermore, 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.

Capacity Markets

Capacity markets provide a means for LSEs to procure capacity needed to meet forecast load and to allow generators to 

recover a portion of their fixed costs. They also provide economic incentives to attract investment in new and existing 

supply-side and demand-side 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-efficiency resources

that will be needed to keep the regional power grid operating 

reliably. RPM market design is based on three-year, forwardlooking 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 whether each capacity seller has market power. If the seller fails that test, that 

seller’s bid is capped so as to replicate that seller’s avoidable 

or opportunity costs.

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 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 higherpriced generator must be run due to a transmission constraint 

that prevents the use of available lower-priced 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 that are jointly pivotal, 

meaning they have the ability to increase the market price 

above the competitive level.
Energy Primer | 97

Price Caps

PJM has a $1,000/MWh offer cap in the energy markets.

Special Provisions for Resources 

Needed to Ensure Grid Reliability

A generator owner who wishes to retire a unit must request 

from PJM to deactivate the unit at least 90 days in advance of 

the planned date. The owner includes in the request an estimate of the amount of project investment necessary to keep 

the unit in operation. PJM, in turn, analyzes if the retirement

would lead to a reliability issue. Additionally, the RTO estimates the period of time it would take to complete transmission upgrades necessary to alleviate the reliability issue. 

If PJM requests the unit to operate past the desired deactivation date, the generator owner may file with FERC for cost

recovery associated with operating the unit until it may be 

deactivated. Alternatively, the owner may choose to receive 

avoided cost compensation calculated according to PJM’s tariff.

Financial Transmission Rights

FTRs provide market participants with a means to offset or

hedge against transmission congestion costs in the day-ahead 

market. An FTR is an instrument that entitles the holder to 

a payment for costs that arise with transmission congestion 

over a selected path, or source-and-sink pair of locations on 

the grid. The FTR also requires its holder to pay a charge for 

those hours when congestion is in the opposite direction of 

the selected source-and-sink pair. Payments, or charges, are 

calculated relative to the combined difference in congestion

prices in the day-ahead and real-time markets across the selected FTR transmission path. 

A related product, ARRs, provide their holders with a share of 

the revenue generated in the FTR auctions. In general, ARRs 

are allocated based on historical load served and can be converted to FTRs. As with FTRs, ARRs provide transmission owners and eligible transmission service customers an offset or

hedge against transmission congestion costs in the day-ahead 

market.

Virtual Transactions

PJM’s market includes a virtual transaction feature that allows 

a participant to buy or sell power in the day-ahead market without requiring physical generation or load. Virtual transactions 

allow for more participation in the day-ahead price setting process, allow participants to manage risk, and enables arbitrage 

that promotes price convergence between the day-ahead and 

real-time markets. 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 financial 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 financial obligation to sellthe bid quantity in the realtime market. The financial 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. Up-to-congestion (UTC) transactions are another type 

of transaction that may be submitted in the day-ahead energy 

market between any two buses either within PJM or between 

a bus within PJM and an external interface. UTC positions are 

liquidated in the real-time energy market. 
98 | Energy Primer Federal Energy Regulatory Commission

Credit Requirements

PJM’s tariff includes credit requirements that a market participant needs to meet in order to participate in the market. The 

credit requirements assist in mitigating the effects of defaults

that would otherwise be borne among all market participants. 

The RTO assesses and calculates the required credit dollar 

amounts for the segments of the market in which an entity 

requests to participate. The market participant may request 

an unsecured credit allowance subject to certain restrictions – 

e.g., the RTO must review the entity’s request relative to various creditworthiness-related specifications such as tangible

net worth and credit scores.

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 day-ahead and real-time energy markets.

SPP

Southwest Power Pool

 Source: Velocity Suite, ABB 

Market Profile

Geographic Scope

Founded as an 11-member tight power pool in 1941, Southwest 

Power Pool (SPP) achieved RTO status in 2004, ensuring reliable power supplies, adequate transmission infrastructure, 

and competitive wholesale electricity prices for its members. 

Based in Little Rock, Ark., SPP manages transmission in 14 

states: Arkansas, Iowa, Kansas, Louisiana, Minnesota, Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, and Wyoming. Its membership 

is comprised of investor-owned utilities, municipal systems, 

generation and transmission cooperatives, state authorities, 

independent power producers, power marketers and independent transmission companies.
Energy Primer | 99

In 2007, SPP began operating its real-time Energy Imbalance 

Service (EIS) market. In the same year, SPP became a FERCapproved Regional Entity. The SPP Regional Entity serves as 

the reliability coordinator for the NERC region, overseeing 

compliance with reliability standards.

In March 2014, SPP implemented its Integrated Marketplace 

that includes a day-ahead energy market, a real-time energy 

market, and an operating reserve market. SPP’s Integrated 

Marketplace also includes a market for Transmission Congestion Rights. The SPP Integrated Marketplace co-optimizes the

deployment of energy and operating reserves to dispatch resources on a least-cost basis.

In 2015, SPP expanded its footprint incorporating the Western 

Area Power Administration – Upper Great Plains region, the 

Basin Electric Power Cooperative, and the Heartlands Consumer Power District. The expansion nearly doubled SPP’s service territory by square miles, adding more the 5 GW of peak 

demand and over 7 GW of generating capacity. 

Peak Demand

SPP’s all-time peak demand of 48 GW occurred in summer 2011.

Import and Exports

SPP has interties with MISO, PJM, and Tennessee Valley Authority, among other systems. Additionally, SPP has two direct-current (DC) interties with ERCOT and seven DC interties 

to the western interconnect through New Mexico, Colorado, 

Nebraska, South Dakota and Montana. 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, 

municipal utilities, state agencies, transmission owners, financial participants, and a federal power marketing administration. 

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 entities 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 Area Power Administration – Upper Great Plains

• Western Farmers Electric Cooperative

Transmission Planning

SPP conducts its transmission planning according to its Integrated Transmission Planning process, which is a three-year 

planning process that includes 20-year, 10-year, and near-term 

assessments designed to identify transmission solutions that 

address both near-term and long-term transmission needs. 

The Integrated Transmission Planning process focuses on 

identifying cost-effective regional transmission solutions,

which are identified in an annual SPP Transmission Expansion

Plan report.
100 | Energy Primer Federal Energy Regulatory Commission

Supply Resources

By plant capacity, the generating mix includes these sources:

Generation Mix

Source: Velocity Suite, ABB

Market Features

Energy Markets

Day-Ahead

The day-ahead market allows market participants to secure 

prices for electric energy the day before the operating day 

and hedge against price fluctuations that can occur in realtime. 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, the RTO constructs aggregate supply and demand curves for each location. The intersection of 

these curves identifies the market-clearing price at each location for every hour. Supply offers below and demand bids

above the identified 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 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 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.

Real-Time 

SPP 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 financial 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, SPP operates a spot market for energy called the realtime market.

The real-time market uses final day-ahead schedules for resources within the RTO and imports and exports as a starting 

point. It then operates a five-minute market to balance generation and loads.

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 SPP, 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 qualified.

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.
Energy Primer | 101

SPP procures ancillary services via the co-optimized energy

and ancillary services market and includes the following services:

• Regulation Up reserves: Resources providing this Regulation Up must be able to move quickly above their scheduled operating point in response to automated signals 

from the RTO to maintain the frequency on the system by 

balancing generation and demand.

• Regulation Down reserves: Resources providing Regulation Down must be able to move quickly below their 

scheduled operating point in response to automated 

signals from the RTO to maintain the frequency on the 

system by balancing generation and demand.

• Spinning Reserves: Resources providing Spinning Reserves are already synchronized to the grid and available

to serve load within a short period following a contingency event such as an unexpected failure or outage of 

generator, transmission line, or other electrical element.

• Supplemental Reserves: Resources that are on-line and/or

off-line but capable of being synchronized to the grid and

fully available to serve load following a specified period

following a contingency event.

Capacity Markets

SPP does not offer a capacity market. However, it requires

each market participant to have sufficient 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 on a systemwide basis or locally. 

SPP applies a set of behavioral and market outcomes 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 – i.e., offer prices close

to short-run marginal costs. SPP’s mitigation test includes a 

local market power test, a pivotal supplier test, and a market impact test. Where mitigation measures are triggered by 

the tests, SPP generates a mitigated market solution that the 

RTO then uses for dispatch, commitment, and settlement 

purposes.

Price Caps

SPP employs an offer cap of $1,000/MWh.
102 | Energy Primer Federal Energy Regulatory Commission

Special Provisions for Resources 

Needed to Ensure Grid Reliability

SPP prepares annual reliability studies as part of its system 

planning responsibilities. In the event that studies reveal a 

potential constraint on SPP’s ability to deliver power to a local 

area on the transmission system, the RTO works with regional 

stakeholders to find alternate transmission, operating procedure, or generation solutions for the constraint and thus maintain grid reliability. SPP parties will determine an appropriate 

sharing of the costs, and, if unable to reach agreement, the 

RTO will submit a proposed cost sharing arrangement to the 

Commission for approval.

Financial Transmission Rights

Financial FTRs provide market participants with a means to 

offset or hedge against transmission congestion costs in the

day-ahead market. SPP refers to FTRs as Transmission Congestion Rights (TCRs). A TCR is an instrument that entitles the 

holder to receive compensation, or requires the holder to pay 

a charge, for costs that arise with transmission congestion 

over a selected path, or source-and-sink pair of locations on 

the grid. A TCR provides the holder with revenue, or charges, 

equal to the difference in congestion prices in the day-ahead

market across the selected TCR transmission path. SPP TCRs 

are monthly and annual products.

A related product, ARRs, provide their holders with a share of 

the revenue generated in the TCR auctions. In general, ARRs 

are allocated based on historical load served. As with TCRs, 

ARRs provide transmission owners and eligible transmission 

service customers an offset or hedge against transmission

congestion costs in the day-ahead market.

Virtual Transactions

SPP’s market includes a virtual transaction feature that allows 

a participant to buy or sell power in the day-ahead market 

without requiring physical generation or load. Virtual transactions allow for more participation in the day-ahead price setting process, allow participants to manage risk, and enables 

arbitrage that promotes price convergence between the dayahead and real-time markets. Cleared virtual supply (virtual offers) in the day-ahead energy market at a particular location in 

a certain hour creates a financial 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 

day-ahead market creates a financial obligation to sell the bid

quantity in the real-time market. The financial outcome is determined by the difference between the hourly day-ahead and

real-time LMPs at the location at which the offer or bid clears.

Credit Requirements

SPP’s tariff includes credit requirements that a market participant needs to meet in order to participate in the market. The 

credit requirements assist in mitigating the effects of defaults

that would otherwise be borne among all market participants. 

The RTO assesses and calculates the required credit dollar 

amounts for the segments of the market in which an entity 

requests to participate. The market participant may request 

an unsecured credit allowance subject to certain restrictions – 

e.g., the RTO must review the entity’s request relative to various creditworthiness-related specifications such as tangible

net worth and various financial measures.

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.

SPP has a two-settlement system, one each for the day-ahead 

and real-time markets. The SPP settlement process calculates 

quantities of energy, ancillary services, TCRs, virtual transactions, among other market features.
Energy Primer | 103

4. U.S. Crude Oil & Petroleum Products

Markets

Petroleum, or crude oil, and its derived petroleum products play a key role in the U.S. economy, accounting for approximately 

one third of primary energy consumption in the U.S. in 2014. Its role is especially important in the transportation sector where, 

despite a steady increase in non-petroleum transportation fuels since 2000, petroleum products accounted for 92 percent of 

all transportation fuels in 2014. The remaining 8 percent consisted of biomass fuels (ethanol and biodiesel), natural gas, and 

electricity.

Petroleum Accounts for Most of the Energy 

Consumption in the Transportation Sector

Source: Derived from EIA data

Unlike methane, the primary component of pipeline grade 

natural gas, petroleum is not consumed in its natural form; 

instead, it is refined into a number of products that can be

used for numerous applications. In the U.S., the largest share 

of crude oil, approximately 90 percent, is consumed as transportation fuels, including gasoline, diesel, and jet fuel. Other 

uses include heating, power generation, and petrochemical 

feedstocks used to manufacture a variety of products including plastics, pharmaceuticals, fertilizers, and construction

materials. 

U.S. Petroleum Products Supply in 2014 

(Million gallons/day)

Source: Derived from EIA data

Petroleum is both produced domestically and 

imported from a number 

of countries. The same is 

true for petroleum products, especially gasoline, 

diesel fuel, and jet fuel. 

The percent of imported 

petroleum and petroleum 

products has been decreasing in recent years as U.S. crude 

oil production from shale has increased. Nearly 50 percent 

of U.S. crude oil production comes from Texas and North 

FERC Jurisdiction

The Federal Energy Regulatory 

Commission’s jurisdiction 

over the oil markets is limited 

to setting pipeline transportation rates and ensuring 

open access in the pipeline 

system.
104 | Energy Primer Federal Energy Regulatory Commission

Dakota, although significant amounts are produced in other

states. U.S. refineries, which convert the crude oil into usable

products, are found throughout the country, but are heavily 

concentrated on the Gulf Coast.

Petroleum

Unlike natural gas, which is a simple molecule consisting of 1 

carbon atom and four hydrogen atoms (CH4), petroleum as

found in the ground is a mixture of hydrocarbons that formed 

from plants and animals that lived millions of years ago. Crude 

oil exists in a liquid form in underground pools or reservoirs, 

Density of an Oil (API Gravity)

The density, or “weight,” of an oil is one of the largest 

determinants of its market value (another key characteristic is sulfur content – see text box, “Sweet or Sour?”). 

The density of an oil is often referred to as “light” or 

“heavy” and is measured using API gravity. API gravity 

is determined using the specific gravity of an oil, which

is the ratio of its density to that of water (density of the 

oil/density of water) at 60 degrees Fahrenheit. Oils are

generally classified as:

Light – API > 31.1 Medium – API between 22.3 and 31.1

Heavy – API < 22.3	 Extra Heavy – API < 10.0

However, specific oils may be categorized differently depending on the region where they are produced and how 

the oil is referred to by commodity traders.

Though specific gravity is a unitless number, API gravity

values in practice are often referred to as degrees. The 

API gravity of West Texas Intermediate is said to be 39.6 

degrees. API gravity moves inversely to density, which 

means the denser an oil the lower its API gravity. An API 

of 10 is equivalent to water, which means oils with an API 

above 10 will float on water while oils with an API below

10 will sink.

in tiny spaces within sedimentary rocks, and near the surface 

in tar (or oil) sands. In its natural state, crude oil ranges in 

density and consistency, from very thin, light-weight and volatile fluidity to extremely thick, semi-solid heavy-weight oil. Its

color can vary from a light golden yellow to a deep black.

Benchmark Crude Oil 

A benchmark crude oil is a specific crude oil that is widely

bought and sold at well-traded locations with commonly 

posted prices. Other quality crude oils are traded with 

reference to benchmark crude oils and the pricing is 

typically adjusted using agreed-upon price differentials

that take into account such factors as API gravity, sulfur 

content, and transportation costs – e.g., from production areas to refineries. WTI oil and Brent are two major

benchmark crude oils with WTI used in the U.S. and Brent 

used in global trade. A third major benchmark, Dubai, is 

mostly used in Asian trade.

Different countries, regions, and geological formations produce different types of crude, which are generally described

as light or heavy, depending on their viscosity, and sweet or 

sour, depending on their sulfur content. As a rule, heavy oils 

are sour as they contain more sulfur. West Texas Intermediate 

(WTI), the U.S. pricing benchmark, is a light, sweet oil delivered at Cushing, Oklahoma. The Brent oil benchmark, also a 

light, sweet oil, is a basket of North Sea oils used to set crude 

oil and petroleum prices around the world. By contrast, Mexico’s Maya crude is both heavy and high in sulfur (sour).

Crude oils that are light and sweet usually command higher 

prices than heavy, sour crude oils. This is partly because gasoline and diesel fuel, which typically sell at a significant premium to heavier products produced in the refining process,

are more easily and cheaply produced using light, sweet crude 

oil. Processing the light, sweet grades require far less sophisticated and energy-intensive refining processes.
Energy Primer | 105

Density and Sulfur Content of Selected Crude Oils

Source: Derived from EIA data

U.S. Crude Oil Supply

In 2014, the U.S. consumed approximately 16 million barrels 

per day (MMbd) of crude oil, of which 54 percent was produced domestically, a reversal from recent years when imports made up the majority of the supply. Between 1994 and 

2013, the U.S. imported most of its crude oil. Imports peaked 

in 2006 at 10.1 MMbd, or 67 percent of total supply. 

U.S. Crude Oil Supply – Increased Production 

Displaces Imports 

Source: Derived from EIA data

Sweet or Sour? 

The terms sweet and sour refer to the sulfur content of 

crude oil. Early prospectors would taste oil to determine 

its quality, with low sulfur oil tasting relatively sweet. 

Crude is considered sweet if it contains less than 0.5 percent sulfur.

Sweet crude is easier to refine and safer to extract and

transport than sour crude. Because sulfur is corrosive, 

sweet crude also causes less equipment damage to refineries and thus results in lower maintenance costs over

time. Due to these factors, sweet crude commands a price 

premium over sour.

Major sources of sweet crude include the Appalachian Basin in Eastern North America, Western Texas, the Bakken 

Formation of North Dakota and Saskatchewan, the North 

Sea of Europe, North Africa, Australia, and the Far East including Indonesia.

Sour crude oil has greater than 0.5 percent sulfur and some 

of this will be in the form of hydrogen sulfide, known for

its “rotten egg” smell. Hydrogen sulfide is considered an

industrial hazard and, thus, sour crude has to be stabilized

via removal of hydrogen sulfide before it can be transported by oil tankers.

Sour crude is more common in the Gulf of Mexico, Mexico, South America, and Canada. Crude produced by OPEC 

Member Nations also tends to be relatively sour, with an 

average sulfur content of 1.77 percent.

Driving the increase in domestic oil production are the same 

developments that resulted in sharp increases in natural gas 

production, horizontal drilling and high-pressure hydraulic

fracturing (fracking). To date, the most prolific example of

success in this technology is in the Bakken Shale in North Dakota. Between 1990 and 2005, production in North Dakota 

averaged 89,000 barrels per day (Mbd). Production began 

to grow in 2006, as companies started to apply the horizontal drilling and fracking techniques. By 2014, production had 

reached 1.1 MMbd, making North Dakota the second biggest 

crude oil producing state in the country. 
106 | Energy Primer Federal Energy Regulatory Commission

In addition to North Dakota, other major producing locations 

in the U.S. include Texas, offshore locations in the Gulf of Mexico, California, Oklahoma, and Alaska. Texas, the largest producing state, also experienced a substantial increase in output 

with the application of the new technologies. Texas onshore 

production fell steadily between 1980 and 2007, when it averaged 1.1 MMbd. However, production began to ramp up as

companies targeted oil rich shale formations, including the 

Eagle Ford Shale and the Permian Basin. Production in the 

Permian Basin, one of the oldest oil producing formations in 

Texas, had been in decline prior to the implementation of the 

new extraction techniques. By 2014, Texas production had 

reached 3.2 MMbd.

One important attribute of rising crude oil production from 

shale is that the majority of the output consists of light, sweet 

oil. Approximately 90 percent of the nearly 3.0 MMbd growth 

in production from 2011 to 2014 consisted of light, sweet 

grades. This is important as it helps determine refinery investments and operations and, thus, influences the types of crude

oil that are imported and processed in U.S. refineries.

Top Five U.S. Crude Oil Producing Locations

Source: Derived from EIA data

Offshore production in the Gulf of Mexico averaged 1.4 MMbd

in 2014. However, it peaked in 2003 and has remained relatively flat for the past 15 years. Producing crude oil from offshore deposits is more technically challenging and costly than 

on-shore, and over the past few years producers have opted 

to shift investments to the shale formations. 

Imports are also an important component to U.S. crude oil 

supply, accounting for 46 percent of U.S. supply, or 7.3 MMbd 

in 2014 (excluding petroleum products). The largest foreign 

supplier of crude oil (excluding petroleum products) is Canada, which in 2014 accounted for 2.9 MMbd or almost 47 percent of total imports. In Canada, unconventional oil production methods have resulted in robust production from the oil 

sands region in Alberta. The second largest supplier was Saudi 

Arabia, with 1.2 MMbd, followed by Mexico, Venezuela, and

Iraq.

Top Ten Foreign Suppliers of Crude Oil to the U.S. 

in 2014

Source: Derived from EIA data

Petroleum Reserves 

At the end of 2014, there were an estimated 1,700 billion barrels of proved reserves in the world. The U.S. accounted for 

49 billion, or 2.9 percent of these reserves. That is sufficient

to last approximately 53 years at current production levels, 

according to BP’s “Statistical Review of World Energy” (June 
Energy Primer | 107

2015). Proved reserves fluctuate as new geological 

supply sources are discovered, as the technology to 

produce from known sources advances, and as price 

fluctuations change the

economics of particular resources. For example, the 

discovery of the pre-salt oil deposits offshore Brazil increased

global proved reserves by adding a new potential source of 

production. The advances in horizontal drilling and slick water

fracturing technology increased the size of proved reserves in

the U.S. and other countries by making shale oil technically recoverable. Proven reserves also increased when crude oil consistently traded above $100/barrel between 2008 and 2014, as

the high prices made drilling in high cost areas economic.

In 2014 Most of the World’s Proved Oil Reserves 

were in the Middle East

Source: Derived from BP Statistical Review of World Energy 2015 data

Although two of the top three countries by proved reserved 

are Venezuela and Canada, most of the world’s proven reserves are in the Middle East. Five countries, Saudi Arabia, 

Iran, Iraq, Kuwait, and the United Arab Emirates, together

hold 46 percent of all proved reserves. In addition, of the top 

10 countries in proved reserves, seven are members of the Organization of Petroleum Exporting Countries (OPEC), an intergovernmental organization of oil-producing countries. This

geopolitical and geographic concentration is an important 

factor as will be discussed later in this chapter. 

Crude Oil Refining

As of January 1, 2012, the U.S. had more than 17.3 MMbd of 

refinery capacity. For historical reasons dating back to gasoline rationing during World War II, the U.S. is divided into five

geographical regions called Petroleum Administration for Defense Districts, or PADDs. Approximately 44 percent, or 7.7 

MMbd of refining capacity, is located along the Gulf Coast, in

PADD 3. 

Petroleum Administration for Defense Districts

Source: EIA

Most of the largest and more modern refineries are situated

along the coast of Texas, Louisiana, Mississippi, and Alabama. 

Many refineries are located close to the traditional crude oil

production or import centers in the Gulf Coast or near major 

population centers where demand for refined products is

greatest, including California and the areas near Philadelphia, 

New York City, and Chicago.

In general, crude oil refining involves processing crude oil

through distillation facilities where the crude oil is heated and 

separated into its lighter and heavier components. The heat

Proved Oil Reserves

Estimated quantities of oil 

that analysis of geologic and 

engineering data demonstrates with reasonable 

certainty are recoverable 

under existing economic and 

operating conditions.
108 | Energy Primer Federal Energy Regulatory Commission

Continental U.S. Refineries – Top 50 by Capacity

Source: Derived from EIA data

causes the lighter, more volatile molecules to rise and, as they 

cool, the heavier components such as heavy fuels and residual 

fuels settle into trays and are carried out of the unit into their 

own processing streams. The lighter molecules rise higher in 

the unit and are processed into light products such as gasoline and naphtha. Depending on the refinery configuration,

heavier components may be further processed to yield higher 

amounts of the more valuable light products. Breaking down 

the heavier products into lighter ones requires more specialized and expensive equipment and processes such as catalytic

crackers and cokers.

Basic Crude Oil Distillation Unit & Product Output

Source: Derived from EIA data

The growth in production of light, sweet oil from shale is 

changing the makeup in the types of crude processed at U.S. 

refineries. During the 1990s when domestic U.S. crude oil production was declining,refineries along the Gulf Coast spent billions of dollars to reconfigure their equipment and operations

to handle imports of heavy, sour crude oil from Mexico and 

Venezuela. Despite these upgrades, refineries in the region

still imported and processed as much as 1.3 MMbd of light, 

sweet crude oil, more than any other region of the country. 

Beginning in 2010, improvements to the crude oil distribution 

system and sustained increases in production in the region (in 

the Permian and Eagle Ford basins) allowed more domestic 

crude oil to reach the Gulf Coast refining centers, significantly

reducing the need for imports of light crude. Since September 2012, imports of light, sweet crude oil to the Gulf Coast 

have regularly been less than 200,000 bbl/d. Similarly, Gulf

Coast imports of light, sour crude also declined and have been 

less than 200,000 bbl/d since July 2013.

Imports of Crude Oil into the U.S. Gulf Coast

Source: Derived from EIA data
Energy Primer | 109

Crude Oil and Petroleum Products 

Transportation

There are more than 190,000 miles of petroleum pipelines 

in the U.S. Because of increased shale production, crude oil 

pipeline mileage grew 8,174 miles or 15.5 percent between 

2009 and 2013. Crude pipelines move oil from the production 

fields and import terminals to refineries for processing into

various products. Products pipelines then distribute the fuels 

to various parts of the country. 

Colonial Pipeline Company is the largest pipeline in the U.S.; 

transporting 844 billion barrel-miles (one barrel transported 

one mile) of petroleum products in 2014. It is one of the most 

important products pipelines in the country as it carries supply 

from the refining centers in Texas and Louisiana to the major demand centers along the U.S. east coast. It transports 

approximately 100 million gallons per day of gasoline, diesel 

fuel, jet fuel, and other products from Houston, Texas to Linden, New Jersey on a 5,500-mile network, crossing 13 states. 

The second largest pipeline, with 583 billion barrel-miles transported in 2014 is Enbridge Energy. This pipeline begins in the 

oil sands producing region in Alberta, Canada, and transports 

53 percent of the Canadian crude oil that comes into the U.S. 

Once in the U.S., it moves the crude oil from North Dakota to 

Chicago and south into Cushing, Oklahoma. A distant thirdlargest pipeline is the TransCanada Keystone Pipeline, which

in 2014 transported 210 billion barrel-miles of crude oil from 

Canada into the U.S. mid-continent and the Gulf Coast. This is 

a different pipeline from the proposed TransCanada Keystone

XL. 

Regulation of crude oil and petroleum product pipelines falls 

under a number of government entities. The Department 

of Transportation’s (DOT) Pipeline and Hazardous Materials

Safety Administration (PHMSA) is responsible for regulating

and ensuring the safe and secure movement of hazardous materials to industry and consumers by all modes of transportation, including pipelines. Its Office of Pipeline Safety ensures

safety in the design, construction, operation and maintenance, and spill response of oil and natural gas pipelines and 

other hazardous liquid transportation pipelines.

FERC’s jurisdictional responsibilities regarding crude oil and 

petroleum product pipelines include:

• Regulation of rates and practices of oil pipeline companies 

engaged in interstate transportation

• Ensuring the furnishing of pipeline transportation to shippers on a non-discriminatory and non-preferential basis

• Establishment of just and reasonable rates for transporting crude oil and petroleum products by pipeline

Changes in U.S. production dynamics in recent years, specifically the growth of crude oil production in areas not traditionally served by oil pipelines, such as the Bakken Shale formation in North Dakota, have taxed the current pipeline system. 

As a result, the country has experienced a sharp increase in 

transportation of crude oil by rail, despite the fact that pipeline transportation is more economic than rail. An advantage 

of rail transportation, however, is that companies can rampup capacity quickly and have more flexibility in origin and delivery points. The largest oil-by-rail movements have originated from PADD 2, specifically in North Dakota. In 2014, more

than 262,000 barrels, or 71 percent of all inter-PADD movement came from PADD 2. The majority of those barrels were 

shipped to PADD 1, likely to feed refineries in the Philadelphia

area. Additionally, approximately 50,000 barrels were imported or exported to Canada via rail. 

Crude-by-Rail Volumes in the U.S. and Canada 

Source: Derived from EIA data
110 | Energy Primer Federal Energy Regulatory Commission

allows for various types of exports including petroleum products, exports of slightly refined crude oil condensate, shipments of crude oil owned by a company to an affiliate refinery

in Canada, and heavy-for-light crude oil swaps with Mexico. 

U.S. exports of petroleum products rose substantially with 

the increase of production of oil from shale. In 2000 the U.S. 

exported 868,000 barrels of finished products. This number

had increased to 2.8 million barrels by 2014. 

Crude Oil and Petroleum Products 

Demand 

The largest demand category 

for petroleum products in 

the U.S. is the transportation 

sector. Motor gasoline alone 

made up 56 percent of petroleum products sold by prime 

suppliers into the U.S. market. 

The second largest is No. 2 distillate, which made up 26 percent of prime supplier sales in 

2014, and which includes diesel fuel, also used in the transportation sector, mostly by long 

distance freight trucking. No. 2 distillates also include fuel oil, 

used for space heating and, in a lesser capacity, for electric 

generation. The next largest demand category is another 

transportation sector fuel, jet fuel, which accounted for 9 percent of sales. All told, demand from the transportation sector 

accounts for approximately 90 percent of all petroleum products consumed in the U.S.

Other petroleum products include: propane used for space

heating and in petrochemical processes; kerosene used in 

heating and lighting; No. 1 fuel oil, which can be blended into 

heating fuel or diesel fuel; No. 4 fuel oil used for commercial 

heating and power generation; residual fuels used in power 

generation and ship boilers; and asphalt used to build roads.

The rise of oil-by-rail shipments has raised some safety issues, 

as there have been a number of serious and, at times, fatal 

incidents involving oil-laden rail cars. The U.S. Department of 

Transportation has worked with the rail and oil industry on 

new regulations involving car design and train operations.

Two Federal statutes limit the movement of crude oil and 

crude oil products. First, the Jones Act of 1916, 46 U.S. Code § 

55102, generally prohibits any foreign built or foreign-flagged

vessel from engaging in trade that begins at any point within 

the United States and delivers commercial cargo to any other 

point within the United States. Because of the limited numbers of oil and petroleum products vessels that meet the 

Jones Act requirements, the ability to move crude oil and refined products between marine ports is in short supply. That

means, for example, that producers are limited in their ability 

to move crude oil to the Gulf Coast via pipeline and then ship it 

to East Coast refiners. Likewise, Gulf Coast refiners are limited

in their ability to move refined products up the East Coast via

waterborne vessels. 

U.S. Exports of Finished Petroleum Products

Source: Derived from EIA data

A second statute, § 754.2 – Crude Oil, enacted during the 1970s 

oil crisis, requires licensing of U.S. crude oil exports. Although 

this statute is widely referred to as the oil export ban, it 

Prime Suppliers

Companies that produce, 

import, or transport 

products across State 

boundaries, to sell to local 

distributors, retailers, or 

end users. Prime supplier 

sales are a good proxy for 

demand.
Energy Primer | 111

Gasoline and No. 2 Distillates Account For Most of 

the Petroleum Use in the U.S.

Source: Derived from EIA data

Crude Oil and Petroleum Products 

Markets and Trading

Because of limited oceangoing transportation options, U.S. 

natural gas markets have historically been shielded from international supply and demand developments. Crude oil and 

petroleum products are traded globally, and their prices are 

greatly influenced by global supply and demand, geopolitical

and economic factors, and the policies of OPEC. Many of the 

countries in the top 10 oil suppliers to the U.S., such as Iraq, 

Colombia, Kuwait, Russia, and Venezuela, have a history of

political unrest or governance issues. These factors can affect

production, reduce supply, and cause prices to rise. As a result, world oil prices have experienced periods of great volatility, driven by supply and demand fundamentals, external 

shocks, and speculative trading.

Geopolitical and Economic Events Drive Crude Oil 

Volatility

Source: Derived from BP Statistical Review of World Energy 2015 data

Note: Prices for 1861-1944 are U.S. average; for 1945-1983 are Arabian 

Light posted at Ras Tanura; for 1984-2014 are Dated Brent; and 2015 are 

Brent as of Q3 2015

As a global commodity, crude oil’s price on the world markets 

is set by the traders who buy and sell the commodity. Although crude oil trades at various locations around the world, 

most trades are based on or derivative to a handful of benchmark crude prices, such as WTI, Brent, and Dubai. There are 

also benchmarks for petroleum products, including New York 

Harbor in the U.S., Amsterdam-Rotterdam-Antwerp (ARA) in

Europe, and Singapore in Asia. 

From 1987 through 2010, WTI and Brent traded within a few 

cents of each other, with WTI generally commanding a small 

price premium. However, the sudden and sharp increase in

production of shale oil in the U.S. resulted in an oversupply at 

Cushing, causing WTI prices to drop below Brent. Between 

2011 and 2014, Brent commanded a premium, reaching as high 

as $27/barrel in September 2011. The Brent premium shrank in

2015, as world prices fell significantly because of a combination of lower demand, particularly from China, and growing 

supply from North America and other producers around the 

world. 
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New Oil Production from Shale Drives Down Oil 

Prices

Source: Derived from EIA data

Despite being a widely traded commodity, the price of crude 

oil is not completely determined by the free market. Member 

countries of OPEC produce much of the oil traded around the 

world, and OPEC attempts to control oil prices by managing 

production by its member countries. Each member country 

has production targets that OPEC lowers to reduce world supply and drive prices up, or increases to drive prices down. The 

largest OPEC producer is Saudi Arabia. Other member countries include Iran, Iraq, Kuwait, Venezuela, Qatar, Libya, the

United Arab Emirates, Algeria, Nigeria, Ecuador, and Angola. 

As of 2015, OPEC member countries produced about 40 

percent of the world’s crude oil, and OPEC’s oil exports accounted for about 60 percent of the total petroleum traded 

internationally. The actions of OPEC, particularly in member 

countries with substantial spare capacity, can and do affect

oil prices. 
Energy Primer | 113

5. Financial Markets and Trading

Financial markets affect physical natural gas and electricity markets in key ways. In the past decade, the commodity markets

associated with natural gas and electricity expanded, both in terms of volumes traded and the types of products offered. One

result from this expansion has been to alter the traditional relationship between physical and financial markets. The traditional

view was that physical markets affect financial; financial products derive their value from physical products. Today, the relationship is bidirectional. Physical markets continue to affect financial markets, but now, financial markets can affect physical markets

– including prices – as well.

This chapter explores natural gas and electricity commodity 

and capital markets.

Financial Markets and Mechanisms

Financial markets are not physical locations like grocery stores 

where one can go to experience the financial marketplace. Instead, they are an array of products, mechanisms, and participants that together flesh out the marketplace.

As mentioned, financial markets differ from physical markets

in that no physical delivery occurs. This does not mean financial markets contain only investors and speculators; physical 

market participants enter the financial market to hedge. Similarly, it does not mean that financial markets involve only contracts that contain financial 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 financial markets are often closely intertwined and use

the same market mechanisms.

Consequently, one good way to understand financial 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 financial markets are conducted through exchanges or over-the-counter (OTC). In the 

case of electricity, trades may also be conducted in regional 

transmission organizations (RTOs are addressed in Chapter 3).

Exchanges

Trading on exchanges is subject to the rules of the exchange 

as well as laws and regulations. Exchange-traded contracts 

are standardized, meaning that specifications for the product’s quality, quantity, and location are established in advance 

by the exchange. Exchange rules typically permit bidirectional 

trading, or the ability to buy or sell with equal ease.

Trading in exchanges is conducted through electronic 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.

Natural gas and electricity are traded on commodity exchanges such as the Nymex, the world’s largest physical commodity 

futures exchange. In addition to other commodities, including 

metals and agricultural products, Nymex facilitates the sale 

and purchase of physical and financial natural gas products

as well as financial power contracts. The ICE also offers natural gas and electricity products, as well as emissions allowances among a host of other commodities. Nodal Exchange 

offers locational (nodal) futures contracts to participants in

the organized electricity markets. Nodal Exchange allows participants to trade electricity contracts for forward months, at 

RTO hubs, zones and nodes.

Margin, or equity contributed as a percentage of the current 

market value of a commodity contract(s), allows market participants 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 
114 | Energy Primer Federal Energy Regulatory Commission

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 are not required to be standardized but rather

can range from complicated individual negotiations for oneoff structured contracts to standard 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 benefits of OTC contracts.

OTC power contracts can be traded 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. Unlike an 

exchange, an electronic brokerage platform matches specific

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 the natural gas contract developed by the North 

American Energy Standards Board (NAESB), and then modify 

it. Others start from scratch. Individually negotiated deals are 

called structured contracts. Two commonly used contracts for 

electricity are the Edison Electric Institute (EEI) Master Power Purchase and Sale Agreement and the WSPP Agreement 

(WSPP was formerly known as the Western Systems Power 

Pool). 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 OTC markets, contracts are bilateral -- i.e., the process of 

negotiating the completion of a purchase or sale is between 

the two market participants.

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 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 services, 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 sufficient 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 maintain 

credit policies and allocate the costs of defaults or other performance failures across market participants. 

RTO markets may have elements that are similar in nature 

to financial transactions. One of these is virtual transactions

(often referred to only as virtuals). 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 participate in virtuals; they 

use the physical product(generation offers or demand bids)in

a way that results in no physical delivery. Virtuals are financial

contracts, directly integrated into the RTO’s operation of its 

physical market; they affect physical supply and demand, and

prices. Virtuals are discussed further in Chapter 3.

RTOs may also offer financial transmission rights (FTRs) programs, also discussed in Chapter 3. Typically, a transmission 

owner that turns over operation of its transmission to the RTO 

wants certainty over its ability to flow 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 
Energy Primer | 115

financial compensation to these transmission owners and firm

rights holders. FTRs are linked to the physical operation of the 

RTO’s system in that the expected capacity of the transmission is used to determine the total capacity of FTRs offered.

FTRs compensate the transmission owners or firm rights holders in a couple of ways. First, the RTOs auction additional FTRs 

to others in the market, including financial 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 firm rights holders. The auction also

determines a value for any FTRs held by the transmission owners or firm 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 benefit a

larger position. It increases the potential return, but also increases risk. Leverage can occur when a trader uses margin 

to trade.

Leverage can be used in other ways. As discussed in Chapter 

6, some traders may try to use leverage to manipulate the 

market. For example, traders may use a smaller position in 

the physical market to benefit a larger position in the financial market. They may buy a financial product whose price is

derived from a physical product. Then, they may try to buy or 

sell or otherwise influence the price of the physical product. If

they succeed, their financial position benefits.

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 benefits of liquidity are often used to justify practices that increase trading or volumes. However, not all trading or volumes are uniformly beneficial 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 is generally 

thought to be liquid. However, when the United States Natural Gas Fund 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 fulfilled by delivery.

By the expiration of the settlement period, the open interest 

in contracts (both in terms of the total number of contracts 

and the number of counterparties) rapidly decreases, so that 

a given number of contracts will represent an increasing share 

of the outstanding prompt-month contracts.

Clearing is a process in which financial 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 
116 | Energy Primer Federal Energy Regulatory Commission

physical contract (physically settled) or a financial payout

made for a financial contract (financially 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 natural gas futures contracts for forward months settle. The final

settlement for a given month occurs 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) 

is calculated based upon the trading in the last half-hour. LD 

settlement is the final price for that particular futures contract

term. The last day for trading option contracts is the day before the futures contract expires.

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 decreasing. For the Nymex natural gas futures contract, 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 financial 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 reflect

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 financially – 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 specific 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 on ICE and Nymex exchanges according to specific formulas, in accordance with

regulations and proposed rules of the Commodity Futures 

Trading Commission. 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, the 

CME Group (CME) imposes accountability levels for any one 

month and for all months, and has limits for expiration-month 
Energy Primer | 117

positions. CME’s accountability for the Nymex Henry Hub natural gas futures contract are 12,000 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 modified.

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 transactions executed during a specified 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 present 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 financial products. Investors, speculators and investment funds also use these physical and financial products for

financial 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 electricity 

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 financial 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 financial contracts, it is the

right to a payout in exchange for payment, although the net 

value may vary over time from a net benefit to a net loss.

Other physical and financial 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 financial product or contract. Standardized derivative contracts trade on

exchanges such as Nymex. Financial contracts are derivatives. 

Futures contracts are derivatives of the physical contract and 

options on futures are derivatives of futures contracts. As 

futures contracts approach expiration, their price should, in 

theory, converge to 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 may not derive their value from 

any other product or contract. Such expiring futures contracts 

may affect spot prices.

Instrument Basics

Each instrument is traded in its own market and is identified

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 specifies what 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 prices. 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. The trade

date is the date on which the contract is written (typically the 

date the trade is executed).
118 | Energy Primer Federal Energy Regulatory Commission

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 financial 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 flow of natural gas would have a begin date of Sept. 1 and an end date of 

Sept. 30.

For the Nymex natural gas futures 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.

Electricity physical and financial contracts may also specify

peak or off-peak delivery, with the peak or off-peak hours defined 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 natural gas futures contract, for example, provides for the delivery of 10,000 MMBtu of natural gas 

in the month specified 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 specified 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 financial derivative uses the Nymex natural 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 natural 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 the 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 other OTC

transactions use whatever location the counterparties to the 

contract desire. For physical contracts, the location must be 

physically viable. For financial products, it can be whateverthe

parties desire (although complicated locations make pricing 

more difficult 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 specified in the contract. For bilateral contracts traded in OTC markets, the quantity contained in the contract can be anything 
Energy Primer | 119

the parties want it to be. For standardized products traded on

electronic brokerage platforms, the quantity is fixed.

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 fixed 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 known 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 majortrading 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 Nymex 

natural gas futures contract is traded more than eight years 

into the future although only the first few years may be very

liquid – i.e., actively traded. 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 final official reported

price for certain contracts and is an average of prices for 

trades occurring during the settlement period. For example, 

the natural gas futures contract settlement price is made during the contract’s 30-minute settlement period – the last 30 

minutes of trading on the contract’s termination day. The 

settlement price forms the basis for the payout for financial

derivatives that use the contract as its underlier, as well as for 

margin calls and for reporting to index publishers.

Physical Products

Physical products involve an obligation to physically deliver. 

Power products include energy, transmission (firm and nonfirm) and ancillary services. Electric energy products include

spot transactions, full requirements sales and bundled services, among others. Natural gas products include the natural 

gas molecules themselves, transportation and storage.

Forward products are contracts for physical 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 commodity, 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 a 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 natural gas futures contract. For this contract, 

the standard contract specifications 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 

fixed 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 specific 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 fixed prices can be used

for price discovery, hedging or speculating. They may be 
120 | Energy Primer Federal Energy Regulatory Commission

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 financial

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 financial 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 financial 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 atthe 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 financial trader could also execute this trade, but would

have to unwind both positions before delivery.

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 floating price

contracts. Indexes are also used by a variety of market participants to inform their decisions in the many steps in the electricity or natural gas supply chain or in trading, known as price 

discovery. Data used in indexes are submitted voluntarily by 

firms 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 financial payout. This is often based

on the value of some physical or financial product specified by

the contract, called the underlier. The value of these financial

contracts is derived from the value of the physical or financial

instrument specified in the contract as the basis for payout; as

such, they are derivatives.

A key benefit of financial products is thatthey 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; the 

individual can simply wait for expiration and receive or pay the 

contract’s payout.

Swaps

A key financial contract structure used in natural gas and electricity markets is the swap, or contract for differences. A swap

is an exchange of one asset or liability for a similar asset or 
Energy Primer | 121

liability. It may entail buying on the spot market and simultaneously selling it forward. Swaps also may involve exchanging 

income flows. Swaps may include calendar spreads or basis

spreads which reflect expectations of time or locational price

variances. 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 specified price at or

before a specified 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 exercise the option or 

let 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, the trader 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 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 benefit 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 

reflecting all their contracts.

Trading requires a buyer and a seller, each willing to transact 

for a price. A buyer bids a price he or she is willing to pay to 

purchase a contract; this is the bid price. A seller offers a product for sale; the price at which the seller 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 bid-ask 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 benefits or loses when

prices go up or down. A position is long if it benefits from increases in price. It is short if it benefits from falling prices. If it

is neutral, benefitting from neither a rise nor a fall in prices, it

is said to be flat.
122 | Energy Primer Federal Energy Regulatory Commission

For example, a trader who purchases a Nymex natural gas futures contract is going long; that contract will benefit from increases in price. A trader who sells the contract is going short; 

the trader will benefit 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 flat.

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 benefits

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 with physical positions are in the market 

to buy and sell natural gas and electricity to enhance profitability of their physical operations. These physical operations 

determine their individual risks and hedging needs, and each 

physical market participant has a risk position related to its 

business 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 sufficient

volumes to serve variable customer demand and in the price 

paid for those volumes. A producer may be concerned about 

selling all output (unless the output may be stored), and 

about the revenues obtained from the gas sale. Physical market participants may have other concerns as well. Producers 

may need a predictable cash flow to support their financing.

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. An LDC also wants a price that regulators and consumers will see as reasonable. Consequently, LDCs usually develop 

a procurement and risk management – hedging – strategy taking these factors into account.

To purchase sufficient quantities, an LDC may create a portfolio of supplies, with a block of firm supply to meet minimum

daily needs. An LDC trader may also decide to buy in the spot 

market to meet demand peaks. An LDC may diversify the 

sources of gas, both to improve reliability of supply but also 

to diversify its price.

An LDC may also manage risk financially. In the commodities

and securities markets, 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.
Energy Primer | 123

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 profit from the market. Investors

are relatively passive; they are in the market to benefit 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 to 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 influence traders’ thinking when analyzing markets for trading opportunities. The first is fundamental

analysis, which takes into account physical demand and supply fundamentals including production, 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) alter traders’ views 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 firms:

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 2009 recession and shake-up in capital markets 

took a toll on capital spending as financial commitments to

infrastructure fell for the first time in years, but spending has

been rising since 2011 (see bar chart).

Source: SNL Energy

The electric industry makes up the bulk of the capital expenditures expected by energy companies. The majority of the 

electric industry’s spending has been on electric transmission 

& distribution and generation.

Types of Capital

Capital comes from two general sources of financing – debt

and equity.
124 | Energy Primer Federal Energy Regulatory Commission

Debt financing involves borrowing money to be repaid over 

time, along with interest at a fixed 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 financial markets with maturities

(when the loan has to be repaid) of more than a year; shorter 

term debtissued by companies through financial 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 refinanced.

• 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 sufficient cash through its operations

or through other financing 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 financial trouble).

• Debt can leverage company profits; 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 financing 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 benefit from the company’s operations, perhaps through

dividends.

• Equity capital can be kept by the company indefinitely.

• Companies can issue shares in the company – stock – 

through financial markets. They may also use private equity – money from venture capital firms 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.

Companies often try to match the type of financing with the

investment they are making. Pipelines, power plants and 

transmission facilities are long-lived assets. They are typically 

financed using long-term capital, such as stock and long-term

bonds, which can have 30-year maturities.
Energy Primer | 125

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 significant problems, it may have to issue especially high-priced debt – junk bonds – to obtain financing.

These are bonds issued by entities lacking investment grade 

credit ratings (see below). In the past few years, marketers 

and financial institutions have taken an interest in the energy

industry, and have provided another source of equity financing. 

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 financial 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, reflected 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 unaffiliated with integrated utilities (and are

known as independent power producers, or IPPs) and those 

that are affiliated but which receive at least half their cash

flow from competitive power sales. The affiliated companies

typically have higher ratings; S&P views the integrated merchants’ business profile 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.
126 | Energy Primer Federal Energy Regulatory Commission
Energy Primer | 127

6. Market Manipulation

Following the energy crisis in the western United States early last decade, Congress enacted the Energy Policy Act of 2005 (EPAct 

2005), which added anti-manipulation provisions to the Federal Power Act, 16 U.S.C. § 824v (2012), and the Natural Gas Act, 15 

U.S.C. § 717c-1 (2012). To implement these anti-manipulation provisions, the Commission issued Order No. 670, adopting the Commission’s Anti-Manipulation Rule, which has been codified as 18 C.F.R. § 1c (2014). 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.

The Anti-Manipulation Rule applies to any entity, which the 

Commission has interpreted to mean any person or form of 

organization, regardless of its legal status, function or activities, and prohibits (1) using a fraudulent device, scheme or artifice, 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 prohibition is intended to deter or punish fraud in wholesale energy markets. The Commission defines 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. 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. 

To violate the Anti-Manipulation Rule, one must also act with 

a sufficient state of mind, that is, level of intent. Intentional

conduct or recklessness (known as scienter) is 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 sufficient 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.
128 | Energy Primer Federal Energy Regulatory Commission

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.” Cargill, Inc. v. Hardin, 452 

F.2d 1154, 1163 (8th Cir. 1971). The Commission recognized this

reality by framing its Anti- Manipulation Rule broadly, rather 

than articulating specific conduct that would violate its rules.

While manipulative techniques may be “limited only by the 

ingenuity of man,” the following are broad categories of illustrative manipulations that have surfaced in the securities and 

commodities markets (including the energy markets) over the 

years. The borders of these categories are flexible 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.

Manipulative Trading Techniques and 

Cross-Product Manipulations

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 

inflate trading volumes or trade at off-market prices to serve

purposes such as maintaining market confidence 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 benefit other positions

in related instruments. 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 practices like wash and round-trip 

trading that are discussed in more detail below fit under this

description as well.

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 from FERC’s Office of Enforcement (Enforcement staff) has investigated and prosecuted

are cross-product schemes in which an entity engages in pricemaking trades in the physical market, often at a loss, with the 

intent to affect the settlement price of price-taking derivative

instruments. Cross-product manipulation is also referred to 

as related-position manipulation. Such trading can violate the 

Anti-Manipulation Rule because the trading is not undertaken 

in response to supply-and-demand fundamentals but rather 

is undertaken to benefit another position. Such trading could

be considered to undermine the functioning of jurisdictional 

markets. 

Key to understanding cross-product manipulation is that financial and physical energy markets are interrelated: physical

natural gas or electric transactions can help set energy prices 

on which financial products are based, so that a manipulator

can use physical trades (or other energy transactions that affect physical prices) to move prices in a way that benefits his

overall financial position. One useful way of looking at manipulation is that the physical transaction is a “tool” that is 

used to “target” a physical price. For example, the physical 

tool could be a physical power flow scheduled in a day ahead

electricity market at a particular “node” and the target could 

be the day-ahead price established by the market operator for 

that node. Or the physical tool could be a purchase of natural 

gas at a trading point located near a pipeline, and the target 

could be a published index price corresponding to that trading 

point. The purpose of using the tool to target a physical price 

is to raise or lower that price in a way that will increase the 

value of a “benefiting position” (e.g., Financial Transmission 

Right or FTR product in power markets, a swap, a futures contract, or other derivative).

Usually, increasing the value of the benefiting position is the

goal or motive of the manipulative scheme. Understanding 

the nature and scope of a manipulator’s benefiting financial

positions—and how they relate to the physical positions—

can be a key focus of manipulation cases. The Commission’s 
Energy Primer | 129

Anti-Manipulation Rule is an intent-based rule: a finding of

manipulation requires proving that the manipulator intended 

(or in some cases, acted recklessly) to move prices or otherwise distort the proper functioning of the energy markets the 

Commission regulates. A company can put on a large physical 

trade that may affect market prices, but if the purpose of that

trade is to hedge risk or speculate based on market fundamentals—rather than, for example, the intent to move prices 

to benefit a related financial position—this conduct, without

more, would not violate the Commission’s Anti-Manipulation 

Rule.

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 wellknown 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 fictitious

transactions or information to a price-index publisher to affect the index settlement price. Another form of information-based manipulation involves providing misinformation 

through conduct that is intended to misrepresent a market 

participant’s characteristics, circumstances, or intentions, 

in order to receive a benefit, payment, or award for which it

would not be eligible but for the misleading conduct. This includes engaging in trading strategies that are intended to create market results that are inconsistent with the purpose of 

the transactions. 

Similarly, wash trading may involve 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 may falsely inflate trading

volumes at a price level and give the impression of greater 

trading activity. False reporting and wash trading have resulted in a number of criminal prosecutions by the Department of 

Justice. 

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 inflated 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 above was that wholesale electricity prices soared. Utilities such as Pacific 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 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 
130 | Energy Primer Federal Energy Regulatory Commission

benefit of the rest of its generation fleet or its financial positions. As withholding is intended to benefit a market participant’s overall portfolio, it is similar to cross-product manipulation, discussed above. 

Representative Matters

The following representative matters involve at least one of 

the types of manipulative schemes described above. Each of 

these matters has either been resolved through settlement or 

is currently pending before a district court or administrative 

law judge.

Barclays Bank, PLC, Daniel Brin, Scott 

Connelly, Karen Levine, and Ryan Smith 

(Barclays and Traders)

On July 16, 2013, the Commission issued an order determining that Barclays and Traders violated the Commission’s AntiManipulation Rule and assessed civil penalties of $435 million 

against Barclays and $18 million against the Traders.1 The Commission also ordered Barclays to disgorge $34.9 million plus 

interest in unjust profits. The Commission found that Barclays

and Traders engaged in loss-generating trading of next-day, 

fixed-price physical electricity on the ICE with the intent to

benefit financial swap positions at primary electricity trading

points in the western United States. In sum, Barclays undertook fixed-price, Day-Ahead physical trades at various Western trading points – tool – to intentionally change the ICE daily 

index – the target – for the benefit of its financial swap positions whose price was based on that index – the benefiting

position. 

Barclays and Traders elected to challenge the penalty in federal district court, and Enforcement staff filed an action to affirm

the Commission’s assessment in the United States District 

1 Barclays Bank PLC, Daniel Brin, Scott Connelly, Karen Levine, and 

Ryan Smith, 144 FERC ¶ 61,041 (2013) (order assessing civil penalties). 

Court for the Eastern District of California on October 9, 2013. 

The matter is pending before that court.

BP America, Inc. and Affiliates

On August 5, 2013, the Commission issued an order to show 

cause and notice of proposed penalty to BP.2 In that proceeding, Enforcement staff alleged that BP made uneconomic

sales at Houston Ship Channel and took steps to increase its

market share at Houston Ship Channel as part of a manipulative scheme to suppress the Houston Ship Channel Gas Daily

index, and that this scheme was motivated by a desire to benefit certain physical and financial positions held by BP whose

price was set by the same index. In sum, as cross-product 

manipulation, Enforcement staff alleged that BP undertook

trades at Houston Ship Channel – the tool – with the intent

to alter the price of the Houston Ship Channel Gas Daily index

- the target – to increase the value of physical and financial

positions whose prices were set by the index - the benefiting

positions. On May 15, 2014, the Commission set the matter for 

hearing to determine whether BP’s conduct violated the AntiManipulation Rule.3

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 profits and pay a civil penalty

of $135 million. Enforcement staff had alleged that CCG entered into significant loss-generating physical and virtual dayahead transactions in electricity markets in and around New 

York State with the intent to move day-ahead price settlements to benefit financial swap positions that received their

prices from those settlements.

2 BP America Inc., 144 FERC ¶ 61,100 (2013).

3 BP America Inc., 147 FERC ¶ 61,130 (2014).
Energy Primer | 131

Deutsche Bank Energy Trading 

(Deutsche Bank)

On January 22, 2013, the Commission approved a settlement 

between the Office of Enforcement and Deutsche Bank, in

which Deutsche Bank agreed to disgorge $172,645 in unjust 

profits and pay a civil penalty of $1.5 million. In the settlement,

Enforcement staff concluded that Deutsche Bank violated the

Commission’s Anti-Manipulation Rule, through cross-product 

manipulation in which it traded physical exports at Silver Peak 

that were not profitable with the intent to benefit its Congestion Revenue Rights (CRR) position. Deutsche Bank had a 

CRR position at the 17-MW Silver Peak intertie that started to 

lose money. To stem those losses, Deutsche Bank submitted 

export bids to change the price at Silver Peak, as that price 

affected the value of Deutsche Bank’s CRR position. By changing that price, Deutsche Bank diminished its losses on the CRR 

position. Deutsche Bank consistently lost money on its export 

at Silver Peak, but those losses were offset by the avoided

losses on its CRR position. In sum, as cross-product manipulation, Deutsche Bank traded physical exports – the tool – to 

alter the price at the Silver Peak – the target – to diminish its 

losses on its CRR position – the benefiting position.

ISO-NE Day-Ahead Load Response 

Program (DALRP) 

Based on an Enforcement investigation of Rumford Paper 

Company (Rumford), Lincoln Paper and Tissue LLC (Lincoln), 

Competitive Energy Services, LLC (CES), and Richard Silkman, 

the Commission in July 2012 issued each subject an order to 

show cause alleging that their conduct related to the DALRP 

in the ISO New England market (ISO-NE) violated the Commission’s Anti-Manipulation Rule. The Office of Enforcement and

Rumford settled the allegations against the company, which 

the Commission approved in March 2013.4 On August 29, 2013, 

4 Rumford Paper Co., 142 FERC ¶ 61,218 (2013) (order approving 

stipulation and consent agreement).

the Commission issued Orders Assessing Civil Penalties to Lincoln, CES, and Silkman, finding that the subjects fraudulently

inflated load baselines and repeatedly offered load reductions

at the minimum offer price in order to maintain the inflated

baseline.5 Enforcement staff found that the scheme involved

uneconomic energy purchases that served no legitimate purpose and were designed to increase DALRP payments that 

would not have otherwise been obtained. The Commission 

determined that this scheme misled ISO-NE, inducing payments to these entities based on the inflated baselines for

load reductions that never occurred. 

The Commission ordered Lincoln to pay $5 million in civil penalties and approximately $379,000 in disgorgement; CES to 

pay $7.5 million in civil penalties and approximately $167,000 

in disgorgement; and Silkman to pay $1.25 million in civil penalties. None of the respondents paid the amounts assessed by 

the Commission. Enforcement staff filed two petitions in the

United States District Court for the District of Massachusetts 

on December 2, 2013 seeking review and affirmance of the

Commission’s orders. These petitions are pending.

5 Lincoln Paper and Tissue, LLC, 144 FERC ¶ 61,162 (2013) (order assessing civil penalty); Competitive Energy Services, LLC, 144 FERC 

¶ 61,163 (2013) (order assessing civil penalty); Richard Silkman, 

144 FERC ¶ 61,164 (2013) (order assessing civil penalty).
132 | Energy Primer Federal Energy Regulatory Commission

JP Morgan Ventures Energy Corporation 

(JPMVEC)

On July 30, 2013, the Commission approved a settlement between the Office of Enforcement and JPMVEC resolving an

investigation of JPMVEC’s bidding practices.6 JPMVEC paid 

$285 million in civil penalties, $124 million in disgorgement to 

CAISO ratepayers, and $1 million in disgorgement to MISO. In 

addition, the company agreed to waive its claims that CAISO 

owed it money from two of the strategies that Enforcement 

staff had investigated, and to conduct a comprehensive external assessment of its policies and practices in the power 

business. 

Enforcement staff determined that JPMVEC violated the

Commission’s Anti-Manipulation Rule by engaging in twelve 

manipulative bidding schemes in CAISO and MISO. These 

schemes distorted a well-functioning market in several ways, 

including but not limited to, misleading CAISO and MISO into 

paying JPMVEC at rates far above market prices; submitting 

bids that were expected to, and did, lose money at market 

rates, as they were not driven by the market forces of supply and demand; defrauding the ISOs by obtaining payments 

for benefits that JPMVEC did not deliver; and displacing other

generation and influencing energy and congestion prices.

6 In Re Make-Whole Payments and Related Bidding Strategies, 144 

FERC ¶ 61,068 (2013).

Louis Dreyfus Energy Services L.P. 

(Louis Dreyfus)

On February 7, 2014, the Commission approved a settlement 

between the Office of Enforcement, Louis Dreyfus, and one

of its traders, Xu Cheng.7 Under the terms of the settlement, 

Louis Dreyfus agreed to disgorge $3,334,000 in unjust earnings, plus interest, and pay a civil penalty of $4,072,257. Cheng, 

who had previously crafted and described the manipulative 

scheme in his doctoral dissertation, agreed to pay a civil penalty of $310,000. In addition, Louis Dreyfus prohibited Cheng 

from virtual trading anywhere in the United States, and agreed 

that he would not be permitted to resume such trading for at 

least two years. 

In the settlement, Enforcement staff concluded that Louis

Dreyfus violated the Commission’s Anti-Manipulation Rule 

when it made certain virtual trades in MISO with the intent to 

increase the value of its nearby FTR position. Louis Dreyfus established an FTR position near the Velva node. Louis Dreyfus 

earned little or no profit on that FTR position, until it started

to place virtual demand bids at the Velva node to benefit the

FTR position. Louis Dreyfus consistently lost money on those 

virtual demand bids, but that loss was offset on its gains on

its FTR position. In sum, as cross-product manipulation, Louis 

Dreyfus submitted virtual demand bids – the tool – to alter the 

price at the Velva node – the target – to increase the value of 

its FTR position – the benefiting position. 

7 MISO Virtual and FTR Trading (Louis Dreyfus Energy Services), 146 

FERC ¶ 61,072 (2014).